NUREG-1771

U.S. Operating Experience

With Thermally Treated

Alloy 600 Steam Generator

Tubes

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation vtREgo<

Washington, DC 20555-0001
I

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NUREG-1771

U.S. Operating Experience

With Thermally Treated

Alloy 600 Steam Generator

Tubes

Manuscript Completed: February 2003

Date Published: April 2003

Prepared by

K. J. Karwoski

Division of Engineering

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
ABSTRACT

Steam generators placed in service in the 1 960s and 1 970s had tubes primarily fabricated from

mill-annealed Alloy 600. 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 numerous facilities, 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. Because of the

safety significance of steam generator tube integrity, this paper evaluates the operating

experience of thermally treated Alloy 600 by looking at the extent to which it is used and results

from steam generator tube examinations.

-111-
CONTENTS

ABSTRACT . ..................................................... iiiCONTENTS . ..................................................... vLIST OF FIGURES ......................................................- viiLIST OF TABLES ..................................................... -viiiEXECUTIVE SUMMARY ....................................................-. xiACKNOWLEDGMENTS ................................................... x.iv1 INTRODUCTION . ........................................................ 1-

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

1.2 Tube Integrity Program ................................................ -2

1.2.1 Purpose of Inspections ...................... . -2-

1.2.2 Eddy Current Testing .....................-.......................... 3-

1.2.3 Tube Repairs .................................................... -5-

1.2.4 Leakage Monitoring ......................-.......................... 6-

1.3 Mill-Annealed Alloy 600 Steam Generator Operating Experience ...............-. 6-

1.4 Thermally Treated Alloy 600 Tubes ......... ............................-. 7-

2 STEAM GENERATOR DESIGNS IN PLANTS WITH

THERMALLY TREATED ALLOY 600 TUBES ..............-................... 11-

2.1 Introduction ................................................... -11-

2.2 Model D5 Steam Generators . .......................................... 12-

2.3 Model F Steam Generators . .........................................-. 14-

2.4 Replacement Steam Generators . .....................................-. 14-

3 THERMALLY TREATED ALLOY 600 STEAM GENERATOR TUBE

OPERATING EXPERIENCE .............................................-. 31-

3.1 Data Gathering Methodoloqv and Introduction ............-................. 31-

3.2 Model D5 Steam Generator Operating Experience ..........-............... 31-

3.2.1 Braidwood 2 ..................................................-. 31-

3.2.2 Byron 2 ................................................... -34-

3.2.3 Catawba 2 ................................................... -40-

3.2.4 Comanche Peak 2 ............................................... 45-

3.3 Model F Steam Generator Operating Experience ...........-................ 47-

3.3.1 Callaway..................................................... . -47-

3.3.2 Millstone 3 ................................................... -49-

3.3.3 Seabrook ................................................... -52-

3.3.4 Vogtle 1 ................................................... -55-

3.3.5 Vogtle 2 ................................................... -58-

3.3.6 Wolf Creek ................................................... -61-

3.4 Replacement Model Steam Generator Operating Experience ......-........... 64-
3.4.1 Indian Point 2 ............................... -64-

3.4.2 Point Beach 1 ............................... -64-

3.4.3 Robinson 2 ............................... -67-

3.4.4 Salem 1 ............................... -72-

3.4.5 Surry 1 ............................... -73-

3.4.6 Surry 2 ............................... -77-

3.4.7 Turkey Point 3 ............................... -80-

3.4.8 Turkey Point 4 ............................... -84-

4 SUMMARY ............................... -153-

4.1 Model D5 Summary ...............-................ 153-

4.2 Model F Summary ...........................-. 154-

4.3 Replacement Model Summary ................................ -154-

4.4 Overall Summary ...............-................ 155-

4.4.1 Forced Outages ............................... -155-

4.4.2 Tube Pulls ............................... -157-

4.4.3 Selected Inspection Findings ........................-....... 158-

4.4.4 Summary and Observations ................................ 160-

APPENDIX A: ACRONYMS ............................... -214-

APPENDIX B: BIBLIOGRAPHY ........ ....................... -215-

-vi-
LIST OF FIGURES

Figure 1-1: Mill-Annealed Alloy 600 Steam Generator Tube Degradation ............. -. 10-

Figure 2-1: Typical PWR Recirculating Steam Generator Without a Preheater ......... -. 18-

Figure 2-2: Typical PWR Recirculating Steam Generator With a Preheater ........... -. 19-

Figure 2-3: U-Bend Features . .............................................-. 20-

Figure 2-4: Number of Plants with Thermally Treated Alloy 600 Steam Generator Tubes as a

Function of Year . ..................................-............. 21-

Figure 2-5: Westinghouse Model D5 Steam Generator Tube Support Locations ....... -. 22-

Figure 2-6: Westinghouse Model D5 Steam Generator Tubesheet Map ..............-. 23-

Figure 2-7: Preheater Region of Westinghouse Model D5 Steam Generator .......... -. 24-

Figure 2-8: Westinghouse Model F Steam Generator Tube Support Locations ........ -. 25-

Figure 2-9: Westinghouse Model F Steam Generator Tubesheet Map ...............-. 26-

Figure 2-10: Westinghouse Model 44F Steam Generator Tube Support Locations ...... -. 27-

Figure 2-11: Westinghouse Model 44F Steam Generator Tubesheet Map .............-. 28-

Figure 2-12: Westinghouse Model 51 F Steam Generator Tube Support Locations ...... -. 29-

Figure 2-13: Westinghouse Model 51 F Steam Generator Tubesheet Map .............-. 30-

Figure 4-1: Model D5: Causes of Tube Plugging (12/01) ........................-. 196-

Figure 4-2: Model D5: Plugging Per Year ....................................-. 197-

Figure 4-3: Model D5: Cumulative Plugging Per Refueling Outage .................-. 198-

Figure 4-4: Model D5: Causes of Tube Plugging Per Year .......................-. 199-

Figure 4-5: Model F: Causes of Tube Plugging (12/01) ..........................-. 200-

Figure 4-6: Model F: Plugging Per Year .....................................-. 201-

Figure 4-7: Model F: Cumulative Plugging Per Refueling Outage ..................-. 202-

Figure 4-8: Model F: Causes of Tube Plugging Per Year ........................-. 203-

Figure 4-9: Replacement Models: Causes of Tube Plugging (12/01) ...............-. 204-

Figure 4-10: Replacement Models: Plugging Per Year ...........................-. 205-

Figure 4-11: Replacement Models: Cumulative Plugging Per Refueling Outage ....... -. 206-

Figure 4-12: Replacement Models: Causes of Tube Plugging Per Year .............-. 207-

Figure 4-13: Number of Thermally Treated Alloy 600 Tubes in Service Per Year ...... -. 208-

Figure 4-14: All Models: Tubes Plugged Per Grouping/Model (12/01) ...............-. 209-

Figure 4-15: All Models: Causes of Tube Plugging (12/01) .......................-. 210-

Figure 4-16: All Models: Number of Tubes Plugged Per Year .....................-. 211-

Figure 4-17: All Models: Percentage of Tubes Plugged Per Year ..................-. 212-

Figure 4-18: All Models: Causes of Tube Plugging Per Year ......................-. 213-

-vii-
LIST OF TABLES

Table 1-1: Plants With Replacement Steam Generators ............................-. 9-

Table 2-1: Plants With Thermally Treated Alloy 600 Tubes ........................-. 16-

Table 2-2: Age of Steam Generators at Plants With Thermally Treated Alloy 600 Tubes . . -17-

Table 3-1: Braidwood 2: Summary of Bobbin Inspections and Tube Plugging .......... -. 87-

Table 3-2: Braidwood 2: Causes of Tube Plugging ...............................-. 88-

Table 3-3: Braidwood 2: Tubes Plugged for Indications Other Than AVB Wear ........ -. 89-

Table 3-4: Byron 2: Summary of Bobbin Inspections and Tube Plugging ..............-. 90-

Table 3-5: Byron 2: Causes of Tube Plugging ...................................-. 91-

Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear ............ -. 92-

Table 3-7: Catwaba 2: Summary of Bobbin Inspections and Tube Plugging ............ -. 95-

Table 3-8: Catawba 2: Causes of Tube Plugging ................................-. 96-

Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear .......... -. 97-

Table 3-10: Comanche Peak 2: Summary of Bobbin Inspections and Tube Plugging .... -102-

Table 3-1 1: Comanche Peak 2: Causes of Tube Plugging ........................-. 103-

Table 3-12: Comanche Peak 2: Tubes Plugged for Indications Other Than AVB Wear . . -104-

Table 3-13: Callaway: Summary of Bobbin Inspections and Tube Plugging (TT Tubes Only)

.................................................................. . -105-

Table 3-14: Callaway: Causes of Tube Plugging (Thermally Treated Tubes Only) ...... -. 106-

Table 3-15: Callaway: Tubes Plugged for Indications Other Than AVB Wear ......... -. 107-

Table 3-16: Millstone 3: Summary of Bobbin Inspections and Tube Plugging .......... -. 109-

Table 3-17: Millstone 3: Causes of Tube Plugging ..............................-. 110-

Table 3-18: Millstone 3: Tubes Plugged for Indications Other Than AVB Wear ........ -. 111-

Table 3-19: Seabrook: Summary of Bobbin Inspections and Tube Plugging ........... -. 113-

Table 3-20: Seabrook: Causes of Tube Plugging ...............................-. 114-

Table 3-21: Seabrook: Tubes Plugged for Indications Other Than AVB Wear ......... -. 115-

Table 3-22: Vogtle 1: Summary of Bobbin Inspections and Tube Plugging ............ -. 116-

Table 3-23: Vogtle 1: Causes of Tube Plugging ................................-. 117-

Table 3-24: Vogtle 1: Tubes Plugged for Indications Other Than AVB Wear .......... -. 118-

Table 3-25: Vogtle 2: Summary of Bobbin Inspections and Tube Plugging ............ -. 119-

Table 3-26: Vogtle 2: Causes of Tube Plugging ................................-. 120-

Table 3-27: Vogtle 2: Tubes Plugged for Indications Other Than AVB Wear .......... -. 121-

Table 3-28: Wolf Creek: Summary of Bobbin Inspections and Tube Plugging ......... -. 122-

Table 3-29: Wolf Creek: Causes of Tube Plugging ..............................-. 123-

Table 3-30: Wolf Creek: Tubes Plugged for Indications Other Than AVB Wear ....... -. 124-

Table 3-31: Indian Point 2: Summary of Bobbin Inspections and Tube Plugging ....... -. 125-

Table 3-32: Indian Point 2: Causes of Tube Plugging ............................-. 126-

Table 3-33: Indian Point 2: Tubes Plugged for Indications Other Than AVB Wear ..... -. 127-

Table 3-34: Point Beach 1: Summary of Bobbin Inspections and Tube Plugging ....... -. 128-

Table 3-35: Point Beach 1: Causes of Tube Plugging ............................-. 129-

Table 3-36: Point Beach 1: Tubes Plugged for Indications Other Than AVB Wear ..... -. 130-

Table 3-37: Robinson 2: Summary of Bobbin Inspections and Tube Plugging ......... -. 131-

Table 3-38: Robinson 2: Causes of Tube Plugging ..............................-. 132-

Table 3-39: Robinson 2: Tubes Plugged for Indications Other Than AVB Wear ....... -. 133-

Table 3-40: Salem 1: Summary of Bobbin Inspections and Tube Plugging ............ -. 134-

Table 3-41: Salem 1: Causes of Tube Plugging ................................-. 135-

Table 3-42: Salem 1: Tubes Plugged for Indications Other Than AVB Wear .......... -. 136-

-viii-
Table 3-43: Surry 1: Summary of Bobbin Inspections and Tube Plugging ............ -. 137-

Table 3-44: Surry 1: Causes of Tube Plugging .................................-. 138-

Table 3-45: Surry 1: Tubes Plugged for Indications Other Than AVB Wear ........... -. 139-

Table 3-46: Surry 2: Summary of Bobbin Inspections and Tube Plugging ............ -. 141-

Table 3-47: Surry 2: Causes of Tube Plugging .................................-. 142-

Table 3-48: Surry 2: Tubes Plugged for Indications Other Than AVB Wear ........... -. 143-

Table 3-49: Turkey Point 3: Summary of Bobbin Inspections and Tube Plugging ....... -. 144-

Table 3-50: Turkey Point 3: Causes of Tube Plugging ...........................-. 145-

Table 3-51: Turkey Point 3: Tubes Plugged for Indications Other Than AVB Wear ..... -. 146-

Table 3-52: Turkey Point 4: Summary of Bobbin Inspections and Tube Plugging ....... -. 150-

Table 3-53: Turkey Point 4: Causes of Tube Plugging ...........................-. 151-

Table 3-54: Turkey Point 4: Tubes Plugged for Indications Other Than AVB Wear ..... -. 152-

Table 4-1: Model D5: Total Number and Percentage of Tubes Plugged (12/01) ....... -. 165-

Table 4-2: Model D5: Number of Tubes Plugged As a Function of Mechanism (Detailed)

(12/01) ............................................................... 166-

Table 4-3: Model D5: Cumulative Plugging Per Year ............................-. 167-

Table 4-4: Model D5: Plugging Per Year .....................................-. 168-

Table 4-5: Model D5: Cumulative Plugging Per RFO ............................-. 169-

Table 4-6: Model D5: Number of Tubes Plugged As a Function of Mechanism Per Year

(Detailed) ..........................................................-. 170-

Table 4-7: Model D5: Number of Tubes Plugged As a Function of Mechanism Per Year

(Summary) . .......................................................... 171-

Table 4-8: Model D5: Fraction of Tubes Plugged As a Function of Mechanism Per Year

(Summary) .......................................................... -172-

Table 4-9: Model F: Total Number and Percentage of Tubes Plugged (12/01) ........ -. 173-

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

(12/01) ....................-......................................... 174-

Table 4-11: Model F: Cumulative Plugging Per Year ............................-. 175-

Table 4-12: Model F: Plugging Per Year .....................................-. 176-

Table 4-13: Model F: Cumulative Plugging Per RFO ............................-. 177-

Table 4-14: Model F: Number of Tubes Plugged As a Function of Mechanism Per Year

(Detailed) ............................................................ 178-

Table 4-15: Model F: Number of Tubes Plugged As a Function of Mechanism Per Year

(Summary) . ......................................................... -179-

Table 4-16: Model F: Fraction of Tubes Plugged As a Function of Mechanism Per Year

(Summary) . ......................................................... -180-

Table 4-17: Replacement Models: Total Number and Percentage of Tubes Plugged (12/01)

.................................................................. .-181-

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

(Detailed) (12/01) . ..................................................... 182-

Table 4-19: Replacement Models: Cumulative Plugging Per Year ..................-. 183-

Table 4-20: Replacement Models: Plugging Per Year ...........................-. 184-

Table 4-21: Replacement Models: Cumulative Plugging Per RFO ..................-. 185-

Table 4-22: Replacement Models: Number of Tubes Plugged As a Function of Mechanism Per

Year (Detailed) . ....................................................... 186-

Table 4-23: Replacement Models: Number of Tubes Plugged As a Function of Mechanism Per

Year (Summary) . ....................................................-. 187-

-Ix-
Table 4-24: Replacement Models: Fraction of Tubes Plugged As a Function of Mechanism Per

Year (Summary) . ....................................................-. 188-

Table 4-25: All Models: Total Number and Percentage of Tubes Plugged (12/01) ...... -. 189-

Table 4-26: All Models: Number of Tubes Plugged As a Function of Mechanism (Detailed)

(12101) ..........................................................-. 190-

Table 4-27: All Models: Number of Tubes Plugged As a Function of Mechanism (Summary) (12/01) ............................................................-. 191-

Table 4-28: All Models: Plugging Per Year ....................................-. 192-

Table 4-29: All Models: Number of Tubes Plugged As a Function of Mechanism Per Year

(Detailed) ..........................................................-. 193-

Table 4-30: All Models: Number of Tubes Plugged As a Function of Mechanism Per Year

(Summary) .........................................................-. 194-

Table 4-31: All Models: Fraction of Tubes Plugged As a Function of Mechanism Per Year

(Summary) .........................................................-. 195-
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.

Tubes installed in U.S. nuclear steam generators placed in service in the 1960s and 1970s

were usually only mill-annealed (passed through a furnace at a high temperature). Over 25

years of 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, approximately nine tube ruptures,

numerous midcycle steam generator tube inspections, and the replacement of steam

generators at numerous plants. In addition, extensive tube degradation contributed to the

permanent shutdown of other plants. Haddam Neck, Maine Yankee, Trojan, Zion 1, Zion 2,

and San Onofre 1 ceased operation with significant amounts of tube degradation.

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 presently used in the steam generators at 17 plants. At another plant, Callaway, the steam

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

600 tubes in the remaining rows. Therefore, thermally treated Alloy 600 is used in

approximately 25% of the currently operating PWRs (18 of 69).

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

documented. The experience with thermally treated Alloy 600 has not been well documented,

although thermally treated Alloy 600 is generally recognized to perform better. This report

summarizes the steam generator operating experience of U.S. PWRs with thermally treated

Alloy 600 steam generator tubes as of December 2001.

A historical review of operating experience identified only six unplanned outages as a result of

steam generator issues in plants with thermally treated Alloy 600 tubes: two plants shut down

after discovering primary-to-secondary leakage, and four after loose part monitors provided

indications that a loose part may be p5resent.

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

and 2001, only 1397 tubes (0.5%) have been plugged. All together, these 18 plants have

operated for approximately 260 calendar years (as of December 2001). On the average each

of these plants has commercially operated for 14 calendar years (as of December 2001). The

dominant degradation mode for thermally treated Alloy 600 tubes is wear. Of the approximately

1400 tubes plugged, approximately 53% of the tubes were plugged as a result of wear. Tube

-xl-
wear occurs when the tube contacts a support structure (e.g., an antivibration bar) or a foreign

object (e.g., a loose part).

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 increased corrosion

resistance is largely due to the thermal treatment process that has superseded the mill

annealing process used in earlier steam generator designs.

The relatively good operating experience of plants with thermally treated Alloy 600 steam

generator tubes can be attributed to several factors besides the heat treatment: 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 plants whose tubes were expanded mechanically or explosively. Since crack growth rate and

time to crack initiation depend in part on the stress level, lower stresses may result in slower

crack growth rates and/or longer times before crack initiation.

A number of issues identified in this historical review may warrant additional investigation in the

future. These issues are summarized in Section 4.4.4. Some of the issues discussed in

Section 4.4.4 include the potential for tubes to continue to degrade following plugging (which

raises questions about the need to stabilize these tubes to prevent them from damaging

adjacent tubes), the potential for mechanically induced tube denting to occur at tube supports,

and the usefulness of the destructive examination of pulled tubes in assessing the causal

mechanism for various types of eddy current indications (e.g., volumetric indications).

Although the operating experience with thermally treated Alloy 600 tubes has been favorable to

date, licensees still need to monitor the tubes to detect the onset of tube degradation (including

cracking) and assure the structural and leakage integrity of the tubes during the intervals

between inspections. A better understanding of some of these issues would be useful in

determining appropriate intervals for future monitoring of tube degradation.

During the preparation of this report in the first half of 2002, several noteworthy events occurred

in plants with thermally treated Alloy 600 steam generator tubes. There were two additional

unplanned outages attributed to steam generator issues, and cracklike indications at a plant.

One of the unplanned outages began after the licensee observed a 75 gallon per day

primary-to-secondary leak due to damage from a loose part, and the other was prompted by an

indication of a loose part (not associated with primary-to-secondary leakage). The cracklike

indications were detected at Seabrook and were discussed in NRC Information Notice 2002-21,

"Axial Outside-Diameter Cracking Affecting Thermally Treated Alloy 600 Steam Generator

Tubing," which was issued on June 25, 2002. At Seabrook, portions of two tubes were

removed for destructive examination. 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

-xii-
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.

-Xlii-
ACKNOWLEDGMENTS

The author thanks April Smith and Matt Yoder for their assistance in compiling, summarizing,

and graphing some of the information contained within this report. The author also thanks

Cheryl Khan and Ted Sullivan for their careful review of this report and helpful comments.

-xiv-
I INTRODUCTION

1.1 Safety Significance

Heat generated in pressurized-water reactors (PWRs) is removed from the reactor core by the

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

pump and one vertically mounted steam generator. There are two to four reactor coolant loops

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

the hemispherical head of the steam generator. The transfer of heat from the primary system

water to the water on the secondary side of the steam generator is accomplished primarily

through the steam generators tubes. This heat transfer boils the water on the secondary side

of the steam generator. The primary coolant then returns to the reactor core via 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.

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

boundary in a PWR. This 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 provided 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.

Because of the potential consequences of steam generator tube leakage, regulatory limits exist

for 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 steam generator

tube 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 break. In the event of 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.

For normal operation, the amount of primary-to-secondary leakage is limited by a plant's

technical specifications. The limit is plant-specific and ranges from approximately 150 to 720

gallons per day (gpd) through any one steam generator. Leakage through all steam generators

is also limited typically to 1 gallon per minute (gpm). For postulated accidents such as the

rupture of a main steam line or feed line, the radiological dose consequences associated with

approximately 1 gpm primary-to-secondary leakage were evaluated as part of the design basis

of the plant. Plant response to a rupture of the main steam line and any leakage of radioactive

-1-
material through the steam generators is a design basis accident considered in the safety

evaluation of PWRs. Typically, plants were designed assuming that primary-to-secondary

leakage during postulated accidents would be less than 1 gpm.

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

(e.g., 150 gpd), there is a possibility that a tube can rupture during normal operation. Leakage

from a ruptured tube can result in primary-to-secondary leak rates in the range of 100 to 700

gpm (depending on the severity of the tube rupture and the capacity of the safety

injection/charging system pumps). PWRs are designed such that operators can rapidly and

effectively respond to the accidental rupture of one steam generator tube during power

operation. Although the rupture of a tube during normal power operation is considered in the

design of PWRs, a tube rupture concurrent with a postulated accident is not.

1.2 Tube Integrity Program

1.2.1 Purpose of Inspections

Because of the importance of steam generator tube integrity, the NRC requires the

performance of periodic inservice inspections of steam generator tubes. The requirements for

the inspection of steam generator tubes are intended to ensure that this portion of the reactor

coolant system maintains its structural and leakage integrity. Structural integrity refers to

maintaining adequate margins against gross failure, rupture, and collapse of the steam

generator tubes. Leakage integrity refers to limiting primary-to-secondary leakage during

normal operation and postulated accidents to within acceptable limits.

The structural criteria that the tubes are intended to meet are specified in Regulatory Guide

1.1 21, "Bases for Plugging Degraded PWR Steam Generator Tubes." Adequate leakage

integrity during transients and postulated accidents is demonstrated by showing that the

resulting leakage from the tubes will not exceed a rate that would violate offsite or control room

dose criteria. These criteria are specified, in part, in Part 100 to Title 10 of the Code of Federal

Regulations (10 CFR Part 100) and in General Design Criteria 19 of Appendix A to 10 CFR Part

50.

To provide assurance of adequate structural and leakage integrity, inspections are performed

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

and/or inservice conditions. In addition, the inservice inspections of the steam generator tubes

provide a means of characterizing the nature and cause of any tube degradation so that

corrective measures can be taken. Tubes that show an indication of degradation that exceeds

the tube repair limits specified in a plant's technical specifications are removed from service by

plugging or are repaired by sleeving, as discussed in Section 1.2.3.

The frequency of the inservice inspections of the steam generator tubes is generally every 12 to

24 calendar months, as specified in a plant's technical specifications. The specified maximum

interval may need to be reduced to every 20 months in cases where previous inspections have

shown extensive degradation, and may be increased to as much as every 40 months in cases

where previous inspections have revealed minor degradation. These intervals are reduced or

extended on the basis of the categorization of inspection results, as defined in the plant's

technical specifications.

-2-
Although many plants' technical specifications include a general provision to extend

surveillances by 25% of the specified interval, this provision is not considered applicable to

steam generator tube inspections; the above criteria indicate the only conditions under which

the surveillance interval for steam generator tube inspections may be changed. This position

was delineated in NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance

Intervals to Accommodate a 24-Month Fuel Cycle," issued on April 2, 1991. As a practical

matter, however, utilities with extensive tube degradation (e.g., plants with mill-annealed Alloy

600 steam generator tubes) generally perform steam generator tube inspections at all refueling

outages, which typically occur every 12 to 24 months.

The minimum number of steam generators inspected and the number of tubes inspected in

these steam generators are specified in the plant's technical specifications. The technical

specifications typically permit a subset of steam generators to be examined provided all steam

generators are performing in a similar manner. The steam generators inspected during a given

outage are alternated so as to ensure the material condition of each steam generator is

monitored over time. Depending on the results of the inspections (i.e., the number and severity

of the flaws identified), additional steam generators may need to be examined during an

outage.

Since the purpose of the steam generator tube inspections is, in part, to ensure adequate

structural and leakage integrity of the tube bundle, more frequent inservice inspections may be

required, depending on the severity of the indications detected. To ensure that the frequency

was adequate for the prior cycle, licensees for PWRs should assess the inspection results

following every outage to ensure that the tubes retained adequate structural and leakage

integrity. This type of assessment is referred to as 'condition monitoring.' In addition,

licensees should project the condition of the tubes 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." These assessments

should be performed because the inspection frequencies and tube repair criteria specified in

the technical specifications were established on the basis of specific assumptions concerning

various parameters such as the forms of degradation (if any) to which the tubes may be

susceptible, limitations of nondestructive examination techniques, and the rate of steam

generator tube degradation. If any of these parameters exceed what was assumed during the

development of the inspection intervals, the basis for the inspection frequency and tube repair

criteria are no longer considered valid.

In summary, the inservice inspection of steam generator tubes is to be conducted at

appropriate intervals, such that the structural and leakage'integrity of the steam generator tubes

is maintained with appropriate margins. These inspections should be adequate to detect

degradation at a sufficiently early stage to preclude the progression of the degradation to the

point that the regulatory criteria regarding steam generator tube structural and leakage integrity

can no longer be met during the interval between inspections.

1.2.2 Eddy Current Testing

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

-3-
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 are used to translate these changes in test coil

impedance into an output that can be monitored by the data analyst. The depth of certain types

of flaws can be determined by the observed phase angle response of this output signal. The

test equipment is calibrated using tube specimens containing artificially induced flaws of known

depth. 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 defect signals at these locations. NUREG/CR-6365

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; etc.)

* 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

As a result of the bobbin coil's limitations, the emergence of new forms of tube degradation

(e.g., stress corrosion cracking), and advancements in computer technology, additional

inspection probes were utilized. Currently, inspections of steam generator tubes generally

employ both a bobbin coil probe and an additional probe, such as a rotating probe. The bobbin

coil probe permits rapid screening of the tube for degradation and can be pulled through a tube

at speeds exceeding 40 inches per second, while the rotating probes are used to detect forms

of degradation at specific locations since they do not suffer from many of the limitations of the

bobbin coil (discussed above).

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

rotating probe head at a specific plant 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 include (1) a pancake coil which is sensitive to both axially and

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

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

axially oriented degradation), or (4) a plus-point coil (which 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

-4-
less sensitive to geometric discontinuities. The major disadvantage of the rotating probes is

their slow inspection speed (typically less than 1 inch 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).

Tubes are generally selected for eddy current testing on a random basis except where

experience indicates critical areas requiring inspection and tubes previously found to contain

detectable wall penetrations (greater than 20%) or imperfections. A preservice inspection of all

steam generators is performed to establish a baseline condition of the tubes. The inservice

inspection frequency is adjusted to account for the history of tube degradation encountered

within the unit's steam generators.

1.2.3 Tube Repairs

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

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

sleeving. Tube degradation is typically discovered during scheduled inservice examinations of

steam generator tubes, and tube repair (plugging or sleeving) is required for all tubes with

indications of tube degradation exceeding the tube repair limits. All plants have a depth-based

repair limit that is applicable to all forms of steam generator tube degradation. Altematives to

this depth-based limit have been approved; however, no alternatives have been approved for

plants with thermally treated Alloy 600 steam generator tubes. The depth-based repair limit

varies from plant to plant, but is typically 40% of the tube wall thickness. That is, tubes with

indications of degradation greater than or equal to 40% must be plugged or repaired. For

plants with thermally treated Alloy 600 steam generator tubes, there are plants which do do not

have the standard 40% depth-based repair limit in their technical specifications. These plants

include Robinson 2 and Callaway, which have depth-based repair limits of 47% and 48%,

respectively.

The plugging and repair limits are established on the basis of the minimum tube wall thickness

necessary to provide adequate structural margins in accordance with Regulatory Guide 1.121

during normal operating and postulated accident conditions. These limits allow for eddy current

error and incremental wall degradation that may occur before the next inservice inspection of

the tube. These plugging and repair limits are 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 additional structural margins associated with

defects such as small-volume thinning and pitting, and they do not consider the external

structural constraints against gross tube failure provided by such support structures as the

tubesheet and tube support plates.

Because of its conservative basis, the depth-based 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 forms of repair

criteria for specific forms of steam generator tube degradation.

-5-
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.

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

approval, have repaired defective tubes by sleeving. After sleeving, the repaired tube may

remain in service. Of the plants with thermally treated Alloy 600 tubes, only Braidwood 2, Byron

2, and Callaway have NRC approval to sleeve tubes as of December 2001. Of these three

plants, only Callaway has installed sleeves in its steam generators. In the case of Callaway,

most of the sleeves (but not all) were installed in mill-annealed Alloy 600 tubes.

1.2.4 Leakage Monitoring

Between tube inspections, plants monitor for a loss of tube integrity by monitoring for

primary-to-secondary leakage. Various methods are used to monitor for tube leakage,

including periodically sampling and analyzing the steam generator secondary water for

radioactivity and continuously monitoring various streams (the steam generator blowdown, each

main steam line, and the condenser air ejector exhaust) for the presence of or increases in

radioactivity. The plant technical specifications limit the amount of primary-to-secondary

leakage that can be present during plant operation. These limits vary from plant-to-plant,

ranging from approximately 150 to 720 gpd. Additionally, technical specifications limit the

specific activity of the secondary coolant (typically to 0.1 microcurie per gram of dose equivalent

1-131). The specific activity is used in determining the radiological consequences of steam

generator tube leakage.

1.3 Mill-Annealed Alloy 600 Steam Generator Ooerating Experience

A variety of steam generator designs exist in the U.S. The susceptibility of steam generator

tubes to degradation is affected by a number of factors, 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 affecting the susceptibility of a tube to

degradation is the tube material and its heat treatment. Early steam generator designs utilized

tubes fabricated from Alloy 600, which was 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,

uSteam Generator Tube Failures," the object 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 (PWSCC). Undissolved intragranular carbides are undesirable

because they provide 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 25 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

-6-
pitting, wear, thinning, wastage, and stress corrosion cracking. The orientation of the stress

corrosion cracking can be either axial, circumferential, or volumetric. Degradation, of one form

or another, has been observed on virtually every portion of the tube. Figure 1-1 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 tube leaks, approximately nine domestic tube ruptures, numerous

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

numerous plants. In addition, extensive tube degradation has contributed to the shutdown of

other plants. 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

2001, 30 plants in the U.S. had replaced their original mill-annealed Alloy 600 steam

generators. With one exception (Palisades), the replacement steam generators typically had

more advanced tube materials. A listing of the plants that replaced their steam generators is

provided in Table 1-1. This table also provides the model and tube material of the replacement

steam generator.

Operating experience for plants with mill-annealed Alloy 600 steam generator tubes is well

documented.

1.4 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 the use of 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 (approximately 7050C) 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 PWSCC, and chromium depletion at the grain

boundaries makes the material more susceptible to outside diameter stress corrosion cracking

(ODSCC).

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 presently used

in 17 plants. Another plant, Callaway, has steam generators in which only the first 10 rows

have thermally treated Alloy 600 tubes; the remaining rows have mill-annealed Alloy 600 tubes.

Other plants (e.g., South Texas 2) may have some thermally treated tubes in their steam

generators; however, the number of tubes made from this material is insignificant and are not

-7-
discussed in this report. Thermally treated Alloy 600 is considered to be highly resistant but not

immune to PWSCC compared to mill-annealed Alloy 600 tubes. The experience with thermally

treated Alloy 600 has not been well documented although thermally treated Alloy 600 is

generally recognized to have better performance. This report provides a summary of the steam

generator operating experience at PWRs with thermally treated Alloy 600 steam generator

tubes.

It is important to evaluate the operating experience of thermally treated Alloy 600 because

although it is no longer the material of choice for new or replacement steam generators, it is

used in a number of plants and has been in service for over 20 years. The evaluation may

provide insights into the behavior of newer steam generator materials such as thermally treated

Alloy 690, which is currently the preferred material for tubes in new and replacement steam

generators. Of the 69 operating PWRs in December 2001, approximately 45% have mill

annealed Alloy 600 steam generator tubes, approximately 25% have thermally treated Alloy 600

steam generator tubes, and approximately 30% have thermally treated Alloy 690 steam

generator tubes.

-8-
Table 1-1: Plants With Replacement Steam Generators

SG ManufacturerlModel I

No. of Completion

Plant Name Loops Original Replacement Date Tube Material'

Surry 2 3 W/51 W/51 F 9/80 600 TT

Surry 1 3 W/51 W/51 F 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 TI

Palisades 2 CE CE 3/91 600 MA

Millstone 2 2 CE-67 BWC 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 BWC 6/96 690 TT

Catawba 1 4 W/D3 BWC 9/96 690 TT

Point Beach 2 2 W/44 W/D47 12/96 690 TI

McGuire 1 4 W/D2 BWC 5/97 690 TT

Salem 1 4 W/51 W/F 7/97 600 TT

McGuire 2 4 W/D3 BWC 12/97 690 TT

St. Lucie 1 2 CE-67 BWC 1/98 690TT

Byron 1 4 W/D4 BWC 1/98 690TT

Braidwood 1 4 W/D4 BWC 11/98 690 TI

South Texas Project 1 4 W/E W/D94 5/00 690 TT

Farley 1 3 W/51 Wi54F 5/00 690 TI

Cook 1 4 W/51 BWC 12/00 690 TT

Arkansas Nuclear One 2 2 CE/2815 W/D109 12/00 690 Tr

Indian Point 2 4 W/44 W/44F 12/00 600 TT

Farley 2 3 W/51 W/54F 5/01 690 TT

Kewaunee 2 W/51 W/54F 12/01 690 TI

Harris 3 W/D4 W/D75 12/01 690 TT

ITT= thermally treated, MA = mill-annealed

-9-
IGA XDSCC

L I Z s

F7171 11-I F1

==N==

U-Bend Cracks

(PWSCC)

Free Span

C ODSCC

ODSCC or

PWSCC PWSCC

\ I o Denting

1, 1

Fretting, Wear, Corrosion

Thinning -IC

f" r-~4 ~ b |~<395

,PWSCC or * *-Pitting ' \ SWud

PWSCC Tubesheet Tubesheet

ODSCC

Figure 1-1. Mill Annealed Alloy 600 Steam Generator Tube Degradation

-10-
2 STEAM GENERATOR DESIGNS IN PLANTS WITH

THERMALLY TREATED ALLOY 600 TUBES

2.1 Introduction

Steam generators in plants with thermally treated Alloy 600 tubes are vertical shell and U-tube

heat exchangers with integral moisture-separating equipment (refer to Figure 2-1 or 2-2). Heat

is transferred from the hot primary coolant as it flows through the inverted U-tubes to the water

on the secondary side of the steam generator. The primary coolant enters and leaves the

steam generators through nozzles in the hemispherical bottom head of the steam generator.

The transfer of heat from the primary system to the water on the secondary side of the steam

generator is accomplished primarily through the steam generator U-tubes. After the primary

coolant flows through the U-tubes, it exits the lower plenum of the steam generator through an

outlet nozzle. A plate in the lower plenum below the tubesheet, called a "divider plate",

separates the inlet and outlet primary coolant and directs the flow through the tubes.

The steam generators are designed with an evaporator section and a steam drum section. The

steam drum section is the upper part containing the moisture separators. The evaporator

section, sometimes called the "tube bundle", is an inverted U-tube heat exchanger containing

the tubes. Typical features of a U-tube are shown in Figure 2-3. The evaporator section may

have a preheater region depending on the model. The preheater enhances heat transfer to the

incoming feedwater and is a series of baffle plates around a portion of the cold-leg side of the

steam generator. Figure 2-1 depicts a typical PWR recirculating steam generator without a

preheater, and Figure 2-2 depicts one with a preheater.

The number of tubes in each steam generator depends on the model but varies from 3,000 to

nearly 6,000 for the plants with thermally treated Alloy 600 tubes. The tubes are welded to a

thick plate, called a "tubesheet", with a hole for each tube end. The tubesheet is approximately

2-feet thick. The tubes are expanded against the tubesheet walls for the full depth of the

tubesheet The tubes are supported with plates at a number of fixed axial locations along the

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

bars are called Uantivibration bars" (AVBs).

Steam generators with thermally treated Alloy 600 tubes were first placed in service in 1980.

Figure 2-4 is a graph of the deployment of steam generators with thermally treated Alloy 600

tubes. Currently, 17 plants have steam generators with thermally treated Alloy 600 tubes.

Another plant, Callaway, has steam generators in which only the first 10 rows have thermally

treated Alloy 600 tubes; the remaining rows have mill-annealed Alloy 600 tubes. All plants with

thermally treated Alloy 600 tubes are Westinghouse-designed plants.

Table 2-1 lists all the plants with thermally treated Alloy 600 tubes as of December 2001. The

table reveals two populations of plants with thermally treated Alloy 600 tubes: (1) plants which

replaced their original steam generators (containing mill-annealed tubes) with ones containing

thermally treated Alloy 600 tubes, and (2) plants whose original steam generators were initially

fabricated with thermally treated Alloy 600 tubes. All of the latter plants have Westinghouse

model D5 and F steam generators.

-1 1-
In addition to the advanced tubing material, steam generators with thermally treated Alloy 600

tubes have other design improvements 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 at the expansion transition region, reducing the potential for stress corrosion cracking,

and 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 the use of 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. Another design

improvement was the use of quatrefoil-shaped holes rather than round holes. The

quatrefoil-shaped holes promote high-velocity flow along the tube, sweeping impurities away

from the support plate locations. The quatrefoil-shaped hole design also limits the contact

between the tube and the support plate to four narrow lands, minimizing local dryout and

chemical concentration.

Table 2-2 indicates the number of calendar years that steam generators in plants currently

using 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 plants that replaced their steam generators with ones containing thermally treated

Alloy 600 tubes. It is interesting to note that many plants which replaced their steam generators

in the early 1980s have operated over twice 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 approximately 14 calendar years.

As alluded to previously, 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 plants that replaced their original steam generators (which had

mill-annealed Alloy 600 tubes) with steam generators containing thermally treated Alloy 600

tubes. The designs of the steam generators in these three categories are discussed further

below.

2.2 Model D5 Steam Generators

Westinghouse model D5 steam generators have 4,570 thermally treated Alloy 600 tubes with

an outside diameter of 0.750-inch and a 0.043-inch 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-shaped holes and V-shaped chrome plated

Alloy 600 anti-vibration bars (AVBs). Figure 2-5 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 2-6 with a tube spacing of 1.063 inches.

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

-12-
and a T-slot. The preheater is a region in the tube bundle which preheats the incoming

feedwater (secondary coolant) prior to 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 2-6.

The preheater region (near the feedwater inlet) and its relation to the tube bundle are shown in

Figure 2-2. The preheater region is located 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 2-7. As can

be inferred from Figure 2-7, the first five rows of tubes in the periphery of the tube bundle are

not supported at baffle plates E and H. 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 2-7, 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 located 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."

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 plants. 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 due to 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 plants with D5 steam

generators involved expanding selected tubes (approximately 124 tubes) at baffle plates B and

D to make the tubes stiffer and splitting feedwater flow 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 plants with four model D5 steam generators, approximately

10% of the main feedwater flow was diverted. The auxiliary nozzle is located in the upper

portion of the steam generator as illustrated in Figure 2-2.

The expansion of tubes at baffle plate locations was intended to limit the tube movement at the

baffle plate intersections to 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 minimize 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.

-13-
The expansions were designed to be located entirely within the baffle plate to prevent bulging of

the tube outside of the baffle plates.

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 means of a hydraulic device 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 2, Byron 2, Catawba 2, and Comanche

Peak 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, 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 have thermally

treated tubes (i.e., only 1,214 tubes per steam generator are thermally treated). The tubes

have an outside diameter of 0.688-inch and a nominal wall thickness of 0.040 inch. 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-shaped holes and V-shaped chrome

plated Alloy 600 AVBs. The first 10 rows of tubes were stress-relieved to improve corrosion

resistance. Figure 2-8 depicts the model F steam 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 2-9 with a tube spacing

of 0.980 inch.

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 (refer to Figure 2-1).

Model F steam generators are used at Callaway, Millstone 3, Salem 1, Seabrook, Vogtle 1,

Vogtle 2, and Wolf Creek. As discussed above, the model F steam generators at Callaway use

thermally treated Alloy 600 only in the first 10 rows of tubes. The model F steam generators at

Salem 1 are replacement steam generators which were originally intended to be installed in the

canceled Seabrook Unit 2 plant. As a result, the Salem 1 steam generators are discussed as

replacement steam generators.

2.4 Replacement Steam Generators

Three different steam generator models are used at plants that replaced their original steam

generators with steam generators with thermally treated Alloy 600 tubes, namely the

Westinghouse models 44F, 51 F, and F. These models do not have a preheater region.

-14-
Westinghouse model 44F steam generators have 3,214 thermally treated Alloy 600 tubes with

an outside diameter of 0.875 inch and a 0.050-inch 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-shaped holes and V-shaped AVBs. Figure 2-10

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

2-11 with a tube spacing of approximately 1.2 inches.

Model 44F steam generators are used at Indian Point 2, Point Beach 1, Robinson 2, and

Turkey Point 3 and 4.

Westinghouse model 51 F steam generators have 3,342 thermally treated Alloy 600 tubes with

an outside diameter of 0.875 inch and a 0.050-inch 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-shaped 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 51 F 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 helped to provide 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 2-12 depicts the model 51 F steam generator tube

support configuration , using the typical naming convention. Model 51 F steam generator tubes

have a square tube pitch as depicted in Figure 2-13 with a tube spacing of approximately 1.281

inches.

Model 51 F 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 Unit 2, which was never completed. The design of the model F steam generators is

discussed in Section 2.3.

-15-
Table 2-1: Plants With Thermally Treated Alloy 600 Tubes

Plant Dt Mel Number Replacement2

I __ ___ _ _ _ _ _ j of S G s I _ _ _ _ _ _

Braidwood 2 1988 D5 4 N

Byron 2 1987 D5 4 N

Callaway3 1984 F 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 1982 51 F 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

'Date of commercial operation or date of steam generator replacement, whichever is later

2N means the plant has its original steam generators; Y means the steam generators are replacements. 3

Only the first 10 rows of the Callaway steam generators have thermally treated tubes; the remaining are

mill-annealed Alloy 600.

-16-
Table 2-2: Age of Steam Generators at Plants With Thermally Treated Alloy 600 Tubes

Plant Operating Time' Operating Time'

l- I F Original SG l|Replacement SG

Braidwood 2 13 N/A

Byron 2 14 N/A

Callaway 17 N/A

Catawba 2 15 N/A

Comanche Peak 2 8 N/A

Indian Point 2 26 1

Millstone 3 16 N/A

Point Beach 1 13 18

Robinson 2 14 17

Salem 1 20 4

Seabrook I 11 N/A

Surry 1 8 20

Surry 2 7 21

Turkey Point 3 9 20

Turkey Point4 10 19

Vogtle 1 15 N/A

Vogtle 2 13 N/A

Wolf Creek 1 16 N/A

'Operating Time = calendar years of operation as of 12/31/01

-17-
Steam Outlet

/

S IISteam t Separators

-C .- Feedwater I Inlet

\ !!iDowncomer Annulus

U-Bend portion

of Tube

I~111 III

till 11X

It1 t MIt

Tube Bundle

Tube Support

I l

TT Tube Sheet

Divider Plate

ANI

Primary Inlet

(Hot Leg)

Primary Outlet

(Cold Leg)

Figure 2-1. Typical PWR Recirculating Steam Generator Without a Preheater

-18-
Steam Outlet

Steam Separators

Level of Auxiliary

Feedwater Nozzle

Tube Bundle

Tube Supports

Lower Shell

Preheater Outlet

Feedwater Nozzle

Preheater Section

Tubesheet _Preheater Inlet

Divider Plate

Primary Coolant Primary Coolant

Inlet Outlet

Figure 2-2. Typical PWR Recirculating Steam Generator With a Preheater

-19-
Apex

Hot Cold

-Tube

Tube Support

Plate

_  .... _ _ _

Hot Leg Cold Leg

Figure 2-3. U-Bend Features

-20-
Figure 2-4: Number of Plants With Thermally Treated Alloy 600 Steam Generator Tubes as a Function of Year

0

NN

C co

0 E

V - co(M w

N9

20

18

16

14

FA

c 12

r

a..

4

2

L0

, .

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000

Year

As of December 2001, there were 69 operating PWRs, 18 of which had thermally treated Alloy 600 steam generator tubes

-21-
3 AVB2 AVB3

AVB 1 VB4

Antivibration4V)V

Bars V

(08) 11H

(07) 1 OH

(06) 09H

(05) 08H

11C (09)

10C (10)

09C (11)

08C (12)

Legend:

TEH = Tube-end Hot

TEC = Tube-end Cold

TSH = Tubesheet Hot

TSC = Tubesheet Cold

AVB = Antivibration Bar

(04) 07H t i " 07C (13) L

36" ' 06C (14)

(03) 05H 0 (15) 18 Fe

36" ,, 04C (16)

(02) 03H I= 03C (17)

8.4 28" 8 02C (1 8)

01H 01C (19)

TSHH TSC

No nw~an ay

Figure 2-5. Westinghouse Model D5 Steam Ge

Tube Support Locations

(Alternate Naming Convention in Parentheses)

nerator

-22-
Row Row

I I I I I I- I I 1 I 50

45

40

35

30

25

20

15

10

5

1

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 000 0 0 0 0 0 0 000 0 00 0 00000 000 0 0 0 0 1000 000 00 0000 00 0 0 0 0 0 0 0000 -0100 00000000 0000 0000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 000000000 O.OEOOI-00.00.0 00000 0000O 00 0000000.0.. 0000-00.000 00000 0 0 00 00 0 0 0 00000000 0 000000000 0 00 00 0 000000 00000 00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00 0 0 0 0 000 0 0 0 00 0 000 00 00 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 0000 00 0 0 0000 0 0 00 0 0

000000 00000000 0 0 0000 000000000 0 000000 00000000 00000 000 00 0 00 0000000 000000000 0 0000000000000 0 000000 00000000 00000 000 00000 00 00 0 0 0 0000000 000000000 000000000 0 000000 00 0 0 00 00 0000 0 00 00 0 0

00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 000000 00 0000 00 0 000 00 0 0 00 0000

00000000000 000000000 0 0000000000000 0 000000 0 0000 000000 000000 000000 00 0 0 0 0 0 0 000000000000 00000000 0 000000 0 0 0 00 0 0 0 00 0 0 0 00 0 00000 00 00000 0 0 000000000 00000000 000000000 0 000000 000 000 0 0 000 00 000000000 00000 00

0 0 00 0 0 00000 00000000000 0000000-000 000000 000 000 0000000 000000000 0 0 0 00 000000000

- 00 0 0000 8 SQ 0 0 , 0 00 0 0 0 0 0 0 00 0 0 0 0 0 0 000000000000000 0 000000 0 000000000000 00 0 00000000

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0000 0 0 0 0 000 000 000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 000000 000000000 000000000 0 0000 000000000 0 0 00 00000 00000000 000000000 000000 000 00 0000000 000000000 000000000 000000000 8000000000 0 000000 0 0000 00000000000000 000000000 00

0000000 000000000 000 000 00000 000000000 0 0 00000 0 000 000000000 0 000 00000 000 000

00 0 0 0 0 0 0 0 0000000 00 0 00 000000 000000000 000000000 000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 000000000 00000 000000 00 000000000n 0 00 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 0 000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 0 0 00I0 0 0 0 0 0

0000000 00000 0000000 00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00 0 0 0 0 0 0 0 0 0 0 0 0 00 C 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 0ooo ~ 0 0 ~ 0 0 0 ~ 0 0 0 0 ~ 0 0 ~ 0 0 o 0 o 0 0 0 0 00 0 0 o 0 o 0 o og g g g gl o o o o o o o oo 0 0 0 0 0 0 0 0 0 0 0 0 00 0 00 0 00 0

oo ooooo 0 0000C0000 o 0 000000 00000000 0 000000 0 00 0 00 OOOC 000000 0

50

45

40

35

30

25

20

15

10

5

1

gg g 00 g g 000000000 g0000 g g g g g g g I g I U g O O g U U g U U g U'UU U0000000 000,000000 U tU~ U U U U V tU V V M U -VV UUU UtJU1 tl0- u U~J ~ J ~ f~I LIt 09000000000>O OOOU O O 0 UO 0000 UO~ U O uouuuo %000000000 00000000 000000000 0100 O 00 00 0 0g0 0 0 0 '0'-UOCo~o~o"0.'0"0"0.'0"0"O, 00000 0000000000000 000000000 000000000 000000000 000000000 000000000 00000000 000 00 00 0000 0 0

000090000000000000000000900000000090000000900 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 9 0 0 0 0 0 0 0 9 0 0 0 00066666 0 666 0 0 0 9 0 0 0 06 6666660666666666 0 0 0 0 0 0 9 0 0 0 0 0 0 0 0 0 0 000 0 0 0 00 0 0 0 006 0 0 0 0 00 0 0 0 00006 0 0 0 6 0 9 0 000 0 0 0 0 000000 0 0 0 0 0 00000000 0 0 0 0 0

0 oooo0oooooo3ooooooooooooZooooooooooooooooooooooooooooooooooooooooooooo 00 

6660 00000000000000000000000000booooooooooooooooooooooooooo000000000o000000000000000000000000000 oooo0ooooooooo ooooooooooooooooooooooooooooooooooooooooooooooooooooooooooo 000000000 0000000000000000000000000000 00 0000000000000~00000090000000009000~00000090000000009000000000 90000000009000000000 000000000 0000000009000000000200000000 o

-0000000000000000000000000000000000000000000000 200000000V( V00000VVZ 0000 OQO000000O0- OOOOOVOV V0000 U00t1S"-'''- Y -

T- 1----

I 1-- I I

I I I I I __ _ , , , , . ,1 , , ,._

120 110 100 90 80 70 60 50 40 30 20 10 1

Column

Figure 2-6. Westinghouse Model D5 Steam Generator Tubesheet Map

-23-
I I

f K

11; j

H

/*' G

14

\1

E

D I

\1 /B/ / /

p tk ' IL IL% IL

t L

L I I

Figure 2-7. Preheater Region of Westinghouse Model

D-5 Steam Generator

-24-
AVB i B6

(8H)7H _____ 7C (8C) I40.20"

(7H)6H 6C(7C)

|40.21"

(6H)5H 5C(6C)

|40.21" Legend:

(5H)4H l 4C(5C) TEH = T

I TEC =Ti 40.02" TSH = Ti

I TSC = Ti

(41-) 3H (4H)3HFBH + 3C (4C) AVBH = = AFF

40.22 " FBC = F

(31-) 2H 402- 2C(3C)I

40.22"

(2H)IH I IC(2C)

(1 H) FBH = 203 FBC (IC)

TSH TSC

TEH TEC

inlet 'Outlet

Figure 2-8. Westinghouse Model F Steam Generator

Tube Support Locations

(Alternate Naming Convention In Parentheses)

ube-end Hot

ube-end Cold

ubesheet Hot

ubesheet Cold

ntflvbration Bar

low Distribution

Baffle Hot

low Distribution

Baffle Cold

-25-
Row Row

-i-

-I I

l

-I- I -- I I I -

7 -I 60

55

50

45

40

35

30

25

20

15

10

5

1

0000000 000000 0 -I- 0000000000 000000000 00

OOOO000 oo 0000000000000 000000 _____ 0000000000 00:000000 0 000 0000 0 000 0000000

0000000000 000000000 00000 00000000 000000000 0000000 00000000000 000000000 EOOOO0000000000000 000000000 000000000 00000000 0000 20000 00000 00 0000000 00000000000000 0000 000000000000 000000000 000000000 00000000 0000000 -000 00000000000000000000 0000000000000000000000000000,0000 1000o..000.00 000000000 0 00000000 000000000 -00 0000000 0000000000 00000000 00000

000000 000000000 000000000 00000000 00990000000 000000-0000 000000000 000 0000000 000000000 000000000 0000000 000 0000 00 0 000000000 0000 00000000 000000000 00000000000000000 00000890000000000000 0 00000000 000000

000000 000000000 000000000 000000000000000 0000000 00000 000000000 0000000

000000000 00000000000000000000000 0000 000000000 00000000.0 00000 0000000000000,0 000000000 00000C 2 00000000 0 000000 0000000 0000000 000000000 000000L 00

0 000000 000-0 0000000800000 00000 000000000 000000000 000000000 0000000 000000 00000000000

000000000000000000000000 

00000000 000R900028000,8 0000000000000 000000000 000000000 000000000000000 000000000000 000000000 00000 00000000 000000000000000 0000000 000000000000000 00I000000000 00000000000000000000 000000000 000000000000000000 00000 00 000000-0 0 0 00000 0000 0000 00000 00000- 0000000000 0000-000000000

0000009000800099 

000000000000 000000000 0000000 000000 00000000 000000000 000000000 000000000 00000000 0 00000000000000000000 00000 0000000 000000000 000000000 000000000 000000000 0 00 0000 0000 0000 0000 0000 0000000 0000000 000000 000000 0000000 00000000000000000000 

000 0000 000000000 06-060000000000 00 00000 00000000 0000000 0000

000 0000 0000 0 0000 000000000 00 000000000 00000 00000 000000000 000000000 00000000 0000 0000000009s900 00000000 0000000--- 90000080000 00000000o 000000000 000000000

000000000000000000000000 99060900906000 00000 0000 000000000000000 000000000 00000

00000000 000000000 00000098000 00000 00000000 00000 000000 00000 000000000000 0000000 000000000 000000000 00000 992000000001,000 000000000090000 0000000000 0 0000000008 0090000000Q 000000000 0 00000000 000000000 000000 00000000000000000000000000000000 000000~0000 000000000 00000 00000000 000000 0000 00900099000 0000000000000000000000000000000000000000 00000000000000000000000000 000000 0 000000000 000000000 000000 99000080000 000000 000000000000 00000000000000 000000 00000"50oo0 0000 0000 0000 000000000000000 000000000000000 00000 0000 0000 0000 0000 000000000 0000000 0000088880000 00000000 000000000 0080090000 000 0000 00000 00 0000000 000000000 000 - 0000 00 0 0000000000000 0- -0-00-00-00-00 0000000000000000000000000000 6 6 OOO0 ~OONOO1<><O>-OC 00000 0000000000000000000000000 000000000 000000000 000000 000000000 00000 0000 0000000 0 0000 0000 000 0000 0000 000000000000 0000 0 0000000 00000 0000 000000000

O0.00000 0000 00000000 0000 0000 0000 00000 00000 0000000 C 0000000 0000000 0000000000000000000000000000000000000000000000000000 0000 0000 000000 000000000 000 00000 0 00000000 000000000 000000000 00000 O000 00000.00 C000000000000000 00000000000000 00000 000000000 00000 000000000 00000 000000 00000 000000 00000 00:0000 0 000000000 000 0000 N-000.0000000O 0000 00000 000000000000 0000000 00000 00000 0000000 0000 00000000000 00000000000000000000000000000000000000000000000000 000000 00000 0000- 000000000000000000000000000000000000 000000 00000 0000000~ 000000000 000000 00000 0 000000000OOOO 0000000 000 -000 0--------00------ 0000000 - OOOOOOOOOO 0000000000 0000000000000 00 000000 0000

60

55

50

45

40

35

30

25

20

15

10

5

1

120 110 100 90 80 70 60 50 40 30 20 10 1

Column

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

-26-
Legend:

TEH = Tube-end Hot

TEC = Tube-end Cold

TSH = Tubesheet Hot

TSC = Tubesheet Cold

FBH = Flow Distribution

Baffle Hot

FBC = Flow Distribution

Baffle Cold

AVB = Antivibratlon Bar

Tubesheet

Primary Inlet '- Primary Outlet

Figure 2-10. Westinghouse Model 44F Steam Generator

Tube Support Locations

-27-
Row Row

45- -45

42- -42

39- -39

36- -36

30 30

27 27

24 24

21 21

18 1

15 15

12 12

9 9

6 6

3 3

92 85 78 71 64 57 50 43 36 29 22 15 8 1

Column

Figure 2-1 1. Westinghouse Model 44F Steam Generator Tubesheet Map

-28-
I II I

AVB2 MAV 0

AVB1 AVB4

7H ' VC

6 \ /_6C

5H - C Legend:

TEH = Tube-end Hot

TEC = Tube-end Cold

TSH = Tubesheet Hot

4H - . . . . . - -4C TSC = Tubesheet Cold

BPH = Baffle Plate Hot

BPC = Baffle Plate Cold

3H - 3C AVB = Antivibration Bar

2H- - . . . - -2C

BP H = _ - BPC

TSH TSC

Tubesheet

TEH - TEC

\ J 3 7 Divider Plate

Inlet Outlet

Figure 2-12. Westinghouse Model 51F Steam Generator Tube Support Locations

-29-
-45

-40

-35

-30

11 . 111-25

I fil filmIllf0

-20

-15

I fill I -I- I 10

I f i I f I I I I I I 10 o I~~11f) 0 i0 I) 0 10 0 t f 0 t f C11 fill C~ ~3it I f) 1 0 N . C O 0

ColumnFF il

Fiur -1.Wet-goueMoe 51 F SemGnrtrTbsetMa

-30-
3 THERMALLY TREATED ALLOY 600 STEAM GENERATOR TUBE

OPERATING EXPERIENCE

3.1 Data Gathering Methodology and Introduction

This section summarizes inspection results for plants with thermally treated Alloy 600 steam

generator tubes through December 2001. Significant additional information from the first half of

2002 is summarized in the Executive Summary and in Section 4. The information was primarily

gathered from reports provided by licensees to the NRC in accordance with their technical

specifications. These licensee reports typically discuss the number and extent of tubes

inspected, the number and location of tubes plugged, and the location and percent of wall

thickness penetration for each indication of an imperfection. The level of detail provided in

these reports varies from plant to plant and frequently from tube inspection outage to outage.

As a result, some plants may not have reported all steam generator tube inspection activities

during a given inspection outage and/or may not have provided all of their insights in their

reports. 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. In spite of these limitations, this report provides useful insights into the extent of tube

inspections and repairs and the general conclusions of the report are valid.

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 was not compiled.

In this section, the plants 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 plant, 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 antivibration (AVBs). In the tables which 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 Oeratina 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

-31-
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 1 H to 11 H on the hot-leg side of the steam generator and from 1 C to 11 C

on the cold-leg side (refer to Figure 2-5). Based on accident analysis considerations, a

maximum of 30% of the tubes can be plugged in any one steam generator and a maximum of

24% of the tubes in the four steam generators can be plugged. Braidwood 2 is authorized in

the plant technical specifications to use Westinghouse laser-welded sleeves as a repair

method.

During refueling outage (RFO) 1 in 1990, 100% of the tubes in each of the four steam

generators were inspected full length with a bobbin coil. As a result of these inspections, two

tubes were plugged. Both of these tubes were plugged as a result of indications of AVB wear.

The maximum depth reported for the AVB wear indications was 53% throughwall.

During RFO 2 in 1991, approximately 50% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil and the remaining tubes in each steam generator

were inspected from the hot-leg tube end through the U-bend (i.e., to the uppermost support

plate on the cold-leg side). As a result of these inspections, 11 tubes were plugged. All of

these tubes were plugged as a result of indications of AVB wear. The maximum depth reported

for the AVB wear indications was 51 % throughwall.

During RFO 3 in 1993, approximately 50% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil and the remaining tubes in each steam generator

were inspected from the hot-leg tube end through the U-bend (i.e., to the uppermost support

plate on the cold-leg side). As a result of these inspections, 16 tubes were plugged. All of

these tubes were plugged as a result of indications of AVB wear. The maximum depth reported

for the AVB wear indications was 54% throughwall.

During RFO 4 in 1994, 100% of the tubes in steam generators B and C were inspected full

length with a bobbin coil. In addition to the bobbin coil inspections, the rotating pancake coil

probe was used to inspect the hot-leg expansion transition region in approximately 10% of the

tubes in steam generators B and C. As a result of these inspections, 6 tubes were plugged. All

of these tubes were plugged as a result of indications of AVB wear. The maximum depth

reported for the AVB wear indications was 47% throughwall.

During RFO 5 in 1996, 100% 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, the rotating pancake coil

probe was used to inspect the hot-leg expansion transition region in 28% of the tubes, 64% of

the dents greater than 5 volts at the hot-leg tube support plates, and the U-bend region of

100% of the row 1 and 2 tubes. These inspections were performed in each of the four steam

generators. The rotating pancake coil probe was also used to inspect 20% of the tube

expansions at preheater baffles B and D in steam generator A.

As a result of these inspections, 35 tubes were plugged. Of the 35 tubes plugged, 29 tubes

were plugged as a result of indications of AVB wear, 2 tubes were plugged as a result of

volumetric indications at the first hot-leg tube support plate, 1 tube was plugged for a single

-32-
axial indication in the U-bend, 2 interior tubes were plugged due to a loose part at hot-leg tube

support 8H (the part could not be retrieved), and 1 tube was plugged for a volumetric indication

at the top of the tubesheet on the hot-leg side. The maximum depth reported for the AVB wear

indications was 67% throughwall.

During RFO 6 in 1997, 100% 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 with a

plus-point coil was used to inspect the hot-leg expansion transition region in 100% of the tubes,

100% of the dents greater than 5 volts at the hot-leg tube support plates, and the U-bend

region of 100% of the row 1 and 2 tubes. These 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% of the tube expansions at preheater baffles B and D in steam generator B.

As a result of these inspections, 28 tubes were plugged. Of the 28 tubes plugged, 12 tubes

were plugged as a result of indications of AVB wear, 15 tubes were plugged as a result of

circumferential indications at the hot-leg expansion transition region, and 1 tube was plugged as

a result of a volumetric cold-leg free-span indication at cold-leg tube support 2C. This latter

indication was reported during the 1994 and 1996 inspections and did not exhibit any significant

change since those inspections. Nonetheless, it was plugged. The maximum depth reported

for the AVB wear indications was 47% throughwall. Prior to tube plugging, in situ pressure

testing was performed on three of the tubes with circumferential indications, including the

indication with the largest maximum and average plus-point coil voltage, the longest arc length,

and one additional indication characterized as possibly inner diameter initiated. None of these

tubes leaked at a pressure of 5000 pounds per square inch (psi). At Byron 2 in 1998 similar

circumferential indications were identified. Portions of several tubes were removed from Byron

2 to characterize the nature of these indications. Based on the results from the destructive

examinations of the pulled tubes, the indications were determined not to be the result of

service-induced cracking or corrosion but rather may have been caused during initial steam

generator fabrication or the first few cycles of operation.

During RFO 7 in 1999, 100% 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 with a

plus-point coil was used to inspect the hot-leg expansion transition region in 25% of the tubes,

25% of the dents and dings greater than 5 volts at the hot-leg tube support plates and in the

tube free span, and the U-bend region of 25% of the row 1 and 2 tubes. These 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% of the tube expansions at preheater baffles B and

D in steam generator C. In addition, visual inspections were performed on all of the tube plugs

and on the secondary side tubesheet region in all four steam generators.

As a result of these inspections, six tubes were plugged. All of these tubes were plugged as a

result of indications of AVB wear. The maximum depth reported for the AVB wear indications

was 44% throughwall.

Secondary side visual inspections were performed during this outage. In steam generator C,

the upper tube bundle was examined, including the divider lane, the tube periphery lane, and

the inner tube bundle. In addition to these upper tube bundle inspections, the top of the

tubesheet region was inspected after sludge lancing in all four steam generators. No

-33-
degradation was found; however, a foreign object, which could not be retrieved, was identified

on the top of tubesheet region in steam generator D. The object was wedged between the row

6 column 2 (R6C2) tube and the R7C2 tube. This object was originally identified during RFO 6

in 1997, at which time an evaluation was performed, and the tubes were allowed to remain in

service since there was no degradation. The RFO 7 inspections did not show any tube

degradation at these locations. An evaluation was performed, and tubes were allowed to

remain in service provided they were inspected for degradation each refueling outage.

During RFO 8 in 2000, 100% 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 hot-leg expansion transition region in

50% of the tubes, 50% of the dents and dings greater than 5 volts at the hot-leg tube support

plates and in the tube free span, and the U-bend region of 50% of the row 1 and 2 tubes (75%

in steam generators B and C and 25% in steam generators A and D). These 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% of the expansions at preheater baffles B and D in steam

generators A and D. In addition, visual inspections were performed on all of the tube plugs and

on the secondary side tubesheet region in all four steam generators.

As a result of these inspections, 11 tubes were plugged. Of these 11 tubes, 10 were plugged

as a result of indications of AVB wear and one row 1 tube was plugged due to a permeability

signal with no sign of tube degradation. The maximum depth reported for the AVB wear

indications was 45% throughwall. The permeability indication had not changed since RFO 6 in

1997, but a conservative decision was made to plug this indication due to the possibility that the

permeability signal could mask future degradation.

The top of tubesheet region was inspected after sludge lancing in all four steam generators.

No degradation was found. The foreign object wedged between tubes R6C2 and R7C2 was

verified to be present. This foreign object has not resulted in any tube degradation.

Of the tubes plugged at Braidwood 2 as of December 2001, the vast majority (77%) were

plugged as a result of AVB wear. The second leading cause of tube plugging was

manufacturing related flaws, which accounted for 17% of the tube plugging. Loose parts,

inspection issues, and other indications accounted for the remaining 6% of tubes plugged.

3.2.2 Byron 2

Tables 3-4, 3-5, and 3-6 summarize the information discussed below for Byron 2. Table 3-4

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 3-5 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 1 H to 11 H on the hot-leg side of the steam generator and from 1 C to 11 C on the

cold-leg side (refer to Figure 2-5). Byron 2 is authorized in the plant technical specifications to

use Westinghouse laser-welded sleeves as a repair method.

-34-
During RFO 1 in 1989, approximately 48% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. The remaining 52% of the tubes were inspected

from the hot-leg tube end to the uppermost support on the cold-leg side (i.e., tube support

11 C). There were 11 tubes plugged during this outage. Of these, one row 1 tube was plugged

for a signal-to-noise indication in the U-bend region indicative of primary water stress corrosion

cracking (PWSCC), one row 1 tube was plugged as a result of a large dent in the U-bend which

was present in the preservice inspection (the tube was plugged to prevent possible PWSCC in

the high-stressed area), two tubes were plugged as a result of wear at the AVBs (maximum

depth was 36% throughwall), one tube was plugged as a result of a loose part (confirmed

during RFO 5), three tubes were plugged for indications slightly above the hot-leg top of

tubesheet as a result of throughwall indications in excess of the plugging criterion (the

maximum depth was 83% throughwall, and one of these three was attributed to a confirmed

loose part during RFO 5), three tubes were plugged as a result of narrow circumferential

indications at the upper edge of the hot-leg tube support plates (one at 5H, two at 8H). With

respect to the two tubes with narrow circumferential indications at 8H, subsequent inspections

in RFO 5 confirmed the presence of a loose part in the vicinity of these indications. With

respect to the tube with a narrow circumferential indication at 5H, subsequent inspections of

adjacent tubes in RFO 5 indicated the possible presence of a loose part in the vicinity of this

indication.

During RFO 2 in 1990, approximately 50% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. The remaining 50% of the tubes were inspected

from the hot-leg tube end to the uppermost support on the cold-leg side (i.e., tube support

11 C). There were 21 tubes plugged during this outage.

Of the 21 tubes plugged during this outage, 19 tubes were plugged as a result of wear at the

AVBs, 1 tube was removed from service due to a 53% throughwall indication that appeared to

be caused by secondary side pitting at hot-leg tube support 8H, and one tube was removed

from service due to a 47% throughwall indication above hot-leg tube support 9H. The

maximum depth reported for the AVB wear indications was 63% throughwall.

During RFO 3 in 1992, approximately 49% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. The remaining 51% of the tubes were inspected

from the hot-leg tube end to the uppermost support on the cold-leg side. There were 29 tubes

plugged during this outage.

Of the 29 tubes plugged, 25 were plugged as a result of wear at the AVBs, 1 tube was plugged

as a result of outside-diameter-initiated indications above hot-leg tube support 1OH and cold-leg

tube support 10C, and 3 tubes were plugged as'a result of outside-diameter-initiated indications

indicative of manufacturing burnishing marks (one had indications above cold-leg tube support

6C and 9C, one tube had indications above hot-leg tube support 1OH, and one tube had

indications above hot-leg tube supports 9H and 11 H). The maximum depth reported for the

AVB wear indications was 49% throughwall.

During RFO 3, video probe inspections were performed verifying the existence of welded stub

tube plugs in 8 locations in each steam generator (32 tubes in all). The stub tube plug locations

are not considered tube locations in the D5 steam generator configuration.

-35-
During RFO 4 in 1993, approximately 49% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. The remaining 51 % of the tubes were inspected

from the hot-leg tube end to the uppermost support on the cold-leg side. There were 36 tubes

plugged during this outage.

Of the 36 tubes plugged, 33 were plugged as a result of wear at the AVBs and 3 tubes were

plugged as a result of indications at the lower support edges, possibly due to pitting,

intergranular attack, localized thinning, or other mechanisms (e.g., loose part wear) which result

in small volumetric indications. These volumetric indications were located at hot-leg tube

support 1 H (two tubes) and 5H (one tube). Two of these three tubes were located near the

periphery of the tube bundle. In addition to the 3 tubes plugged as a result of volumetric

indications at tube supports, 12 other indications were reported. Five of these 12 indications

were at hot-leg tube supports and the remainder were at cold-leg supports. One of these 12

indications was plugged since it was a tube that also contained an AVB wear indication in

excess of the repair criteria. Of the 33 tubes plugged for AVB wear, 3 were plugged as a result

of what was believed to be wear associated with an AVB stiffener strap. Based on an

evaluation of the inspection data, the licensee reported that the AVB wear rate had slowed

since the previous cycle; however, more indications were found during this inspection than in

previous ones. The maximum depth reported for the AVB wear indications was 53%

throughwall.

With respect to the three volumetric indications plugged at the tube supports, subsequent

inspections of adjacent tubes in RFO 5 indicated the possible presence of a loose part in the

vicinity of at least one of these indications (i.e., the degradation mechanism for one of these

three indications is most likely wear from a loose part).

During RFO 5 in 1995, approximately 52% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. The remaining 48% of the tubes were partially

inspected from the hot-leg tube end to the uppermost support on the cold-leg side. There were

29 tubes plugged during this outage. In addition to the bobbin coil inspections, the rotating

pancake coil probe was used to inspect the hot-leg expansion transition region in approximately

20% of tubes in steam generator B.

Of the 29 tubes plugged during this outage, 21 were plugged as a result of wear at the AVBs, 7

were plugged as a result of indications of possible loose parts, and 1 tube was plugged due to

an "unusual" volumetric signal at the top of the tubesheet. The maximum depth reported for the

AVB wear indications was 47% throughwall.

Based on the inspection results through RFO 5, the licensee reported that tube wear at the

AVBs appears to be decreasing from outage to outage both in terms of the growth rate and the

total number of indications observed.

There were two locations of suspected loose parts in steam generator B and two in steam

generator C. In steam generator B, one location resulted in the plugging and stabilizing of five

tubes for a possible loose part at the upper edge of hot-leg tube support 5H. These five tubes

were near the periphery (columns 4 and 5). The second location of possible loose parts in

steam generator B affected three tubes near the periphery of the T-slot. The part, a gasketlike

-36-
material, was located at cold-leg tube support 2C and was removed from the steam generator

and the tubes were left in service.

In steam generator C, one loose part location resulted in the plugging and stabilizing of two

tubes as a result of a possible loose part at the upper edge of hot-leg tube support 5H. These

tubes were near the periphery of the T-slot, and were plugged and stabilized. The tubes were

not accessible, and the licensee could not perform a video inspection or retrieve the part. Two

adjacent tubes had been plugged in previous outages. These tubes were deplugged and

stabilized. The other location in steam generator C with possible loose parts had a volumetric

indication at the upper edge of hot-leg tube support 8H. The tube was left in service after

search and retrieval methods were used to remove a wedge-shaped object from the steam

generator. Two tubes adjacent to this one were plugged in previous outages.

The tube with the "unusual" volumetric signal identified in RFO 5 was located in steam

generator B at row 49 column 54 slightly above the hot-leg top of tubesheet. The indication

was first identified as a result of a video inspection performed before and after sludge lancing.

This tube is located near the periphery of the tube bundle and adjacent to the T-slot. Two

adjacent tubes were plugged during RFO 1 as a result of a loose part which was removed

during that outage. This tube was plugged during this outage after rotating pancake coil results

indicated a volumetric indication at this location.

Byron 2 was shut down on August 8, 1996, due to a primary-to-secondary leak in steam

generator A of approximately 120 gallons per day. Since the leak occurred near the end of the

operating cycle, the licensee decided to enter the refueling outage early (i.e., RFO 6). During

RFO 6, 100% of tubes in all four steam generators were inspected full length with a bobbin coil.

In addition to the bobbin coil inspections, a rotating pancake coil probe was used to inspect the

hot-leg expansion transition region for 25% of the tubes in each of the four steam generators.

A rotating probe equipped with a plus-point coil was used to inspect the U-bend region of 25%

of the row 1 and 2 tubes (57 tubes per steam generator) in each of the four steam generators.

In addition, the rotating pancake coil probe was used to inspect the expanded portion of 25% of

the tubes that were expanded in the preheater region (34 tubes per steam generator). Lastly,

25% of the tubes with dents greater than 5 volts (as measured with a bobbin coil) were

inspected with a rotating pancake coil probe. There were 30 tubes plugged during this outage.

The tube that leaked was inspected with eddy current and video probes. It was determined that

a foreign object had caused the leak. The foreign object was removed and was analyzed to

determine its origin. The part affected four tubes, all of which were plugged. The object was

1.7-inches by 1.2-inches by 0.055 inches and had a triangular shape. The object was

thermal-cutting debris from a 12- to 18-inch pipe. The loose part was located slightly above the

cold-leg tubesheet in the periphery of the tube bundle.

An additional 26 tubes were plugged during this outage. Nineteen of these tubes were plugged

as a result of wear at the AVBs. Four were plugged as a result of indications slightly above

cold-leg tube support 2C (these tubes were inspected visually, revealing scale buildup on all

four tubes; only one of these tubes had a volumetric indication based on rotating pancake coil

examination). One of these 26 tubes was plugged due to a geometry change that resulted in

the probe skipping over a section of the tube, preventing a complete exam (the geometry

change was in the U-bend region of a row 1 tube). One tube was plugged as a result of a

-37-
volumetric indication slightly above (or at) cold-leg tube support 2C (the indication originated

from the outside diameter, and a historical review of the data indicated minimal growth both in

phase and amplitude). One of these tubes was plugged as a result of a volumetric indication

slightly above (or at) hot-leg tube support 1 H (which originated from the outside diameter of the

tube; a historical review showed minimal growth in both phase and amplitude). The maximum

depth reported for the AVB wear indications was 46% throughwall.

During this outage, the licensee noticed that it had not inspected 26 tubes in steam generator D

during RFO 3 (spring 92) and 4 tubes were not inspected during RFO 5 (spring 95) as a result

of misencoding tubes (i.e., data from one tube was labeled as coming from another tube). The

omissions were attributed to the operators inability to properly locate the inspection fixtures,

moving the fixture without recalibration, or failure of the operator to use the "add cal point'

feature of the data analysis software (which permits the operator to locate the fixture and the

tubes to be inspected).

During RFO 7 in 1998, 100% 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 hot-leg expansion transition region in

100% of the tubes in each of the steam generators, the U-bend region of 100% of the row 1

and 2 tubes in each steam generator, the preheater baffle plate expansions in 25% of the tubes

in steam generator A (34 tubes containing 68 expansions), and 100% of the hot-leg dents with

voltages greater than 5 volts. In addition to these eddy current inspections, a visual inspection

of the secondary side of steam generator C (e.g., wedges, tie rod nuts, jacking studs) was

performed, along with a visual inspection of the top of tubesheet region in all four steam

generators and a visual inspection of all previously installed plugs. Thirty eight tubes were

plugged during this outage.

During RFO 7, circumferential indications were identified at the hot-leg top of tubesheet region

for the first time. A total of 29 indications were detected. Four of these tubes were in situ

pressure-tested to verify structural integrity. No leakage was measured when the tube was

pressurized to three times the normal operating differential pressure. Three of the in situ

pressure tested tubes were also removed for destructive examination. Two tubes were cut 3

inches below the hot-leg tube support 3H and one tube was cut 3 inches below hot-leg tube

support 5H. The destructive examinations indicated that the circumferential indications were

not service-induced cracking or corrosion but shallow grooves that may have been caused

during initial steam generator fabrication or the first few cycles of operation. Burst testing

confirmed the indications had no impact on the structural integrity of the tubes. All 29 tubes

with circumferential indications were stabilized and plugged.

Of the remaining nine tubes plugged, one was plugged as a result of wear at the AVBs, three

were plugged due to confirmed loose parts which were visually identified and removed either

during this outage or during a previous outage (these indications were plugged since a

site-qualified depth sizing technique was not available), and five were plugged for other

reasons, as discussed below. The maximum depth reported for the AVB wear indications was

43% throughwall.

Of the five tubes plugged for "other" reasons, four tubes had outside-diameter-initiated

volumetric indications near the top edge of tube support plates. These indications were found

-38-
with a bobbin coil and confirmed by plus-point coil examination. A review of previous inspection

data and operating experience did not reveal the presence of foreign objects; however, the

indications were considered to be very similar to wear scars left by foreign objects. These

tubes were plugged. The last tube plugged for "other" reasons was plugged as a result of a

large geometry distortion in the U-bend region. This tube was located in row 2, and no

degradation was identified during the evaluation of the bobbin or plus-point coil data.

During RFO 8 in 1999, 100% 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 hot-leg expansion transition region in

25% of the tubes in each of the steam generators, the U-bend region of 25% of the row 1 and 2

tubes in each steam generator, the preheater baffle plate expansions in 25% of the tubes in

steam generator A (34 tubes containing 68 expansions), and 25% of the hot-leg dents with

voltages greater than 5 volts. In addition to these eddy current inspections, visual inspections

were performed on all previously installed welded plugs, 25% of previously installed mechanical

plugs, 100% of newly installed tube plugs, and at the top of tubesheet region in all four steam

generators. Fourteen tubes were plugged during this outage.

Of the 14 tubes plugged during the outage, 9 were plugged as a result of wear at the AVBs, 1

was plugged for wear in the preheater region, 2 were plugged for wear due to a foreign object,

1 was plugged as a result of a foreign object signal, and 1 was plugged for a volumetric

indication near a support plate. Many of these indications are discussed in further detail below.

The maximum depth reported for the AVB wear indications was 50% throughwall.

As discussed above, one tube was plugged as a result of preheater wear at cold-leg tube

support 7C. This indication was estimated to be 28% throughwall and was preventatively

removed from service. In addition to this tube, three adjacent tubes were plugged as a result of

foreign objects. Two of these tubes had indications of tube wear (i.e., wall loss) and the third

tube had a signal attributable to a foreign object with no wall loss. These indications were

slightly above (or at) hot-leg tube support 5H. These tubes were in the periphery of the tube

bundle and were stabilized prior to plugging. The one tube plugged as a result of a volumetric

indication near a support plate had an outside-diameter-initiated signal near the top edge of

cold-leg tube support 2C. The affected tube is nearthe periphery of the tube bundle.

During RFO 9 in 2001, only steam generator B was inspected. Steam generator B was chosen

for inspection since it historically has had the most degradation. All the tubes in steam

generator B were inspected full length with a bobbin coil and a visual inspection of all plugs was

performed. Rotating probes equipped with a plus-point coil were only used to further

characterize indications detected by the bobbin coil. Four tubes were plugged during this

outage.

The indications in three of the four tubes plugged during this outage were attributed to wear

associated with a foreign object, and the fourth tube was plugged because of an

outside-diameter-initiated volumetric indication. Two of the three tubes plugged as a result of

foreign object wear were adjacent to each other. These tubes were located in the periphery of

the tube bundle and the wear occurred at (or near) hot-leg tube support 5H. These two tubes

were stabilized and plugged. The third tube plugged for wear associated with a foreign object

was located near the periphery of the tube bundle near the T-slot. The wear measured 9%

-39-
throughwall and was occurring near cold-leg tube support 2C. The foreign object was removed

during a previous outage. The tube plugged for an outside-diameter-initiated volumetric

indication had an eddy current signal slightly above cold-leg tube support 2C. The tube with

this indication is located in the interior of the tube bundle.

During this outage, eight tubes were identified with preheater wear. The maximum reported

depth for any of these indications was 13% throughwall. All indications were at cold-leg tube

support 7C. The number of tubes with preheater wear went up slightly since the previous

inspection.

As of December 2001, AVB wear is the dominant degradation mechanism at Byron 2,

accounting for 58% of the plugged tubes. About 18% of the plugged tubes had manufacturing

flaws, including the 29 tubes plugged in RFO 7 for circumferential indications at the hot-leg top

of tubesheet which were confirmed through tube pulls to most likely be the result of

manufacturing anomalies. Loose parts account for 12% of the tube plugging. A notable feature

of the loose part indications is the active region in steam generator B at hot-leg tube support 5H

bounded by rows 12 through 15 and columns 4 through 7. This region has accounted for 10 of

the 27 tubes plugged as a result of loose parts. Another such active region is in column 56 of

steam generator C between rows 38 and 41. This region has accounted for 4 of the 27 tubes

plugged as a result of loose parts. The tubes in both these regions have been stabilized as the

part has not been removed based on the information supplied to the NRC. For other tubes

affected by loose parts, tubes were plugged several cycles after the part was removed. It is not

clear from the information provided whether the plugging of these tubes was a result of

continued degradation or was a preventive measure.

Lastly, one region in steam generator A was reported to have several indications in a region of

scale/deposit buildup. This region is bounded by rows 44 through 49 and columns 66 through

74. All five tubes plugged in this region had indications near cold-leg tube support 2C.

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 2-5. 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 located in the cold leg of the steam generators. The lowermost

tube support (i.e., 1 H) is a flow distribution baffle. It is 0.75 inch thick.

In August 1987, during the first cycle of operation, Catawba 2 shut down to repair a pump seal.

During this outage, the licensee elected to inspect steam generators A and D to eliminate the

need to do eddy current inspections of all four steam generators during the first refueling

outage. No defective tubes were identified during these inspections.

-40-
During RFO 1, which began in December 1987, steam generator tube inspections were

performed in steam generators B and C. Steam generators A and D were not scheduled to be

inspected since they were inspected during the maintenance outage in August 1987. During

the evaluation of the steam generator B eddy current data, a 77% throughwall defect initiating

from the outside diameter of the tube at the top of tubesheet region was identified. The eddy

current signal was indicative of degradation due to a loose part. As a result of this indication,

visual inspections were performed on the secondary side of all four steam generators. These

visual inspections identified foreign objects on the tubesheets of all four steam generators and

exterior tube damage on one tube in steam generator B and one tube in steam generator D, as

discussed below.

Visual inspections were performed on the secondary side of all four steam generators prior to

and subsequent to sludge lancing. The pre-sludge-lancing visual inspections in steam

generator A resulted in the identification of a 2-inch long nail and two pieces of wire. All of

these foreign objects were removed. Post-sludge-lancing visual inspections in steam generator

A resulted in the identification of a carbon steel block in the annulus area. After enlarging a

6-inch handhole, the block was removed and subsequently identified as a spacer block used

during steam generator fabrication.

Pre-sludge-lancing visual inspections in steam generator B identified a nut and three large

studs. Two of the studs were lying adjacent to the defective tube discussed above. The nut

was removed with a magnet. The studs were identified as jacking studs that had apparently

been left in the steam generator during fabrication. The studs were removed after enlarging an

inspection port. Post-sludge-lancing visual inspections in steam generator B resulted in the

identification of a carbon steel weld rod in the annulus region. This object was not removed

because of difficulties in reaching and grasping it, but an analysis performed by the licensee

indicated the part could be left in service for the next operating cycle.

Pre-sludge-lancing visual inspections in steam generator C revealed a small piece of wire and a

piece of weld slag on the tubesheet. These were removed from the steam generator. No

additional foreign objects were discovered in steam generator C during the post-sludge-lancing

visual inspections.

Pre-sludge-lancing visual inspections in steam generator D resulted in the identification of a

piece of metal, some small rocks, and a small piece of wire. The piece of metal was removed,

but the other material was left in place because the licensee believed that subsequent sludge

lancing would flush it into a more accessible area where it could be more easily removed.

Post-sludge-lancing visual inspections in steam generator D were unable to locate the rocks

and piece of wire; however, a badly damaged tube and another slightly damaged tube were

discovered near where the debris had been.

As a result of identifying the visual damage to the tubes in steam generator D, the August 1987

eddy current data for these two tubes were reevaluated. This reevaluation revealed that the

severely damaged tube had a 50% throughwall flaw that was not identified during the August

1987 data evaluation. Due to these findings, all steam generator A and D eddy current data

from August 1987 was reevaluated. This reevaluation revealed that the severely damaged tube

in steam generator D and one other tube in steam generator A had contained indications that

exceeded the plant's repair criteria but were not identified during the original inspection. The

-41-
tube in steam generator A had a 65% throughwall indication; however, the location of the wear

on this tube was not considered indicative of damage due to loose parts. One of the reasons

the licensee missed these indications in August 1987 was that the data was evaluated only by

one analyst rather than by two analysts. The use of two analysts to evaluate the data had been

approved by the licensee but not yet implemented.

Based upon the loose objects discovered in the steam generators and the defective tubes

identified during the reevaluation of the August 1987 eddy current data, additional eddy current

testing of the peripheral tubes in steam generators A and D was performed (the peripheral

tubes in steam generators B and C were inspected during this outage as part of the initial eddy

current testing sample). As a result of these inspections, three additional indications in steam

generator A and one indication in steam generator D were identified that required plugging.

These tubes had not been inspected in August 1987 and the location of the wear was not

indicative of damage due to loose parts. In total, four tubes in A and two tubes in D were

plugged during the first outage.

In summary, tube inspections were performed slightly before RFO 1 and during RFO 1. All four

steam generators were inspected. The bobbin coil was used to inspect the full length of

approximately 25% of the tubes in steam generator A, 12% of the tubes in steam generator B,

11 % in steam generator C, and 26% in steam generator D. In addition to these full-length

exams, partial-length inspections were performed on approximately 2.5% of the tubes in each

of the four steam generators. Seven tubes were plugged as a result of the inspections. Of

these, two were plugged due to wear associated with confirmed loose parts. The nature of the

indications in the other five tubes was not specified, but one had an indication at the 3rd tube

support plate, one had an indication at the 7h tube support plate, one had an indication in the

freespan above the 12t' tube support plate, one had two indications in the freespan above the

2nd and 5' tube support plates, and one had an indication in the freespan above the 3rd tube

support plate.

During RFO 2 in 1989, approximately 32% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. As a result of these inspections, eight tubes were

plugged. The nature of the indications in these tubes was not specified; however, two adjacent

tubes were plugged for indications at the 3rd tube support plate, two adjacent tubes had

indications slightly above the 18 t tube support plate, one tube had an indication slightly above

the 17th tube support plate, one tube had an indication slightly above the 14 t tube support plate,

and one tube had an indication slightly below, or at, the 8th tube support plate. The eighth tube

plugged was a row 1 tube for which no indication was reported.

During RFO 3 in 1990, approximately 71 % of the tubes were inspected full length with a bobbin

coil and the remaining 29% of the tubes received a partial inspection. In addition to the bobbin

coil inspections, the rotating pancake coil probe was used to inspect the hot-leg expansion

transition region in 100% of the tubes. As a result of these inspections, 19 tubes were plugged.

Of the 19 tubes plugged, 14 were plugged as a result of wear at the AVBs, 3 were plugged for

indications slightly above (or at) the 71h tube support plate, and no indications were reported for

the other 2 tubes that were plugged. The maximum depth reported for the AVB wear

indications was 59% throughwall.

-42-
During RFO 4 in 1991, 100% 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, the rotating pancake coil

probe was used to inspect the hot-leg expansion transition region in 100% of the tubes. Of the

12 tubes plugged during this outage, 6 tubes were plugged as a result of wear at the AVBs, 2

adjacent tubes were plugged as a result of outside-diameter-initiated indications slightly above

or at the 5'1' tube support plate, 2 adjacent tubes were plugged as a result of

outside-diameter-initiated indications slightly above (or at) the 7t tube support plate, 1 tube was

plugged as a result of outside-diameter-initiated indications slightly above (or at) the 7th tube

support plate, and one tube was plugged for outside-diameter-initiated indications above the 15'

and 18t tube support plate. In addition to these 12 tubes, eight thimble (stub) tubes in each leg

of each steam generator were plugged during this outage. These are not considered tubes in

the model D5 steam generators. The maximum depth reported for the AVB wear indications

was 44% throughwall.

During RFO 5 in 1993, 100% 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, the rotating pancake coil

probe was used to inspect the hot-leg expansion transition region in 100% of the tubes. Of the

43 tubes plugged during this outage, 2 tubes were plugged as a result of wear at the AVBs, 3

tubes were plugged for indications at the hot-leg expansion transition (2 classified as single

axial indications, the other as an outside diameter indication), 30 tubes were plugged for

indications in the freespan region (i.e., above various tube supports and the AVBs), 6 tubes

were plugged for indications at the tube support plates (including 5 tubes with indications in the

preheater region at the 18th tube support, some of which were classified as axial indications),

and the reason for plugging 2 other tubes was not evident from the data submitted. The

indications in the free span were located throughout the tube bundle. The maximum depth

reported for the AVB wear indications was 43% throughwall.

During RFO 6 in 1994, 100% 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, the rotating pancake coil

probe was used to inspect the hot-leg expansion transition region in 100% of the tubes. Of the

31 tubes plugged, 1 was plugged as a result of wear at the AVBs, 4 tubes were plugged for

indications at the hot-leg expansion transition (2 classified as nonquantifiable indications, 1 as a

single axial indication, and 1 as an inside-diameter-initiated indication), 6 were plugged as a

result of indications at the tube support plates, and 20 were plugged for indications in the

freespan. These latter indications were on both the hot-leg and the cold-leg side of the steam

generator and many were classified as volumetric or as outside diameter indications. The

maximum depth reported for the AVB wear indications was 40% throughwall.

During RFO 7 in 1995, approximately 55% 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, the

licensee committed to perform rotating probe inspections in response to Generic Letter 95-03,

"Circumferential Cracking of Steam Generator Tubes.' These inspections were to be

performed at the hot-leg expansion transition region in at least 50% of the tubes and the

U-bend region of 20% of the row 1 and 2 tubes. Of the 23 tubes plugged during this outage, 1

tube was plugged as a result of wear at the AVBs, 2 tubes were plugged for indications at the

hot-leg top of tubesheet (1 classified as a pit and 1 as volumetric), 10 tubes were plugged as a

result of indications in the freespan, 5 tubes were plugged for indications at the tube support

-43-
plates, and the reason for plugging 5 other tubes was not evident from the data submitted. The

maximum depth reported for the AVB wear indications was 39% throughwall.

During RFO 8 in 1997, approximately 55% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. Of the 10 tubes plugged during this outage, 2

tubes were plugged as a result of wear at the AVBs, 3 tubes were plugged as a result of

indications at the hot-leg top of tubesheet attributed either to steam generator manufacture or

loose parts wear, 1 tube was plugged for an indication in the freespan, and 4 tubes were

plugged for inspection issues (2 for permeability variations, 1 for not obtaining rotating probe

data, and 1 for general data quality issues). The maximum depth reported for the AVB wear

indications was 43% throughwall.

During RFO 9 in 1998, approximately 52% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. In addition to these full length inspections,

approximately 4% of the tubes in each steam generator were partially inspected. A rotating

probe equipped with a plus-point coil was used to inspect the hot-leg expansion transition

region in 100% of the tubes and the U-bend region of 100% of the row 1 and 2 tubes. A

rotating probe was also used to inspect a 20% sample of the tubes in the preheater region at

tube supports 17 and 18. Of the 9 tubes plugged during the outage, 1 tube was plugged as a

result of wear at the AVBs, 3 tubes were plugged as a result of wear at the tube support plates

(2 on the hot-leg at tube supports 1 H and 7H, 1 on the cold-leg at tube support 17C), 1 tube

was plugged for an indication at a tube support plate attributed either to steam generator

manufacture or loose parts wear, 2 tubes were plugged for indications at the hot-leg top of

tubesheet attributed either to steam generator manufacture or loose parts wear, 1 row 1 tube

was plugged for a dent signal change in the U-bend (classified as a multiple axial indication),

and 1 tube was plugged for a permeability signal. The maximum depth reported for the AVB

wear indications was 42% throughwall.

During RFO 10 in 2000, approximately 95% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil, and the remaining 5% were partially inspected. Of

the seven tubes plugged during the outage, one tube was plugged as a result of wear at the

AVBs, two tubes were plugged as a result of wear attributed to foreign objects (both at hot-leg

tube support 1 H, neither in the periphery), two tubes were plugged because the probe became

lodged in the U-bend (both row 2 tubes), one tube was plugged because a rotating probe

inspection was not performed in the U-bend (a row 1 tube), and one tube was plugged because

a rotating probe inspection was not performed in the hot-leg top of tubesheet region. The

maximum depth reported for the AVB wear indications was 42% throughwall.

During RFO 11 in 2001, approximately 44% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil and an additional 5% were partially inspected. A

rotating probe equipped with a plus-point coil was also used to inspect the hot-leg expansion

transition region in 100% of the tubes, the U-bend region of 100% of the row 1 and 2 tubes,

100% of the expansions in the preheater region (i.e., at tube supports 17 and 18), a 20%

sample of dings/dents greater than 5 volts, and a 20% sample of dings/dents between 2 and 5

volts at tube support 8. No tubes were plugged as a result of these inspections.

As of December 2001, 183 tubes had been plugged at Catawba 2. The reason for plugging

many of these tubes was not reported by the licensee (i.e., the reason for plugging 68% of the

-44-
plugged tubes was not reported). Although the exact nature of the indications in these plugged

tubes was not reported, the number of indications requiring plugging at Catawba 2 has declined

since the early-to-mid 1990s.

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 1 H to 11 H on the hot-leg side of the steam generator and from 1 C to 11 C

on the cold-leg side (refer to Figure 2-5).

During RFO 1 in 1994, approximately 24% 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, the

licensee also used a rotating pancake coil to inspect the hot-leg expansion transition region in

359 tubes. These rotating pancake coil examinations were distributed between steam

generators A, B, and D. No tubes were plugged as a result of these inspections.

During RFO 2 in 1996, approximately 47% of the tubes in steam generators A and D were

inspected full length with a bobbin coil. In addition, the hot-leg expansion transition region in

approximately 46% of the tubes in these two steam generators were inspected with a rotating

pancake coil probe. The rotating pancake coil probe was also used to inspect the U-bend

region of approximately 100 tubes in each of these two steam generators. No tubes were

plugged as a result of these inspections.

During RFO 3 in 1997, the licensee inspected tubes in each of the four steam generators. The

bobbin coil was used to inspect the full length of 85% of the tubes in steam generator A, 100%

of the tubes in steam generators B and C, and 52% of the tubes in steam generator D. A

rotating probe equipped with a plus-point coil was used to inspect the hot-leg expansion

transition region in approximately 20% of the tubes, the U-bend region of 20% of the row 1 and

2 tubes (46 tubes), 20% of the expansions at preheater baffle plates B and D (28 tubes per

steam generator), 100% of the dents greater than or equal ito 5 volts at hot-leg tube support

plate 3H, and a sampling of dents greater than or equal to 5 volts up through hot-leg tube

support plate 11 H.

As a result of the RFO 3 inspections, eight tubes were plugged. Five of these tubes were

plugged as a result of wear at the AVB. The maximum depth reported for the AVB wear

indications was 53% throughwall. Two of the eight tubes were plugged as a result of a

confirmed loose part. The licensee removed the part from the steam generator after cutting an

access port near the part. The part was at hot-leg tube support 8H in row 49 columns 53 and

54. One of the eight tubes was plugged as a result of a restriction approximately 3 inches

above the top of the tubesheet on the cold-leg side of the steam generator. This tube was in

row 14 column 67.

-45-
During RFO 4 in 1999, approximately 20% 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 hot-leg expansion transition region in approximately 20%

of the tubes, the U-bend region of 20% of the row 1 and 2 tubes (46 tubes), 20% of the

expansions at the preheater baffle plates, 100% of the dents greater than or equal to 5 volts at

hot-leg tube support plate 3H, and 20% of the dings greater than or equal to 5 volts in the

straight section of the hot leg.

Five tubes were plugged as a result of the inspections. Three of the five tubes were plugged

for wear associated with possible loose parts. One of these possible loose parts was at the top

of cold-leg tube support 6C; the other loose part, a faster nut affecting two tubes and lodged

between them, was in the first inch above the top of the tubesheet. These latter two tubes were

in column 59 rows 36 and 37. One of the five tubes was plugged for an obstruction in the tube

31 inches above hot-leg tube support plate 1 OH. This tube could not pass a

0.610-inch-diameter probe. In a previous inspection this tube passed a smaller bobbin coil

probe, which detected a large dent at this location. One of the five tubes was plugged for a

pitlike indication 6 inches above the hot-leg top of tubesheet. This indication had been tracked

since RFO 2 (the first inservice inspection of the tube) and was attributed to a manufacturing

artifact or loose part.

During RFO 5 in 2000, approximately 42% of the tubes in steam generator A and approximately

79% of the tubes in steam generator 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 the hot-leg expansion transition region in approximately 43% of the tubes in steam

generator A and 44% in steam generator D, the U-bend region of approximately 45% of the row

1 and 2 tubes in steam generator A (103 tubes) and 46% of the row 1 and 2 tubes in steam

generator D (104 tubes), the expansions at the preheater baffle plates in approximately 42% of

the expanded preheater tubes in steam generator A (59 tubes) and 40% of the expanded

preheater tubes in steam generator D (55 tubes), and 100% of the dents greater than 5 volts at

hot-leg tube support plate 3H. Steam generators B and C were not inspected.

During RFO 5, four tubes were plugged, all for indications of wear at the AVBs. The maximum

depth reported for the AVB wear indications was 42% throughwall.

The licensee's historical tracking of AVB wear growth rate indicates that as the steam

generators accumulate operating time, the AVB wear growth rates falls. The licensee has two

possible explanations. The first is that the amplitude of vibration for each tube is finite, and

tube wear eventually reaches a specific depth and then stops. The second explanation is that

the volumetric wear rate is constant. As the depth and area of the wear increase, the volume

affected decreases, and the rate of progression through the tube wall apparently falls.

Of the 37 tubes plugged at Comanche Peak as of December 2001, 54% were plugged prior to

commencing commercial operation, 24% were plugged as a result of AVB wear, and 14% were

plugged for loose parts. The extent of the steam generator inspections has been more limited

at Comanche Peak than at the other plants with D5 steam generators.

-46-
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 are discussed. 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 steam generators could be significantly different than

in other model F steam generators so that the experience may differ.

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 (refer to

Figure 2-8). 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

is authorized in the plant technical specifications to use laser-welded sleeves and

electrosleeves to repair defective tubes.

Prior to commercial operation, four thermally treated tubes were plugged in the Callaway steam

generators. During RFO 1, no thermally treated tubes were plugged.

During a maintenance outage in April 1987, approximately 20% of the tubes in steam

generators B and C were inspected with a bobbin coil. Presumably this sample included 20%

of the thermally treated tubes. During RFO 2 in September 1987, approximately 60% of the

tubes in steam generators A and D were inspected with a bobbin coil. Presumably this sample

included 60% of the thermally treated tubes.' One thermally treated tube was plugged as a

result of these two inspections. This tube was plugged as a result of an eddy current indication

at hot-leg tube support 7H.

During RFO 3 in 1989, 100% of the tubes in steam generators B and C were inspected full

length with a bobbin coil: In addition to the bobbin coil inspections, the licensee also used a

rotating probe to inspect the hot-leg expansion transition region in approximately 250 tubes, the

area above and below hot-leg tube support 7H on an additional 250 tubes, and the U-bend

region of approximately 10 row 1 tubes in steam generator B. -The U-bend inspections were

performed to obtain additional information on anomalies found in the U-bend region of row 1.

No detectable discontinuities were found during the rotating probe inspections. One thermally

treated tube was plugged as a result of a single axial indication at the cold-leg flow distribution

baffle.

-47-
During RFO 4 in 1990, 100% of the tubes in steam generators A and D were inspected full

length with a bobbin coil. No significant rotating probe testing was performed on the thermally

treated tubes and no thermally treated tubes were plugged during this outage.

During RFO 5 in 1992, 100% of the tubes in steam generators B and C were inspected full

length with a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil

probe was used to inspect the U-bend region of 100% of the row 1 and 2 tubes in steam

generator C (244 tubes). One thermally treated tube was plugged as a result of the

inspections. This tube (row 2 column 98) was removed from service due to an undefined

indication just above cold-leg tube support 7C. This indication was not detected with the bobbin

coil, and the eddy current analyst judged this indication to be a distorted signal (the distortion

caused by its location in the U-bend transition). The hot-leg expansion transitions were

shot-peened during this outage to limit the likelihood of PWSCC.

During RFO 6 in 1993, 100% 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 pancake coil

probe was used to inspect the hot-leg expansion transition in 126 tubes in steam generator A

and 482 tubes in steam generator D. No thermally treated tubes were removed from service

during this outage.

During RFO 7 in 1995, 100% of the tubes in steam generators B and C were inspected full

length with a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil

probe was used to inspect the hot-leg expansion transition region of 405 thermally treated tubes

(8.3% of the thermally treated tube population). These inspections concentrated on the sludge

deposition zones of steam generators A and C, where most of the crack indications were found

in the mill-annealed tubes and where thermally treated tubes would most likely be affected. No

indications were identified as a result of the rotating probe inspections of the thermally treated

tubes; however, four thermally treated tubes were plugged during this outage. Of the four

tubes plugged, two had indications approximately 4 inches above the tubesheet on the cold-leg

side of steam generator B. These indications were 38% and 45% throughwall. The indications

were attributed to loose parts wear damage since a large foreign object was later removed from

steam generator B. In addition to these two tubes, two other thermally treated tubes were

plugged. Although not specifically identified by the licensee, the staff believes these two tubes

were located in row 1 column 1 in steam generators C and D and were damaged by improper

installation of the chemical cleaning equipment. Chemical cleaning was performed during RFO

7 to reduce the potential for ODSCC and intergranular attack.

During RFO 8 in 1996, 100% 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 the hot-leg expansion transition of 100% of the tubes

in all four steam generators and the U-bend region of 113 tubes in row 1 of steam generator C.

(The licensee originally planned to inspect the U-bend region of 100% of the unplugged row 1

tubes (i.e., 121 tubes), but eight tubes exhibited restrictions and were inspected with a bobbin

probe.)

As a result of these inspections, five thermally treated tubes were plugged and three thermally

treated tubes were sleeved with laser-welded sleeves. Of the five tubes plugged, three were

plugged for volumetric indications, one was plugged for an axial indication, and one was

-48-
plugged for a circumferential indication. All five of these indications were located on the hot-leg

side of the steam generator near the top of the tubesheet. Of the three tubes sleeved, two

were sleeved for circumferential indications and one was sleeved for a volumetric indication.

These three indications were also located on the hot-leg side of the steam generator near the

top of the tubesheet.

During RFO 9 in 1998, 100% of the tubes in steam generators B and C 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 hot-leg expansion transition region of 100% of the

tubes in all four steam generators, and the U-bend region of 121 of the row 1 tubes in steam

generator A (i.e., 100% of the inservice row 1 tubes). No thermally treated tubes were plugged

or repaired during this outage as a result of these inspections.

During RFO 10 in 1999, 100% 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 the expansion transition of 100% of the tubes in all

four steam generators and the U-bend region of 100% of the row 1 and 2 tubes in steam

generator D. As a result of these inspections, three thermally treated tubes were

electrosleeved. These tubes had volumetric indications slightly above the top of tubesheet on

the hot-leg side of the steam generator.

During RFO 11 in 2001, 100% of the tubes in steam generators B and C 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 hot-leg expansion transition region of 100% of the

tubes in all four steam generators, the U-bend region of 100% of the row 1 and 2 tubes in

steam generator B, and 20% of the dents and dings greater than 2 volts (as identified by the

bobbin coil exam) in steam generators B and C. One thermally treated tube was plugged as a

result of the inspections. This tube had an axial indication slightly above the top of the

tubesheet on the hot-leg side of the steam generator.

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 2-8.-

During RFO 1 in 1987, approximately 9% of the tubes in each of the four steam generators

were inspected with a bobbin coil. The extent of the inspections was not specified (e.g., full

length). As a result of the tube inspections performed during this outage, two tubes were

plugged. Both tubes were plugged for wear at the AVBs. The maximum depth reported for the

AVB wear indications was 34% throughwall.

-49-
During RFO 2 in 1989, approximately 42% of the tubes in steam generators A and C were

inspected full length with a bobbin coil. In addition, approximately 2% of the tubes in steam

generators A and C were partially inspected from the cold-leg tube end to the top support on

the hot leg. As a result of these inspections, four tubes were plugged during this outage. Three tubes were plugged as a result of wear at the AVBs, and one row 1 tube was plugged due to a distorted signal above hot-leg tube support 8H. This indication was located at the

hot-leg tangent point (i.e., the point where the tube starts to bend in the U-bend region--see Figure 2-3). The maximum depth reported for the AVB wear indications was 51 % throughwall.

During RFO 3 in 1991, approximately 63% of the tubes in steam generators B and D were

inspected full length with a bobbin coil except the row 1 tubes, which were inspected from the

hot-leg tube end to the top tube support on the cold-leg side (i.e., tube support 8C). Five tubes

were plugged during this outage. All five were plugged as a result of wear at the AVBs. The

maximum depth reported for the AVB wear indications was 53% throughwall. The licensee

considered the wear at the AVBs at Millstone 3 similar to the wear experienced in other model F

steam generators. The wear was primarily observed at the AVBs in the tubes in row 20 and

higher on the periphery and row 30 and greater in the middle of the tube bundle. The AVB

wear flaws in the middle of the tube bundle tended to be shallower than those on the periphery.

As a result of extended shutdowns in 1991 and 1992, the NRC approved an extension of the

steam generator tube inspection interval in August 1993. This extension extended the

inspection interval during cycle 4 from 24 to 31 months. Up to this point, primary-to-secondary leakage in the steam generators had been below 0.08 gpd.

During RFO 4 in 1993, approximately 77% of the tubes in steam generator A and approximately 65% of the tubes in steam generator C were inspected full length with a bobbin coil. These

inspections included all tubes in steam generators A and C which were not inspected during RFO 2. In addition to the bobbin coil inspections, a rotating probe was used to inspect the

hot-leg expansion transition region in approximately 40 tubes. Seven tubes were plugged during this outage. All of these tubes were plugged as a result of wear at the AVBs. The

maximum depth reported for the AVB wear indications was 61 % throughwall.

During RFO 4, eight Westinghouse Alloy 600 mechanical plugs were removed and replaced. One unexpected finding of the plug replacement program was that one of the eight tubes (row 50 column 95), which was plugged in 1989 as a result of wear at the AVBs, had progressed in

depth from 43% to 100% throughwall. To prevent the tube from severing and contacting adjacent tubes, the tube was stabilized.

During RFO 5 in 1995, approximately 75% of the tubes in steam generators B and D were

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, the Cecco 5

probe was used to inspect the hot-leg top of tubesheet region in approximately 11 % of the

tubes in steam generators B and D. The extent of inspection was from 12 inches above the

hot-leg top of the tubesheet to the hot-leg tube end. These inspections were performed in

response to the inspection results at Callaway, where circumferential cracking was identified

near the top of the tubesheet. The Cecco 5 exams were performed in the high sludge region and also in tubes with excessive tube geometry variations caused by the hydraulic tubesheet

expansion process. These geometry variations could increase the stress in the tubes at these

locations, which are considered more susceptible than other locations to PWSCC. Eleven

-50-
tubes were plugged during this outage, all for wear at the AVBs. The maximum depth reported

for the AVB wear indications was 59% throughwall.

In the beginning of an extended shutdown period during cycle 6 in 1996, the licensee inspected

the full length of 100% of the tubes in steam generator C 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

hot-leg expansion transition region in approximately 10% of the tubes in steam generator C and

the U-bend region of 25 row 1 tubes. Two tubes were plugged as a result of this inspection, for

wear at the AVBs. The maximum depth reported for the AVB wear indications was 44%

throughwall.

In September 1998, as a result of the extended midcycle maintenance outage from April 1996

through June 1998, the NRC authorized an extension to the 24-month steam generator tube

inspection interval specified in the Millstone 3 technical specifications. This extension permitted

the licensee to postpone the next inspection until the next refueling outage or July 1, 1999,

whichever was earlier.

During RFO 6 in 1999, 100% of the tubes in steam generators A and C 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 various locations in steam generators A and C,

including the hot-leg expansion transition region in approximately 48% of the tubes, the U-bend

region of approximately 50% of the row 1 and 2 tubes, selected dents at hot-leg tube supports,

and various tubesheet anomalies (153 tubes in steam generator A and 45 tubes in steam

generator C). In addition to the inspections of steam generators A and C, limited bobbin

inspections (42 tubes) and rotating probe inspections (2 tubes) were performed in steam

generator D. These inspections were performed to address two flaw indications and several

possible loose parts which were reported during the RFO 5 (1995) inspections.

Of the 14 tubes plugged during this outage, 13 tubes were plugged as a result of wear at the

AVBs and 1 tube was plugged as a result of a single volumetric indication consistent with loose

part damage. This latter tube was located in a high-flow region and the indication was at the

top of the hot-leg tubesheet. The maximum depth reported for the AVB wear indications was

51% throughwall. During cycle 6, minimal (less than 1 gpd) primary-to-secondary leakage was

observed.

With respect to the inspection of steam generator internal components, the licensee indicated

that it planned to perform J-tube inspections during RFO 7.

During RFO 7 in 2001, 100% of the tubes in steam generators B and D were inspected full

length with a bobbin coil. In addition to the bobbin coil inspections, a rotating probe was used

to inspect various locations in steam generators B and D, including the hot-leg expansion

transition region in approximately 50% of the tubes, the U-bend region of approximately 50% of

the row 1 and 2 tubes, and all previously reported dents and dings in the hot-leg portion of the

tube.

Of the 51 tubes plugged as a result of the inspections, 16 tubes were plugged as a result of

wear at the AVBs, 29 tubes were plugged as a result of volumetric indications (one of which

also had a pluggable AVB wear indication and is included in the 16 tubes discussed above),

-51-
and 7 tubes were plugged because they were close to loose part indications (as identified by

eddy current testing). The maximum depth reported for the AVB wear indications was 47%

throughwall.

Of the 29 tubes plugged as a result of volumetric indications, 12 were at the cold-leg flow

distribution baffle, 1 was at the hot-leg flow distribution baffle, 13 were at the top of the

tubesheet on the hot-leg side, and 3 were at the top of the tubesheet on the cold-leg side. The

licensee attributed most of these indications to foreign object wear based on the presence of

adjacent loose part indications in many of the affected tubes and on the distribution of the

indications within the tube bundle. Most, but not all, of these indications were at or near the

periphery of the tube bundle. There was a cluster of 10 tubes with volumetric indications at the

top of the tubesheet on the hot-leg side. The licensee attributed the cluster to steam generator

fabrication since eddy current testing identified outside diameter axial scratches in the

expanded portion of some of the tubes within the cluster (scratches the licensee considered to

have been made during fabrication prior to tube expansion). These 10 tubes were all located in

columns 23 or 24. Of the 29 indications, 16 were detected during the bobbin coil inspections,

and the remaining 13 indications were detected as a result of rotating probe inspections of

tubes adjacent to the 16 tubes with bobbin indications (i.e., during the expanded inspections

done after the bobbin indications were identified).

Of the seven tubes plugged for indications of loose parts, six were in tubes adjacent to tubes

with the volumetric indications discussed above, and one was isolated and in the interior of the

bundle. For most of the 36 tubes with volumetric indications and/or loose part indications

(attributed to loose parts or fabrication), no loose parts were visually confirmed since sludge

lancing was performed concurrent with eddy current testing. Two machine curls were removed

and a third part was identified visually but could not be removed. The licensee speculated that

the loose parts were a result of an upper bundle flush in 1999 (i.e., the flush freed foreign

objects that were previously stationary). None of these 36 tubes were stabilized.

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 2-8.

During the preservice inspection, six tubes exhibited indications of inadequate tube expansion

in the tubesheet area. These tubes were subsequently reexpanded and satisfactorily

reexamined prior to commercial operation.

During RFO 1 in 1991, approximately 32% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. During this outage, 10 tubes were plugged: 4

were plugged as a result of wear at the AVBs, 4 to bound a loose part that could not be

retrieved, and 2 for "high wall loss" indications. The maximum depth reported for the AVB wear

-52-
indications was 38% throughwall. Of the high-wall-loss indications, one was considered a

manufacturing burnishing mark and the other was a low-amplitude signal in the free span on

the cold-leg side. In addition to these plugs, two bare holes were replugged in steam generator

B. (A bare hole plug is a short piece of tubing closed at the top. It is installed like a normal

tube. As a result it looks like a normal tube end when viewed from the steam generator

channel head [i.e., from the primary face of the tubesheet]. Since bare hole plugs are exposed

to primary coolant and potentially to secondary coolant, they can degrade with time.)

During RFO 2 in 1992, approximately 43% of the tubes in steam generators A and D were

inspected full length with a bobbin coil. In addition to these full-length inspections, partial-length

inspections were performed in a limited number of tubes (1% in steam generator A, less than

1% in steam generator D). No tubes were plugged as a result of these inspections.

During RFO 3 in 1994, approximately 41% of the tubes in steam generators B and C were

inspected full length with a bobbin coil. In addition to these full-length inspections, partial-length

inspections were performed in approximately 2% of the tubes in steam generators B and C.

These partial length inspections were performed from the cold-leg tube end to the uppermost

support on the hot-leg side since these tubes were only inspected on the hot-leg and through

the U-bend during RFO 1 in 1991. One tube was plugged during this outage. This tube was

plugged as a result of wear at the AVBs. The maximum depth reported for the AVB wear

indications was 55% throughwall.

During RFO 4 in 1995, approximately 43% 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 Cecco

probe was used to inspect the hot-leg expansion transition region of approximately 9% of the

tubes in steam generators A and D, and a rotating probe equipped with a plus-point coil was

used to inspect the U-bend region of approximately 20% of the row 1 tubes in steam generators

A and D. The rotating probe was also used to inspect dents and dings in 12 tubes in steam

generators A and D.

During this outage, abnormal signal indications at the tube tangent point were reported. The

tangent point is the point on the tube where the U-bend meets the straight tube length (i.e., the

point where the tube begins to bend--refer to Figure 2-3). A review of the 1985 baseline data

for a sample of these tubes confirmed the indications were present at that time and had not

changed during operation. The indications are believed to be caused by geometry variations

introduced during the bending process. Rotating probe inspections performed during previous

inspections confirmed the tangent point signals to be non-flaw-like.

During this outage, 12 tubes were plugged. All 12 were plugged as a result of wear at the

AVBs. The maximum depth reported for the AVB wear indications was 55% throughwall.

The licensee assessed the progression of wear at the AVBs from RFO 2 to RFO 4. The

assessment included 172 AVB flaws which were greater than 20% throughwall in RFO 4. The

licensee determined that (1) AVB flaws can initiate at any time, (2) the growth rate of AVB flaws

is highest during the first cycle in which a flaw initiates, (3) for flaws greater than 10%

throughwall in RFO 2, the average growth rate during subsequent cycles was 4.5% throughwall

per cycle, and (4) the maximum growth rate observed over the two cycle period was 37%

-53-
throughwall (or 19% per cycle). This maximum growth rate was observed at both a newly

initiated and a preexisting flaw location.

During RFO 5 in 1997, 100% of the tubes in steam generators B and C were inspected full

length with the bobbin coil, except for the U-bend region of every other row 1 tube, which was

tested with a rotating probe equipped with a plus-point coil. In addition to the bobbin coil

inspections, a rotating probe equipped with a plus-point coil was used to inspect the hot- and

cold-leg expansion transition regions in 100% of the tubes in steam generator B. In steam

generator C, a rotating probe equipped with a plus-point coil was used to inspect the hot-leg

expansion transition region in every other pair of columns. Hot-leg dents and dings at or below

the fifth hot-leg tube support in steam generators B and C were also inspected with a rotating

probe equipped with a plus-point coil.

Of the 13 tubes plugged during this outage, 7 were plugged as a result of wear at the AVBs, 4

as a result of wear associated with loose parts, and 2 as a result of a volumetric indication

(wear) at cold-leg tube support 5C. The loose part that resulted in four tubes being plugged

was verified visually at the top of the hot-leg tubesheet but attempts to retrieve the part were

unsuccessful. The two tubes plugged for volumetric indications near cold-leg tube support 5C

were believed to be associated with loose part wear; however, no indications of a loose part

were still present at this location. The maximum depth reported for the AVB wear indications

was 56% throughwall. An assessment of AVB wear rates between 1994 and 1997 (32 effective

full-power months [EFPMs]) indicated an average growth of 6.3% for steam generator B and

4.2% for steam generator C over the 32 EFPM interval.

During RFO 6 in 1999, 100% 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 row 1 and 2 tubes. In addition to

the bobbin coil inspections, rotating probes equipped with a plus-point coil were used to inspect

the hot-leg expansion transition region in 50% of the tubes, the U-bend region of 50% of the

row 1 and 2 tubes, and 40% of all dents and dings in steam generators A and D.

During this outage, 25 tubes were plugged. All 25 tubes were plugged as a result of wear at

the AVBs. The maximum depth reported for the AVB wear indications was 71% throughwall.

The tube had not been inspected in four cycles. The structural limit for AVB wear is 75%

throughwall. An assessment of AVB wear rates between 1995 and 1999 indicated an average

growth of 5.3% for steam generator A and 8.3% for steam generator D.

During RFO 7 in 2000, 100% 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 and 2 tubes. In addition to

the bobbin coil inspections, rotating probes equipped with a plus-point coil were used to inspect

the hot-leg expansion transition region in 50% of the tubes, the U-bend region of 50% of the

row 1 and 2 tubes, and 40% of all hot-leg dents and dings with bobbin voltages greater than 5

volts in steam generators B and C. Additionally, visual inspections were performed to confirm

the presence of loose parts at tube locations exhibiting possible loose part eddy current signals

and to assess the condition of all installed tube plugs in the hot- and cold-leg of steam

generators B and C.

Of the 16 tubes plugged during this outage, 13 were plugged as a result of wear at the AVBs

and 3 were plugged as a result of possible loose part wear and/or the presence of a possible

-54-
loose part. Two of these three plugged tubes were adjacent and had indications at the hot-leg

top of tubesheet region. One of these two tubes had a volumetric indication while the other had

a possible loose part signal (i.e., no tube degradation was noted). The presence of the part

could not be confirmed. The third tube plugged on a count of a loose part was in row 1 and had

a volumetric indication near hot-leg tube support 1 H. The licensee speculated that the

indication was caused by contact with an unknown object such as a foreign object or the tooling

used during secondary-side cleaning. The maximum depth reported for the AVB wear

indications was 57% throughwall.

Seabrook has experienced minor primary-to-secondary leakage (less than 2 gpd) since cycle 5

in steam generators B and D as discussed below. During cycle 6, Seabrook observed small

amounts of leakage coming from steam generator D. During RFO 6, a tube with a 71%

throughwall AVB wear scar was plugged in this steam generator. Subsequent to the outage, no

primary-to-secondary leakage was observed in steam generator D; however, during cycle 7,

Seabrook observed minor primary-to-secondary tube leakage in steam generator B. This

leakage was less than 0.2 gpd. After startup from RFO 7, no leakage was observed; however,

several months into cycle 8 minor steam generator leakage was once again observed in steam

generator B. This leakage was less than 1 gpd.

3.3.4 Vogtle 1

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 FBC/BPC to 7C on the cold-leg side (refer to Figure 2-8).

During the preservice inspection, 100% of the tubes in all four steam generators were inspected

full length. No tubes required plugging as a result of the preservice inspection; however, the six

tubes plugged by the manufacturer were verified as plugged during this inspection.

Profilometry was performed for 100% of the tubes from the tube end to 2.5 inches above the

top of the tubesheet. The tubes which were found to be underexpanded were reexpanded. No

tubes were found to be overexpanded.

During RFO 1 in 1988, approximately 13% of the tubes in steam generators A and D were

inspected full length with a bobbin coil.- As a result of these inspections, one tube was plugged

as a result of freespan degradation. The tube was plugged for indications above the fifth

hot-leg tube support and the fourth cold-leg tube support. Both measured 39% throughwall.

During RFO 2 in 1990, approximately 27% of the tubes in steam generators A and D were

inspected full length with a bobbin coil and approximately 42% of the tubes in steam generators

B and C were inspected full length with a bobbin coil. In addition to these full-length

inspections, the U-bend regions of approximately 43% of the tubes in steam generators A and

-55-
D and approximately 33% of the tubes in steam generators B and C were inspected with a

bobbin coil.

During the inspection, several rotating pancake coil probe inspections were performed as a

result of eddy current indications at the tangent point (refer to Figure 2-3). Specifically, rotating

pancake coil probe inspections were performed as a result of indications at the cold-leg tangent

point on the tubes in steam generator D and at the hot- and cold-leg tangent points in several

tubes in steam generator C. These inspections did not confirm any flawlike indications. Of the

four tubes plugged during the inspection, all were attributed to AVB wear. The maximum depth

reported for the AVB wear indications was 45% throughwall.

During RFO 3 in 1991, approximately 20% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. No tubes were plugged as a result of these

inspections.

The licensee performed additional inspections during RFO 3 to verify what types of plugs had

been installed prior to operation (i.e., at the factory). Two types of welded plugs were typically

installed at the factory: a flush-welded plug and a bare-hole plug. The bare-hole plug is a short

piece of tubing closed at the top. It is installed like a normal tube. As a result it looks like a

normal tube end when viewed from the steam generator channel head (i.e., from the primary

face of the tubesheet). The flush-welded plug, on the other hand, appears to be a blank spot

on the tubesheet when viewed from the channel head. Since bare-hole plugs are exposed to

primary coolant and potentially to secondary coolant, they could degrade with time. At Vogtle 1,

steam generator C has four shop plugs installed (in two tubes) and steam generator D has

eight shop plugs installed (in four tubes). All of the shop plugs were determined to be flush

welded plugs.

During RFO 4 in 1993, approximately 52% of the tubes in steam generators B and C were

inspected full length with a bobbin coil. All four tubes plugged during this outage were plugged

as a result of wear at the AVBs. The maximum depth reported for the AVB wear indications

was 47% throughwall.

During RFO 5 in 1994, approximately 75% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. The licensee inspected all four steam generators

as a result of a recommendation from the vendor concerning wear at the AVBs. The vendor's

recommendation was based on operating experience at other plants that have changed their

operating conditions as a result of a power uprate and/or T-hot reduction. The vendor

recommended the inspection of 75% of the total tube population in each of the four steam

generators and the inspection of 100% of the tube population in rows 25 and greater. All 12

tubes plugged during this outage were plugged as a result of wear at the AVBs. The maximum

depth reported for the AVB wear indications was 52% throughwall. The inspection did not

reveal any areas of concern as a result of the power uprate implemented at Vogtle during the

preceding cycle.

During RFO 6 in 1996, approximately 60% 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 the hot-leg expansion transition of

approximately 20% of the tubes in steam generators A and D. All four tubes plugged during the

-56-
outage were plugged as a result of wear at the AVBs. The maximum depth reported for the

AVB wear indications was 42% throughwall.

In May 1996, shortly after starting up from RFO 6, Vogtle 1 was shut down in response to a

possible loose part on the primary side of steam generator D. On entering the hot-leg channel

head, licensee personnel found a support pin nut from a control rod guide tube assembly. The

nut's locking device was wedged into the bottom of a tube. It was subsequently removed.

Another object, believed to be a fragment from the support pin nut, was found on the cold-leg

side of the steam generator. The lower tubesheet on the hot-leg side was impacted by the

loose object and numerous indications were noted. The hot-legs of the other three steam

generators did not exhibit any signs of damage. During the next (i.e., RF 7) 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 RF 7.

During RF 7 in 1997, 100% of the tubes in steam generators B and C were inspected full

length with a bobbin coil, and 100% of the tubes in steam generator D were inspected full

length from the hot leg to ensure that the integrity of the tubes had not been compromised and

that the tubes were not obstructed or damaged by loose parts from the broken pin. There were

no tubesheet restrictions through which a probe could not be inserted.

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 approximately 40% of the tubes in

steam generators B and C and the U-bend region of approximately 40% of the row 1 and 2

tubes in steam generators B and C (98 tubes in B and 98 in C).

As a result of the RFO 7 inspections, 15 tubes were plugged: 12 as a result of wear at the

AVBs, 2 due to obstructions/restrictions, and 1 for a loose part indication. The latter three tubes

were subjected to a fiberoptic visual inspection. The inspection of the tube at row 4 column 3

revealed a foreign object that appeared to be a piece of fractured metal about the size and

shape of the failed support pin. No attempt was made to retrieve the loose part. The other two

tubes (R4C4 and R1iC31) were restricted at the U-bend transition region preventing the

passage of a 0.520-inch bobbin probe, and were subsequently removed from service (visual

inspection attempts at these locations were unsuccessful). The maximum depth reported for

the AVB wear indications was 44% throughwall.

During RF 8 in 1999, 100% 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 the hot-leg expansion transition of approximately 50%

of the tubes, and the U-bend region of approximately 40% of the row 1 and 2 tubes in steam

generators A and D (98 tubes in A and 98 in D). A visual inspection of previously installed

plugs showed no signs of leakage. No tubes were plugged as a result of these inspections.

The licensee analyzed the RF 8 inspection results using Wear Projection Technology. The

analysis indicated that tubes with wear at the AVBs in steam generators A and D should not

require stabilization for the foreseeable operating life of the plant. This analyses is believed to

have included an evaluation of previously plugged tubes. The licensee stated that it was also

tracking possible loose part indications at several locations in steam generator A (but none in

-57-
steam generator D). One of these locations was near the top of the tubesheet; another was at

the upper edge of the hot-leg baffle plate. Based on plus-point examination, this latter

indication was characterized as a volumetric indication associated with wear from a loose part.

An analysis of tube wear rates for steam generators A and D based on the RFO 6 and RF 8

results indicated that the two-cycle 95% cumulative distribution growth rates were 6.5% for

steam generator A and 11.4% for steam generator D. The average growth rates over this

period were 2.0% and 6.8%, respectively.

During RFO 9 in 2000, approximately 100% of the tubes in steam generators B and C 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 hot-leg expansion transition of

approximately 60% of the tubes, the U-bend region of approximately 50% of the row 1 and 2

tubes (122 tubes per steam generator), and approximately 20% of the hot-leg and U-bend

freespan dings greater than 5 volts (as measured by the bobbin coil) in steam generators B and

C.

Of the two tubes plugged during this outage, one was attributed to a volumetric indication and

the other to wear at the AVBs. The volumetric indication was located slightly above the top of

the tubesheet on the hot-leg side and was attributed to an artifact of fabrication; however, there

was no historical rotating probe data to confirm this hypothesis so the tube was plugged. The

maximum depth reported for the AVB wear indications was 41 % throughwall.

The licensee stated it was tracking indications of possible loose parts in steam generators B

and C. These loose parts are at, or just above, the tubesheet. Some are in the sludge zone

rather than in the periphery. None of the loose parts are associated with tube wear. Attempts

were made to retrieve the objects identified; where objects could not be removed, analyses

were performed to verify that the objects would not challenge tube integrity during the next

cycle.

An analysis of tube wear rates for steam generators B and C based on the RF 7 and RFO 9

results indicated that the two-cycle 95% cumulative probability growth rate was 9.7% for steam

generator B and 7.4% for steam generator C. The average growth rates over this period were

4.8% and 3.4%, respectively.

Prior to RFO 9, the licensee used the Wear Projection Technology to determine that one

plugged tube in steam generator B with an AVB wear indication would need stabilization by

RF 11 (fall 2003) and two additional tubes in steam generator B would need stabilization by

RFO 13 (spring 2005). Given these results, no tubes with wear indications were stabilized

during RFO 9.

A visual inspection of tube plugs was performed. There were no visible signs of leakage from

the plugged tubes.

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

-58-
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 (refer to Figure 2-8).

During the preservice inspection, 100% of the tubes in all four steam generators were inspected

full length. In addition, 13 tubes that were plugged by the manufacturer were verified to be

plugged during this inspection. Two additional tubes were plugged as a result of the tube

inspections performed during the preservice inspection. Profilometry was performed for 100%

of the tubes from the tube end to 2 inches above the top of the tubesheet.

During RFO 1 in 1990, approximately 20% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil. In addition to these full-length inspections, the

U-bend region of approximately 46% of the tubes in each of the steam generators was

inspected with a bobbin coil. No tubes were plugged as a result of these inspections. Several

tubes had indications which appeared deep by the bobbin coil, but inspection with a rotating

probe did not confirm degradation at these locations.

During RFO 2 in 1992, approximately 20% of the tubes in each of the four steam generators

were inspected full length with a bobbin coil and several tubes in each of the four steam

generators were inspected partially (e.g., from the uppermost cold-leg tube support to the end

of the tube on the hot-leg side of the steam generator). Approximately 600 tubes in steam

generator B were also inspected as part of a program investigating potential loose parts in the

periphery of the tube bundle. No tubes were plugged as a result of these inspections.

Steam generators B, C, and D were inspected to verify the types of plugs installed during the

fabrication of the steam generators. These inspections verified that the plugs installed after

fabrication were flush-welded to the tube (rather than bare-hole plugs). The plugs in steam

generator A were installed as a result of the preservice inspection, not during fabrication (i.e.,

no plugs were installed during fabrication in steam generator A).

During RFO 3 in 1993, approximately 53% of the tubes in steam generators A and D were

inspected full length with a bobbin coil. A loose part was identified on the cold-leg baffle plate

adjacent to the tube in row 57 column 68 in steam generator D. The loose part was removed

and the tube was left in service since the extent of tube wear was less than the repair/plugging

limit. An additional 12 bobbin coil inspections were performed around the tube with wear, and

a rotating probe inspection of the tube in row 57 column 68 was performed. No tubes were

plugged as a result of these inspections. -

During RFO 4 in 1995, approximately 78% of the tubes in steam generators B and C were

inspected full length with a bobbin coil. During this outage, the licensee implemented a

recommendation from Westinghouse concerning AVB wear operating experience from plants

that have changed their operating conditions as a result of a power uprate and/or T-hot

reduction. Westinghouse recommended the inspection of 75% of the total tube population in

each of the two steam generators and the inspection of 100% of the tube population in rows 25

-59-
and greater. All three tubes plugged during this outage were plugged as a result of wear at the

AVBs. The maximum depth reported for the AVB wear indications was 60% throughwall. The

inspection did not reveal any areas of concern as a result of the power uprate implemented at

Vogtle during the preceding cycle.

During RFO 5 in 1996, 100% 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 was used

to inspect the hot-leg expansion transition region of approximately 20% of the tubes in steam

generators A and D. All six tubes plugged during this outage were plugged as a result of wear

at the AVBs. The maximum depth reported for the AVB wear indications was 51% throughwall.

During RFO 6 in 1998, 100% of the tubes in steam generators B and C 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 hot-leg expansion transition of approximately 40%

of the tubes in steam generators B and C and the U-bend region of approximately 40% of the

row 1 and 2 tubes in steam generators B and C (98 tubes in B and 98 in C). No tubes were

plugged as a result of these inspections. A visual inspection of previously installed plugs in

steam generators B and C did not reveal any visible signs of leakage.

An analysis of tube wear rates at the AVBs for steam generators B and C indicated that the

two-cycle 95% cumulative distribution growth rate decreased from 13.1% (measured from RFO

2 to RFO 4) to 11.7% (measured from RFO 4 to RFO 6).

During RFO 7 in 1999, 100% of the tubes in steam generators A and D were inspected full

length with the bobbin coil. 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 of approximately 53%

of the tubes in steam generators A and D, the U-bend region of approximately 40% of the row 1

and 2 tubes in steam generators A and D, and 20% of the straight tube section dents greater than 5 volts in steam generators A and D. A visual inspection of previously installed plugs in

steam generators A and D did not reveal any visible signs of leakage.

All five tubes plugged during this outage were plugged for wear at the AVBs. The maximum

depth reported for the AVB wear indications was 40% throughwall.

The licensee evaluated the need to stabilize tubes in steam generators A and D as a result of

AVB wear using the Wear Projection Technology. The licensee identified no tubes that would

need stabilization during the foreseeable operating life of the plant.

An analysis of wear rates indicated the average wear rate for a two-cycle period was 4.1% for

steam generator A and 3.8% for steam generator D. The 95% cumulative distribution growth rate for a two-cycle period was approximately 7.8% for steam generator A and 7.3% for steam

generator D. Loose parrt signals were also analyzed following the outage. Many of the loose

parts observed during the eddy current examination had not resulted in tube wear.

During RFO 8 in 2001, 100% of the tubes in steam generators B and C 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 hot-leg expansion transition region of

approximately 64% of the tubes in steam generators B and C, approximately 100% of hot-leg

-60-
dents in the straight section which were greater than 5 volts as identified by the bobbin coil,

20% of the dents in the U-bend which were greater than 5 volts, and the U-bend region of

approximately 60% of the row 1 and 2 tubes in steam generators B and C (146 tubes in steam

generator B and 146 in C). No tubes were plugged as a result of these inspections. A visual

inspection of previously installed plugs in steam generators B and C did not reveal any visible

signs of leakage.

Based upon the results of the inspection, the licensee concluded that tube stabilization would

not be required in either steam generator until after the end of plant life. An analysis of tube

wear rates indicated that the 95% cumulative probability growth over two cycles was 3.5% for

steam generator B and 2.1% for steam generator C. The average growth rates for these steam

generators were slightly negative (based on RFO 6 and RFO 8 data), implying that there is little

or no growth in the wear indications at the AVBs. This negative growth rate can also be

attributed to slight differences (within tolerances) between the standards used in the

inspections.

Several indications of loose parts are being tracked in steam generator C. Since none of these

indications were expected to cause excessive wear, the affected tubes were left in service.

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.

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 (refer to Figure 2-8).

Before the steam generators were placed in service, 15 tubes were plugged. In addition, three

holes had been drilled in the cold-leg tubesheet of steam generator A in locations where tubes

were not supposed to exist and these three holes were also plugged.

During RFO 1 in 1986, approximately 7%of the tubes in steam generators B and C were

inspected full length with a bobbin coil. In addition to these full-length inspections, a few

partial-length inspections were performed with a bobbin coil. These partial-length inspections

were performed in the U-bend region of the steam generator from the top tube support plate on

the hot-leg side to the top tube support plate on the cold-leg side. No tubes were plugged as a

result of these inspections.

During RFO 2, no steam generator tube inspections were performed; however, during RFO 3 in

1988, approximately 53% of the tubes in each of the four steam generators were inspected full

length with a bobbin coil. This was the first inspection for steam generators A and D. During

this outage a disproportionate number of indications were detected in steam generator D, and

the licensee was unsuccessful in developing an explanation for this condition at that time.

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During RFO 3, 22 tubes were plugged, 19 of them for wear at the AVBs. The maximum depth

reported for the AVB wear indications was 73% throughwall. During RFO 7 in 1994, 6 of these

19 tubes were deplugged, inspected, and returned to service. All six of these tubes had AVB

wear indications less than the plugging criterion both in RFO 7 as well as in RFO 3. The three

other tubes plugged during this outage had eddy current indications in the freespan portion of

the tube. One of these three tubes had an indication above the hot-leg baffle plate, another

tube had an indication above the cold-leg baffle plate, and the third tube had an indication

above hot-leg tube support 6H. The tube with an indication above the hot-leg baffle plate and

the tube with an indication above the cold-leg baffle plate were returned to service during RFO

5 in 1991.

During RFO 4 in 1990, approximately 56% of the tubes in steam generators B and D were

inspected full length with a bobbin coil. Both of the two tubes plugged during this outage were

plugged as a result of wear at the AVBs. The maximum depth reported for the AVB wear

indications was 42% throughwall.

During RFO 5 in 1991, approximately 28% of the tubes in steam generator A and approximately

22% of the tubes in steam generator C were inspected full length with a bobbin coil. In addition

to these full-length inspections, approximately 4.5% of the tubes in steam generator C were

inspected with a bobbin coil from the cold-leg tube end to the top cold-leg tube support (i.e.,

7C). Two tubes were plugged during this outage, both as a result of wear at the AVBs. The

maximum depth reported for the AVB wear indications was 43% throughwall.

Two tubes were unplugged and returned to service during RFO 5 after eddy current testing

indicated that it was acceptable. These tubes had been plugged during RFO 3 in 1988. One of

these tubes had an indication whose reported depth at the time of original plugging was less

than the plugging criterion.

During RFO 6 in 1993, 100% of the tubes in steam generator B were inspected full length with

a bobbin coil. All five tubes plugged during this outage were plugged as a result of wear at the

AVBs. The maximum depth reported for the AVB wear indications was 50% throughwall. Four

additional locations were plugged in steam generator B during this outage. These locations are

referred to as "bare holes' and do not have tubes inserted into them. Bare holes are holes in

the steam generator tubesheet which were capped internally by the manufacturer prior to steam

generator delivery and installation. Bare holes can have either stub-type or bar-type plugs

installed. The four locations in steam generator B had 26-inch stub-tube type plugs installed.

These bare holes are not inspected as part of the inservice inspection program and were

plugged to preclude the possibility of leakage.

During RFO 7 in 1994, 100% of the tubes in steam generators A and D were inspected full

length with a bobbin coil. Of the 33 tubes plugged during this outage, 31 were plugged as a

result of wear at the AVBs, 1 tube was plugged due to an indication slightly below (or at) hot-leg

tube support 1 H, and 1 tube was plugged for a volumetric indication slightly below (or at)

hot-leg tube support 2C. The maximum depth reported for the AVB wear indications was 56%

throughwall.

During RFO 7, 17 tubes with Alloy 600 mechanical plugs were deplugged and inspected as part

of the plug replacement program in response to NRC Bulletin 89-01, "Failure of Westinghouse

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Steam Generator Tube Mechanical Plugs." Of these 17 tubes, 6 were returned to service since

the inspections indicated that the tubes were acceptable (they had been plugged for AVB wear

in RFO 3 and the depth of the wear was less than the plugging criterion). The inspection of

these 17 previously plugged tubes revealed that (1) some indications of AVB wear had

progressed further through the tube wall despite being plugged, (2) some indications of AVB

wear showed little or no change (zero or negative growth) between the time the tube was

plugged and the time of this inspection, and (3) some AVB locations for which no degradation

was reported at the time of plugging had indications of AVB wear.

During this outage, repairs and inspections were performed on bare holes in steam generator

A. Five stub-type bare-hole plugs were mechanically plugged and one bar-type bare-hole plug

was removed and replaced with a welded plug. Three other bar-type bare-hole plugs were

inspected with a rotating pancake coil probe and left in service.

During RFO 8 in 1996, 100% of the tubes in steam generators B and C 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 hot-leg expansion transition region in 20% of the

tubes in steam generators B and C and the U-bend region of 20% of the row 1 tubes in steam

generators B and C. All 16 tubes plugged during this outage were plugged as a result of wear

at the AVBs. The maximum depth reported for the AVB wear indications was 60% throughwall.

During RFO 9 in 1997, 100% 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 the hot-leg expansion transition region in

approximately 55% of the tubes in steam generators A and D and the U-bend region of 50% of

the row 1 and 2 tubes in steam generators A and D. All 19 indications plugged during this

outage were plugged as a result of wear at the AVBs. The maximum depth reported for the

AVB wear indications was 60% throughwall.

During RFO 10 in 1999, 100% of the tubes in steam generators B and C were inspected full

length with a bobbin coil. In addition to the bobbin coil inspections, a rotating probe was used

to inspect the hot-leg expansion transition region in 55% of the tubes in steam generators B

and C and the U-bend region of 50% of the row 1 and 2 tubes in steam generators B and C. All

six tubes plugged during this outage were plugged as a result of wear at the AVBs. The

maximum depth reported for the AVB wear indications was 57% throughwall.

During the RFO 10 inspections of steam generators B and C, tube wear at the AVB

intersections and wear due to prior loose parts were observed. No loose parts were detected

near the location of the worn tubes. In addition, a number of distorted signals were identified at

the flow distribution baffle plate, primarily on the cold-leg side of the steam generator. The

licensee considered the location of these signals atypical with regard to any potential corrosion

degradation. A review of the 1996 inspection data for these indications showed no change in

the shape or size of these signals. All of the signals were inspected with a rotating probe.

Seven signals were confirmed as wear indications with the rotating probe and were sized with a

bobbin coil and left in service. In addition to the flow distribution baffle plate indications, several

indications, which were sized, were reported at (or near) the top of the hot-leg tubesheet and

one indication was reported above hot-leg tube support 7H (this indication may be near the first

AVB).

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During RFO 11 in 2000, 100% of the tubes in steam generators A and D were inspected full

length with a bobbin coil. In addition to the bobbin coil inspections in steam generators A and

D, a rotating probe was used to inspect the hot-leg expansion transition region in 55% of the

tubes and the U-bend region of 50% of the row 1 and 2 tubes. Of the 32 tubes plugged during this outage, 30 were plugged as a result of wear at the AVBs. The maximum depth reported for

the AVB wear indications was 65% throughwall. The other two tubes were plugged for

volumetric indications at the hot-leg top of tubesheet and at hot-leg tube support 4H. Rotating

probe inspections of these tubes led the licensee to conclude that the indication at the top of

tubesheet was most likely a result of manufacture and the indication at the hot-leg tube support

was a benign indication, having been present in the prior two inspections with essentially no

change.

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 since 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.

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 2-10.

Prior to operation, two tubes were plugged in the replacement steam generators. These tubes

were plugged because they were expanded above the top of the tubesheet. In addition, one

tubesheet was misdrilled during fabrication, resulting in an extra hole on one side of the steam

generator. This hole was plugged with a welded plug. During the preservice inspection, 100%

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 hot-leg expansion transition region of 100% of the tubes in all four steam

generators and the U-bend region of 100% of the row 1 and 2 tubes in all four steam

generators.

The first inservice inspection of the replacement steam generators is not planned until the fall of

2002.

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

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plugged and deplugged during each outage for each of the two steam generators. Table 3-35

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 2-10.

Prior to the preservice inspection in 1984, three tubes in steam generator A were plugged with

welded shop plugs. No tubes in steam generator B were plugged. During the preservice

inspection in January 1984, 100% of the active tubes in both steam generators were inspected

full length with a bobbin coil. As a result of the preservice inspection, one tube was plugged in

steam generator B. The tube had a 60% throughwall defect approximately 25 inches above the

hot-leg tubesheet.

During RFO 12 in 1985, approximately 3% of the tubes in steam generators A and B were

inspected full length with a bobbin coil. In addition to these full-length inspections,

approximately 0.6% of the tubes in each steam generator were inspected from the hot-leg tube

end through the U-bend region. No tubes were plugged as a result of these inspections.

During RFO 13 in 1986, approximately 3.8% of the tubes in steam generator A and

approximately 4.5% of the tubes in steam generator B were inspected full length with a bobbin

coil. In addition to these full-length inspections, a number of partial-length inspections were

performed. In steam generator A, "U-bend tests" were performed in 0.6% of the tubes. In

steam generator B, 0.6% of the tubes received U-bend tests, 0.3% of the tubes were inspected

through the fourth tube support, and approximately 7.7% of the tubes were inspected through

the third tube support. Presumably these latter inspections were from the hot-leg tube end to

the third or fourth hot-leg tube support. No tubes were plugged as a result of these inspections.

During RFO 14 in 1987, no steam generator tube inspections were performed.

During RFO 15 in 1988, approximately 4.0% of the tubes in steam generator A and

approximately 3.5% of the tubes in steam generator B were inspected full length with a bobbin

coil. The initial inspections showed no indications in either steam generator; however, two

tubes were damaged in the cold leg of steam generator B as a result of a project to remove

tube-lane-blocking-devices. As a result of this damage, the tubes were plugged and five tubes

in this steam generator received partial-length inspections. A loose parts concern was raised

during the closeout inspection following the blocking device removal project in steam generator

A. As a result of this concern, approximately 5.6% of the tubes in steam generator A were

inspected through the first tube support plate.

During RFO 16 in 1989, approximately 18% of the tubes in steam generator A and

approximately 19% of the tubes in steam generator B were inspected full-length with a bobbin

coil. In addition to these full length inspections, approximately 2% of the tubes in each steam

generator were inspected from the hot-leg tube end to the uppermost support on the cold-leg

side of the steam generator (i.e., the sixth cold-leg tube support), and approximately 0.6% of

the tubes in steam generator B were inspected as a result of manufacturing burnishing marks.

Manufacturing burnishing marks appear randomly throughout the tube bundle and are a result

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of attempts to dress or buff scratches made in the tubes during the fabrication of the tube

bundle. No tubes were plugged as a result of these inspections.

During RFO 17 in 1990, no steam generator tube inspections were performed; however, the

plugs in the three tubes in steam generator B were repaired as a result of concerns with stress

corrosion cracking in Alloy 600 plugs.

During RFO 18 in 1991, approximately 18% of the tubes in each of the two steam generators

were inspected full length with a bobbin coil. In addition to these full-length inspections, a

number of partial-length exams were performed in both steam generators. These partial-length

inspections included inspections in the periphery of the tube bundle to address loose parts

concerns and to address the degradation found in steam generator A (discussed below). In

addition to the bobbin coil inspections, a rotating pancake coil probe was used to inspect a

number of manufacturing burnishing marks.

Two tubes were plugged during this outage. One tube in steam generator A was plugged for a

68% throughwall flaw located approximately 0.6-inch below hot-leg tube support 5H and

attributed to wear from interaction with the tube support. The other tube plugged during this

outage was in steam generator B. It was plugged as a result of a 38% throughwall AVB wear

indication.

During RFO 18, remote video equipment was used to inspect up through the second tube

support plate region in both steam generators. During these inspections, the annular region,

the tube lanes, the baffle plates, and a few tubes into the tube bundle were inspected. In

addition, in steam generator A, the inspection port at the sixth tube support plate was removed

to allow access for inspection. The tube bundle was found to be in very good condition. A

sample of boiler scale found throughout the steam generator was removed for analysis to

determine a method for removal and also to attempt to quantify its thermal properties. Sludge

lancing was performed on both steam generators. Post-cleaning examination was performed

and verified the effectiveness of the cleaning.

During RFO 19 in 1992, approximately 18% of the tubes in both steam generators were

inspected full length with a bobbin coil. In addition to these full-length inspections, a number of

tubes in the periphery were inspected partially to address loose parts concerns. No tubes were

plugged as a result of these inspections. However, one tube (in row 38 column 69) was

reported as not being expanded in the hot-leg tubesheet.

During RFO 20 in 1993, approximately 18% of the tubes in both steam generators were

inspected full length with a bobbin coil. In addition to these full-length inspections, a number of

tubes in the periphery were inspected partially to address loose parts concerns. No tubes were

plugged as a result of these inspections.

During RFO 21 in 1994, no steam generator tube inspections were performed, although a loose

parts inspection was performed in steam generator A and sludge lancing was performed in both

steam generators. Presumably the loose parts inspection was performed visually.

During RFO 22 in 1995, 100% of the tubes in both steam generators were inspected full length

with a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was

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used to inspect the portion of the tube within the tubesheet for approximately 20 tubes. One

tube was plugged as a result of a 45% throughwall AVB wear indication discovered during

these inspections.

During RFO 23 in 1996, no steam generator tube inspections were performed. The plant was

shut down for most of 1997.

During RFO 24 in 1998, 100% of the tubes in both steam generators were inspected full length

with a bobbin coil with the exception of the U-bend region of the row 1 and 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 of 20% of the tubes, the U-bend region of 1 00%

of the row 1 and 2 tubes, and a sample of dented locations (55 tubes in steam generator A and

68 tubes in steam generator B). No tubes were plugged as a result of these inspections. At

this point, the steam generators had been operating for approximately 11.5 EFPY.

During RFO 25 in 1999, no steam generator tube inspections were performed.

In February 2000, the licensee shut down the plant to investigate an indication of a loose part.

After a thorough investigation and inspection found no loose parts, the unit was restarted. The

scope and method of inspection were not provided.

During RFO 26 in 2001, 100% of the tubes in both 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 hot-leg expansion transition region of approximately 40%

of the tubes and the U-bend region of approximately 20% of the row 1 tubes. One tube was

plugged during this outage as a result of a 39% throughwall AVB wear indication.

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 (AVT). The tube supports are numbered

as shown in Figure 2-10 (although the AVBs are numbered 01A, 02A, 03A, and 04A rather than

AVB1, AVB2, AVB3, and AVB4, respectively).

The first steam generator inservice inspection after the steam generator replacement in 1984

was performed during RFO 10 in 1986. During RFO 10, approximately 9% of the tubes in each

of the three steam generators were inspected full length with a bobbin coil. In addition to these

full-length inspections, approximately 0.8% of the tubes were inspected from the hot-leg tube

end through the U-bend to the uppermost (i.e., sixth) support plate on the cold-leg side. These

partial-length inspections were performed primarily on the tubes in rows 1 through 4. No tubes

were plugged as a result of these inspections.

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During RFO 11 in 1987, approximately 9% of the tubes in each of the three steam generators

were inspected full length with a bobbin coil. In addition to these full-length inspections,

approximately 0.7% of the tubes in each of the three steam generators received a partial-length examination, typically from the hot-leg tube end to the sixth (uppermost) tube support plate on

the cold-leg side. No tubes were plugged as a result of these inspections. One tube in steam

generator C was found to have been expanded above the top of the secondary face of the

tubesheet. This tube was not plugged.

During RFO 12 in 1988, approximately 20% of the tubes in each of the three steam generators

were inspected full length with a bobbin coil. In addition, approximately 0.5% of the tubes in

each of the three steam generators received a partial-length examination, typically from the

hot-leg tube end to the sixth (uppermost) tube support plate on the cold-leg side. As a result of

these inspections, one tube was plugged. This tube had a 76% throughwall indication near the

hot-leg tubesheet. The indication was characterized as a gouge indicative of a defect caused

by debris. The last time this tube had been inspected was during the 1984 preservice

inspection. No indication had been reported at this location. A secondary side inspection of the

affected steam generator in 1988 did not reveal any debris. As a result of identifying the

degradation in this tube, the licensee inspected approximately 20 tubes from the hot-leg tube

end through the first or second hot-leg tube support in the vicinity of the affected tube. No

similar indications were observed during these inspections.

In April 1989, Robinson 2 was shut down to investigate alarms from the loose part monitoring

system. The alarms indicated the possibility of a loose part in the hot-leg channel head of

steam generator C. Upon investigation, the alarm was attributed to a control rod guide tube

support pin nut (i.e., a split pin nut). The nut was removed. It had damaged the hot-leg tubesheet and tube ends in steam generator C. Some of the tubesheet face markings used to

identify tubes on the hot leg were obliterated, and the damage to the hot-leg tube ends resulted

in limitations on the ability to insert inspection probes at these locations. As a result of this

event, in 1990 the licensee for Robinson 2 submitted a request to modify its technical

specifications in 1990 to permit tube inspection from either the hot- or the cold-leg side of the

steam generator.

During RFO 13 in 1990, approximately 20% of the tubes in each of the three steam generators

were inspected full length with a bobbin coil. In addition to the bobbin coil inpections, a rotating pancake coil probe was used to inspect the hot-leg expansion transition region of approximately

3% of the tubes in each of the three steam generators. Indications of copper deposits were

noted both in the bobbin and the rotating probe data. The rotating pancake coil inspections

were focused on the sludge pile region. One row 2 tube was plugged for an indication above

the cold-leg tubesheet as a result of the inspections. The licensee speculated that this

indication was from a loose part, possibly the same loose part which resulted in the plugging of

the tube during RFO 12 in 1988 (although the degradation identified during 1988 was on the

hot-leg side of the steam generator). No surrounding tubes had indications of tube damage.

During RFO 14 in 1992, approximately 20% of the tubes in each of the three steam generators

were inspected full length with a bobbin coil. The row 1 tubes were only examined from the

hot-leg tube end to the sixth support plate on the cold-leg side of the steam generator. No

random rotating pancake coil inspections were performed during this outage, unlike the

previous outage. One tube was plugged as a result of the bobbin coil inspections. This tube,

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located in row 1 column 29 in steam generator A, was plugged because a 0.580-inch diameter

probe could not pass through the tube at the sixth (uppermost) hot-leg tube support plate. A

review of historical data showed that an indentation was present in the tube in 1984 (i.e., during

the baseline inspection). This indentation prevented the passage of a 0.720-inch diameter

probe in 1984, but the tube was left in service. Sludge height measurements made during this

outage indicated that the sludge height did not exceed 3 inches. As was the case during RFO

13, indications of copper were observed in the eddy current data.

During RFO 15 in 1993, approximately 35% of the tubes in each of the three steam generators

were inspected full length with a bobbin coil. The row 1 tubes were only examined from the

hot-leg tube end to the sixth support plate on the cold-leg side of the steam generator. The

bobbin coil inspection included all tubes which had not been inspected since the 100% baseline

inspection in 1984. In addition to the bobbin coil inspections, a rotating pancake coil probe was

used to inspect approximately 20% of the hot-leg manufacturing buff marks in each of the three

steam generators (approximately 80 tubes total). Tubes inspected with a rotating pancake coil

probe at buff mark locations were also inspected with this probe at the hot-leg expansion

transition region.

As a result of these inspections, one tube was plugged. This tube, located in row 2 column 6 of

steam generator A, was plugged because neither a 0.610-inch diameter probe nor a 3/8-inch

diameter poly shaft could be passed through the tube. During the baseline inspection

performed in 1984, a 0.720-inch probe could not pass through this tube, but the tube was left in

service.

In February 1994, Robinson 2 was shut down for repairs to an emergency diesel generator.

During this shutdown, a loose-parts-monitor alarm from steam generator C was investigated.

The investigation revealed two strips of metal resting on the tubesheet, one near the periphery

of the tube bundle and the other by a handhole. Their composition was similar to that of

welding electrodes believed to have been used to fabricate the replacement steam generator

shell welds. The metal strips were removed from the steam generators, and two tubes (row 1

column 90 and row 3 column 90) were plugged because of localized wear where the metal

strips contacted the tubes. One of the metal strips was observed laying across the tube lane,

wedged between columns 90 and 91 and leaning against three rows of tubes in column 90.

The tube in row 1 column 90 exhibited a 33% throughwall indication on the hot-leg side of the

steam generator and a 57% throughwall indication on the cold-leg side. The tube in row 3

column 90 exhibited a 26% throughwall indication on the cold-leg side. These tubes had been

examined during RFO 13 in 1991 and found to be free of degradation. Two nearby tubes had

been plugged in prior outages due to either outside diameter wear or manufacturing marks.

These tubes located in row 2 column 90 and row 7 column 92 were plugged in 1990 and 1988,

respectively. The row 2 tube indication was on the cold-leg side and the row 7 indication was

on the hot-leg side of the steam generator. These indications may have been related to the

loose part. A total of 484 tubes were inspected during this unplanned outage.

As of June 29, 1994, Robinson 2 had only six tubes plugged (not including the 28 tubes

plugged prior to operation) and had accumulated only 6.5 effective full-power years on its steam

generators.

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During RFO 16 in 1995, 100% of the tubes in steam generator C were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

to examine the remaining 80% of the hot-leg manufacturing buff marks in steam generator C

not inspected during the 20% RFO 15 (1993) sample. These examinations were performed to

ensure that these indications were manufacturing related rather than flaws. In all, 101 steam

generator C hot-leg buff marks were inspected in RFOs 15 and 16. No tubes were plugged as

a result of these inspections.

Visual inspections were performed in all three steam generators during this outage. These

inspections included a detailed foreign object search and retrieval (FOSAR) inspection at the

top of the tubesheet. Although some collar scaling was found in all three steam generators, no

significant detrimental conditions were identified.

As of 1995, Robinson 2 had performed sludge lancing five times since the steam generator replacement, including the sludge lancing during the 1995 outage. Analysis of sludge samples showed a declining trend in the amount of copper in the sludge. Excessive copper deposits on

the outside diameter of the steam generator tubing can often mask defects, making eddy current detection more difficult. In 1986, copper levels ranged from 30% to 35%. In 1993,

copper levels ranged from 11 % to 15%. This downward trend in copper is attributed to the

replacement of the condenser and feedwater heater tubing (presumably with non-copper alloys), the use of full-flow condensate polishing, and the sludge lancing.

During RFO 17 in 1996, 100% of the tubes in steam generator A were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

to inspect the steam generator A hot-leg manufacturing buff marks not inspected during RFO

15 in 1993 (i.e., the remaining 80% of the population) and all new hot-leg buff marks identified

during RFO 17. The rotating pancake coil probe was also used to inspect hot-leg dented

intersections, the U-bend region of 20% of the row 1 and 2 tubes, and the hot-leg expansion transition region of 40% of the tubes in steam generator A. During this outage, one tube was

plugged as a result of a 38% throughwall indication believed to be caused by a loose part.

During RFO 18 in 1998, approximately 63% of the tubes in steam generator B and

approximately 50% of the tubes in steam generator C 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 50% of the hot-leg side manufacturing buff marks, 50% of

the dents greater than 2 volts in amplitude at tube supports, the hot-leg expansion transition

region of approximately 50% of the tubes, and the U-bend region of approximately 50% of the

row 1 and 2 tubes in steam generators B and C.

As a result of these inspections, no tubes were plugged; however, two tubes had signal

responses indicative of a loose part. Visual inspection in the vicinity of these tubes indicated a

piece of wire adhering to the two tubes. Attempts to retrieve the wire were unsuccessful. The

affected tubes did not exhibit any signs of degradation (i.e., there was a signal of a loose part but no wear signal associated with a loose part). Dents in the free span and at tube supports

were also reported during this outage. Most of these dents were attributed to initial

manufacture, but a few were attributed to transient loose parts based on their location, the

signals for the latter dents generally being lower in amplitude than for dents that are

manufacturing related.

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During RFO 19 in 1999, approximately 50% of the tubes in steam generator A 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 hot-leg expansion transition region of

approximately 60% of the tubes, approximately 20% of the hot-leg manufacturing buff marks,

dents, and benign indications (50 exams in 42 tubes), and the U-bend region of 100% of the

row 1 and 2 tubes. No tubes were plugged as a result of these inspections.

During the inspection, five tubes were considered to have imperfections due to manufacturing

irregularities at the tubesheet interface. In addition, three tubes contained indications detected

with the low-frequency channel indicating the presence of a loose part. No degradation was

associated with the loose part.

The licensee identified 54 indications in 34 tubes with the plus-point coil. These indications

were located in the periphery of the tube bundle on both the hot- and the cold-leg sides of the

steam generator. These indications were small in volume and were dispositioned as being the

result of either maintenance equipment contact or transient loose parts. The indications were

sized with a site-qualified sizing technique and left in service. The indications were attributed to

maintenance equipment contact based on the location/height of the indications, the eddy

current response, the limited number of loose parts observed, video tapes with evidence of

wear marks on the secondary side of tubes, and the absence of wear growth for a few

previously identified indications.

In addition to these tubes, one tube in the cold-leg was reported as having no tube expansion in

the tubesheet, and one tube was reported as having a slight overexpansion at the tubesheet

interface. The unexpanded tube was left in service since the portion of the tube within the

tubesheet did not exhibit any degradation during a full-length inspection with a rotating probe

and since the tube end weld is the pressure boundary and no credit was taken for the

expansion of the tube within the tubesheet. The overexpanded tube was also left in service.

During RFO 20 in 2001, approximately 50% of the tubes in steam generators B and C 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% of the hot-leg manufacturing buff

marks, 20% of the dents, the U-bend region of 50% of the row 1 and 2 tubes, and the hot-leg

expansion transition region of 50% of the tubes in steam generators B and C. There was no

primary-to-secondary leakage at the time RFO 20 was entered.

As a result of these inspections, four tubes were plugged. One of these tubes was plugged

because a dent, present since steam generator fabrication, prevented an examination by a

qualified bobbin probe and the use of a rotating probe resulted in poor-quality data. -A second

tube was plugged for a 43% throughwall wear indication at the hot-leg flow distribution baffle.

The wear was attributed to a transient loose part. This tube is located in the periphery of the

tube bundle and no indication was present during the previous inspection of this tube in 1998.

A third tube was plugged for wear near the top of the hot-leg tubesheet. This tube also had a

wear indication (approximately 32% throughwall) attributed to a transient loose part. Ultrasonic

testing performed on this tube led the licensee to attribute the indication to wear. This tube is

not in the periphery of the tube bundle. A fourth tube was plugged for an obstruction in the tube

above the sixth hot-leg tube support plate. This tube would not permit the passage of a

0.650-inch diameter rotating probe, but did permit the passage of a 3/8-inch poly shaft. The

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obstruction was attributed to foreign material lodged in the tube, although visual examinations

were not performed to confirm this. The obstruction is not located near a tube support (i.e., it is

midspan). This tube was previously examined during RFOs 15 and 16 with no obstruction

noted (i.e., a 0.720-inch probe passed through the tube).

Secondary side visual inspections have been performed at Robinson 2. This inspection

involves inspection of the tube support plates up through the flow slots to the bottom of the top

tube support plate. No upper bundle fouling or corrosion product buildup in the tube support

plate areas was identified. Minor deposition was observed in the land area of the quatrefoil

support with no bridging of the deposits between the lands.

The licensee refers to a number of tubes as "wrapper MOD tubes." These tubes were

damaged during a wrapper modification in which a small piece of the wrapper was cut out at the

handhole to allow access for in-bundle lancing. The vendor inadvertently scratched a number

of tubes while cutting out the wrapper. The licensee identified the scratches and used a

rotating probe equipped with a plus-point coil to examine each affected tube in the area of

concern.

During the first 10 years of operation of the replacement steam generators, a sample of tubes

was inspected in all three steam generators during each outage at Robinson 2. In subsequent

years, a subset of steam generators was inspected each outage, with one steam generator

being examined one outage and the other two steam generators being examined the following

outage.

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 Unit 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 (refer to Figure 2-8).

During RFO 13 in 1999, the first inservice inspection of the replacement steam generators,

100% 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 U-bend region of 20% of the row 1 and 2 tubes in steam generators A

and C (100 tubes in all), the hot-leg expansion transition region of 20% of the tubes in steam

generators A and C, and 20% of the dents at the tube support plates with magnitudes greater

than 5 volts and 20% of freespan dings with magnitudes greater than 5 volts up to 2 inches

above hot-leg tube support 7H in each steam generator. In 2001, it was noted that one tube in

steam generator C had not been inspected with a bobbin probe because the tube locationwas

misencoded.

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Of the 10 tubes plugged during this outage, 8 were plugged for AVB wear and 2 were plugged

because they were not properly expanded into the tubesheet (i.e., the tube was not

hydraulically expanded the full depth of the tubesheet). Wear at the AVBs was observed in all

four steam generators, and the growth rates were within expectations for the first cycle of

operation of model F steam generators. The licensee indicated it expected the growth rates to

decrease during subsequent inspections. The maximum depth reported for the AVB wear

indications was 54% throughwall. For the two unexpanded tubes, the licensee performed an

evaluation demonstrating the design requirements were met for all analyzed conditions. During

this outage, one loose part was identified in steam generator D. The part did not cause wear

on any of the tubes and attempts to remove it were unsuccessful.

During RFO 14 in 2001, 100% 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 U-bend region of 100% of the row 1 and

2 tubes in each steam generator, the hot-leg expansion transition region of 50% of the tubes in

steam generators B and D, and 100% of the dents at the hot-leg tube support plates with

magnitudes greater than or equal to 5 volts and 100% of hot-leg freespan dings with

magnitudes greater than 5 volts in each steam generator.

As a result of these inspections, 35 tubes were plugged. Of the 35 tubes plugged during this

outage, 29 were plugged as a result of wear at the AVBs, 2 were plugged for loose part

indications, and 4 were plugged for unacceptable data quality. The maximum depth reported

for the AVB wear indications was 64% throughwall. The two loose part indications were

detected in the U-bend region near the seventh cold-leg tube support. One of these indications

was in a row 1 tube of steam generator A and one was in a row 2 tube in steam generator B.

The indication in the row 1 tube was above the seventh cold-leg tube support and was aligned

with one of the tube support contact points (i.e., one of the four tube support lands). The

indication in the row 2 tube was below the seventh cold-leg tube support and was between two

of the tube support contact points. Of the four tubes plugged for unacceptable data quality, one

was plugged due to a permeability variation, two were plugged because they would not permit

the passage of a 0.520-inch diameter plus-point probe (although they were inspected with a

bobbin coil), and one was plugged because the 0.520-inch diameter plus-point probe skipped or

stalled in the U-bend region.

A visual inspection of installed steam generator tube plugs was performed to verify that the

plugs were installed in the proper location and to identify signs of leakage. No anomalies were

noted during this inspection.

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

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 51 F steam generators. These steam generators were

installed at the plant in 1981. The tube supports are numbered as shown in Figure 2-12.

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During the first refueling outage following replacement (RFO 1) in 1983, approximately 9% of

the tubes in steam generator B and approximately 11 % of the tubes in steam generator C were

inspected with a bobbin coil from the hot-leg tube end through the top tube support on the

cold-leg side (i.e., 7C). No tubes were plugged as a result of these inspections.

During RFO 2 (i.e., the second refueling outage following replacement) in 1984, approximately

26% of the tubes in steam generator A and approximately 17% of the tubes in steam generator

B were inspected full-length with a bobbin coil. In addition to these full length inspections,

approximately 6% of the tubes in steam generator A and approximately 4% of the tubes in

steam generator B were inspected with a bobbin coil from the hot-leg tube-end to the

uppermost cold-leg tube support (i.e., 7C).

Three of the four tubes plugged during RFO 2 were plugged for indications at (or near) the

hot-leg tube support plates and one was plugged for an indication at (or near) the hot-leg

tubesheet. The depths for the defects in these tubes were estimated at the time to be 44%,

60%, 89%, and 96% throughwall, respectively. No additional details were provided.

During RFO 3 in 1986, approximately 86% of the tubes in steam generator A, approximately

46% of the tubes in steam generator B, and approximately 86% of the tubes in steam generator

C were inspected full length with a bobbin coil. In addition to these full-length inspections, the

remaining 14% of the tubes in steam generator A, 2% of the tubes in steam generator B, and

the remaining 14% of the tubes in steam generator C were inspected with a bobbin coil,

primarily from the hot-leg tube-end to the uppermost cold-leg tube support (i.e., 7C).

Of the four tubes plugged during this outage, one tube was plugged as a result of multiple

indications between hot-leg tube supports 2H and 4H, one tube was plugged for an indication at

cold-leg tube support 2C, one tube (i.e., row 2 column 7) was plugged for a restriction, and one

tube location was plugged because the tube was removed to destructively examine an

indication at (or near) hot-leg tube support 7H.

During RFO 4 in 1988, approximately 24% of the tubes in steam generators B and C were

inspected full length with a bobbin coil. In addition to these full-length inspections,

approximately 3% of the tubes in steam generators B and C were inspected with a bobbin coil

from the hot-leg tube-end to the uppermost cold-leg tube support (i.e., 7C).

No tubes were plugged as a result of these inspections. From the results of the 1986 tube pull,

the licensee concluded that many of the distorted indications or undefined signals in steam

generator tubes were insignificant indications (either less than 20% throughwall or not relevant).

These indications were recorded for future tracking and trending purposes.

During RFO 5 in 1990, approximately 4% of the tubes in steam generator A, approximately 26%

of the tubes in steam generator B, and approximately 37% of the tubes in steam generator C

were inspected full length with a bobbin coil. In addition to these full-length inspections,

approximately 2% of the tubes in steam generator A, approximately 1% of the tubes in steam

generator B, and approximately 2% of the tubes in steam generator C were partially inspected

along various lengths of the tube with the bobbin coil. These partial-length exams were

primarily on the hot-leg side of the steam generator. In addition to the bobbin coil inspections, a

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rotating pancake coil probe was used to inspect the hot-leg expansion transition region of 100%

of the tubes in each of the three steam generators.

As a result of these inspections, portions of two tubes were pulled for destructive examination

and the tube locations were plugged. The tubes were pulled to examine axial and

circumferential anomalies at the top of the tubesheet. The examination found no operationally

induced degradation of the tube wall.

During RFO 6 in 1992, approximately 35% of the tubes in steam generators A and B were

inspected full length with a bobbin coil. One of the two tubes plugged during this outage was

plugged for a dent and an associated indication at hot-leg tube support 4H and the other tube

was plugged as a result of wear at the AVBs. The maximum depth reported for the AVB wear

indications was 35% throughwall.

During RFO 7 in 1994, approximately 100% of the tubes in steam generator B were inspected

full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil

probe was used to inspect the hot-leg expansion transition region of approximately 9% of the

tubes in steam generator B. Of the four tubes plugged during the outage, all were plugged as a

result of wear at the AVBs. The maximum depth reported for the AVB wear indications was

24% throughwall.

During RFO 8 in 1995, 100% of the tubes in steam generator C were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

to inspect the hot-leg expansion transition region of 9% of the tubes in steam generator C. As

a result of these inspections, one tube was plugged for wear at the AVBs. The maximum depth

reported for the AVB wear indications was 29% throughwall.

During RFO 9 in 1997, 100% of the tubes in steam generator A were inspected full length with

the bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was

used to inspect the hot-leg expansion transition region of approximately 22% of the tubes in

steam generator A.

Of the five tubes plugged during this outage, three were plugged because tube restrictions

prevented the bobbin probe from passing through the tube, one was plugged due to wear at the

AVBs, and one was plugged for a permeability signal. The restricted tubes were all in row 1

and would not allow the passage of a probe through the cold-leg tube end. The tube with a

permeability signal was considered unsuitable for inspection. The maximum depth reported for

the AVB wear indications was 25% throughwall.

During RFO 10 in 1998, 100% of the tubes in steam generator B were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

to inspect the hot-leg expansion transition region of approximately 20% of the tubes and the

U-bend region of 20% (19) of the row 1 tubes in steam generator B. Ultrasonic testing (UT)

was performed on five tubes to characterize anomalous signals.

Of the six tubes plugged during the outage, three tubes in row 1 were plugged because

restrictions at the hot-leg tubesheet prevented a complete inspection, and three tubes were

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plugged for indications at the hot-leg side baffle plate attributed to a foreign object. These latter

indications were inspected with a rotating probe and characterized as volumetric indications.

During RFO 11 in 2000, approximately 100% of the tubes in steam generator C were inspected

full length with a bobbin coil. In addition to the bobbin coil Inspections, a rotating probe was

used to inspect the hot-leg expansion transition region of approximately 20% of the tubes and

the U-bend region of 100% of the row 1 tubes (94 tubes) in steam generator C.

Of the eight tubes plugged during this outage, seven were plugged as a result of wear at the

AVBs and one was plugged for a volumetric indication between AVB 2 and AVB 3. Inspection

of this latter tube with a rotating probe indicated that the indication was on one side of the tube

("one-sided wear"). The AVBs are V-shaped bars which extend into the bundle to row 8 and

row 11. The wear indication on this latter tube (in row 11 column 38) appeared to correspond to

the bottom of the AVB (i.e., the V section) rather than to the leg of the AVB. There was no

indication at this location in 1995, the last time this tube was inspected. The maximum depth

reported for the AVB wear indications was 33% throughwall. The average growth rate per cycle

for AVB wear indications since the last inspection of steam generator C was 4.1% and the

maximum growth rate per cycle was 8.0%. These growth rates were twice the rates observed

following prior inspections.

During this outage, several dents at the sixth and seventh tube supports were detected. Of the

46 dents reported at the sixth tube support plate, 17 were greater than 5 volts and did not

appear in previous inspection data and were therefore inspected with a rotating probe equipped

with a plus-point coil. The plus-point coil confirmed that the bobbin coil indications were

low-level dents corresponding to the edge of the tube support plate. No cracklike or other

forms of tube degradation were noted. Some locations had multiple dent indications

corresponding to the quatrefoil lands.

During RFO 12 in 2001, 100% of the tubes in steam generator A 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 hot-leg expansion transition region of approximately 20%

of the tubes and the U-bend region of 100% of the row 1 tubes in steam generator A.

Of the five tubes plugged during this outage, one tube was plugged as a result of wear at the

AVBs, one tube (in row 10 column 44) was plugged as a result of a wear indication that was

attributed to the tip (i.e., the V section) of the AVB contacting the tube, and three tubes were

plugged as a result of wear indications caused by sludge lancing equipment used during

RFO 11 in 2000. Attempts to characterize the indication in the tube at row 10 column 44

associated with the wear indication at the tip of the AVB were unsuccessful because the

0.680-inch rotating probe equipped with a plus-point coil could not pass through either the

hot-leg or the cold-leg tangent point of the U-bend. The maximum depth reported for the AVB

wear indications was 30% throughwall. The average growth rate per cycle for AVB wear

indications since the last inspection of steam generator A was 1.5% and the maximum growth

rate per cycle was 5.3%. These growth rates were consistent with prior performance of this

steam generator.

During this outage, approximately 40 tubes were identified with dent indications at the sixth and

seventh tube supports. The licensee stated these dent indications appeared to be concentrated

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in the periphery of the tube bundle near the wedge regions and were at (or near) the edges of

the support plate. Altogether 507 tubes with dent indications (located throughout the tube

bundle) were recorded this outage. Most of these dents were less than 5 volts.

During the preceding cycle, there was a small (0.5 gpd) primary-to-secondary leak in steam

generator B.

At the completion of RFO 12 in 2001, the replacement steam generators at Surry 1 had

operated for approximately 15.5 EFPYs. Only 43 tubes had been plugged as of this outage.

Approximately 15 were plugged for wear at the AVBs, 2 for wear associated with the tip of the

AVB, 7 for restrictions, 3 for loose parts, 8 for manufacturing flaws or mechanical damage

during maintenance, 1 for data quality, and 7 for other reasons.

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

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 51 F steam generators. These steam generators were

installed at the plant in 1980. The tube supports are numbered as shown in Figure 2-12.

During the first refueling outage following replacement (RFO 1) in 1981, the tubes in steam

generators A and B were inspected. No tubes were plugged as a result of these inspections.

During RFO 2 (the second refueling outage following replacement) in 1983, approximately 1%

of the tubes in steam generator A were inspected full length with a bobbin coil. In addition to

these full-length inspections, approximately 20% of the tubes in steam generator A and

approximately 17% of the tubes in steam generator C were inspected with a bobbin coil from

the hot-leg tube-end to the uppermost cold-leg tube support (i.e., 7C). No tubes were plugged

as a result of these inspections.

During RFO 3 in 1985, approximately 16% of the tubes in steam generators A and B were

inspected full length with a bobbin coil. In addition to these full-length inspections,

approximately 6% of the tubes in steam generator A and approximately 5% of the tubes in

steam generator B were inspected with a bobbin coil from the hot-leg tube-end to the

uppermost cold-leg tube support (i.e., 7C). No tubes were plugged as a result of these

inspections.

In June 1986, Surry 2 was shut down, in part because of a primary-to-secondary leak in steam

generator A. A pressure test revealed a leak on the cold-leg side of a tube in the periphery

(row 41 column 28). A video inspection in the region between the tubes and the steam

generator wrapper revealed several loose objects lying on the tubesheet and against or

between adjacent tubes in the vicinity of the leaking tube. The loose object was identified as a

grinding burr and was removed. Altogether 23 tubes were inspected during this outage. In

addition to the leaking tube, eddy current signals were observed in two neighboring tubes, and

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an eddy current signal suggesting the presence of a loose object was observed in another tube.

All the signals were attributed to the grinding burr. Only the leaking tube was plugged.

During RFO 4 in 1986, approximately 18% of the tubes in steam generator B and approximately

17% of the tubes in steam generator C were inspected full length with a bobbin coil. In addition

to these full-length inspections, approximately 4% of the tubes in steam generators B and C

were inspected with a bobbin coil from the hot-leg tube-end to the uppermost cold-leg tube

support (i.e., 7C). No tubes were plugged as a result of these inspections.

During RFO 5 in 1988, approximately 24% of the tubes in steam generator A and approximately

23% of the tubes in steam generator C were inspected full length with a bobbin coil. In addition

to these full length inspections, approximately 3% of the tubes in steam generators A and C

were inspected from the hot-leg tube-end to either cold-leg tube support 6C or 7C. No tubes

were plugged as a result of these inspections.

In 1989, no steam generator tube inspections were performed at Surry Unit 2. However, the

plugs in one tube in steam generator A were removed and replaced as a result of industry

experience with mechanical tube plug failures. During this replugging operation, an adjacent

tube (in row 41 column 27) was inadvertently plugged on the hot-leg side only. This plug was

subsequently removed during RFO 6 in 1991.

During RFO 6 in 1991, approximately 35% of the tubes in steam generators A and C were

inspected full length with a bobbin coil. No tubes were plugged as a result of these inspections.

As discussed above, the plug installed in 1989 in the hot leg of the tube in row 41 column 27 in

1989 was removed. The tube was subsequently inspected and returned to service.

During RFO 7 in 1993, 100% of the tubes in steam generator B were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

to inspect the hot-leg expansion transition region of approximately 9% of the tubes in steam

generator B. As a result of these inspections, two tubes were plugged for wear at the AVBs.

The maximum depth reported for the AVB wear indications was 20% throughwall.

During RFO 8 in 1995, 100% of the tubes in steam generator A were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

to inspect the hot-leg expansion transition region of approximately 9% of the tubes in steam

generator A.

Four of the five tubes plugged during this outage were plugged for axially oriented indications at

the top of tubesheet on the cold-leg side and the fifth tube was plugged for a restriction at the

tubesheet on the hot-leg side. The axially oriented indications were attributed to pitting.

During RFO 9 in 1996, 100% of the tubes in steam generator C were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

to inspect the hot-leg expansion transition region of approximately 20% of the tubes in steam

generator C.

Of the eight tubes plugged during this outage, three tubes were plugged as a result of wear at

the AVBs, two tubes were plugged for single axial anomalies in the hot leg at the top of the

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tubesheet, two row 1 tubes were plugged for restrictions (one at the hot-leg tube end and the

other at the cold-leg tube end), and one tube was plugged for a multiple axial anomaly and

distorted roll indication at the top of the tubesheet on the hot-leg side. The maximum depth

reported for the AVB wear indications was 42% throughwall.

During RFO 10 in 1997, approximately 100% of the tubes in steam generator B were inspected

full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil

probe was used to inspect the hot-leg expansion transition region of approximately 20% of the

tubes and the U-bend region of approximately 20 row 1 tubes in steam generator B.

Five tubes were plugged during this outage. Two row 1 tubes were plugged because they did

not allow passage of a 0.720-inch diameter probe (although they did allow passage of a

0.680-inch diameter probe), and three tubes were plugged as a result of wear at the AVBs.

The maximum depth reported for the AVB wear indications was 25% throughwall.

During RFO 11 in 1999, 100% of the tubes in steam generator A were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

to inspect the hot-leg expansion transition region of approximately 20% of the tubes and the

U-bend region of approximately 20% (19) of the row 1 tubes in steam generator A.

Eight of the nine tubes plugged during this outage were plugged for pitlike indications near the

top of the tubesheet on the cold-leg side and one row 1 tube was plugged because it would not

allow passage of a 0.720-inch diameter probe (although it did allow passage of a 0.680-inch

diameter probe). One of the eight tubes plugged for pitlike indications was in steam generator

C. The pitlike indication in this tube was reported to be 26% throughwall in 1995/1996.

Prior to this outage the licensee had been tracking six cold-leg pit indications above the

tubesheet secondary face in four tubes in the Surry 2 steam generators. Copper deposits,

which are a potential contributor to the development of steam generator tube pits in Alloy 600

material, were present on the tubing prior to chemical cleaning in 1994, and the pitting is

believed to have initiated prior to the chemical cleaning. During the 1999 outage, the licensee

inspected all but one of these tubes by UT and removed all four tubes from service because of

concerns with nondestructive examination sizing uncertainty. The results of the inspections

supported the licensee's conclusion that the indications were volumetric corrosion-induced

degradation. However, no tubes have been removed to confirm pitting as the degradation

mechanism.

Over the last few outages, a number of tubes had been plugged due to restrictions in the row 1

tubes. The concern with the "dinged" row 1 tubes was considered closed as a result of this

inspection because all steam generators had been inspected since the phenomenon was

judged to have begun. All identified tubes exhibiting this phenomenon have been removed

from service. The nature of the dings on the row 1 tubes was not described; however, they are

believed to have been made by maintenance equipment used during outages.

The maximum growth rate per cycle for AVB wear indications in steam generator A was 3.7%.

During RFO 12 in 2000, 100% of the tubes in steam generator C were inspected full length with

a bobbin coil. In addition to the bobbin coil inspections, a rotating pancake coil probe was used

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to inspect the hot-leg expansion transition region of approximately 20% of the tubes and a

rotating probe equipped with a plus-point coil was used to inspect the U-bend region of 100% of

the row 1 tubes (92 tubes) in steam generator C.

All seven tubes plugged during this outage were plugged as a result of wear at the AVBs. The

maximum depth reported for the AVB wear indications was 43% throughwall. The average

growth rate per cycle for AVB wear indications since the last inspection of steam generator C

was 3.8% and the maximum growth rate per cycle was 7.0%. These growth rates are

approximately twice the rates documented from prior inspections although they are similar to

the rates seen in steam generator C of Surry 1.

During this outage, several dents were detected at the sixth and seventh tube support. These

dent signals appear to be associated with contact between the tubes and the quatrefoil land,

not with contact between the tube and corrosion products (as was observed at plants with

carbon steel tube support plates). Altogether 251 dented locations were identified with voltages

greater than or equal to 2.0 volts. The number of reported dent indications increased during this inspection as a result of lowering the reporting threshold for dents from 5 volts to 2 volts.

The inspection guidelines at Surry 2 require dents greater than or equal to 5 volts to be

inspected with a rotating probe unless a review of historical data confirms that the signal

voltage and phase attributes are essentially unchanged from previous inspections. A total of 74

dent locations (28 hot-leg and 46 cold-leg) had to be inspected with the rotating probe. These

inspections confirmed the dent signals and most of the signals corresponded to the edge of the

tube support plate and were in line with the quatrefoil lands. No crack-like or other forms of

tube degradation were noted at any of the dent locations. Some support plate locations had

two or more dents that corresponded with the quatrefoil lands.

At the completion of RFO 12 in 2000, the replacement steam generators at Surry 2 had

operated for approximately 15.2 EFPYs. Only 39 tubes had been plugged as of this outage, 15

for wear at the AVBs, 12 for pitlake indications, 1 for a foreign object, 6 for restrictions, 3 for

anomalous indications at the top of hot-leg tubesheet, and 2 for manufacturing flaws.

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 2-10. 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, overexpanison 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

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susceptible to cracking than nonoverexpanded areas. Based on accident analysis

considerations, a maximum of 20% of the tubes in the three steam generators can be plugged.

During RFO 8 in 1983, the first refueling outage following replacement, approximately 10% of

the tubes were inspected (the actual numbers of tubes and steam generators inspected were

not readily available). No tubes were plugged as a result of these inspections.

During RFO 9 in 1985, approximately 8.6% of the tubes in steam generator A, approximately

13.1% of the tubes in steam generator B, and approximately 6.2% of the tubes in steam

generator C were inspected full length with a bobbin coil. Of the four tubes plugged during this

outage, one exceeded the plant technical specification plugging criterion and the other three

were plugged as a preventive measure. Three of the indications were near the top of the

hot-leg tubesheet and the other indication was at tube support 4H. The maximum depth

reported for these indications was 56% throughwall.

During RFO 10 in 1987, approximately 10.1% of the tubes in steam generator A, approximately

10.3% of the tubes in steam generator B, and approximately 11.6% of the tubes in steam

generator C were inspected full length with a bobbin coil. One tube was plugged during this

outage as a result of a 48% throughwall indication in the cold-leg sludge pile. The nature of this

indication was not provided. In addition, two stub tubes (i.e., non-full-length tubes) with shop

plugs in steam generator C were plugged. Stub tubes are not considered tube locations.

During RFO 11 in 1990, 100% of the tubes in each of the steam generators were inspected full

length with a bobbin coil. Of the 11 tubes plugged during this outage, 7 were plugged as a

result of wear at the AVBs, 2 were plugged for indications near the top of the tubesheet (1

above the hot-leg tubesheet, 1 above the cold-leg tubesheet), and 2 were plugged for

indications at the tube support plates. The nature of these four indications was not provided.

The maximum depth reported for the AVB wear indications was 39% throughwall. In addition,

four stub tubes with shop plugs, two in steam generator A and two in steam generator B were

plugged.

During RFO 12 in 1992, 100% of the tubes in each of the three steam generators were

inspected full length with a bobbin coil. Of the seven tubes plugged during this outage, three

were plugged as a result of wear at the AVBs, one was plugged for an indication above hot-leg

tube support 6H (the uppermost tube support), one was plugged for an indication above

cold-leg tube support 2C, one was plugged for an indication above the cold-leg tubesheet, and

one was plugged for an indication above cold-leg tube support 6C (the uppermost tube

support). The maximum depth reported for the AVB wear indications was 35% throughwall.

During this outage, the secondary side of each of the three steam generators was visually

inspected. Debris was found inside steam generator B, and the areas with debris were

cleaned. No other reportable indications were found during the secondary side inspections.

During RFO 13 in 1994, 100% of the tubes in each of the three steam generators were

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating

pancake coil probe was used to inspect the hot-leg expansion transition region of the

overexpanded tubes in two of the three steam generators and approximately 2% of the dents

on the hot-leg side in one steam generator. Of the four tubes plugged during this outage, three

were plugged as a result of wear at the AVBs, and one was plugged for an indication at (or

-81-
near) hot-leg tube support 1 H. The maximum depth reported for the AVB wear indications was

41% throughwall. In addition, one tube was replugged because the original welded plug was

leaking.

During RFO 14 in 1995, 100% of the tubes in each of the three steam generators were

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating

pancake coil probe was used to inspect the hot-leg expansion transition region of 100% of the

overexpanded tubes (approximately 300 tubes) and 20% of the dented tube support

intersections in one steam generator. One of the two tubes plugged during this outage was

plugged as a result of wear at the AVBs and the other as a result of an indication slightly above

the top of tubesheet on the hot-leg side of the steam generator. The maximum depth reported

for the AVB wear indications was 42% throughwall.

During RFO 15 in 1997, 100% of the tubes in each of the three 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 hot-leg expansion transition region of 100% of the overexpanded

tubes (approximately 300 tubes) in steam generators A and B, the U-bend region of 20% of the

row 1 tubes, 20% of the dented tube support intersections in steam generator A, and 10% of

the dented tube support intersections in steam generator B.

Of the 14 tubes plugged during this outage, 8 were plugged for indications slightly above the

hot-leg top of tubesheet, 1 was plugged for an indication at (or near) hot-leg tube support 5H, 1

was plugged for an indication at (or near) hot-leg tube support 6H, 1 was plugged for an

indication at (or near) cold-leg tube support 3C, 2 were plugged because they were adjacent to

a foreign object, and 1 was plugged as a result of wear at the AVBs. The maximum depth

reported for the AVB wear indications was 37% throughwall.

During RFO 16 in 1998, 100% of the tubes in each of the three 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 hot-leg expansion transition

region of 20% of the overexpanded tubes in two of the three steam generators (approximately

68 tubes), the U-bend region of 20% of the row 1 tubes in two of the three steam generators,

and 20% of the dented tube support intersections in two of the three steam generators. This

was the first outage in which a plus-point coil was used. Previously, a three coil rotating probe

had been used. One tube was plugged during this outage as a result of wear at the AVBs. The

maximum depth reported for the AVB wear indications was 39% throughwall. During this

outage the licensee performed secondary side cleaning and inspections. These inspections

included a visual inspection of the feed ring and moisture separating equipment and ultrasonic

thickness measurements of the feed ring. No adverse findings were reported.

During RFO 17 in 2000, approximately 50% of the tubes in each of the three 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 hot-leg expansion

transition region of 100% of the tubes, the U-bend region of 20% of the row 1 and 2 tubes, and

20% of the hot-leg dents in each steam generator. This was the first outage in which extensive

rotating probe inspections were performed at the hot-leg expansion transition area. This

inspection was the 10"' inspection of the current steam generators, which at the start of RFO 17

had operated for approximately 12.2 effective full power years (EFPYs).

-82-
Of the 69 tubes plugged during this outage, 5 were plugged as a result of wear at the AVBs and

the remaining 64 were plugged for reasons given below. The maximum depth reported for the

AVB wear indications was 43% throughwall.

During the outage, 64 tubes were identified as having possible corrosion degradation or original

manufacturing indications. Both volumetric and circumferential indications were detected. All

41 volumetric indications initiated from the outside diameter of the tube. Of the 23

circumferential indications, 15 initiated from the inside diameter of the tube and 8 initiated from

the outside diameter of the tube. All of these indications were detected with the rotating probe.

Generally they were not detectable with the bobbin probe due to their proximity to tube

geometry changes at the top of the tubesheet. All of these indications were plugged and the

circumferential indications were stabilized.

During RFO 17 in 2000, the licensee conducted an investigation to determine the cause of the

indications detected at the hot-leg top of tubesheet. This investigation included a review of the

steam generator design features, manufacturing information, inspection techniques, and

historical and current chemistry programs. Due to the lack of prior rotating probe inspection

data and the limited number of defects identified in thermally treated Alloy 600 tubing, the

results were inconclusive for the circumferential and volumetric indications. The licensee

suggested two potential causes: (1) the indications were true indications generated by stress

corrosion cracking and intergranular attack, or (2) the indications were false positive indications

produced by manufacturing anomalies or deposits at the top of the tubesheet or introduced by

the inspection technique.

Based on the review of applicable industry experience and subsequent inspection data from

Turkey Point 4, the licensee reevaluated the circumferential and volumetric indications detected

at Unit 3 during RFO 17 in March 2000 was performed. After the Unit 3 March 2000 inspection,

an eddy current inspection of the Turkey Point 4 steam generators (which have the same

design as Turkey Point 3 steam generators) was performed in October 2000, and similar

indications were reported near the top of the tubesheet. Based on ultrasonic investigation of

several of these circumferential indications in Unit 4, the licensee concluded that the

circumferential indications detected in Unit 3 during RFO 17 in March 2000 were a result of

minor geometric variations associated with the tube-to-tubesheet joint fabrication process and

were not due to degradation. The licensee also determined that tubes removed from steam

generators of similar design contained similar minor geometric variations. These variations

resulted from the tube-to-tubesheet joint fabrication process and produced circumferential

indications such as those observed at Turkey Point 3 and 4.

The licensee also concluded that the volumetric indications reported during March 2000 were a

result of an overly conservative analysis of the inspection data. This conclusion was based on

a post-outage review by various industry experts, a reanalysis of the data, and the ultrasonic

examination of two similar volumetric indications in the Turkey Point 4 steam generators in

October 2000. The ultrasonic examination at Unit 4 showed that one indication was a result of

minor wall loss consistent with wear from a prior foreign object and the other indication was a

single pitlike indication (although it was sharper and more defined than pit indications examined

by ultrasonic techniques in another model F steam generator). On this basis, the licensee

concluded that the volumetric indications were not due to corrosion-induced degradation. This

-83-
conclusion was supported by the Unit 3 RFO 18 inspection (discussed below), in which no

additional circumferential, volumetric, or pitlike indications were detected.

As a result of this effort, the licensee concluded that of the 64 volumetric and circumferential

indications originally identified, only 26 tubes contained volumetric or pitlike indications (possibly

due to manufacturing and installation artifacts) and the remaining 38 tubes contained no

degradation (13 had circumferential geometric anomalies, 23 had dings or dents, and 2 had

manufacturing buff marks).

During RFO 18 in 2001, 100% of the tubes in each of the three 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 hot-leg expansion transition region of approximately 50% of the

tubes, the U-bend region of some of the row 1 and 2 tubes, and selected hot-leg dents in each

steam generator.

Of the 14 tubes plugged during this outage, 12 were plugged as a result of indications of

mechanical wear at the broached tube support plates, 1 was plugged as a result of wear at the

AVBs, and 1 was plugged because of a restriction in the U-bend region prevented an inspection

of the tube. The maximum depth reported for the AVB wear indications was 34% throughwall.

One of the 12 tubes plugged for mechanical wear at the tube support plates also had an

indication attributed to a loose part. One of the indications on this tube exceeded the technical

specification repair limit of 40% throughwall; however, the depth of the indication was not

provided. During this outage, the licensee examined the secondary side of steam generator A

for debris and damage. No reportable indications were identified. Additional visual inspections

of the inner bundle regions of the hot-leg tubesheet in steam generator C revealed several

small objects (small wires, scale deposits). The objects were inaccessible and could not be

retrieved.

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

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 2-10.

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, overexpanison 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 nonoverexpanded areas. Based on accident analysis

considerations, a maximum of 20% of the tubes in the three steam generators can be plugged.

-84-
According to steam generator fabrication records, nine tubes (one in one of the steam

generators and eight in another) were plugged in the steam generators before the preservice

inspection. Based on information submitted following the 1993 steam generator tube

inspections, 15 tubes in steam generator A, 7 tubes in steam generator B, and 9 tubes in steam

generator C were plugged before the steam generators were placed in service.

During RFO 9 in 1984, the first refueling outage following replacement, the licensee inspected

approximately 6.5% of the tubes in steam generator A, approximately 5.0% of the tubes in

steam generator B, and approximately 15.6% of the tubes in steam generator C. The

inspections in steam generator C included some partial-length examinations of bulged regions

at the top of the tubesheet. No additional details on these bulged regions were provided. No

tubes were plugged as a result of these inspections.

During RFO 10 in 1986, approximately 10.2% of the tubes in steam generator A, approximately

9.9% of the tubes in steam generator B, and approximately 10.7% of the tubes in steam

generator C were inspected. Presumably these were full-length inspections performed with a

bobbin coil. No tubes were plugged as a result of these inspections.

During RFO 11 in 1988, 100% of the tubes in each of the three steam generators were

inspected full length with a bobbin coil. One tube was plugged as a result of these inspections.

The tube was plugged because a piece of a hose clamp was caught inside the portion of the

tube expanded into the hot-leg tubesheet. Attempts to remove the clamp were unsuccessful.

During RFO 12 in 1991, 100% of the tubes in each of the three steam generators were

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating

pancake coil probe was used to inspect the hot-leg expansion transition region of 74% of the

tubes that were overexpanded above the top of the tubesheet in one steam generator. One

tube was plugged during this outage. The tube was plugged due to a restriction approximately

2 inches below the secondary face of the hot-leg tubesheet. This tube was inspected with a

0.720-inch diameter probe during the preservice inspection and a 0.650-inch diameter probe in

1988, and permitted the passage of a 0.5-inch diameter wand during this outage. A

Welch-Allyn video probe inspection showed that no foreign object was present in the tube and

revealed minor irregularities of the inside surface.

During RFO 13 in 1993, 100% of the tubes in each of the three steam generators were

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating

pancake coil probe was used to inspect the hot-leg expansion transition region of 85% of the

tubes that were overexpanded above the top of the tubesheet in one steam generator. No

tubes were plugged as a result of these inspections. During this outage, the secondary side of

all three steam generators was visually inspected with no reportable indications noted.

During RFO 14 in 1994, 100% of the tubes in each of the three steam generators were

inspected full length with a bobbin coil. In addition to the bobbin coil inspections, a rotating

pancake coil probe was used to inspect the hot-leg expansion transition region of 85% of the

tubes that were overexpanded above the top of the tubesheet in one steam generator and 54%

of the hot-leg dents in one steam generator. No tubes were plugged as a result of these

inspections.

-85-
During RFO 15 in 1996, no steam generator tube inspections were performed.

During RFO 16 in 1997, 100% of the tubes in each of the three 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 hot-leg expansion transition region of 20% of the tubes that were

overexpanded above the top of the tubesheet, the U-bend region of 20% of the row 1 tubes,

and 20% of the hot-leg dents in two of the steam generators. No tubes were plugged as a

result of these inspections.

During RFO 17 in 1999, no steam generator tube inspections were performed.

During RFO 18 in 2000, approximately 50% of the tubes in each of the three 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 hot-leg expansion

transition region of 100% of the tubes, the U-bend region of 20% of the row 1 and 2 tubes, and

20% of the hot-leg dented locations in each of the three steam generators. This was the first

large-scale inspection of the hot-leg top of tubesheet region with a rotating probe at Turkey

Point 4. Of the 10 tubes plugged during this outage, 1 tube was plugged as a result of wear at

the AVBs, 1 tube was plugged for wear at the hot-leg baffle plate, 1 tube was plugged for a

permeability signal at the hot-leg expansion transition region, and 7 tubes were plugged as a

result of possible corrosion degradation. These latter tubes had volumetric and pitlike eddy

current indications. The maximum depth reported for the AVB wear indications was 36%

throughwall.

-86-
Table 3-1: Braldwood 2: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SGA -SG B I SG C SG D Total Total Cumul. Percent Outage Date EFPY Insp. Plug DePt Insp. Plug DePI Insp. lug DePI nsp. lug DePI Plug DePI Plugged Plugged Notes

eop_12 1 _ 0 3 ____6 0 6 0 03 __

RFO1 04/26/90 1.162 4569 0 = 4568 0 4570 2 _ 4567 0 2 0 8 0 04

RFO2 11/11/91 2 288 2285 4 _ 2284 0 2284 7 2284 0 11 0 19 0.10 1

RFO3 04/13/93 3 405 2440 6 2374 1 1 2370 8 2430 1 16 1 34 0.19 1

RFO4 10/25/94 4.566 _ 4568 0 4553 6 6 0 40 0 22

RFO5 04/12/96 5 838 4559 17 4568 2 4547 4 = 4566 1 2 35 0 75 0.41

RFO 6 10/20/97 4542 7 4566 3 4543 12 4554 61 28 0 103 0 56

RFO 7 05/05/99 4535 0 4563 1 4531 4 4548 1 6 0 109 0 60

RFO8 10/28/00 4535 8 4562 1 4527 1 4547 1 1 0 120 0 66 2

Totals: 43 0 10 1 44 0 24 0 121 1

Plant Data Acronyms

Model: D5 Pre-op = pnor to operation

T-hot (approximate) Cumul. . cumulative

Tubes per steam generator. 4570 Insp. = number of tubes Inspected Number of steam generators: 4 Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refueling outage Notes

1. All tubes in each steam generator were examined through the U-bend

2. Cycle 8 expected to be 1.425EFPY. -

-87-
Table 3-2: Braidwood 2 Causes of Tube Plugging

Year 1990 1991 1993 1994 1996 1997 1999 2000

Cause of Tube Plugging/Outage P RFO 1 RFO 2 RFO3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8

AVB 2 11 16 6 29 12 6 10

Wear Pre-heater TSP (D5) _

TSP ___

Confirmed 2

Not confirmed,

Loose Parts periphery

Not confirmed, not

penpherv _

Obstruction From PSI, no

Restriction proaression Service-induced 1

Manufacturing Preservice 6 -1

Flaws Other 15

Probe lodged .... ....

Inspection Data quality

Issues Dent/aeometry Permeability 1

Not inspected

To of tubesheet I____

Free span __ T 1 1

Other TSP 2

Other/not reported

TOTALS| 61 2 11| 15| 61 351 281 61 11

j Notes: I I I | I I I | 2 | | |

Totals

92

0

0

2

0

0

Totals

92

2

0 0

20

20

_1

0

0

os 1

01

1 120 1 2

Notes

1. One tube deplugged during RFO 3 Assumed it was a tube plugged prior to commercial operation.

2. Fifteen tubes plugged with circumferential indications at hot-leg top of tubesheet reclassified as manufacturing anomalies based on tube pulls from Byron 2.

-88-
Table 3-3: Braidwood 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location F Characterization Stabilized

31-53 1H 5 Volumetnc

STEAM GENERATOR B

Tube Location RFO Characterization Stabilized

1-45 U-bend 8 Permeability

48-29 FS (2C) 6 Volumetnc

STEAM GENERATOR Cj jTube Location # CharactenizationStblzd TE M G N R ORRFO 

STEAM GENERATOR D

Tube Location RFO# Charactenzation Stabilized'

1-11 U-bend 5 Single axial indication

30-48 1 H 5 Volumetnc

36-60 TSH 5 Volumetnc

43-72 8H 5 Confirmed Loose Part (CLP) (part could not be retneved)

43-73 8H 5 CLP (part could not be retneved)

'An empty cell Indicates that it was not reported wnetner me Moe was araDuIUie or MI

-89-
Table 3-4: Byron 2: Summary of Bobbin Inspections and Tube Plugging

Outage 

Completion Cumul. SG A SG B _SG C S GDI Total Total Cumul. Percent Date EFPY Insp. Plug IePI Insp. P ugDePI insp. Plug DePI Insp. Plug DePI Plug DePI Pluqged Plugged Notes Pro-op_ 4 2 4 1 11 0 11 0 06 RFO 

RFO 2 

1 01/01/89 

09/01/90 2278 

2270 

2 2277 6 _ 2279 3 2284 0 11 0 22 0 12 1 1 2268 17 2272 1 2273 2 21 0 43 0 24 1

RFO 3 03/01/92 2252 9 2215 9 2235 5 = 2223 6 29 0 72 0 39 1 RFO 4 10/02/93 2259 6 2239 23 2260 7 2264 0 36 0 108 0 59 1 RFO5 03/01/95 2398 9 _ 2386 8 2456 7 2448 5 _ 29 0 137 075 1 RFO 6 09/01/96 4539 11 _ 4505 10 4543 6 4556 3 30 0 167 0 91 2 RFO 7 05/05/98 4528 7 1 4495 26 4537 5 4553 0 38 0 205 1.12 RFO 8 11/04/99 4521 1 4469 8 4532 3 4553 2 14 0 219 1 20 3 RFO9 04/13/01 4461 4 4 0 223 1 22 4

Totals: 50 0 113 0 41 0 19 0 223 0

Plant Data Acronyms Model: D5 Pre-op = prior to operation T-hot (approximate): Cumul. = cumulative

Tubes per steam generator: 4570 Insp. = number of tubes inspected Number of steam generators: 4 Plug = number of tubes plugged

DePI = 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. Cycle 8 expected to be 1.412 EFPY.

4. Cycle 9 expected to be 1.4 EFPY.

-90-
Table 3-5: Byron 2 Causes of Tube Plugging

Year 1989 1990 1992 1993 1995 1996 1998 1999 2001

Cause of Tube Plugging/Outage Pre-Op RFO 1 RFO 2 RFO 3 RFO 4 RFO 5 RF6 RFO 7 RFO 8 RFO9

AVB 2 19] 25 33 21 19 1 9

Wear Pre-heatrTSP (5) _._ = =

TSP __ _ _ __ _ _31

Confirmed _ 4 1 4 3 1

Not confirmed,

Loose Parts periphery 1 1 7 3 2

Not confirmed, not

Periphery

Obstruction From PSI, no

Restriction progresslon ___- Service-induced

Manufacturing Preservice 11

Flaws Other 29

Probe lodged

Inspection quali 1 = _ 

Issues Dent/geometry 1 1 1 Permeability _______

Not inspected .

Top of tubesheet 2___

Other Freepan ___.__ 1 1 3 4 1 TSP It 1 2 2 4 1

Other/not reported

ICCOD_==

TOTALS| 11 11l 211 291 361 291 301 381 14 4

Notes: I I | 1,2,3 | | 1 4 | 5 | 6 | 7 | 8 I

Totals Totals

129

1 130

01

13

14 27

0 0

1 1 40

0

1

3 4

0

2

11 22

1 1

00 0

1 2231 223

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 part In B at TSH In R49C55 and R49C56 was confirmed as was loose part in C at 8H In R49C54 and R49C55. Suspect part In C at 5H in R38C56 Refer to RFO

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 inC at 5H In R40C56 and R41C56. A117 plugged. 6. Leaker outage. StabilizedA-R16C110InCL.

7. 3 tubes pulled with circumferential indications at top of tubesheet Indicated the 29 circumferential indications were manufacturing related indications. All 29 were stabilizer

8. 3 tubes with PLPs were stabilized. B-R15C5, R15C6, R14C6. Stabilized tube with pre-heaterwearB-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.

-91 -
Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO 1 Charactenzation Stabilized'

1-87 U-bend RFO 1 Large dent

1-110 U-bend RFO I Signal to noise indication indicative of PWSCC

15-109 TSC RFO 6 CLP (part removed)

15-110 TSC RFO 6 CLP (part removed)

15-111 TSC RFO 6 CLP (part removed)

16.110 TSC RFO 6 CLP (part removed) - leaker Y (cold)

44-67 2C RFO 7 OD volumetnc

46-67 FS (2C) RFO 6 Scale/deposits

47-66 FS (2C) RFO 6 Scale/deposits

48-74 FS (2C) RFO 6 Scale/deposits

49-74 FS (2C) RFO 6 Scale/deposits

'An empty cell indicates that it was not reported whether the tube was stabilized or not

-92-
Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

STEAM GENERATOR B

Tube Location RFO # Charactenzation Stabilized'

1-2 U-bend RFO 6 Geometry change

2-57 U-bend RFO 7 Geometry change

12-4 5H RFO 5 Possible loose part (PLP) (onentation by magnet) Y

12-5 5H RFO 5 PLP (onentation by magnet) Y

13-4 5H RFO 5 PLP (onentation by magnet) V

13-5 5H RFO 5 PLP (onentation by magnet) Y

14-5 5H RFO 5 PLP (onentation by magnet) Y

14-6 5H RFO8 6 PLP 

14-7 5H RFO 9 PLP V

15-5 5H RF6O8 PLP

15-6 5H RFO 8 PLP Y

15-7 5H RFO9 PLP Y

20-56 2C RFO 9 CLP (removed In RFO 5) N

20-57 2C AFO 6 OD volumetric (CLP removed In RFO 5)

21-55 2C RFO 7 CLP removed In RFO 5

25-7 TSH RFO 1 Mechanism not reported

27-8 TSH RFO 1 Mechanism not reported

28-25 1 H RFO 7 CLP (removed - outage not specified)

28-26 1 H RFO4 Volumetnc

37-67 FS (2C) RFO 9 OD volumetric

47-76 2C RFO 8 OD volumetnc

49-51 7C RFO 8 Preheater wear V

49-54 TSH RFO 5 CLP (removed In RFO 1)

49-55 TSH RFO 1 Not reported (CLP in RFO 5, part removed in RFO 1)

49-56 TSH RFO 1 PLP (CLP in RFO 5, part removed In RFO 1)

'An empty cell Indicates that It was not reported whether the tube was stabilized or not

-93-
Table 3-6: Byron 2: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

STEAM GENERATOR C I.

Tube Location RFO # Charactenzaton Stabilized'

9-39 FS (1OC) RFO 3 ODI

FS (1 OH)

18-25 tH RFO 7 ODvoumetnc

19-27 1 H RFO 7 OD volumetnc

21-29 1H RFO 4 Volumetnc

22-29 1 H RFO 6 OD volumetnc

33-66 8H RFO 2 Pit

34-66 8H RFO 7 OD volumetnc

38-56 5H RFO 1 Narrow circumferential indication (PLP in RFO 5) Y RFO 5

39-56 5H RFO 4 PLP YRFO5

40-56 5H RFO 5 PLP Y

41-56 5H RFO 5 PLP Y

49-53 8H RFO 7 CLP (part removed in RFO 5)

49-54 8H RFO 1 Narrow circ (CLP removed in RFO 5)

49-55 8H RFO 1 Narrow circ (CLP removed in RFO 5)

STEAM GENERATOR 0

Tube Location RFO 3 Charactenzation Stabilized'

20-34 FS (6C) RFO 3 Outside diameter indication (ODI) -manufactunng bumishing mark (MBM)

FS (9C) _ _ _ _ _

22-37 10H RFO 3 ODI- MBM

37.17 FS (9H) RFO 3 ODI

F S (I 1 1H ) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

44-74 FS (5H) RFO 2 ODI

FS (9H) _______ _______________________________r___________________________ __________

'An empty cell inuicaLes inai n was not reponeo wnemer me tuute was bdunilzuu or [Jut.

-94-
Table 3-7: Catawba 2: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A S B SG C SG D _ Total Total Cumul. Percent Outage Date EFPY Insp. Plug e Insp. Plug I Inp. Pl DePI Insp. Plug DePI Plug DePI Pluqged Plugged Notes

Pre-op 1 7 1 5 14 0 14 0 08 1 Mid-Cycle 08/26/87 0 0 0 0 14 0 08 2

RFO 1 02/12/88 1133 4 546 1 515 0 1215 2 7 0 21 0.11

RFO2 04/01/89 1456 2 1519 5 F1443 1 1542 0 a 0 29 0.16

RFO3 07/01/90 3274 9 . 3230 1 3243 2 3265 7 19 0 48 0 26

RFO4 11/20/91 4554 7 4556 0 4566 4 4556 1 12 0 60 0 33

RFO5 03/01/93 4547 14 4556 6 4562 13 4555 10 43 0 103 0 56

RFO6 06/01/94 5 62 4533 6 4550 11 _ 4549 5 4545 9 31 0 134 0.73

RFO7 11/01/95 2569 10 2476 2 2419 5 2596 6 23 0 157 0 86 RFO8 04/01/97 7.93 2624 1 2520 5 2447 0 2628 4 10 0 167 0 91

RFO9 09/01/98 2501 1 _ 2317 5 2273 1 2485 2 9 0 176 0 96_ RFO10 03/01/00 4303 0 _ 4401 4 4313 2 4309 1 _ 7 0 183 1 00_ RFO11 10/15/01 2210 01 1890 0 1807 0 2071 0 . 0 0 183 1 00 _

Totals: 55 0 47 0 34 0 47 0 183

Plant Data

Model: D5

T-hot (approximate): 618 F

Tubes per steam generator: 4570

Number of steam generators: 4

Acronyms

Pre-op = prior to operation

Cumul. = cumulative

Insp. = number of tubes Inspected

Plug = number of tubes plugged

DePI = 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 outage.

-95-
Table 3-8: Catawba 2 Causes of Tube Plugging

Year 1988 1989 1990 1991 1993 1994 1995 1997 1998 2000 2001

Cause ot Tub Plugging/Outage Pre-Op jRFO1 RFO2 RFO3 RFO4 IRFO5 RFO6 RFO7 RF08 RF0O10 RFO11

Wear AVB Pre-heater TSP 14 6 2 1 1 2 1 1 (D5) I _ =_ I _ 1

TSP _ = 2

Confirmed 2 __

Not confirmed,

Loose Parts eiher _ _ _

Not confirmed, not

peripherv 2

Obstruction From PSI, no

Restriction prLqqess!on _ - _ _ | - - - Service-induced

Manufacturing Preservice 14-

Flaws Other

Probe lodged __._ 2

Inspection Data quality __=_=_ 1 = Issues Dent/geometry _ 1

Permeability _____ _ 2 1 _ Not inspected 1 2

Top of tubesheet ____ 3 4 2 3 2

Other Free span 3 4 1 30 20 10 1

TSP 2 3 3 5 6 6 5 1

Other/not reported 1 2 2 5

sc oDD =___ _____ __=_=

I TOTALS| 141 7 81 191 121 431 311 231 101 9i 71 0i

Notes: I I I '

Totals |

2

0

Totals

31

4-

0_ 0

01

141 14 i

14

0t 14 2

1

1 10

3

14

691 124

311

10

01 0

1 183 18

1. Since no tubes were plugged dunng the 1987 mid-cycle outage, reference is just made to RFO 1 in this table.

-96-
Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Charactenzation Stabilized'

1-5 FS(12); 4+ 9 7 ODI, volumetnc

1-6 4+ 8 7 ODI, volumetric

1-7 4+ 6 7 ODI, volumetnc

3-9 FS(12,13,15-19), 7 Absolute dnRft indication (ADI), non-quantifiable Indication (NOI),

15+1.5, 16-1.0, volumetnc, ODI

TSC, 19+1.5

7-12 7 5 ?

8-107 FS(7,8,10) 6 NOI, ODI, volumetnc

15-50 FS(1 0) 8 Bobbin indication greater than 40% through-wall, no degradation found

(NDF) with rotating probe

15-77 FS(2,5) t ODI, location not Indicative of PLP

16-72 TSH 6 IDI

19-102 . 7

21 -1 05 FS(10) 5 001, volumetnc

24-104 FS(10) 5 ODI, NOI

24-1 08 FS(7,8), 8-1 4 6 NOI, ODI, volumetnc

24-67 3 1 ODI, location not indicative of PLP

24-68 3 2 00

24-69 3 2 OD

25-19 FS(3,5,6,7,9,10) 7 Nal, volumetnc, ODI

25-86 ? 7

25-100 FS(4,11,17) 5 ODI, volumetnc, NQI

28-102 FS (3. 7) 5 ODI, volumetnc, NOI

29-24 FS(7) 6 NOI, ODI

29-70 FS (2) 5 ODI, volumetnc

29-96 FS (10) 5 ODI, volumetnc

34-91 ? 7 7

40-72 TSH 6 NOI

43-68 FS(10) 9 Permeability

44-49 FS (5,6,7,10) 7 NOI, ODI, volumetnc

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

-97-
STEAM GENERATOR A -

Tube Location RFO # Characterization Stabilized'

49-40 7+.1 3 OD

49-41 7+ 65 5 ODI, NOI

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 0D

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

An empty cell indicates that it was not reported whether the tube was stabilized or not.

-98-
Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

STEAM GENERATOR B

Tube Location RFO II Charactenzation Stabilized'

1-61 FS(9) 9 Dent signal change

2-99 U-bend 10 Plus-point lodged in U-bend

8-31 FS(1. 16) 5 ODI,volumetnc

16-29 1H+ 5 10 Wear, no size available - PLP

17-90 14+1 4 2 OD

20-104 TSH 9 MBMIPLP wear

21-62 8- 3 2 OD

25-40 FS(18) 5 ODI

26-26 FS(3) 5 ODI. volumetnrc

28-106 TSH 5 ODI, volumetnc

29-23 FS(9,11) 5 ODI, volumetnc

29-87 FS(7) 6 ODI, volumetnc

29-105 TSH 8 MBMIPLP wear

30-90 FS(4) 6 ODI, volumetnc

31-89 17-.1 7+2 2 2 OD

33-68 8+1 63 6 ODI

33-74 B+t 52 6 ODI

33-78 8+1 41 6 ODI

34-42 IH+ 5 10 Wear, no size available - PUP

35-38 FS(1 1) 7 ODI, volumetric

35-41 1H+5 9 MBM/PLP wear

36-36 FS(10) 5 ODI

36-56 TSH 7 NOI, volumetnc, pd

37-35 FS(10) 6 ODI, NOt

38-82 FS(2,3), AVB 6 NOI, ODI, volumetnc, wear

39-85 FS(10.11,17) 8 Lack of RPC data

39-97 U-bend - 8 Permeability

40-19 , TSH 8 MBMIPLP wear

40-64 1+0 56 6 ODI, volumetric

41-20 TSH 1 CLP (removed)

41-64 1+057 6 ODI, volumetnc

43-22 TSH 8 MBMIPLP wear

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+13,18+2 5 2 OD

Ar[I VMPIY CXii IFIiUikdLt0b Uldi It VWOO Fl01 I PUTLUU WiIiiiU[ It: IV LULt: Wdb 5toUIII~tUu Ur 1101

-99-
Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

STEAM GENERATOR C

Tube Location RFO # Charactenzation Stabilized'

1-5 ? 2 7

1-22 U-bend 10 No plus-point exam in U-bend

2-30 U-bend 10 Probe lodged in U-bend

9-35 TSH 6 SAI

13-15 10-1 7 7 ODI, volumetnc

18-45 TSH 7 ODI, volumetnc

19-85 ? 7

20-109 ? 7 ?

27-16 FS(1) 5 ODI, volumetnc

31-77 TSH 5 SAt

32-79 9-1 34 7 ODI, volumetric

33-24 FS(4,10,12); 6 ODI, volumetnc

9-0 86; 9-2.96

39-20 FS(9,12,13.15) 6 NQI, ODI, volumetnc

39-47 FS(11,13) 6 NQI, volumetnc

39-67 FS(9,10,11,13) 5 NQI, ODI, volumetnc

9+1 47

39-71 8+1 4, FS(12) 5 ODI, volumetnc, ADS

39-75 U-bend, FS(12) 5 ODI, NOI

39-87 FS(t), 18+ 4 4 OD

41-65 16+.9,16+1 4; 5 NOI, ODI, volumetnc

FS(8,10,18)

42-61 FS(6); 9+1.6 5 ODI

42-92 18+ 8; 18+2 4 5 ODI, volumetnc

42-93 7 5 ?

43-34 U-bend, 5 ODI, absolute dnft signal (ADS)

FS(2,5,1 3)

43-91 FS(10) 5 ODI

46-59 FS(1,13) 5 ODI, volumetric

46-87 FS(10) 6 ODI

49-61 5+ 7 4 OD

49-62 5+.7 4 OD

'An empty cell indicates that it was not reported whether the tube was stabilized or not

-100-
Table 3-9: Catawba 2: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

STEAM GENERATOR D

Tube Location RFO # Charactenzation Stabilized'

2-1 FS(14) 7 ODI, volumetric

2-46 FS(16) 5 NQI, volumetric

4-43 FS(3,15) 6 ADI, ODI, volumetric

6-19 FS(8,10) 7 NOI, volumetric

6-81 FS(12) 8 Data quality

7-26 FS(7,10,12,13,14) 7 NOI, ODI, volumetric

9-2 9+1.1, FS(7,10) 5 NO, ODI

14-4 FS(7,10) 5 ADS, ODI

15-29 FS(12) 7 ADI, volumetric

15-108 TSH 6 NOI

16-62 8-1.1, FS(7,10) 6 ADI, ODI, volumetric

17-103 FS(1,4,13) 5 NOI, ODI, volumetric

19-65 TSH 10 No RPC 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

25-43 FS(11,12,13,16) 5 ADS, NO!, volumetric

25-44 FS(7,10) 5 ODI

28-81 9-1.2, 9-2 4, 6 ODI, volumetnc

FS (110) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

29-96 3 .

30-59 9-0 6, FS(7) 6 ODI

33-16 7H+ 3 9 Wear, no sizing

33-48 1F0S-1.1,10+07, 6 ODI, volumetric

FS(110)

35-93 U-bend 8 Permeability in U-bend

40-67 FS(8,10) 6 ODI, volumetric

41-43 U-bend, FS(9,11) 6 NOI, ODI, volumetric

42-24 FS(1 0) 5 ODI, volumetric

43-62 FS(3) 1 ODI, location not indicative of PLP

48-75 TSH 9 MBM, PLP wear

49-34 ? 3 ?

49-63 TSH 5 SAl

49-64 TSH 1 CLP (loose part washed away)

An empty cell indicates that it was not reported wriether the tube was stabilized or not

-101-
Table 3-10: Comanche Peak 2: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A SGB SGC -SG D Total Total Cumul. Percent Outage Date EFPY lnsp. Plug DePI Insp. I DepInspl DePI Plug Dept Plug DePI Plugged Plugged Notes Pre-o_ 5 3 3 9 20 0 20 0 11 RFO 1 11/01/94 ____ 1104 0 ___ 1078 0 ___ 1062 0 ___ 1125 0 ___0 0 20 01 RFO 2 03/15/96 __ _ _ 2149 0 _ _ _ __ _ 2161 0 __ _0 0 -2001 RFO 3 11/14/97 ____ 3867 3 ___ 4567 5 - 4567 0 _ 2389 0 _ 8 0 28 01

RFO 4 04/09/99 ____ 914 1 914- 0 __ 914 0 ___ 914 4 5 0. 33 0.8

RFO 5 10/09/00 ____ 1927 3 -3609,1 _ 4 0 37 0 20

Totals: 12 0 8 0 3 0 14 0 37 0

Plant Data

Model. D5

T-hot (approximate). 618 F

Tubes per steam generator: 4570

Number of steam generators. 4

Notes

1. Cycle 5 was 1.433 EFPY.

Acronyms

Pre-op = prior to operation

Cumul. = cumulative

Insp. = number of tubes Inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refueling outage

-102-
Table 3-11: Comanche Peak 2 Causes of Tube Plugging

Year 1994 1996 1997 1999 2000

Cause of Tube Plugging/Outage Pre-Op RFO 1 RFO 2 RFO 3 R 4_ 5

AVB 5 4

Wear Pre-heater TSP (05) _

_ _ _ _ _ _ TSP _ _ ___ 

Confirmed ,_ 2

Not confirmed,

Loose Parts periphery 2

Not confirmed, not

eripherv 1

Obstruction From PSI, no

Restriction poqre sslon . _____ Service-induced 1 1

Manufacturing Preservice 20

Flaws Other

Probe lodged __

Inspection Data quality Issues DenVqeometrv _y__

Permeability

Not inspected

Top of tubesheet = 1

Other TSP span TSP ___

Other/not reported

SCC ID_ _D _OD ._

TOTALS1 201 01 01 81 51 4

Notes:

Totals

=91

2

2

Totals

9

5

0 2

2

20 20 20

0

0

0 0

0

0

1

0 1

01

01

0 O

0 1

1 371 3

-103-
Table 3-12: Comanche Peak 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO# Charactenzation Stabilized'

34-96 TSH 4 Pit, manufacturing artifact, PLP

49-53 8H 3 CLP

49-54 8H 3 CLP

STEAM GENERATOR B

Tube ILocation RFO # CharactenizationStblzd

14-67 TSC |3 | Restncted tube

STEAM GENERATOR C

jTube ILocation RFO* I Characterization miiiiii Stabilized'

STEAM GENERATOR D

Tube Location RFO # Characterization Stabilized'

12-92 60 4 PLP

20-106 10OH 4 Restnicted tube/dent

36-59 TTS 4 PLP

37.59 TTS 4 PLP

'An empty cell indicates that it was not reported whether the tube was stabilized or not

-104-
Table 3-13: Callaway: Summary of Bobbin Inspections and Tube Plugging (TT Tubes Only)

Completion Cumul. SG A SG B | SG C SG D Total Total Cumul. Percent Outage Date EFPY nsp. lu DePI Insp. Plug DPI De In Plug DePI Insp. Plug DePI Plug DePI Plugged Plugged Notes

Preop1 2 0 0 2 4 0 4 0.08 RFO 1 ___0 0 4 0 08 1

Mid-Cycle 04/07/87 243 0 243 0 0 0 4 0.08 2

RFO2 10/02/87 728 1 _728 0 1 0 5 010 3 RFO 3 04/24/89 1214 0 124 11 ____0 ___ 6 0.12 __

RFO4 10/23/90 1211 0 1214 1214 12124 0 0 6 0.12

RFO 5 04/28/92 1 1214 0 1213 1 1 0 7 014 RFO 6 10/28/93 12111 0- 1212 0 -0__ 0 ____ 7 0.14 RFO 7 05/01/95 0211 1214 2 1212 1 1 4 0 11 0'23 4

RFO8 11/11/96 1211 1 2 1 1211 1 5 0 16 033 4,5 RFO9 04/01/98 0 _ 1210 0 1210 0 0 0 0 16 033 4

RFO10 11/05/99 1210 0 0 0- 1210 0 0 0 16 0.33 4,6 RFO11 05/21/01 0 1210 0 = 1210 1 0 1 0 17 035 4

Totals: 4 0 4 0 5 0 4 0 17 0

Plant Data

Model: F

T-hot (approximate): 618 F

Tubes per steam generator: 5626(1214 are TT)

Number of steam generators: 4

Acronyms

Pre-op = prior to operation

Cumul. = cumulative

Insp. = number of tubes inspected

Plug = number of tubes plugged

DePI = 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 Tr 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. 3 tubes were repaired with laser welded sleeves: 1 in steam generator A, 2 In steam generator C.

6. 3 tubes in steam generator C were repaired by electrosleeving.

-105-
Table 3-14: Callaway Causes of Tube Plugging (Thermally Treated Tubes Only)

Year _ _1987 1987|1989 1990 1992 1993 1995 6 1998 1999 2001 Cause of Tube Plugging/Outage Pre-Op RFO1 Mlid-Cy RFO2 RFO3 RFO4 FO 5 O 6 RFO7 RFO 8 RFu9 RFO10 RFO il

AVB __.,__ __._....__

Wear Pre-heater TSP 5D)

_TSP

Confirmed -

Not confirmed, Loose Parts peripherv _ 2

Not confirmed, not

eripherv .

Obstruction From PSI, no Restriction progression .__ _ _ Service-induced

Manufacturing .reservice - -

Flaws Other - _

Probe lodged - -

Inspection Data aualitv

Issues Dent/qeometrv y_ __=

Not inspected =. Top of tubesheet -

Other Free span . t 1 2 2 TSP _

Other/not reported j

SCC ODD I_ - ___ -

I TOTALS1 41 01 01 1* 11 01 1 01 41 51 01 0° I

Notes:1 I I I I I I I I I I I I 1 2 1

Totals Totals|

0

0 0 0

0

2 2

0

o 0

0

0o

0

0

01 0

0T

1 171 17

0T

7 4 7

Notes

1. 3 thermally treated tubes were repaired by Inserting laser welded sleeves. These tubes are not reflected in the totals 2. 3 thermally treated tubes were repaired by electrosleeving These tubes are not reflected In the totals.

-106-
Table 3-15: Callaway: Tubes Plugged for Indications Other Than AVB Wear

(Thermally Treated Tubes only)

STEAM GENERATOR A

Tube Location RFO t Characterization Stabilized'

2-87 TSH+3 47 8 Single volumetnc Indication N

3-44 7H 2 45% through-wall indication

8-115 TSH-O 06 8 Tube sleeved, single circumferential Indication

STEAM GENERATOR B

Tube Location RFO # Charactenzation Stabilized'

1-100 TSH-0 11 8 Single circumferential Indication Y

1-119 TSH+3 89 8 Single volumetnc indication N

1-120 TSC+4 02 7 38% wall thinning, PLP N

1-121 TSC+3 66 7 45% wall thinning, PLP N

'An empty cell Indicates that It was not reported whether the tube was stabilized or not

-107-
Table 3-15 Callaway: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

(Thermally Treated Tubes only)

STEAM GENERATOR C

Tube Location RFO # Charactenization Stabilized'

1-1 I C 7 Obstruction, damage due to chemical cleaning equipment N

2-6 TSH+0 07 8 Single axial indication N

2-10 TSH-0.01 1t Single axial indication N

2-98 7C+1.5 5 Undefined indication 1 5 Inches above 71h cold-leg tube support

4-11 FBC 3 Single axial Indication

1-= TSH+0 12 10 Tube electrosleeved (8.), single volumetnc Indication

9-64 TSH+0 24 10 Tube electrosleeved (8"), single volumetnc indication

10-48 TSH+0.17 8 Tube sleeved (laser welded), single volumetnc indication

10-70 TSH-0 08 8 Tube sleeved (laser welded), single circumferential indication

10-93 TSH+O 23 to 0 91 10 Tube electrosleeved (8"), single volumetnc Indication

STEAM GENERATOR D

Tube Location RFO # CharacterIzation Stabilized'_1

1-1 TSC+17725 Dent, damage due to chemical cleaning equipment N

7-102 TSH+0 18 .8 _ Single volumetnc Indication N

'An empty cell indicates that it was not reported whether the tube was stabilized or not

-108-
Table 3-16: Millstone 3: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A SG B SG C SG D Total Total Cumul. Percent Outage Date EFPY Insp. Plug DePi tnsp. Plug DePI Insp. Pug DePI nsp. Plug DePt Pluq DePI Plugged Plugged Notes Pre-op 3 3 3 1 10 0 10 0 04 RFO 1 11/24/87 543 1 501 0 506 0 504 1 2 0 12 005 RFO 2 05/29/89 2431 4 2358 0 4 0 16 0 07 RFO 3 02/21/91 3555 0 3546 5 5 0 21 0.09 RFO 4 08/21/93 4350 6 - 3660 1 _ 7 0 28 0.12 RFO 5 05/9/95 4237. 1 ______ _ 4236 10 1 I 01 39 0 17 Mid-Cycle 10/01/96 5622 2 2 0 41 0.18 1 RFO 6 05/17/99 5612 12 5620 2 42 0 14 0 55 0 24 RFO7 02/18/01 _ 5622 0 5609 51 51 0 106 0 47

i i i i i i i i i i i I I I I I I I

t t I I

I I _ _ __I_-- I _ I__ I

Totals: 26 0 4 0 8 0 68 0 106 0

Plant Data

Model: F

T-hot (approximate): 617 F

Tubes per steam generator: 5626

Number of steam generators: 4

Acronyms

Pre-op = pnor to operation

Cumul. = cumulative

Insp. = number of tubes Inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = rnfiuinn noitaon

Notes

1. Licensee elected to perform steam generator tube Inspections during an extended shutdown penod.

-109-
Table 3-17: Millstone 3 Causes of Tube Plugging

Year 1987 1989 1991 1993 1995 1996 1999 2001

Cause of Tube Pluggaing/OutagePr-O RFO 1 _RFO 2 RIFO3 RFO04 |RF0 jMidCRF0 6 iRF0

AVB 2 3 5 7 11 2 13 15

Wear Pre-heater TSP (D5) ___

TSP _

Confirmed - _

Not confirmed,

Loose Parts peripherv y_ 1 6

Not confirmed, not

periphery

Obstruction From PSI, no

Restriction progression _ _ _ _ _ _ Service-induced

Manufacturing Preservice 10 .__ .

Flaws Other

Probe lodged __.__

Inspection Data quality _ _

Issues Dentgeome"t_ _ . _ ___ Permeabllty

Not inspected

Top of tubesheet = 13

Other Free span __1_=_t 13 TSP ____13

Other/not reported _

SCC IDOD .__ _ 

TOTALSI 101 21 41 51 71 11i 21 141 511

Notes: I I I I I I I I I I 1 I

Totals

5E

C

C

C

Totals

58

8

0 0

0

10 10

0

0

0 0

0

0

13

4 30

0 I

0

_0 0

|1061 106j

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."

-110-

- - ___ ____ __ ---- --- - ____ -__ _ __ __ __ ----- ___
Table 3-18: Millstone 3: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Charactenization Stabilized'

1-122 8H+1O 56 2 36% throughwall, distorted eddy current signal

20-6 TSH+0 07 6 Volumetnc - possible loose part

[ ~STEAM GENERATOR B]

Tube Location RFO # Charactenization Stabilized'j

STEAM GENERATOR C

Lcto F# Caatrzto _ue tblz

'An empty cell indicates that ii was not reponeo wnesner uei WuDE was s-0111-0 rI JUL

-111-
Table 3-18: Millstone 3: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

STEAM GENERATOR D -.

Tube Location |RFO # Characterization Stabilized'

1-119 TSH+13 94 7 Volumetnc N

1-120 TSH+14.11 7 Volumetnc N

1-121 TSH+14 09 7 Volumetnc N

15-18 TSH+0 27 7 Possible loose part (not in penphery of bundle) N

35-23 TSH+0 09 7 Volumetnc - possibly manufactunng related N

37-23 TSH+O 15 7 Volumetnc - possibly manutacturing related N

37-24 TSH+0.15 7 Volumetric - possibly manufactunng related N

38-107 1C+1 45 7 Volumetnc - possible loose part N

39-107 1C+1 52 7 Volumetnc - possible loose part N

42-23 TSH+0 16 7 Volumetnc - possibly manufacturing related N

43-23 TSH+0.t 1 7 Volumetnc - possible manufactunng related and AVB wear N

43-24 TSH+0.14 7 Volumetnc - possibly manufacturing related N

44-23 TSH+0.13 7 Volumetnc - possibly manufacturing related N

44-24 TSH+0 14 7 Volumetric - possibly manufactunng related N

45-23 TSH+0.15 7 Volumetnc - possibly manufactunng related N

45-24 TSH+0.13 7 Volumetnc - possibly manufactunng related N

52-53 TSC+0 81 7 Volumetnc (not in penphery of bundle) N

52-54 TSC+0 25 7 Volumetnc (not in penphery of bundle) N

53-54 TSC+0 01 7 Volumetnc (not in penphery of bundle) N

53-79 1C+0 9 7 Volumetnc - possible loose part N

54-45 1 C+0 5 7 Volumetnc N

54-79 1 C+0 51 7 Possible loose part N

54-80 1 C+0 43 7 Volumetric - possible loose part N

54-81 1C+0.48 7 Possible loose part N

55-45 1 C+0 58 7 Volumetnc N

55-46 1 C+0 77 7 Volumetnc N

57-74 1C+1 01 7 Volumetnc - possible loose part N

57-75 1 C+0 58 7 Possible loose part N

57-79 1H+0 91 7 Volumetnc - possible loose part N

58-54 1 C+0 56 7 Volumetnc N

58-55 1 C+0 70 7 Volumetric - possible loose part N

58-56 1 C+0 69 7 Volumetnc N

58-74 7 Possible loose part N

58-75 1 C+0 64 7 Volumetnc - possible loose part N

59-55 1 C+0 68 7 Possible loose part N

59-56 1 C+0 61 7 Possible loose part N

'An empty cell indicates that it was not reported whether the tube was stabilized or not.

-112-
Table 3-19: Seabrook: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A SG B SG C SG D Total Total Cumul. Percent

Outage Date EFPY nsp. Plug DePI Insp. P DePI Insp. DePI np. ug DePI Plug DePI lued Plugged Notes

Pre-op 4 4 5 0 13 0 13 0 06 1

RFO1 08/28/91 1797 0 1761 1 1747 8 _ 1884 1 10 0 23 0.10

RFO 2 10/01/92 2409 0 2400 0 0 0 23 0 10

RFO 3 05/12/94 2327 1 _ 2337 0 1 0 24 0.11 i= RFO 4 11/27/95 ____ 2424 8 -2443 4 12 ____0 __ 36 0.161

RFO 5 06/10/97 242_ 5620 9 5613 4 2443 13 0 49 0 22 2

RFO 6 04/20/99 5614 5 5621 20 25 0 74 0 33

RFO7 11/09/00 5611 7 5609 9 16 0 90 0 40

Totals: 17 0 22 0 26 0 25 0 90 0

Plant Data

Model: F

T-hot (approximate):

Tubes per steam generator: 5626

Number of steam generators: 4

Notes

1. Based on data contained in RFO 4 reports.

2. Between RFO 3 and 5, the plant operated for 32 EFPM

Acronyms

Pre-op = prior to operation

Cumul. = cumulative

Insp. = number of tubes Inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refueling outage

-113-
Table 3-20: Seabrook Causes of Tube Plugging

Year 1991 1992 1994 1995 1997 1999 2000 Cause of Tube Plugging/Outage Pre-Op R RFO 2 RFO3 RFO4 RFO5 RF06 RF07

AVB 4 1 12 7 25 13 Wear Pre-heater TSP (D5). _ -

TSP _ Confirmed 4 4

Not confirmed,

Loose Parts periphery 1

Not confirmed, not

peniphery _ 2 2

Obstruction From PSI, no

Restriction Droqression

Service-induced

Manufacturing Preservice 13

Flaws Other

Probe lodged __.

Inspection Data quality ______ Issues Dent/geometry .- Permeablity .

Not inspected

Top of tubesheet -

Other Free span . 2 TSP__ _

Other/not reported _

SCC ID_...___= OD _

TOTALS1 131 10| 01 11 121 131 25 16

Notes:

Totals

62

0

0

8

1

Totals

62

13

O

0

0s

0 1

0

0

0 0

0

901 9

Notes

-114-
Table 3-21: Seabrook: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Charactenzation Stabilized'

STEAM GENERATOR B

Tube Location RFO # Charactenzation Stabilized'

27-24 FS (6H) 1 37% throughwall, high wall loss indication - MBM

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

STEAM GENERATOR C

Tube Location RFO U Charactenization Stabilized'

1-11 TSH + 19 06 7 Volumetric - possible loose part

11-120 FS (7C) 1 High wall loss

22-12 SC 5 Volumetnc - possible loose part (not In penphery of bundle)

22-13 5C 5 Volumetnc - possible loose part (not In penphery of bundle)

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 Volumetnc - possible loose part (not in penphery of bundle)

44-28 TSH + 0 06 7 Possible loose part (not In penphery of bundle)

L STEAM GENERATOR D

[Tube I Location RFO | Charactenzation Stabilized'

'An empty cell Indicates that it was not reported whether the tube was stabilized or not

-115-
Table 3-22: Vogtle 1: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A . S_ G B SGC -G Total Total Cumul. Percent Outage Date EFPY Insp. Plug DePI Inp. Plug DePI Plug DePI Insp. Plug I DePI Plug DePI Plugged Plugged Notes

RFO Pr-p0 _ 0 __ _ __ _ 4 _ 6 0 6 0 03 _ _ 1 10/22/88 754 1 0 2 821 0 6 1 0 7 0 03

RFO 2 03/11/90 1514 0 2357 4 2403 0 1471 0 4 0 11 0 05 RFO 3 10/08/91 . 1067 0 1050 0 1078 0 1011 0 0 0 11 0 05 RFO 4 04/03/93 2951 0 2934 4 4 0 15 0 07 RFO 5 10/01/94 4224 0 - 4213 4 1 4231 5 4220 3 12 0 27 0 12 RFO 6 03/22/96 3387 4 _ 3395 0 4 0 31 0 14 RFO 7 10/05/97 5618 3 5615 6 = 5619 6 15 0 46 0 20 RFO 8 03/15/99 10 06 5621 0 5613 0 _ 0 0 46 0 20 1 RFO 9 10/11/00 =_ - - - f 5615 0 5609 2 2 0 48 0 21 2

. _ _

Totals: 5 0 11 0 19 0 13 0 48 0

Plant Data

Model: F

T-hot (approximate) 618 F

Tubes per steam generator: 5626

Number of steam generators 4

Acronyms

Pre-op = prior to operation

Cumul. = cumulative

Insp. = number of tubes inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refueling outage Notes

1. 949 EFPD between RFO 6 and RFO 8

2 2.9 EFPY between RFO 7 and RFO 9.

3 RF 8 to RF 10 proiected to be 277 EFPY, Expect cumulative time to be 1283 EFPY

-116-
Table 3-23: Vogtle 1 Causes of Tube Plugging

Year O 1988 1990 1 1993 1994 | 1996 1997 1999 2000 Cause of Tube Plugging/Outage Pre-p RFO 1 2 R RFO 3 4 RFO R 6 6 RFO7 RFO 8 RF09 AVB 4 4 12 4 12 Wear Pre-heater TSP (D5 _

TSP

Confirmed - -

Not confirmed, Loose Parts perphery

Not confirmed, not Deriphery

Obstruction From PSI, no

Restriction progression - Service-induced -

2 Manufacturing Preservice 6 -

Flaws Other

Probe lodged

Inspection qa~Aj~ -

Issues Dent/geometry

Permeability ___. _ _ _ _ .. __ _

Not Inspected Top ottubesheet ___ ___ __ .._ _ __ 1 Other Free span

Other/not reported

scC ID . . _ _- _

TOTALS1 61 11 41 0o 41 121 41 15| 2

Notes: I I I I I I I I I I

Totals ITotals

3701 37

C

0 1

0 2

2 _

0 6

0

0

0 0

0

1

0 2

00 0

481 48

Notes

-117-
Table 3-24: Vogtle 1: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Charactenzation Stabilized'

28-37 5H+7 0 t 39% throughwall indication

4C+380

[ ~STEAM GENERATOR BJ

Tube Location RFO# Charactenzation Stabilized'j

STEAM GENERATOR C

Tube Location RFO # Characterization Stabilized'

21-13 TSH+0 21 9 Volumetnc

STEAM GENERATOR D

Tube Location RFO# Characterization Stabilized'

1-31 U-bend 7 Obstruction to a 0520-inch probe

4-3 TSH 7 Confirmed loose part - part not removed

4-4 U-bend 7 Obstruction to a 0 520-inch probe

'An empty celi indicates that it was not reported whether the tube was stabilized or not

-118-
Table 3-25: Vogtle 2: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. .G C SG D Total Total Cumul. Percent Outage Date EFPY Insp. Plu2 DePI Insp. Plug DeP Insp. Plug DePI Insp. Plug DeI Plug DePI Plugged Plugged Notes Pre-o _ 2 4 _ 1 8 15 0 15 0_07 RFOQ1 10/03/90 ____ 11431 0 __ 1130 0 ___ 1139 0 __ 1135 0 ____0 0 __ 15 0 07 __

RFO 2 03/30/92 1056 0 ___ 1570 0 ___ 1066 0 __ 1061 0 -0 0 __ 15 0 07 __ RFO 3 10/02/93 2984 0 _____ 3008 0 ____0 0 __ 15 0 07 __ RFO 4 03/16/95 _ _ _ __ 4382 3 - 4576 01___ 3 0l 18 0 08 ___ RFO 5 09/30/96 5624 1 - 1 5618. ____ 6 01 24 011 RFO 6 04/02/98 5619 0 - 5625 01 I__ __ 0 0 ___ 24 0 11 1 RFO 7 10/22/99 5623 1 1 __ 561314 ___5 0 ___29 0.13 2 RFO 8 04/24/01 _ _ _ __ 5619 0 - 5625 ___ ___ 0 0 _ _ 29 0.13 _ _

Totals: 4 0 7 0 1 0 17 0 29 0

Plant Data

Model: F

T-hot (approximate): 618 F

Tubes per steam generator: 5626

Number of steam generators: 4

Notes

1. 1015 EFPD between RFO 4 to RFO 6.

2. 2.7 EFPY between RFO 5 to RFO 7.

Acronyms

Pre-op = prior to operation

Cumul. = cumulative

Insp. = number of tubes inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refueling outage

-119-
Table 3-26: Vogtle 2 Causes of Tube Plugging

Year 1990 1992 1993 1995 1996 1998 1999 2001 Cause of Tube Plugging/Outage P~PreO RFO1 RFO 2 RFO 3 RFO 4 RFO 5 RFO 6 RFO 7 RFO 8

AVB |3 6 5 Wear Pre-heater TSP (D5) .

TSP I

Confirmed

Not confirmed,

Loose Parts penphery

Not confirmed, not

_ penihery

Obstruction From PSI, no Restriction prwxresslon _ _

Service-induced

Manufacturing Preservice 15 __ _ _ Flaws Other

Probe lodged _ _ _

Inspection Data quality __.__,

Issues Permearnlty

Not Inspected

Top ol tubesheet

Other Free span TSP

Other/not reported

SCC ID . _. . __I ODI

TOTALS| 151 01 01 01 31 61 01 51 01

Notes: I I I I I I I I I I

Totals Totals

14

o 14

0 O

0

0 0

0 0

0 -

15 1

0 1

0

0

o 0

0

0

0

01 0

0 0

1 291 2

Notes

-120-

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

I STEAM GENERATOR A I

ITube Location RFO# Characterization Stabilized

STEAM GENERATOR B

Tube Location RFO # Charactenzation Stabilized'

STEAM GENERATOR C

Tube Location RFO# Charactenzabon| Stabilized'

STEAM GENERATOR D

Tube Location RFO # Characte nzation Stabilized'

'An empty cell Indicates that it was not reported whether the tube was stabilized or not

-121-
Table 3-28: Wolf Creek: Summary of Bobbin Inspections and Tube Plugging

Completion SG A SG G B SGC SG D Total Total Cumul. Percent

Outage Date Cumul. EFPY Insp. Pluq DePI Insp. DePI Insp. Plug DePI Insp. Plug I DePI Plug DePI Plugged Plugged Notes

Pre-op 8 3 4 15 0 15 0 07 RFO 1 10/27/86 0 68 _393 0 384 0 0 0 15 0 07 RFO 2 1 66 0 0 15 0 07 1

RFO 3 11/18/88 2 33 2969 1 2972 1 2973 3 2975 17 22 0 37 0 16 RFO 4 04/04/90 3 47 3205 0 3169 2 2 0 39 0 17 RFO 5 10/24/91 4 69 1565 0 1227 2 2 2 2 39 0 17 _ RFO 6 03/31/93 5 71 _ 5623 5 5 0 44 0 20 RFO 7 10/11/94 6 98 5617 9 -_ _ -5607 24 6 33 _ __6 71 0 32 __ RFO 8 03/05/96 6 5617 12 5619 4 16 0 87 0 39 RFO9 11/06/97 5608 5 5589 14 19 0 106 0 47 RFO 10 04/24/99 5605 1 5615 5 6 0 112 0 50 RFO11 10/20/00 5603 3 5575 29 32 C0 144 064

Totals: 26 0 22 0 18 2 86 6 152 8

Plant Data

Model: F

T-hot (approximate). 618 F

Tubes per steam generator. 5626

Number of steam generators, 4

Notes

1. No tube inspections were poerormed during RFO 2.

Acronyms

Pre-op = prior to operation

Cumul = cumulative

Insp = number of tubes inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refueling outage

-122-
Table 3-29: Wolf Creek Causes of Tube Plugging

Year 1986 1988 1990 1991 1993 1994 1996 1997 1999 2000 Cause of Tub Plugging/Outage Pre-Op RFO 1 RFO 2 RFO3 RFO4 iR 5 O RFO 6 RF09 RFO1 RFO11 AVB 19 2 5 25 16 19 6 30 Wear Pre-heater TSP (D5) . -- _ _ - . __ .

Confirmed

Not confirmed, Loose Parts peripherv

Not confirmed, not

.p reripherv

Obstruction From PSI, no Restriction progression

Service-induced -

Manufactunng Preservice 15 _ Flaws Other .__=

Probe lodged

Inspection Dantage. = =_ Issues Dent/geom;etry__,,_,=_ Isus Permeability ___

Not inspected Top of tubesheet -

Other Free span 3 -2

Ohr TSP 3__ 2

Other/not reported 2

SCC ID

j TOTALS1 151 01 01 221 21 01 51 271 16| 191 61 32

Notes: 2 1 1

Totals

124

0

0

0

0

Totals

124

0

0 0

0

-15

1

-O S

0

0

0 0

01

1 1441 14=4

Notes

1. Deplugged 2 Free Span 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.

-123-
Table 3-30: Wolf Creek: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterzation Stabilized'

15-68 1 H-0 81 7 55% thnoughwall indication

45-91 TSH-0 07 11 Volumetnc

L ~STEAM GENERATOR B]

Tube Location RFO # Charactenization Stabilized'

STEAM GENERATOR C

Tube Locabon RFO 6 Charactezation Stabilized'

14-17 6H+9 26 3 36% throughwall

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 Characterzation Stabilized'

7-88 4H+O 54 t11 Volumetnc

19-93 2C+O 08 7 Volumetnc

'An empty cell iniicates tnal , was nol reponea wnemher tri LUDe wds btdulaleu 0i 11UL

-124-
Table 3-31: Indian Point 2: Summary of Bobbin Inspections and Tube Plugging

j Completion Cumul. SGA SG B SG C SG D Total Total Cumul. Percent Outage Date EFPY Insp. Plug DePI Innp. DePI Insp. Plug DePI Insp. PlugI DePI Plug DePI Plugged Plugged Notes Pre-op 0 0 _ 0 21 2 0 2 0 02 ______ ______ _= 000 _______ 0 00 _ _ _

_______ 0 00 _ _

______________ 0 00 _ _

- - __ ___ _ _____0 00 _ _

- - __ ___ _ _____0 00 _ _

- - ____ _ _ ____ _ ___ _0 00 _ _

0 00 _ _

Totals: 0 0 0 0 0 0 2 0 2 0

Plant Data

Model 44F

T-hot (appmximate)

Tubes per steam generator 3214

Number of steam generators, 4

Notes

Acronyms

Pre-op = pnor to operation

Cumul = cumulative

Insp. = number of tubes inspected - - Plug a number of tubes plugged DePI = number of tubes deplugged -- ~ RFO = refueling outage

-125-
Table 3-32: Indian Point 2 Causes of Tube Plugging

Year

Cause of Tube Plugging/Outage Pre-Op

AVB

Wear Pre-heater TSP (D5)

TSP

Confirmed

Not confirmed,

Loose Parts penpherv

Not confirmed, not

Deripherv

Obstruction From PSI, no

Restriction P10esio ____________ Service-induced

Manufacturing Preservice 2

Flaws Other

Probe lodged

Inspectlon Data quality

Issuet Dent/geometry

Permeability

Not inspected

Top of tubesheet

Other Free span TSP

Other/not reporled

SCC IDOD

TOTALS1 2

i Notes:

Totals

O

0

0

0

Totals

0

0

01

0 0

0

2 Z

0

0

O 0

0 0

0

0 0

01

0 01

Notes

-126-
Table 3-33: Indian Point 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATORA A

Tube I Location I RFO# I Charactenzation I Stabilized'

STEAM GENERATOR B

Tube Location RFO # Charactenzation Stabilized'

STEAM GENERATORC l

Tube I Location I RFO# I Charactenzation I Stabilized' |

STEAM GENERATOR D

Tube I Location I RFO# I Charactenzation I Stabilized'

'An empty cell Indicates that It was not reported whether the tube was stabilized or not.

-127-
Table 3-34: Point Beach 1: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A SG B Total Total Cumul. Percent

Outage Date EFPY Plug DePI Insp. Plug I DePI Plug DePI Plugged Plugged Notes

Pre-op 04/09/84 3211 3 3214 1 1 4 0 4 0 06

RFO 12 04/13/85 101 0 101 0 0 0 4 0 06

RFO 13 04/19/86 122 0 146 0 0 0 4 006

RFO 14 1987 0 0 4 0 06

RFO 15 05/06/88 129 0 112 2 0 6 09s 

RFO 16 04/11/89 _ 592 0 - 610 0 0 ° 0 6 09 0 = RFO 17 04/09/90 __ _ _ _ _ ___ _ _ _0 __ _ 6 ___ 009 _ _

RFO 18 04/18/91 ____ 576 1 ___ 584 1 _ 2 ____0 a__ 0 12

RFO19 04/18/92 591 0 592 0 0 0 8 0 12 RFO 20 04/17/93 ____ 588 0 ___ 591 0 0 ____0 ____8 0.12

RFO 21 1994 583 0 591 0 0 8 0 12

RFO 22 03/25/95 3210 0 3210 1 _ 1 0 9 014

RFO023 1996 __ _ _ _ _ _0 _ _ 0 _ _ 9 0.14

RFO24 03/31/98 3210 0 - 3209 0 _ 0 9 014

RFO025 12109/99 _ _ _ _ _ _ _ _ _ _ 0 __ _ _0 __ _ 9 0 14 Mid-Cycle 03/05/00 _0 0 9 014 1

RFO 26 04/24/01 13 5 3210 0 32091 1 0 10 016

Totals: 4 0 6 0 10

Plant Data Acronym Model 44F Pre-op = pnor 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

DePI = number of tubes deplugged

RFO = refueling outage Notes

1. Plant was shut down to investigate an indication of a possible loose part

-128-
Table 3-35: Point Beach 1 Causes of Tube Plugging

Year 1985 1986 1987 1988 1 990 1991 1992 1993 1994 1995 1996 1998 1999 2000 2001 Cause of Tuba Pluing/Outage Pre-OP RFO 12 RFO 13RFO t41RFO 151RFO 916 RFO 17 S RFO 19 RFO20 RFO 21 RFO 22 RFO 23 RFO 24 RFO 25 M i RFO 26 Totals Totals I IAVB I 3 Wear Pre-heate_ TSP (D5) - - |t __ 0 4

tfs~onrr _ __ ~ 1_== C rtm~ed - 0 Not confirmed,

Loose Parts Neripteno __+_ __ 0 0 Not confirnednot

Obstruction From PSI, no _ Restriction Prp-giressloio 0 _! ! 0

Manufacturing Preservice 4 6 Fiws Fo~~arob loded1 21 i 6

......... o.i0

Issus __n!!e___try 0 a

Ptere bi tx'___________ ___

To-p ot tubesheet _

Other TeP __. . _ __=_

Other/not reported -

SCC ID

TOTALSI 41 0 0 0o 21 01 0o 21 01 01 01 1t 01 01 0 1 tOI 10

Notes I I I

NOS

I. Mid-cycle outage due lo an indication of a possible loose part

-129-
Table 3-36: Point Beach 1: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # I Charactenzation Stablized1

21-63 5H-0 65 J 18 | 68% throughwal wear indication

STEAM GENERATOR B

Tube Locaton RFO # Characterization Stabilized'

1-1 TSC+18- 15 Damaged dunng tube lane blocking device removal

2-1 TSC+18" 15 Damaged dunng tube lane blocking device removal

-An emptycell inuicalus thtld IL Wdb not UrpJoIteU wht IIFLLeItl LUUe Wda bidUshhLUU UT nIUb

-130-
Table 3-37: Robinson 2: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A SG B SG C Total Total Cumul. Percent

Outage Date EFPY Insp. Plug DePI Insp. Plug DePI Insp. Plug DePI Plua DePI Pluqqed Pluaqed Notes

15 4 9 28 0 28 0 29 RFO10 02/01/86 306 0 305 0 287 0 0 0 28 0 29

RFO 11 05/01/87 301 0 _ 301 0 296 0 0 0 28 0 29

RFO 12 12/05/88 630 0-O. 631 0 633 1 1 0 29 0 30 Mid-Cycle 04/15/89 0 0 29 0 30 1

RFO 13 11/01/90 654 0- 655 0- 653 1 - 1 0 30 0 31 2

RFO 14 04/28/92 661 1 659 0 667 0 1 0 31 0 32

RFO 15 10/05/93 1084 1 - 1187 0 1083 0 1 0 32 033

Mid-Cycle 03/20/94 _ 484 2 2 0 34 0 35 3

RFO16 06/21/95 3201 0 0 0 34 0 35 RFO 17 09/27/96 3197 1 - = 1 0 35 0 36

RFO 18 04/14/98 2025 0 1607 0 0 0 35 036

RFO 19 10/24/99 1610 0 0 C0 35 036

RFO 20 04/27/01 t161t9 1 - 1697 3 4 0 39 040

Totals: 18 0 5 0 16 0 39 0

Plant Data

Model. 44F _

T-hot (approximate): 604 F _ _ Tubes per steam generator: 3214 !

Number of steam generators: 3

Acronyms

Pre-op = prior to operation

Cumul =cumulative

Insp = number of tubes inspected

Plug = number ot tubes plugged

DePI = number of tubes deplugged

RFO = refuelina outage Notes

1 Mid-cycle outage to investigate an indication of a possible loose part on the primary side of the steam generator Ni

2. Cycle 13 (RFO 12 to RFO 13) planned for 347 EFPD

3. Mid-cycle outage to investigate an indication of a possible loose part on the secondary side of the steam generator.

o tube inspections performed.

-131-
Table 3-38: Robinson 2 Causes of Tube Plugging

Year 1986 1987 1988 1989 1990 1992 1993 1994 1995 1996 1998 1999 2001

Cause of Tube Plugging/Outage Pre-Op IRFO10 IRFO 11 RFO12 Mid-Cyc RFO13 RFO14 RFO15 Mid-Cy RF016 RFO 17 RFO18 RFO19 RFO 20

AVB

Wear Pre-heaterTSP (D5) = _____TS P I I

Confirmed __ 2 -

Not confirmed,

Loose Parts periphery _ _1 1 t 1

Not confirmed, not I

periphery I -

Obstruction From PSI, no 1 _

ReStriction Service-induced I - 1 t 

Manufacturing Preservice 281

Flaws Other .. _.___

Probe lodged

Inspection Data quality-- -- - -

Issues Dent/gometry -= = = .

Not inspected

Top of tubesheet

Other Free span _|__

.._ __ __H _ _ __ __ _ __ _._._ Other/not _.________________ .____________ . __ _ __ _ _ __ _______ ________ reported

sCC IL)__ - _

I TOTALS| 281 01 01 11 01 1 1 1 21 01 1| 01 01 41

Notes I I I I I I 1 1 1 1 1 | I I I

Totals

0

0

0

2

4

1

2

Totals

0

73

2 28

0

i o0 I

0

001

0 1

01

0

1 391 397

Notes

1 Mid-cycle outage due to an Indication of a possible loose part

-132-
Table 3-39: Robinson 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location FFO # Charactenzation | Stabilized'

1-29 6H 14 Restriction at 6H (since preservice inspection)

2-6 6H 15 Restriction at 6H (since preservice inspection) T

37-73 Cold-leg 17 Possible loose part in penphery (38% throughwall Indication)

STEAM GENERATOR B

Tube Location RFO # Charactenzation Stabilized'

43-55 20 Dent (since manufacture) resulting In poor data quality

STEAM GENERATOR C

Tube Location RFO # Charactenzation Stabilized'

1-90 TSH, TSC 1994 57%/O throughwall confirmed loose part indication

2-90 TSC+0 6' 13 44% throughwall possible loose part indication

3-90 TSC 1994 33% throughwall confirmed loose part Indication

7-92 TSH 12 76% throughwall gouge-like Indication Indicative of a debns related

defect

32-26 TSH+0 28" 20 32% throughwall wear indication attnbuted to transient loose part

33-34 6H 20 Obstruction above 6H

44-56 FBH+0 45' 20 Flow distnbution baffle wear Indication attnbuted to transient loose part

'An empty cell indicates that it was not reported wnether the tube was stabilized or not

-133-
Table 3-40: Salem 1: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SGA GB GC SG D Total Total Cumul. Percent

Outage Date EFPY Insp. Plug DePI Insp. Plug DePI Ine. Plu PI Insp. Plug DePI Plug DePI Plugged Plugged Notes

Pre-op 0 3 _ 9 1 _ 13 0 13 0 06

RFO 13 10/15/99 5626 3 5623 0 5617 4 - 5625 3 10 0 23 0 10

RFO 14 05/03/01 5623 6 t 5623 12 5 613 _1 5622 6 _ 35 0 58 026 _

Totals: 9 0 15 0 24 0 10 0 58 0

Plant Data

Model. F

T-hot (approximate)-

Tubes per steam generator: 5626

Number of steam generators, 4

Acronyms

Pre-op = prior to operation

Cumul = cumulative

Insp = number of tubes inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refueling outage

-134-
Table 3-41: Salem 1 Causes of Tube Plugging

Year 1999 2001

Cause of Tube Plugging7Outage PreO RFO 13 |RFO 14

'AVB 8 29

Wear rha TS _ .

_____ _____ TSP_ _ _ _ _

Confirmed =

Not confirmed,

Loose Parts periphr ._ 2

Not confirmed, not

penpherv

Obstruction From PSI, no Restriction proqression _ Service-induced

Manufacturing Preservice 13 3

Ftaws Other 2

Probe lodged __ =

Inspection Data quality 3

Issues Dtnggeomelry_ ._ Permeabllity _ 1

Not Inspected .

Top of tubesheet

Other Free span _ _ TSP

Other/not reported

SCC ID ___

TOTALS| 131 101 35

Notes:1 I I 1 2

Totals

30

Totals

37

2

n O

( 0 0

13 i 2- 15 7

0

3

o 4

1

0

0

0

01

1 581 578

Notes

1. 2 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.

-135-
Table 3-42: Salem 1: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A - -

Tube Location RFO# Charactezation Stabilized'

1-3 Above 7C 14 Possible loose part indication aligned with one of tube support lands

58-48 5H+6 69 to 14 Permeability

5H+32 09'

STEAM GENERATOR B

Tube Location RFO # CharacterIzatIon Stabilized'

1-43 7H+2 17- 14 Data quality/obstruction

STEAM GENERATOR C

Tube Location RFO # Charactenzation Stabilized'

1-4 7H+5 81 14 Data quality- probe skipping/stalling

46-64 Tubesheet 13 Tube not fully expanded into tubesheeI

54-60 Tubesheet 13 Tube not fully expanded into tubesheet

STEAM GENERATOR D

Tube Location RFO 4 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

'An empty cell ndicates tnall i was not reponea wneuier Me tuDe was SiduImLzu ofr FUL

-136-
Table 3-43: Surry 1: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A SG B SG C Total Total Cumul. Percent

Outage Date EFPY Insp. DP su Pnsp. Plug DePuInsp. I DePI Plug DePI Plugged Plugqed Notes

Pre-op _1 i| _ 1 0 2 0 2 002

RFO 1 03/01/83 13 316 0 378 0 0 0 2 002 1

RFO2 11/01/84 23 858 3 562 1 4 0 6 006 . -

RFO 3 06/01/86 34 2869 0 1553 2 2874 2 4 0 10 0.10

RFO 4 04/01/88 4.7 788 0 788 0 0 0 10 0.10

RFO 5 10/01/90 60 152 0 8811 0 1 1246 2 1 2 0 12 012

RFO6 03/01/92 7.1 1170 2 1170 0 2 0 14 014

RFO 7 02/01/94 87 3339 4 4 0 18 018

RFO 8 10/01/95 100 = 3338 1 1 0 19 019

RFO 9 03/01/97 11 3 3336 5 5 0 24 024

RFO 10 10/01/98 127 3334 6 6 0 30 030

RFO 11 04/01/00 140 = = 3337 8 8 0 38 038

RFO 12 10/01/01 15.5 3331 5 - 5 C 0 43 043

I I- II_

Totals: 16 0 14 0 13 0 43 0

Plant Data

Model 51F - I

T-hot (approximate):

Tubes per steam generator 3342 -- - -- -

Number of steam generators 3 ---

Acronvm

Pre-op = pnor to operation

Cumul = cumulative

Insp = number of tubes inspected

Plug = number of tubes plugged

DePI = 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)

-137-
Table 3-44: Surry 1 Causes of Tube Plugging

Year _ _ 1983 1984 1986 1988 1990 1992 1994 1995 1997 1 998 2000 2001

Cause of Tube Plugging/Outage Pro-Op RFO 1 FO 2 RFO3 RFO4 RFO5 RFO6 RFO7 |RFO RFO9 RFO10 RFO11 RFO12

Wear PAVB TSP ( _ - _ - - _ 1 4 1 1 7 1 ITSP _ _ _ _

Confirmed

Not confirmed,

Loose Parts peripher- 3

Not confirmed, not _ pernihery

Obstruction From PSI, no

Resticton ession Restriction Service-induced - -_ - _ _ 3 _

Manufacturing Preservice 2 - . | = = .__

Fiaws Other t ! 2 - --

Probe lodqed - -

Inspection Data quality __= _ _ -__ __ _ ._ = __=

Issues Dent/geometry -___ __

Not Inspected

Top of tubesheet 1 _ _

Other Fre repan - --- _ 3 I |=tF- 1 

Other/not reported _____

I TOTALS| 21 0 41 41 0 21 21 41 1 51 61 8 5

Notes:| I I I 1 2 | | 3 | 1 4 | 4 5 |

Totals

15

0

0

0

3

0

Totals

15

3

o 7

71

2 1 1

61 8

0

0

0 1

41 9

0

0I 0

0 I

1 431 43

Notes

1. Assumed tube plugged for a restriction was service-induced.

2 A tube pulled for destructive examinabon was classified as a manufacturing fiaw.

3 Two tubes pulled for destructive examination revealed manufactunng flaws.

4. One tube plugged for Indication in U-bend attributed to interaction with (wear from) the tip of the AVB was classified as a free span Indication

5 Three tubes plugged as a result of mechanical damage from the sludge lancing equipment were classified as manufacturing flaws.

-138-
Table 3-45: Surry 1: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A |

Tube Location RFO # Charactenzation Stabilized'

1-9 TSC+16- 12 Mechanical damage due to sludge lancing equipment

1-28 TSC, TSH+16 12 Mechanical damage due to sludge lancing equipment

1 -35 TSC 9 Restnction

1-36 TSC 9 Restnction

1-37 TSC 9 Restnction

1-67 TSH+16- 1 2 Mechanical damage due to sludge lancing equipment

10-44 U-bend Freespan 12 Wear caused by bp of AVB

13-20 4H 6 31% throughwall indication associated with a dent

14-85 9 Permeability

36-58 TSH 2 60% throughwali indication

37-20 7H 2 89% throughwall Indication

39-60 5H 2 96% throughwail Indication

STEAM GENERATOR B

Tube Location RFO# Charactenzation Stabilized'

1-58 TSH 1 0 Restnction

1-59 TSH 1 0 Restnction

1-60 TSH 10 Restriction

111-4 2H to 4H 3 Multiple indications between 2H and 4H ranging from 33% to 53%

throughwall

32-14 FBH 10 22% throughwall possible loose part wear Indication

32-16 FBH 1 0 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

46-46 3H 2 44% throughwall indication

'An empty cell Indicates that it was not reported whether the tube was stabilized or not

-139-
Table 3-45: Surry 1: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

STEAM GENERATOR C

Tube Location RFO # Characte|zation Stabilized'

2-7 3 Restnction

10-53 Tubesheet 5 Tube pulled - no service induced degradation

11-38 U-bend Freespan 11 Wear caused by tip of AVB

25-57 Tubesheet 5 Tube pulled - no service induced degradation

40-70 7H 3 Tube pulled - no service induced degradation

'An empty cell indicates that it was not reported whether the tube was stabilized or not

-140-
Table 3-46: Surry 2: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. . SG A SG B SG C _ Total Total Cumul. Percent Outage Date EFPY Insp. Plug DePI Insp. P DePI Insp. P DePI Plug DePI Plugged Plugged Notes Pre-op 0 1 1 2 0 2 002 RFO1 12/01/81 1 1 0 0 0 0 2 002 1 RFO2 06/01/83 24 701 0 572 0 0 0 2 0 02 2 RFO3 04/01/85 3 6 535 0 534 0 0 0 2 002 Mid-Cvclo 06/01/86 4 5 23 1 1. 0 3 0 03 3 RFO4 10/01/86 4 7 586 0 1 580 0 C 0 3 0 03 RFO 5 10/01/88 529 786 0 781 0 0 0 3 0 03 RFO 6 03/01/91 7:2 1180 0 __ 1175 0 - 0 ____0 _ _ 3 0 03 __

RFO7 03/01/93 87 3342 2 = 2 0 5 005

RFO8 02/01/95 102 3340 5 - _ - 0 10 010 RFO9 04/01/96 11 2 3341 8 8 0 18 018

RFO10 10/01/97 12 5 3340 5 5 0 23 023 RFO 11 04/01/99 13 9 3335 8 1 9 0 32 032 _ RFO12 10/01/00 152 21 _ 3332 7 _ 7 0 J9 39 0 _391

Totals: 15 0 7 0 17 0 39

Plant Data

Model: 51F

T-hot (approximate):

Tubes per steam generator 3342

Number of steam generators: 3o,

Acronyms

Pre-op = prior to operation

Cumul. = cumulative

Insp = number of tubes inspected

Plug = number of tubes plugged DePI = number of tubes deplugged

RFO refuelinn niotan

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., itmited full-length inspections) 3. During a plant shutdown, a 21 gpd primary-to-secondary leak was investigated and 23 tubes were inspected.

-141-
Table 3-47: Surry 2 Causes of Tube Plugging

Year _ 11981 1983 1 1985 1 1986 1986 1988 1991 1993 1995 1996 1997 1999 2000

Cause of Tube Plugging/Outage Pre-Op RFO1 RFO2 RF03[ MId-Cy RFO 4 RFO 5 RFO 6 RFO 7 RFO 8 RFO 9 RFO10 RFO1 1 RF012

AVB _ I 2 3 3 7

Wear ?re-heater TSP (D5) I _ ___

TSP _ _............-_ -_ -

Confirmed

Not confirmed, . | 

Loos Parts e periphery _

Not confirmed, not

p_______ eripherv y

Obstruction From PSI, no

Rsrcinprogiression Restriction Service-induced j = 1 2 2 1

Manufacturing [Preservice_211_-__ -

Flaws Other _

Probelodged

Inspection 

Issues 

Data 

Dent/geometry 

quality ___ 

__ =_F__

I___

Not Inspected

Top of tubesheet 4 3 8

Other Ohr Free TSP span - _| _ - _ . _ _ ._ __

Other/not reported t t I =__ _ __ = =

scc ID _ _ _ __.

j TOTALS| 21 01 01 01 11 01 01 01 21 51 81 51 91 7

Notes: I I I I I 1 i | | 1 | 2 1 1 1 2

Totals

15

0

0

0

0

0

Totals

15

1

E

6

2

0

15

0

j 391 391

Notes

1. During a plant shutdown, a 21 gpd primary-to-secondary leak was Investigated

2 Top of tubesheet indications attributed to 'pitlike' Indications.

-142-
Table 3-48: Surry 2: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Characterization Stabilized'

1-36 8 Restnction

1-59 TSH 8 Restriction

4-36 TSC 8 Axially oriented anomaly - pitlike indication

4-43 TSC+2 44 11 Pitlike indication

4-45 TSC+2 3 11 Pitlike indication

TSC+3 2

6-38 TSC+3 8 11 Pitlike indication

TSC+4 2

6-39 TSC 8 Axially onented 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 11 Pitlike indication

TSC+5 47

7-50 TSC 8 Axially onented anomaly - pitlike indication

7-57 TSC+3 06 11 Pitihke indication

9-51 TSC+3 19 11 Pitlike Indication

41-28 TSC 1986 Confirmed loose part - part removed

STEAM GENERATOR B -

Tube Location RFO # | Charactenzation | Stabilized'

1-34 10 Restiction --

1-35 10 Restnction

STEAM GENERATOR C

Tube Location RFO # Charactenzation Stabilized'

1-36 TEH 9 Restnction

1-59 TEC 9 Restnction

25-13 TSC+2 2 11 Pitlike indication

31-27 TSH 9 Single axial anomaly

34-73 TSH 9 Single axial anomaly

35-68 TSH 9 Multiple axial anomaly

'An empty cell indicates that it was not reported whether the tube was stabilized or not.

-143-
Table 3-49: Turkey Point 3: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A SG B I SG C = Total Total Cumul. Percent Outage Date EFPY Insp. Plug DePt Insp. Plug DePI Insp. Plug DePI Pluq DePI Plugged Plugged Notes Pre-op 13 7 19 39 0 39 0 40 1 RFO 8 10/01/83 0 0 0 _ 0 39 0 40 2 RFO 9 06/01/85 276 0 420 4 199 0 4 0 43 0 45 RFO 10 06/13/87 _ 324 0 332 0 373 1 1 0 44 0 46 _ RFO 11 03/13/90 3203 2 _ 3205 3 3194 6 = 11 0 55 0.57

RFO 12 10/18/92 3199 1 3200 1 3188 5 1 7 0 62 0641

RFO 13 04/25/94 _ 3198 1 3199 1 3183 _2 _ 4 C0 66 068 RFO 14 09/19/95 3197 0 3198 2 _ 3181 0 2 0 68 071

RFO 15 03/19197 3197 3 3198 9 3181 2 - 14 0 82 0 85

RFO 16 10/08/98 10 7 3194 0 3187 1 3179 0 _ 1 0 83 0 86

RFO 17 03/15/00 12 2 1609 25 1601 28 _ 127 6_ 16 69 0 152 1 58 RFO 18 10/13/01 136 3169 1 315 11 = 3163 2 = 14 _ 0 166 1 72 _

Totals: 46 0 67 0 53 0 166 0

Plant Dta

Model 44F

T-hot (approximate):

Tubes per steam generator 3214

Number of steam generators 3

Acronyms

Pre-op = prior to operation

Cumul = cumulative

Insp. = number of tubes Inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refuelinn noutan

Notes

1. Number of tubes plugged Inferred from other inspection results

2. Extent of Inspections not readily available. No tubes were plugged dunng this outage.

-144-
Table 3-50: Turkey Point 3 Causes of Tube Plugging

Year 1983 1985 1987 1990 1992 1994 19 1997 | 1998 2000 2001 Cause of Tube Plugging/Outage Pre-Op RFO8 RF9 RF10 RFO 1 RF12RFO13 RF14 RFO15 1RF016 RFO17 RFO18

Wear PAV e eTSP 5) . 7 3 3 1 |- 5

ITSP ______12

Confirmed - - _ - -_ Not confirmed,

Loose Parts perlpery __ . _ _ _ 2 . _ . Not conflrmed, not

oerlhery _

Obstruction From PSI, no Restriction progession._ __ _. Service-induced 1

Manufacturing Preservice 39 _ ____ Flaws O0ther_| _ Probe lodged._ _ Inspection Da q. _______ isue Dent/geometry ___ Isu, Permablltv -

Not fnspected _ Top of tubesheet 3 1 2 1 8 64

Other ,Free span 1 2 4 1 . 64 

Other/not reported

SCC [ID.,_ ., [OD

TOTALS1 391 01 41 11 III 71 41 21 141 1 691 14

Notes: 1

Totals

22

0

12

0

Totals

34

2

01

1 1

1

39 39

0

0

0

0 0

0

0

79

3 - 0

0 _

0

1 1661 16

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

-145-
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 11 240-percent throughwall indication

10-31 TSH-0 15 17 Circumferential indication (reclassified as no service-related degradation) Y

13-5 TSH+3 8 15 No charactenzation 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+0.1 1 17 Volumetnc Indication (reclassified as a pit)

18-84 TSH+0 16 17 Volumetnc indication (reclassified as a pit)

19-84 TSH+0 91 17 Volumetnc Indication (reclassified as a pit)

TSH+0 46

21-32 6H+2.3 12 44-percent throughwall indication

21-87 TSH+0 68 17 Volumetnc indication (reclassified as no service-related degradation)

28-75 TSH+0 15 17 Volumetnc indication (reclassified as a pit)

29-75 TSH+O 14 17 Volumetnc

30-65 TSH+O 24 17 Volumetnc indication (reclassified as no service-related degradation)

31-18 6H+1 1 15 Volumetnc

31-77 TSH+0 1 17 Volumetnc indication (reclassified as a pit)

32-15 1 H-0 45 18 Wear

32-23 TSH-0 05 17 Circumferential indication (reclassified as no service-related degradation) Y

32-63 TSH+O 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 Volumetnc 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 Volumetnc indication (reclassified as no service-related degradation)

36-69 TSH+0 21 17 Volumetric

38-66 TSH+0.23 17 Volumetnc indication (reclassified as no service-related degradation)

39-67 TSH-0 05 17 Volumetnc indication (reclassified as no service-related degradation)

44-36 TSH+0 7 15 Volumetnc

'An empty cell indicates that it was not reported whether the tube was stabilized or not

-146-
Table 3-51: Turkey Point 3: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

- - STEAM GENERATOR BTube Location RFO # Charactenzation Stabilized'

1-3 18 Restnction In U-bend

1-14 TSH-0 28 17 Circumferential Indication (reclassified as no service-related degradation) Y

7-92 TSH+0 57 17 Volumetnc indication (reclassified as no service-related degradation)

8-8 tH+0 7 13 44-percent throughwall indication

15-17 TSH-0.06 17 Circumferential indication (reclassified as no service-related degradaton) Y

15-76 3H-0.7 18 Wear

19-10 TSH+0 24 17 Volumetnc indication (reclassified as a pit)

19-12 TSH+O 54 17 Volumetnc Indication (reclassified as a pit)

19-13 TSH+0 25 17 Volumetnc indication (reclassified as a pit)

19-14 TSH+O 29 17 Volumetnc indication (reclassified as a pit)

20-10 TSH+0 03 17 Volumetnc Indication (reclassified as a pit)

20-12 TSH+_ 21 17 Volumetnc Indicaton (reclassified as a pit)

20-13 TSH+0 03 17 Volumetric indicaton (reclassified as a pit)

21-56 TSH+0 43 17 Volumetnc indication (reclassified as no service-related degradation)

22-53 TSH+0 58 17 Volumetnc indication (reclassified as no service-related degradation)

23-7 TSH+0 58 17 Volumetnc indication (reclassified as no service-related degradation)

23-41 3C+0 5 15 Volumetn

25-32 4H+0 0 9 31-percent throughwall Indicabon

25-34 TSH+0 2 17 Volumetnc Indication (reclassified as no service-related degradation)

26-71 TSH+0 12 17 Volumetnc 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

28-41 3C+0 69 18 Wear

3C+0 61

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 degradabon) V

34-57 TSH+0.1 17 Volumetnc Indication (reclassified as a pit)

37-20 TSH+0 4 15 Volumetnc

37-46 TSH+0 04 17 Volumetnc indication (reclassified as a pit)

38-39 TSH+0 17 Circumferential indicabon (reclassified as a volumetric) Y

-147-
STEAM GENERATOR B

Tube Location RFO #| Charactenzation Stabilized'

38-45 TSH+0.16 17 Circumferential indication (reclassified as a pit) Y

38-46 TSH+0 59 17 Volumetnc indication (reclassified as a pit)

38-69 2H+0.99 18 Wear

39-39 5H+0 8 15 Volumetnc

39-59 TSH+0 19 17 Volumetnc indication (reclassified as no service-related degradation)

40-39 5H 11 2 40-percent throughwall indication

41-43 TSH+O 04 17 Volumetnc indication (reclassified as no service-related degradation)

41-44 TSH+O 6 15 Volumetnc

41-65 TSH+O 63 17 Volumetnc indication (reclassified as no service-related degradation)

42-30 TSH+0 4 9 36-percent throughwall indication

42-37 TSH+0.7 14 44-percent throughwall indication

42-38 TSH+1 5 15 Volumetnc

43-33 TSH+0 14 17 Volumetnc indication (reclassified as a pit)

44-40 TSH+0 3 15 82-percent throughwail volumetric indication, pit

TSH+1.8

44-41 TSH+0 2 15 Volumetnc

TSH+0 4

TSH+0 5

44-42 TSH+0 4 17 Volumetnc indication (reclassified as a pit)

45-41 TSH+O 6 15 Adjacent to a loose part so tube was plugged

45-42 TSH+1.3 15 Adiacent to a loose part so tube was plugged

45-43 TSH+0 6 9 56-percent throughwall indication

TSH+0 8

45-44 TSH+3 6 9 39-percent throughwall indication Tube was replugged in RFO13 since

TSH+3 8 plug was leaking

45-47 TSH+0 64 17 Volumetnc indication (reclassified as no service-related degradation)

'An empty cell indicates that it was not reported whether the tube was stabilized or not.

-148-
Table 3-51: Turkey Point 3: Tubes Plugged for Indications Other Than AVB Wear (cont'd)

STEAM GENERATOR C

Tube Location RFO # Charactenzation Stabilized'

1-20 TSH-0 12 17 Circumferential Indication (reclassified as no service-related degradation) Y

2-55 TSC+24 1 12 60-percent throughwall Indication

2-70 2C+0 7 12 45-percent throughwall Indication

3-46 TSH-0 08 17 Circumferential indication (reclassified as no service-related degradation) Y

7-3 TSH+0 09 17 Volumetnc Indication (reclassified as no service-related degradation)

13-89 TSC 11 Ž4O-percent throughwall indication

14-6 TSH 11 240-percent throughwall indicabon

14-89 CL 10 48-percent throughwall indication in sludge pile

15-44 TSH+O 03 17 Circumferential Indicabon (reclassified as no service-related degradation) Y

19-85 2H-0 78 18 Wear

20-66 6C+2 4 12 41-percent throughwall Indication

22-7 TSH+0.55 17 Volumetric Indication (reclassified as no service-related degradation)

23-7 TSH+0 59 17 Volumetnc indication (reclassified as no service-related degradation)

30-69 TSH-0 03 17 Circumferential Indication (reclassified as no service-related degradabon) Y

31-24 TSH+0.16 17 Circumferential indication (reclassified as a volumetnc Indication) Y

32-64 2H-0 59 18 Wear

33-66 TSH+0 6 15 58-percent throughwall indication

34-40 TSH-0 08 17 Circumferential indication (reclassified as no service-related degradation) Y

34-66 TSH+0 23 17 Volumetnc 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 volumetnc Indication) Y

45-49 TSH+2 89 17 Volumetnc indication (reclassified as no service-related degradation)

'An empty cell Indicates that it was not reported whether the lube was stabilized or not

-149-
Table 3-52: Turkey Point 4: Summary of Bobbin Inspections and Tube Plugging

Completion Cumul. SG A SG B | _SG C Total Total Cumul. Percent Outage Date EFPY Insp. TPlug DePI Ip. I Plu DOI oel Insp. Plug DePI Pluq DePI Plugqed Pluqed Notes

Pre-op 15 7 9 31 0 31 0 32 1

RFO9 05/15/84 211 0 162 0 502 0 0 0 31 032

RFO 10 03/16/86 328 0 _ 318 0 _ 345 0 0 0 31 032

RFO11 11/15/88 3199 1 3207 0 3205 0 1 0 32 033

RFO 12 05/13/91 3198 0 3207 1 3205 0 1 0 33 034

RFO13 04/28/93 3198 0 3206 0 3205 0 C 0C 33 0 34

RFO14 10/17/94 3198 0C 3206 0 3205 0 0 0 33 034

RFO 15 03/01/96 I_ 0 0 33 034

RFO16 09/22/97 3198 0 3206 0 3205 0 0 33 0 34 RFO17 03/01/99 _ 00 CC 33 034

RFO18 10/09/00 1602 3 1604 5 = 1607 2 = 10 0 43 045

Totals: 19 0 13 0 11 0 43 0

Plant Data

Model. 44F

T-hot (approximate)

Tubes per steam generator: 3214

Number of steam generators. 3

Acronyms

Pre-op = prior to operation

Cumul = cumulative

Insp = number of tubes Inspected

Plug = number of tubes plugged

DePI = number of tubes deplugged

RFO = refueling outage Notes

1. Number of tubes plugged was deduced based on information provided in various reports

-150-
Table 3-53: Turkey Point 4 Causes of Tube Plugging

Year 1984 1986 1988 11991 1993 1994 1996 1997 1999 2000

Cause of Tube Plugging/Outage IPre-Op |RFO RFO10| 11RFO 12|RF013 RFO14 RFO15 RFO16 RFO17 RF018

AVB T = =_1

Wear Pre-heater TSP (D5) I _ _ __ _

TSP __

Confirmed .==__, = i 

Not confirmed,

Loose Parts periphery _ ___ _

Not confirmed, not

Prent~herv

Obstruction From PSI, no

Restriction prqreqssion

Service-induced __ _ _ _ _ _ 1 _ __

Manufacturing Preservice 31_=_=

Flaws Other _ ___ _

Probe odjged -_

Inspection Data quality

Issues Pemteabotry - = 

Not inspected -

Top of tubesheet 7

Other Free span n = =

TSP__ ___ ___ ___ _

Other/not reported

SCC ID 0_ _ _

TOTALS| 311 01 01 11 1 01 01 0 0 0 10

Notes: I I I I I I I I I I I I

1

0

Totals

2

O 0

0

2

31

0

0

0

0

1

0

7

0

0

0

0

0

2

31

1

7

I

r 433T1 43

Notes

-151-
Table 3-54: Turkey Point 4: Tubes Plugged for Indications Other Than AVB Wear

STEAM GENERATOR A

Tube Location RFO # Charactenzation Stabilized'

2-5 HL Tubesheet 11 Clamp stuck inside tube. Attempts to retneve were unsuccessful

12-25 18 Permeability signal in expansion transition area

26-80 TSH+2.27 18 Pit

33-73 TSH+0 17 18 Volumetnc indication

STEAM GENERATOR B

Tube Location RFO Characterization Stabilized'

2-90 FBH-0 46 18 Wear

8-81 TSH-2.0 12 Restnction

20-80 TSH 18 Pit

21-80 TSH+0 05 18 Pit

29-62 TSH+0 12 18 Pit

43-51 TSH-0 04 18 Pit

Tube | Location RFO # Charactenzation Stablized'

3-91 TSH+0 18 Pit

'An empty cell indicates that it was not reported whether the tube was stabilized or not

-152-
4 SUMMARY

The following sections summarize the operating experience presented in Section 3.

Summaries are provided for each of the three groupings of plants (i.e., model D5, model F, and

replacement models). There is also a combined summary. The combined summary includes a

discussion on tubes removed for destructive examination, discussion on unscheduled steam

generator outages (i.e., forced outages), and observations regarding the results from the

inspections.

4.1 Model D5 Summary

There are a total of 73,120 thermally treated tubes in the four plants with model D5 steam

generators. Cumulatively, these four plants have operated for 51 calendar years (as of

December 2001), and have commercially operated for an average of 13 calendar years (as of

December 2001). Of the 73,120 tubes in these steam generators, only 563 tubes (0.8%) 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 53% of the tubes-were plugged as a

result of tube wear. This wear occurred predominantly at the antivibration bars (AVBs),

although some occurred at tube support plates and near loose parts. With only a few 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 (17%) of the tubes were plugged as a result of

flaws attributed to manufacturing.

Figures 4-2 and 4-3 depict the number of tubes plugged at each plant as a function of year and

refueling outage, respectively. These figures indicate, for the most part, that the four plants are

operating similarly. The information in Figure 4-2 is summarized in Tables 4-3 and 4-4. The

information in Figure 4-3 is summarized in Table 4-5.

Figure 4-4 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 4-6, 4-7, and 4-8. In this figure,

tubes plugged prior to commercial operation were treated as being plugged during the year the

plant began commercial operation (in previous tables and figures in this report, tubes plugged

prior to 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 plants with D5 steam generators typically performed

bobbin coil inspections in all four steam generators during each refueling outage in the 1990s.

In addition, with the exception of Comanche Peak 2, these inspections usually involved a large

percentage of the tubes (i.e., greater than 50%). In 2000 and 2001, these plants began

reducing the number of steam generators inspected and/or the number of tubes inspected

during the refueling outage. For example, in 2000 Comanche Peak 2 only inspected two steam

generators, and in 2001 Byron 2 only inspected one steam generator.

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4.2 Model F Summary

There are a total of 117,376 thermally treated tubes in the six plants that originally installed

model F steam generators in their plants. Cumulatively, these six plants have operated for

approximately 88 calendar years as of December 2001, and have commercially operated for an

average of 15 calendar years (as of December 2001). Of the 117,376 tubes in these steam

generators, only 434 tubes (0.4%) 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, approximately 74% of the tubes were plugged as a

result of tube wear. This wear occurred predominantly at the AVBs, although some occurred

near loose parts. No (or a very limited number of) tubes have been plugged for wear at the

tube support plates. In addition to tube wear, many (14%) of the tubes were plugged as a

result of manufacturing flaws.

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 4-6 and 4-7 depict the number of tubes plugged at each plant as a function of year and

refueling outage, respectively. These figures indicate, for the most part, that the six plants are

operating similarly. The information in Figure 4-6 is summarized in Tables 4-11 and 4-12. The

information in Figure 4-7 is summarized in Table 4-13.

Figure 4-8 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 4-14, 4-15, and 4-16. In this figure,

tubes plugged prior to commercial operation were treated as being plugged during the year the

plant began commercial operation (in previous tables and figures in this report, tubes plugged

prior to 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 plants with model F steam

generators typically inspect 100% of the tubes in two of the four steam generators each

refueling outage. Of particular note, however, is that the majority of the tubes at Callaway are

mill-annealed.

4.3 Replacement Model Summary

There are a total of 90,766 tubes in the eight plants with replacement steam generators that

contain thermally treated Alloy 600 tubes. Cumulatively, these eight plants have operated for

approximately 120 calendar years as of December 2001, and have commercially operated for

an average of 15 calendar years (as of December 2001). Of the 90,766 tubes in these steam

generators, only 400 tubes (0.4%) have been plugged. This information is summarized in

Table 4-17.

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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 31% of the tubes were

plugged as a result of tube wear. This wear occurred predominantly at the AVBs although

some occurred near loose parts. No (or a very limited number of) tubes have been plugged for

wear at the tube support plates. Replacement steam generators appear to be less susceptible

to wear at the AVBs than the model F steam generators as evidenced by operating experience

and evaluations. In addition to tube wear, many (33%) of the tubes were plugged as a result of

manufacturing flaws.

Figures 4-10 and 4-11 depict the number of tubes plugged at each plant as a function of year

and refueling outage, respectively. These figures indicate, for the most part, that the eight

plants are operating similarly with the possible exception of Salem 1, which has Model F steam

generators, and Turkey Point 3, which has plugged significantly more tubes than the other

plants. The information in Figure 4-10 is summarized in Tables 4-19 and 4-20. The information

in Figure 4-11 is summarized in Table 4-21.

Figure 4-12 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 4-22, 4-23, and 4-24. In this

figure, tubes plugged prior to commercial operation were treated as being plugged during the

year the plant began commercial operation (in previous tables and figures in this report, tubes

plugged prior to 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 plants with replacement

steam generators with thermally treated Alloy 600 tubes have a variety of strategies for

inspecting their steam generators. Several plants inspect a subset of steam generators each

refueling outage (e.g., one of three steam generators is inspected each 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." Yet

others inspect all steam generators every outage. Plants that skip cycles or skip steam

generators typically inspect 100% of the tubes in the steam generators inspected.

4.4 Overall Summary

4.4.1 Forced Outages

As of December 2001, the steam generator operating experience of plants with thermally

treated Alloy 600 has been favorable. These plants account for approximately 25% of the

currently operating PWRs. A historical review identified only six unplanned outages as a result

of steam generator issues in plants with thermally treated Alloy 600 tubes: two due to

primary-to-secondary leakage and four due to indications of loose parts (e.g., loose parts

monitor alarms). These six outages are discussed below. (During the preparation of this report

in the first half of 2002, two additional unplanned outages attributed to steam generator issues

occurred. One of these was attributed to leakage and one was attributed to an indication of a

loose part. These are briefly discussed below.)

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Only two plants with thermally treated Alloy 600 tubes have experienced any significant

primary-to-secondary leakage. One of these plants, Byron 2, entered a refueling outage early

as a result of a 120-gallon-per-day primary-to-secondary leak in 1996. The cause of the leak

was a foreign object attributed to thermal-cutting debris from a pipe whose diameter was

somewhere between 12 and 18 inches. The foreign object was located on the secondary side

of the steam generator. This object damaged four tubes and the tubes were plugged. One

tube had a 100% throughwall indication, one had a 56% throughwall indication, and the

remaining two tubes were plugged as the result of nonquantifiable volumetric indications found

by a rotating pancake coil probe. The other plant, Surry 2, shut down in June 1986 as a result

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 steam generator tube 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 as a result of this outage. Other plants (e.g., Seabrook) have experienced

amounts of leakage (< 5 gallons per day) too small to necessitate a plant shutdown. The

sources of such small amounts of leakage are usually never conclusively identified. (As

mentioned in the Executive Summary, Byron 2 shut down in June 2002 as a result of a 75- to

80- gpd primary-to-secondary leak. Preliminary investigations indicate the cause of the leak

was a loose part.)

In February 2000, the licensee for Point Beach 1 shut down the unit 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 was shut down in response to a possible loose part on the primary side

of steam generator 4. Upon entering the hot-leg channel head, licensee personnel found a

support pin nut from a control rod guide tube assembly. 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, the licensee for Robinson 2 shut down the facility for repairs to an emergency

diesel generator. During this shutdown, the licensee also investigated a loose parts monitor

alarm. 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 from the

steam generators 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 due to either

outside diameter wear or manufacturing marks. These indications may have been related to

the loose part.

On April 3, 1989, the licensee for Robinson 2 shut down the unit as a result of audio signals

indicating a loose part in the hot-leg channel head of steam generator C. When the licensee

opened the steam generator manway, 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

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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.

(As briefly discussed in the Executive Summary, Wolf Creek was shut down in May 2002 as a

result of a loose part located on the primary side of the steam generator. The part was a

control rod guide tube support pin nut and locking device.)

4.4.2 Tube Pulls

To characterize eddy current indications found during steam generator tube inservice

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 only been

removed from two such plants as of December 2001: Surry 1 and Byron 2. The results of

these examinations are discussed below. (During the preparation of this report in the first half

of 2002, portions of two tubes were removed from Seabrook as discussed below.)

* In 1998, Byron 2 removed portions of three tubes with circumferential indications at the

hot-leg expansion transition region for destructive examination. A total of 29 tubes with

circumferential indications were identified and plugged and stabilized 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

700 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

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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 plants with thermally treated Alloy 600 to

characterize these indications.

(As discussed in the Executive Summary, portions of two tubes were pulled from Seabrook in

May 2002 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. In all

15 tubes were found to have indications at 42 tube support plate intersections. The maximum

depth of the indications was estimated to be 62% throughwall and the lengths ranged from 0.3

to 0.75 inch. The NRC issued Information Notice 2002-21, 'Axial Outside-Diameter Cracking

Affecting Thermally Treated Alloy 600 Steam Generator Tubing," on June 25, 2002, describing

the nondestructive examination results from Seabrook. 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.)

4.4.3 Selected Inspection Findings

Some of the more noteworthy findings from inspections of thermally treated Alloy 600 tubes are

summarized below. Except as noted, the tubes discussed below were plugged. In addition,

none of these tubes were removed for destructive examination except for two of the tubes at

Seabrook (as discussed in Section 4.4.2).

* As briefly discussed in the Executive Summary, axial crack-like indications were detected at

42 tube-to-tube-support-plate intersections in 15 tubes at Seabrook in May 2002. Two

tubes were pulled to characterize the nature of the degradation., 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.

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* 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 due to

loose parts and to fabrication-related defects.

* At Turkey Point 3 in 2001, 12 tubes were plugged as a result of indications of mechanical

wear at the broached tube support plates. Plugging of tubes for wear at tube support plates

is fairly rare in plants with thermally treated Alloy 600 tubes.

* At Turkey Point 3 in the spring of 2000, 41 volumetric pitlike indications, 15

inside-diameter-initiated circumferential indications, and 8 outside-diameter-initiated

circumferential indications were identified. 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 extensively used at Turkey Point 3. As a result of these findings, the

licensee began a review of historical data and industry experience, during the outage, 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 due to 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 since 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 Information Notice

2001-016, "Recent Foreign and Domestic Experience With Degradation of Steam Generator

Tubes and Internals."

* At Surry 1 in 2000 and 2001, 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 located at (or near) the

edges of the support plate.

* At Braidwood 2 in 1996, one axial indication was detected in a small-radius tube (in row 1).

The licensee concluded at that time that the most likely cause for this indication was primary

water stress corrosion cracking (PWSCC).

* 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.

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__ 

1

* At Millstone 3 in August 1993, a tube was deplugged in order to replace the plug with a

more corrosion-resistant material. This tube had been plugged in 1989 as a result of a 43%

throughwall wear indication at the fifth anti-vibration bar. During the 4 years the tube was

plugged, the defect had apparently grown from 43% to 100% 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,

located 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.

* At Surry 2 in the mid-1990s, the licensee began detecting a limited number of pitlike

indications above the tubesheet on the cold-leg side of the steam generator. The licensee

used the rotating pancake coil terrain plot display as the primary basis for classifying the

signals as pitlike indications. The indications were nearly round and were located in the

cold leg above the tubesheet expansion 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 which was

performed in 1994. New pits are unlikely to initiate in future cycles because the licensee

removes copper-rich sludge, the major contributor to pitting, and has improved its chemistry

control program. The licensee eventually plugged all 12 tubes with pitlike indications due to

the uncertainty in nondestructive sizing estimates.

4.4.4 Summary and Observations

As depicted in Figure 4-13, there were 281,262 thermally treated Alloy 600 tubes placed in

service at 18 plants between 1980 and 2001. Cumulatively, these 18 plants have operated for

approximately 260 calendar years (as of December 2001) and have commercially operated for

an average of 14 calendar years (as of December 2001). Of these 281,262 tubes, only 1397

tubes (0.5%) have been plugged. The number and percentage of tubes plugged at the 18

plants with thermally treated tubes are summarized in Table 4-25. Figure 4-14 depicts the total

number and percentage of tubes plugged in plants with thermally treated Alloy 600 tubes as a

function of model/grouping (i.e., model D5, model F, replacement models).

Tables 4-26 and 4-27 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. Of the

approximately 1400 tubes plugged, approximately 53% of the tubes were plugged as a result of

tube wear. Tube wear occurs as a result of contact between the tube and a support structure

(e.g., an anti-vibration bar) or a foreign object (e.g., a loose part). Loose parts can be

introduced during steam generator fabrication, during maintenance activities, or as a result of

corrosion degradation of other components in the primary or secondary side of the steam

generator (e.g., a split pin nut). The rate of tube wear from support structures is generally

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predictable and is readily managed. Wear from loose parts is usually unexpected and can only

be detected by inspection, loose parts monitoring systems, or primary-to-secondary leakage.

The wear in thermally treated tub6s has occurred predominantly at the AVBs although some

occurred near loose parts. A very limited number of tubes have been plugged for wear at the

tube support plates.

The percentage of tubes plugged for wear is greater for the Model F steam generators than for

the Model D5 or replacement model steam generators. Manufacturing flaws also accounted for

a significant percentage of tube plugging, accounting for 21% of the tubes plugged. The

plugging of 23% of the tubes was attributed to "other" degradation mechanisms. Several tubes

have been plugged due to restrictions. The nature and causes of many of these restrictions

have not been provided.

Plants with replacement steam generators with thermally treated Alloy 600 tubes have a variety

of strategies for inspecting their steam generators. Several plants inspect a subset of steam

generators each refueling outage (e.g., one of three steam generators is inspected each

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." Yet others inspect all steam generators every outage. Plants that skip cycles or

skip steam generators typically inspect 100% of the tubes in the steam generators inspected.

In general, licensees with thermally treated Alloy 600 tubes inspect a subset of the total number

of steam generators during an outage (e.g., two of four steam generators are inspected during

one outage and the remaining two steam generators are inspected during the next outage).

Such inspection programs result in an inspection frequency for thermally treated Alloy 600

tubes of every two cycles. At a few plants, steam generators are inspected every three

operating cycles (e.g., at intervals of 48 effective full-power months).

Based on a review of inspection summary reports, tube inspections in plants 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 consistent with

Nuclear Energy Institute 97-06, "Steam Generator Program Guidelines." There have been no

reported instances in which a thermally treated Alloy 600 tube did not satisfy the structural

performance criterion (e.g., three times the normal operating differential pressure).

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 been

relatively constant since the early 1990s. The data used to compile these figures is

summarized in Table 4-28.

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 4-29, 4-30, and 4-31. In this

figure, tubes plugged prior to commercial operation were treated as being plugged during the

year the plant began commercial operation (in previous tables and figures in this report, tubes

plugged prior to operation were treated as a distinct group independent of the actual

year/outage in which they were plugged).

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As a result of reviewing the operating experience with thermally treated Alloy 600 steam

generator tubes, the following observations are made:

* A number of plants with mill-annealed Alloy 600 tubes stabilize tubes as a result of finding

circumferential indications. Stabilization is intended to prevent a plugged tube from

contacting neighboring tubes in the event that it severs. A tube could sever as a result of

tube degradation that continues to progress following plugging. Some plants assess the

need to stabilize forms of degradation (e.g., wear) other than circumferential indications and

preventively stabilize tubes when indications reach or are projected to reach certain limits.

* At least one plant identified a tube that continued to wear following plugging. The wear

indication proceeded throughwall after being plugged four years earlier with a 43%

throughwall indication. The potential for tubes to continue to degrade following plugging

raises questions about the need for tube stabilization in the future.

* Plugging of tubes for wear at tube support plates is fairly uncommon in plants with thermally

treated Alloy 600 tubes. Recently plants have reported plugging tubes for this form of

degradation. In addition, plants have been observing denting at tube supports

corresponding to the quatrefoil lands.

* Some plants cut out access ports in the steam generator shell in order to remove loose

parts. Plants remove the loose parts to prevent the initiation or continuation of wear

degradation to tubes and/or to avoid preventively plugging and stabilizing tubes that may

potentially be affected by these loose parts.

* Several plants, if not all, plug stub tubes since these locations are not routinely inspected

during the inservice inspection.

* Several plants have reported tube expansion anomalies in the tubesheet. These areas are

locations where degradation is likely to occur. These anomalies include tubes that were not

expanded, tubes that were not expanded for the full length of the tubesheet, and tubes that

were expanded above the top of the secondary face of the tubesheet. For tubes that were

not expanded, some plants have plugged these tubes while others have reexpanded the

tubes to avoid inspecting these tubes every outage (presumably with a rotating probe).

Tubes that were not expanded do not appear to be found until well after the start of

operation. When a tube was not fully expanded for the full length of the tubesheet, the

expansion transition occurs below the secondary face of the tubesheet, resulting in an open

crevice region where sludge deposits can accumulate. The expansion of a tube above the

top of the secondary face of the tubesheet is an anomaly which results in an area of higher

stress. Some plants inspect all identified expansion anomalies with a rotating probe.

* Performing tube inspections concurrent or after maintenance activities (e.g., sludge lancing)

may make it difficult to assess the cause of indications since the maintenance activities may

cause the loose parts to move . On the other hand, performing tube inspections before

maintenance activities may result in missing indications of degradation induced during these

activities and/or result in missing opportunities to find loose parts introduced as a result of

these activities.

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* Manufacturing buff marks (MBMs) and free span differential (FSD) signals are the result of

a light buffing of the tubes to remove small imperfections of the tubing outside diameter.

The two types of signals are generally analogous, except that the FSDs are readily

discernable in the differential channels of the eddy current data, whereas MBMs are called

in the absolute channel. Historical reviews are frequently performed for MBMs and FSD

signals to determine if they have changed phase angle and/or voltage since the baseline. If

the signal changes, supplemental rotating probe testing is typically performed.

* The few tubes pulled for destructive examination suggest that manufacturing anomalies or

some other phenomena are producing eddy current signals indicative of degradation. The

ability of the nondestructive examination techniques to distinguish true flaw signals from

these anomalous inspection signals may become important as the second-generation

steam generators age (and the potential for corrosion increases). Performing

comprehensive baseline inspections before the steam generators are placed in service

could provide confidence that "anomalous" nondestructive examination signals are truly

signals from manufacturing marks rather than from service-induced conditions.

* Plants initially identify manufacturing flaws well after placing the steam generators in

service. This is attributed to many factors including more stringent calling criteria,

improvements in analyst performance, and improvements in inspection technology.

* Plants have found a number of indications (volumetric and linear) for which no definitive root

cause was identified (although plausible explanations for the indications were put forward).

The frequency of finding such indications appears to be increasing.

* A number of volumetric indications attributed to tube wear have been detected in the

midspan of tubes and/or in the interior of the tube bundle. Material reviewed during the

development of this report contained no insights on how a foreign object moves deep into

the interior of the tube bundle without damaging other tubes on its path. In addition, no

information was available on whether an object was found or retrieved near the location of

the tube wear in many of these cases.

* Obstructions to the passage of bobbin coil probes have been identified in a few tubes.

These obstructions were often identified only after a number of years of operation. The

causal mechanism for these obstructions was not readily ascertainable. Obstructed tubes

were reported at Callaway in 1996 (in a tube inspected in 1992), Comanche Peak in 1997,

Surry 1 and 2 in the mid-1990s as well as in 1986, Vogtle 1 in 1997, and Robinson 2 in

2001.

* Volumetric indications have been detected at several plants. The cause of these indications

has not been determined through removal of tubes for destructive examination. Destructive

examination might provide insights on the nature of the indications. Volumetric indications

have been reported at a number of plants, including Braidwood 2 in 1996 (1 H), Byron 2 in

1996 (2C and 1 H), Byron 2 in 2001 (above 2C), and at Wolf Creek in various years.

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

-163-
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 due to the thermal treatment process that has superseded the mill

annealing process used in earlier steam generator designs.

The relatively good operating experience for plants 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 plants whose tubes were expanded mechanically or explosively. Since 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.

This historical review has identified a number of issues which may warrant additional

investigation in the future.

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

(including cracking) and to assure the structural and leakage integrity of the tubes during the

intervals between inspections. A better understanding of the nature of a number of these

findings would be useful in determining appropriate intervals for future monitoring of tube

degradation.

-164-
Table 4-1: Model D5: Total Number and Percentage of Tubes Plugged (12/01)

Plant || Number of Tubes I I Percent Plugged I Operating Time2 1

l Plugged' l l l

Braidwood 2 120 0.66 13

Byron 2 223 1.22 14

Catawba 2 183 1.00 15

Comanche Peak 2 37 0.20 8

TOTALS: 563 0.77

1

As of 12/31/01

2Operating Time = calendar years of operation as of 12/31/01

-165-
Table 4-2: Model D5: Number of Tubes Plugged as a Function of Mechanism (Detailed) (12101)

Tubes Percentage Tubes Percentage Cause of Tube Plugging Plugged of Plugs Plugged of Plugs

AVB 258 45.8%

Wear Pre-heater TSP (D5) 2 0.4% 262 46.5%

TSP 2 0.4%

Confirmed 19 3.4%

Not Confirmed,

Loose Parts Periphery 16 2.8% 38 6.7%

Not Confirmed, Not

Periphery 3 0.5%

Obstruction From PSI - no

Restriction progression 0 0.0% 2 0.4% Service Induced 2 0.4%

Manufacturing Preservice 50 8.9%

Flaws Other 44 7.8% 94 16.7%

Probe Lodged 2 0.4%

Inspection Data Quality 2 0.4% Issues DentGeometr 4 0.7% 15 2.7%

Permeability 4 0.7%

Not Inspected 3 0.5% /

Top of Tubesheet 18 3.2%

Other Free Span 80 14.2% 152 27.0%

TSP 44 7.8%

Other/Not Reported 10 1.8%

SCC 0D 0 0.0% 0 0.0%

TOTALS| 5631 100.0%| 5631 100.0 % |

Total Tubes: 73120

Fraction Plugged 0.77%

-166-
Table 4-3: Model D5: Cumulative Plugging Per Year

Comanche

Year Braidwood 2 Byron 2 Catawba 2 Peak 2

Pre-Op 6 11 14 20

1986 .

1987 14

1988 21

1989 22 29

1990 8 43 48

1991 19 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

-167-
Table 4-4: Model D5: Plugging Per Year

Comanche Model D5 Year Braidwood 2 Byron 2 Catawba 2 Peak 2 Totals

Pre-Op 6 11 14 20 51

1986 0 1987 0 0 1988_____7 7 1989 11 8 19

1990 2 21 19 42

1991 11 12 23 1992 29 29

1993 15 36 43 94

1994 6 _____ 31 0 37 1995 29 23 0 52

1996 35 30 0 65

1997 28 10 8 46 1998 38 9 47

1999 6 14 5 25 2000 11 ____ 7 4 22

2001 -41 0 ______ 4

Totals: 120 223 183 37 563

-168-
Table 4-5: Model D5: Cumulative Plugging Per RFO

Comanche

Outage Braidwood 2 Byron 2 Catawba 2 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

RFO 7 109 205 157

RFO 8 120 219 167

RFO 9 223 176

RFO 10 183

RFO 11 1831

-169-
Table 446: Model D5: Number of Tubes Plugged As a Function of Mechanism Per Year (Detailed)

Cause of Tub

Wear

Looe Part.

Obstruction

Restricton

Manuficturdng

Flaws

Inspodblon Issues

Other

SCC

Ah

IPr

N4

=l

to

VI

e-h"aterTk.'{U5) | - ;pI- --- I---

II

{ r

A Conirmned, lo-Cnimt

....-_ _ ....._,-

1. .I &--- .totre w It _ ._ ....... _ _1 -__- T..i - t I-) _, i-- -4-

.. ...... _. -_

r l Ixsn l| I I I | I ! i 1 l 21

pr-ol

SPe

0th

Prot

Pen

Not

Fro

TSF

Not

toD

OD

aresslo .

Total. Totls1

2582 252

2

1 9

16 38

3

o2

2h- o

44 94

2

2

4 1 5

4

3

1 _

152

10_

i 831 5031

Lqgegm.

... .f...- f- .. --.i-- I- -. -.

i- No-ts

h2in

-170-
Table 4-7: Model D5: Number of Tubes Plugged As a Function of Mechanism Per Year (Summary)

Year 1980 198i 1982 983 1984 1985 1986 1987 988 1 11990 98 9 1991 1992 1993 1t994 1995 1996 1997 198 1999 2000 00

Cause I__

Wear = -= 2 35 17 25 51 7 22 48 1 _3 6 1_

2oose1Parts__B 612 3__12 3_ Riestrictions ___ ___

Manufacturning - _ 14 11 1 6 - 15 19 =2._ 29 

Oaethern Issues 3 5 __

___ -1 5thr 7 6 4 43 30 22 1 5 2_ 1

01 0o 0o 0o 01 01 141 11 131 191 421 231 291 1141 371 521 651 461 471 251 221 4

Notes i I I I I I I

Total

262

38

2

94

152

0

I6rn 3

Not

-171-
Table 4-8: Model D5: Fraction of Tubes Plugged As a Function of Mechanism Per Year (Summary)

CauseI Year 1981 1982 - 1983 1 

_ 198 19851 198 1989 9 1991 1992 1993| 1994 :1995 198 1997 1 988 2000 2001 Wear. ______t__ J 083 074 086 045 019 042 4--. ...... 074_041 _7011 06064 068 i ._0 ..06_024 R-festrIctions - - - 4 26__~o - 0 ___

Inspaction Issues -01

Other 038 . _- ___ 1 2 _00 009 .006 0 08 23 sCc __38_ 01 0026 015 0 11 015 008 02 I___ __ I_

0 001 0001 0001 0001 000 000 1001 100 100I 1001 1001 1001 1001 1001 1001 100| 1001 1001001 100 100 100I

Notes I

Totals

0 47

10001 0t17

0 03

027

j1 001

-172-
Table 4-9: Model F: Total Number and Percentage of Tubes Plugged (12/01)

| Plant I Number of Tubes Percent Plugged | Operating Time2

Plugged, l l

Callaway3 17 0.35 17

Millstone 3 106 0.47 16

Seabrook 1 90 0.40 11

Vogtle 1 48 0.21 15

Vogtle 2 29 0 13 13

Wolf Creek 1 144 0 64 16

TOTALS: 434 0.37

'As of 12/31/01

2Operating Time = calendar years of operation as of 12/31/01

3

Thermally Treated Tubes only

-173-
Table 4-10: Model F: Number of Tubes Plugged as a Function of Mechanism (Detailed) (12101)

Tubes Percentage Tubes Percentage Cause of Tube Plugging Plugged of Plugs Plugged of Plugs

AVB 295 68.0%

Wear Pre-heater TSP (D5) 0 0.0% 295 68.0%

TSP 0 0.0%

Confirmed 9 2.1%

Not Confirmed,

Loose Parts Periphery 10 2.3% 24 5.5%

Not Confirmed, Not

Periphery 5 1.2%

Obstruction From PSI - no

Restriction progression 0 0.0% 2 0.5% Service Induced 2 0.5%

Manufacturing Preservice 63 14.5%

Flaws Other 0 0.0% 63 14.5%

Probe Lodged 0 0.0%

Inspection Data Quality 0 0.0% Issues Dent/Geometry 0 0.0% 0 0.0%

Permeability 0 0.0%

Not Inspected 0 0.0%

Top of Tubesheet 19 4.4%

Other Free Span 13 3.0% 50 11.5%

TSP 18 4.1%

Other/Not Reported 0 0.0%

SCC 0D 0 0.0% 0 0.0%

TOTALS| 4341 100.0%| 4341 100.0%

Total Tubes: 117376

Fraction Plugged 0.37%

-174-

I
Table 4-11: Model F: Cumulative Plugging Per Year

Outage |Callawa Millstone3 Seabrook Vogtlel Vogtle2 Wolf Creek

Pre-Op4 10 13 6 15 15

1986 4 r 15

1987 5 12

1988 _ 7 37

1989 6 16

1990 6 11 15 39

1991 21 23 11 39

1992 7 23 15

1993 7 28 15 15 44

1994 24 27 71

1995 11 39 36 18

1996 16 41 31 24 87

1997 49 46 _ _ __ 106

1998 16 24

1999 16 55 74 46 29 112

2000 90 48 144

2001 17 106 291

-175-
Table 4-12: Model F: Plugging Per Year

Model F Outage Callaway Millstone 3 Seabrook Vogtle 1 Vogtle 2 Wolf Creek Totals Pre-Op 4 10 13 6 15 15 63 1986 0 0 0

1987 1 2 3 1988 _ _ 1 = 1 = 22 23

1989 1 4 0 0 a_5 O5

1990 0 4 0 2 6

1991 ______5 10 0 ______0 15

1992 1 0 __ _ _ _ _0 1

1993 0 7 4 0 5 16

1994 ______1 12 ______27 40

1995 4 11 12 3 30

1996 5 2 4 6 16 33

1997 13 15 19 47

1998 0 0 0

1999 0 14 25 0 5 6 50 2000 16 2 32 50

2001 1 51 _ _0 52

Totals: 17 106 90 48 29 144 434

-176-
Table 4-13: Model F: Cumulative Plugging Per RFO

Outage Callaway Millstone 3 Seabrook Vogtie 1 Vogte 2 Wolf Creek

Pre-Op 4 10 13 6 15 15

RFO1 4 12 23 7 15 15

RFO2 5 16 23 11 15 15

RFO3 6 21 24 11 15 37

RFO4 6 28 36 15 18 39

RFO5 7 39 49 27 24 39

RFO6 7 55 74 31 24 44

RFO7 11 106 90 46 29 71

RFO8 16 46 29 87

RFO9 16 48 106

RFO10 16 112

RFO11 17 144

-177-
Table 4.14: Model F: Number of Tubes Plugged As a Function of Mechanism Per Year (Detailed)

Weer I

qj. ... _...- I_.---_I

.ro-hater TSPJD5) rspI I ..... . .... . t ....... . .... --- . - "" 1- -- -t '" 1 -~~ '',- -' -- I---t I- --- ~l-~- - !---- --- -~ - IConl.med I I i i i i ; I I

Laoa. Parts Nt

P4

NIm

)I Confrlmd.

At Confrmed, Not

.- I '1--- i 1 ........ . .t.. - .. .. -. ----. ..-- ............ . . ....- -. . . .. t-t-.i.-...... ..... 1 -.-- 6

!- -n - I =rPtSI -no i i ; i i i i i i i i I 2jI, 1 21 1 I

esetriction

Manutacturing

Flaws

Inspettion Issues

Other

PtF

Pi

F

Pi

N,

.i

F

T!

N,

oq.assaoli ..-. . 1 .. -- _ , .- -- 2 †I.... 

Totals

295

0

0

9

10

S

0

2

63

0

00

0

0

0

19

13

is

0

Total.

295

24

2

63

50

o

hta lually

hi4 /e r ety j.. _ = =. .-- --. I ----- i-1 --

a. Span t 1- - -... 41 t .._ 0' i _.t.. . I ....... .I 2

[ 2

.i'I- ...... .. ...-.......- ............. -- -. .. ....- .. . - | ---- - - I; -- , i ! i . scc C ............. ...ID . t .- .. - ...... , -- - ----.---- -! - -F.1-- - .1--------

j 4341 4341

i No~t.

-178-
Table 4-15: Model F: Number of Tubes Plugged As a Function of Mechanism Per Year (Summary)

Year 1980 1981 1982 1983 1 1984 I 1988 1987 1988 i 1989 1 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Cause T otls

Wear - 2 19 3 6 II __. _16 38 26 2 3 _ 49 44 15 295

Los as_417__1 3 7 24

4anfaturng10 6 15 13 -- 63 Inspection Isues .- E -! - _6 4_ i> -_2_ - : -- 016

Other __ -1 22 2 5_ 3 30 so

sC c _ __ __ _ __I__ _I__ _ __ _ I___ 

I 01 01 01 01 41 151 101 91 231 201 191 151 11 161 401 301 331 471 01 50 50 52 434

Notes I I I I I I I

-179-
Table 4-16: Model F: Fraction of Tubes Plugged As a Function of Mechanism Per Year (Summary)

Cause ar 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 I 1990 _1991 1992 1993 1 994 1995 1991_ 1997 1998 91299 2000 2001

Wear 0 22 0 83 _ 0 15 032 073 1 00 0 95 0 __7 0 _8 0 81=

Restrictions - 0

ePat __ . _ ._ 027 00 .__..__. _01 00 00. ,_. _ _

Other - .0 11 0 17 010 _ 100 01 = 5 0 07 5

0 001 0001 0001 000 1 00 1 001 1 00 1 001 1 00 1 00 1 00 1 00 1 00 1 00 1 00 1 00 1 001 1 001 0001 1 00 100 100

Notes I I I I I I I I

0 68i

006

0 00

015

012

1=0

-180-
Table 4-17: Replacement Models: Total Number and Percentage of Tubes Plugged (12/01)

Plant | Number of Tubes Percent Plugged Operating Time2

j Plugged1 I FecetPug

Indian Point 2 2 0.02 1

Point Beach 1 10 0.16 18

Robinson 2 39 0.40 17

Salem 1 58 0.26 4

Surry 1 43 0.43 20

Surry 2 39 0.39 21

Turkey Point 3 166 1.72 20

Turkey Point 4 43 0.45 19

TOTALS: 400 0.44

'As of 12/31/01

2

Operating Time = calendar years of operation as of 12/31/01

-181-
Table 4-18: Replacement Models: Number of Tubes Plugged as a Function of Mechanism (Detailed) (12/01)

Tubes Percentage Tubes Percentage Cause of Tube Plugging Plugged of Plugs Plugged of Plugs

AVB 93 23.3%

Wear Pre-heater TSP (D5) 0 0.0% 107 26.8%

TSP 14 3.5%

Confirmed 3 0.8%

Not Confirmed,

Loose Parts Periphery 11 2.8% 15 3.8%

Not Confirmed, Not

Periphery 1 0.3%

Obstruction Obstrction From PSI - no progPression 2 0.5% 19 4.8%

Restriction Service Induced 17 4.3%

Manufacturing Preservice 121 30.3% 131 32.8%

Flaws Other 10 2.5%

Probe Lodged 0 0.0%

. Data Quality 4 1.0%

Inspueto Dent/Geometry 0 0.0% 7 1.8% Issues Permeability 3 0.8%

Not Inspected 0 0.0%

Top of Tubesheet 102 25.5%

Other Free Span 12 3.0% 121 30.3%

Ohr TSP 7 1.8% 1230%

Other/Not Reported 0 0.0%

SCI ID 0 0.0% 0 0.0% _________00) 0 0.0% 000

TOTALS| 4001 100.0%| 4001 100.0%|

Total Tubes: 90766

Fraction Plugged 0.44%

-182-
Table 4-19: Replacement Models: Cumulative Plugging Per Year

Turkey Point Turkey Point Outage Indian Point 2 Point Beach 1 Robinson 2 Salem 1 Surry 1 Surry 2 3 4 Pre-Op 2 4 28 13 2 2 39 31 1980

1981 2

1982

1983 2 2 39

1984 __ _ _ _ _4 6 __ _ _ _ _31 19854 4 6 2 43

1986 4 28 10 3 31 1987 4 28 44

1988 6 29 10 3 32

1989 _ _ _ _ __6 29

1990 6- 30 12 55 33

1991 _ _ _ _ _ -8 _ _ _ __ _ _ _ __3 33

1992 . 8 31 14 62

1993 ______-_8 32 5 33 1994 , 8 34 18 66 33 1995 9 34 19 10 68

1996 _ _ _ _ __9 35 __ _ _ _ _ _ _ _ _ _ _18 33 1997 9 35 24 23 82 33

1998 9 35 30 83

1999 9 35 23 32 33 2000 9 I 38 39 152 43

2001 __10 39 58 43 _ 1661

-183-
Table 4-20: Replacement Models: Plugging Per Year

Turkey Point Turkey Point Replacement Outage Indian Point 2 Point Beach 1 Robinson 2 Salem 1 Surry 1 Surry 2 3 4 Totals

Pre-Op 2 4 28 13 2 2 39 31 121

1980 0

1981 0 0

1982 0

1983 0 0 0 0

1984 0 4 0 4

1985 0 0 4 4

1986 0 0 4 1 . 0 5

1987 _ _ _ _ _ 0 0 _ _ _ _ _ 1 1

1988 2 1 0 0 1 1 4

1989 _ _ _0 0 __ __ _ _0

1990 0 1 2 11 14

1991 2 0 1 3

1992 0 1 2 7 10

1993 0 1 2 0 3

1994 0 2 4 4 0 10

1995 1 0 1 5 2 9

1996 0 1 8 0 9

1997 5 5 14 0 24

1998 0 0 6 1 7

1999 0 0 10 9 0 19

2000 _ 0 8 7 69 10 94

2001 1 4 35 5 14 59

Totals: 2 10 39 58 43 39 166 43 400

-184-
Table 4-21: Replacement Models: Cumulative Plugging Per RFO

Turkey Point Turkey Point

Outage Indian Point 2 Point Beach 1 Robinson 2 Salem 1 Surry 1 Surry 2 3 4

Pre-Op 2 4 28 13 2 2 39 31

RFO 1 4 28 23 2 2 39 31

RFO 2 4 28 58 6 2 43 31

RFO 3 4 29 10 2 44 32

RFQ4 6 30 10 3 55 33

RFQ 5 6 31 12 3 62 33

RFO 6 6 32 14 3 66 33

RF 7 8 34 18 5 68 33

RFO 8 8 35 19 10 82 33

RFO 9 8 35 24 18 83 33

RF 10 8 35 30 23 152 43

RF 11 9 39 38 32 166

RFO 12 9 43 39

R F Q 13 _ _ _ _ _9 _ _ _ _ _ _ _ _ __ _ _ _ __ _ _ _

RF 14 9

RFO 15 10

RFO 16 .

RF 17

RFO 18 .

RFO 19

RFO 20

RF 21 .

RF 22

-185-
Table 4-22: Replacement Models: Number of Tubes Plugged As a Function of Mechanism Per Year (Detailed)

CauC. of Tube F

AY Wear Pro heate

TSP

Conlome

Not Conll

Loose Parts F-t.trt

Not Conh

Pwbrhern

Obstructon F-rom PS

Serice II

Mauatrn PreservKr Flews Other

Probe Lo oate Ow

Inspection lIsus DeoVGeA

Perrneab

Not Insp.

Other Free Spa TSP__ ____ ____ ____ Not Rer

Sccc

CL-d

lhined,

r 1 I 1 I 3 .--- 7-' ---- I- I- t----t- - _fl_ i1 I f-- _ _ t - 4 1 s--#-- CItlea, Not

-II

Iduced

:0

doeq

!.bity

aede

ibesheet

I I

Total Totalsi

0 107

14

2 19 17

121 131

10

4

o 7

0

102

121

0 I

r 4001 4001

†._t†1

I= -I -; | .- -I -- __ 31 - - I- II - - -------- 4 4 -- 4 - - ._._ rt__-' Fnorled

Vollfu l l I . , +

--- -- --t- .-I -----+ -- -11

Note.,

-186-
Table 4-23: Replacment Models: Number of Tubes Plugged As a Function of Mechanism Per Year (Summary)

Year 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 199 2000 2001

Cause I Totals WearS- 7 2 4 21 7 31 3 5 11 8 _21 44 10

Loose Parts - 1 12_ 1 2 34 is

Restrictions _ _ I_ I ... Ji 12 b 3 1219 Wea2j __32 1 2 45 171 Inspection Issues 5 7

Other 4 4 2 1 _e 1 3 11 _, 8 72 1 121

; 21 21 391 311 361 41 51 11 41 01 141 31 101 31 101 91 91 371 71 191 961 591 400

Notes I I I I I I I I I I I I I I I I I I I I I

-187-
Table 4-24: Replacement Models: Fraction of Tubes Plugged As a Function of Mechanism Per Year (Summary)

Year 1980 1981 1982 1 9894 | 195 198ts 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Wear 050 0.67 040 067 070 033 033 014 014 042 022 _075

Manut actunns 100 100 100 _. 100 0 _ 00 __ = 05 0 014 ._ _ 035 ____ 011.002_00 ._ . ............ ..... __ ...... ____ ____

Re - t i t - o s -- 0 2 0. _ _ _ P _ 5 - _ j 0 33 0 10 * . Q _ __ 0 11 0 22 0 14 0 43 0 05 0 03 -inspection 

Other Issues 1 ]____ ___-- - -. 0 i - -. 001 00 ! °" I { 040 _0O_ = 029 - 010 056 033 030 042 075 002

1 00o 1o 1 0 1 00 10 1 o00 1 1 I 00o I 00o 0 00o 100l 100 1 00 100 1 0 1 00 10 1 0 1 00 10o 1o00o 1o00l

Notes I I I I I I I I I I

Totals

0 27

0 04

0 05

033

0 02

0 30

1 001

-188-
Table 4-25: All Models: Total Number and Percentage of Tubes Plugged (12/01)

Plant ||Number of Tubes | Percent Plugged Operating Time2

l l | Plugged',

Braidwood 2 120 0.66 13

Byron 2 223 1.22 14

Callaway 17 0.35 17

Catawba 2 183 1.00 15

Comanche Peak 2 37 0.20 8

Indian Point 2 2 0.02 1

Millstone 3 106 0.47 16

Point Beach 1 10 0.16 18

Robinson 2 39 0.40 17

Salem 1 58 0.26 4

Seabrook 1 90 0.40 11

Surry 1 43 0.43 20

Surry 2 39 0.39 21

Turkey Point 3 166 1.72 20

Turkey Point 4 43 0.45 19

Vogtle 1 48 0.21 15

Vogtle 2 29 0.13 13

Wolf Creek 1 144 0.64 16

TOTALS: 1397 0.50

'As of 12/31/01

2Operating Time = calendar years of operation as of 12/31/01

-189-
Table 4-26: All Models: Number of Tubes Plugged As a Function of Mechanism (Detailed) (12101)

Model D5 Model F Replace ent Models All Models

Tubes Percentage Tubes Percentage Tubes Percentage Tubes Percentage Cause of Tube Plugging Plugged of Plugs Plugged of Plugs Plugged of Plugs Plugged of Plugs AVB 258 45.8% 295 68.0% 93 23.3% 646 46.2%

Wear Pre-heater TSP (D5) 2 0.4% 0 0.0% 0 0.0% 2 0.1%

TSP 2 0.4% 0 0.0% 14 3.5% 16 1.1%

Confirmed 19 3.4% 9 2.1% 3 0.8% 31 2.2%

Not Confirmed,

Loose Parts Peripher v16 2.8% 10 2.3% 11 2.8% 37 2.6%

Not Confirmed, Not

Periphery 3 0.5% 5 1.2% 1 0.3% 9 0.6%

Obstruction From PSI - no Restriction progression 0 0.0% 0 0.0% 2 0.5% 2 0.1%

Service Induced 2 0.4% 2 0.5% 17 4.3% 21 1.5%

Manufacturing Preservice 50 8.9% 63 14.5% 121 30.3% 234 16.8%

Flaws Other 44 7.8% 0 0.0% 10 2.5% 54 3.9%

Probe Lodged 2 0.4% 0 0.0% 0 0.0% 2 0.1%

Inspection Data Quality 2 0.4% 0 0.0% 4 1.0% 6 0.4%

Issues Dent/Geometry 4 0.7% 0 0.0% 0 0.0% 4 0.3%

Permeability 4 0.7% 0 0.0% 3 0.8% 7 0.5%

Not Inspected 3 0.5% 0 0.0% 0 0.0% 3 0.2%

Top of Tubesheet 18 3.2% 19 4.4% 102 25.5% 139 9.9%

Other Free Span 80 14.2% 13 3.0% 12 3.0% 105 7.5%

TSP 44 7.8% 18 4.1% 7 1.8% 69 4.9%

Other/Not Reported 10 1.8% 0 0.0% 0 0.0% 10 0.7%

ID 0 0.0% 0 0.0% 0 0.0% 0 0.0% _________ OD0 01 0.0% 01 0.0% 0 0.0%1 01 0.0%-/

| TOTALS| 5631 100.0%| 4341 100.0%| 4001 100.0%| 13971 100.0%|

Total Tubes:

Fraction Plugged:

Average Age (years):

73120

0.77%

12.8

117376

0.37%

14.6

90766

0.44%

15.1

281262

0.50%

14.4

-190-
Table 4-27: All Models: Number of Tubes Plugged as a Function of Mechanism (Summary) (12/01)

Model D5 Model F Replace ent Models All Models

Tubes Percentage Tubes Percentage Tubes Percentage Tubes Percentage Cause of Tube Plugging Plugged of Plugs Plugged of Plugs Plugqed of Plugs Plugged of Plugs

AVB

Wear Pre-heater TSP (D5) 262 46.5% 295 68.0% 107 26.8% 664 47.5%

TSP

Confirmed

Not Confirmed,

Loose Parts Periphery 38 6.7% 24 5.5% 15 3.8% 77 5.5%

Not Confirmed, Not

Periphery

Obstruction From PSI - no Restriction Progression 2 0.4% 2 0.5% 19 4.8% 23 1.6%

Service Induced

Manufacturing Preservice -- 94 16.7% 63 14.5% 131 32.8% 288 20.6% Flaws Other __ _ _ ___ _ _ _ _

Probe LodgedInspection Data Quality-- Inspeton Dent/Geometry 15 2.7% 0 0.0% 7 1.8% 22 1.6% Issues Permeability'

Not Inspected _

Top of Tubesheet

Other Free Span 152 27.0% 50 11.5% 121 30.3% 323 23.1% TSP

Other/Not Reported .

SCC ID 0 0 0.0% 0 0.0% 0 0.0% 0 0.0%

TOTALSI 563 100.0%| 4341 100.0%1 400 ) 100.0%| 13971 100.0%|

Total Tubes:

Fraction Plugged:

Average Age (years):

73120

0.77%

12.8

117376

0.37%

14.6

90766

0.44%

15.1

281262

0.50%

14.4

-191-
Table 4-28: All Models: Plugging Per Year

Replacement Tubes in TT

Year Model D5 Model F Models All Models SGs

Pre-Op 51 63 121 235 281262l

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 23 15 3 41 227622

1992 29 1 10 40 227622

1993 94 16 3 113 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

Totals: 563 434 400 1397

-192-
Table 4-29: All Models: Number of Tubes Plugged As a Function of Mechanism Per Year (Detailed)

Wear 69 __ 521 _5

W o r

Loose Parts

(ontrmed _ _

Not Confirmed.

P.enn-khe .1 .1 ol .1 _1 i .. i, i 4------ - j 1 Nn~rnnfimnrt+nt 1 I I I i i|_q1i9 

l.- -11.1-nu rwl i l1 .1 ________ n _ I ! I I I 41 2

Obstruction

Rsttriction

- Dr. lno- -i I , - ... ------ -4- - I_..... _ 4-------4-- ----- - ---- - 1-- . - -|_fi§Ae_ n- 1 I ., n 7i ,- i -! -l -- i -w - . .7. . .. - Manut clurln_ F

Inspection Issus

he~r

?abOualilty

)en.IGrony.

1rmmea~~,dv_ insoeected

Fop e!aubeshea _

~ree Scoan

---- 1_, ------------- I _3_ JD _ - -1_ I - - ifH __ 6 10t 1.'

Tota64

16

31

21

234

54

13'

10'

61

11

TotalS

664

77

23

299

22

2 ¶

21

, = Other

scc

fl

j 1397

Notas

Notes

-193-
Table 4-30: All Models: Number of Tubes Plugged As a Function of Mechanism Per Year (Summary)

Cause Year 1980 1981 19821T 19|51- -9 1 1 1992 199 9 | 1 1997 1998 1999 2000 2001

Wear 26 IL I..~ LeostriParts _ __. . __ 2 1 9 

. 5_ 1 4 29 -. . _ 51 10 79 7 62 1 I 6 .7 80 591 4 -- Re-strictions~ .. [.._.... . 1 - - InMaucturing 2 2 -39 31is36 15-25 17 15 9-8 = _ 2 28 . 299 i 2 3 insoectio issues -.. **-- -]1 5 311 6 5

scC ter - _ - - -t------ 4 2 2__ _ _2 1 _2 j 9 18 16 76 32 __________

i 21 21 391 311 401 191 291 211 401 391 751 411 401 1331 871 911 1071 1301 541 94 168 115

Notes I

RMu

Totals

664

77-

23

288

323

0

-194-
Table 4-31: All Models: Fraction of Tubes Plugged As a Function of Mechanism Per Year (Summary)

Year 1980 11981 1982 t983 1 1984 1 1985 1986 1987 1988 1989 1 1990 1991 1992 1 1993 1 1994 1 1995 196 1997 1998 1999 12000 2001 i

Cause I - T - I Totals Wear fe- - 010 048 013 0_64 073 0473 052 060 056 074 04 Oil 078 046 051 048

LooesParitsoa 0030 3 - 3 0 002 0036- 001 00 002,00 0 606k00 __ 0 0 02

10050 Pans __ ____ _ 0 03 00 0 ___ _ 0 01 0 01 007 008 01 O 00 3 02 0 02

Manu0acturin0 160t0t 100 1-00 9Q 0 79 086 081 020 0 3 020 2C 0 _ j 022 054 010 01 003 0 21

Inpcinotses Other _____ 10 0 0 010 0 021 100 00i010 02 0 01 0 015 0 015 0 025 0 0 32 0 0 0 38032 0 017 0 012 0 013 0 0600 OIl 045 1000 028 0 023 002

I i ooi 1 Is 0 1 I 0t1 I 00 1 I 00 1 I 00 1 I 0 1 Ioo 1 _1 oo- 1 o 1 Iool Io 0 1 I_ 0 1 I I0 01 I 0 0 01 1 I 00 4 1 00 1 0 04 0 0

r Noes I I I I I I I I -I I I I I I

-195-
Figure 4-1: Model D5: Causes of Tube Plugging

-SCC (0.00%)

Other (27.00%)

Inspection Issues (2.66%)

Manufacturing Flaws (16.70%)

Obstruction Restriction (0.36%)

WWear (46.54%)

ii5

i..i... _

551i. i_

Loe Parts (6.75%)

-196-
Figure 4-2: Model D5: Plugging Per Year

50

40

U)

m

la 30

a3

X 20

a)

10

0

-250

_____ ___ ___ ___ ___ I I~ __ ___ __ __ __ = ___:-A

U, a)

-M

a X- 7

L

I 1/, I

'i I

-J . -gl I

- UU

-o

la

a)

150 3

0~U,

a,

100 F

a)

di R k M w

- - - - -- 5

M

E

U

Pre-Op 1987 1989 1991 1993

Year

1995 1997 1999 2001

V

--- Braidwood 2 A Byron 2 I Catawba 2 -0 Comanche Peak 2

Braidwood 2 7 Byron 2 E Catawba 2 Zl Comanche Peak 2

-197-
Figure 4-3: Model D5: Cumulative Plugging Per Refueling Outage

250 Ir . . . .

200

ax

0)

0)

IL 150

a)

nI-

, 100

E

0

50

0

I I --- Ak

I AC--- I-,&--

// -Z

//111 ,

/Z--f

7Y'/ __Rr------M

/,/ // ez /,-

X* ///"'m

1z -AK

I-,-

T-

s i L I

Pre-Op RFO I RFO2 RFO3 RFO4 RFO5 RFO6 RFO7 I I I

RFO8 RFO9 RFO10 RFO11

Refueling Outage Number (RFO)

-O- Braidwood 2 A Byron 2 I Catawba 2 -- Comanche Peak 2

-198-
Figure 4-4: Model D5: Causes of Tube Plugging Per Year

1.0

l 0.8

CDtn

tEL 0.6

a)

4-04-

0 0.4

._

LL 0.2

0.0

[-rro

l

-1

At i

I I I I I I I I rtl.= I

1980 1982 1984 1986 1988 1Awn

Year

1992 1994 1996 1998 2000

Wear

Inspection Issues

go Loose Parts

m Other

UmRestrictions E Manufacturing

Scc

-199-
Figure 4-5: Model F: Causes of Tube Plugging (12/01)

-ScC (0.00%) Other (11.52%)

Inspection Issues (0.00%)

Manufacturing Flaws (14.52%)

Obstruction Restriction (0.46%)

Loose Parts (5.53%)

Wear (67.97%)

-200-
Figure 4-6: Model F: Plugging Per Year

60

50

m0 aCU 4 0

la

m 30

us U)

4) 20

1-

1 0

0

U) r-

.:

a)

cn0)

0)

U) am

.0

._

C)E

0

Year

-W- Callaway + Millstone 3 - Seabrook --

E Callaway m Millstone 3 0 Seabrook K

K- Vogtle 1

I Vogtle 1

EBU

Vogtle 2

Vogtle 2

- Wolf Creek

- Wolf Creek

-201-
Figure 4-7: Model F: Cumulative Plugging Per Refueling Outage

160

140

' 120

a)

0)

0)

H: 100

Un

.0am

= 80

0)

U 60

E

C.) 40

= ==< <_ < == I I I

Ad ===ZV _ /-

S

=== =D =A=4--

Hf _ . . -/ ' / .'

v < t 79

X, >' s x

r to v ,-

= Aim

s'< tK

_ _ _ _ A=

20

0

Pre-Op RFO I RFO 2 RFO 3 RFO4 RFO5 RFO6 RFO7 RFO8

Refueling Outage Number (RFO)

RFO 9 RFO10 RFO11

-U- Callaway -0- Millstone 3 >X Seabrook X Vogtle 1 mB Vogtle 2 V Wolf Creek

-202-
1.0

D 50.8

0)

w0)

Un 0.6

a)

4-

0 0.4

Cu

&L 0.2

0.0

Figure 4-8: Model F: Causes of Tube Plugging Per Year

1984 198519861987 198819891990 1991 1992199319941995 19961997 1998199920002001

Year

I Wear m Loose Parts

K Inspectton Issues E Other

m I Restnctions 7 Manufactunng

0 SCC

-203-
Figure 4-9: Replacement Models: Causes of Tube Plugging (12/01)

jmSCC (0.00%)

Other (30.25%°J)

Inspection Issues (1.75%)

Manufacturing Flaws (32.75%)

-Wear (26.75%)

Loose Parts (3.75%)

Obstruction Restriction

(4.75%)

-204-
Figure 4-10: Replacement Models: Plugging Per Year

70

60

LM 50

m

a) 40

0)

R: 30

(0

a)

-8 20

10

0

_ . -zuu

il r /i : I

e lr 1:0 v -0

C,)

0)

a,a)

0

a,

3

K

n

a.

E

0)

- - I m '' EDi -!P-- S |' 

I 

*ffEi= 10%0 

rr-u

p 1 9 9 3 9 5 1 9 8 - 1 9 89I H~ I

Pre-O p 1981 1983 1985 1987 1989 4t

Year

Indian Point 2 7 Point Beach 1

i Surry 1 Surry 2

-*- Indian Point 2 G Point Beach 1 o

-^- Surry 1 >< Surry 2 m

I I I I - -I 1----t --- I I

1993 1995 1997 1999 2001 -

I Robinson 2 L Salem 1

| Turkey Point 3 `UY Turkey Point 4

- Robinson 2 -s Salem 1

- Turkey Point 3 -*- Turkey Point 4

-205-
Figure 4-11: Replacement Models: Cumulative Plugging Per Refueling Outage ...

/.UU

M

0) cn150

aIn

0)

3 100

a)

E= 50

C.)

tXL~xlxr M

T S _ B - L 1 5P+P l

e ~~~~I s= SX

t X,"X

0

Pre-Op RFO 2 RFO 4 RFO 6 RFO 8 RFO 10 RFO 12 RFO 14

Refueling Outage Number (RFO)

_- Indian Point 2 - Point Beach 1 E- Robinson 2 - Salem 1

zA- Surry 1 X Surry 2 EE Turkey Point 3 -- Turkey Point 4

-206-
1 0-

la 0 8 -

0)

a:

a)

M

IUp 064

4-

0

U -

IL 0.2 -

0.0 -

Figure 4-12: Replacement Models: Causes of Tube Plugging Per Year

~~llu1I

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

E Wear m Loose Parts m lt U Restnctions

7 Inspection Issues 7 Other m SCC

-207-

E Manufactunng
Figure 4-13: Number of Thermally Treated Alloy 600 Tubes in Service Per Year

300 -- _ _ _

250- --- rl I12_

0)200--_

ou 150 -

fl0 --

z

50 - - _

0 - -- _ __ __

-N- Model D5 - Total Tubes

El Model F - Total Tubes

-0-- Replacement Models - Total Tubes

G All Models - Total Tubes

Ir

Model DF - Active Tubes

V Model F - Active Tubes

A- Replacement Models - Active Tubes

zA-- All Models - Active Tubes

08-
Figure 4-14: All Models: Tubes Plugged Per Grouping/Model (12/01)

Replacement Models (28.63%)

400 tubes

Model D5 (40.30%)

563 tubes

Model F (31 .07%)-

434 tubes

-209-
Model 4-15: All Models: Causes of Tube Plugging (12/01)

(00%) F_ 0 %) Other(I1 52%) --- \

Other (27 WO%) Inspection Issues (O 00%)

Manufactunng Flaws (14 52%)

Wear (46 54%)

Inspdcton Issues (2 66%)

Obstrucbon Restiction (O 46%)

Loose Parns (5 53%)

'- - e ir (67 97%)

Manufacturing Flaw (16 70%) P

Obstruction ResLtncton (O 38%) Loose Parts (675%)

(Replacemcent Models ) (All Models)

FSCC (o 0O%) F scc ( 00%)

Other (23 t2%)-'\ Wear (26 75%) Other (30 25%)

Inspection Issues (1 75%)

Manufaruneg Fbas (32 75%)

Inspecton Issues (1 57%) -Wear (47 53%)

Loose Parts (3 75%)

Obstruction Restiction (4 75%)

Manufacturing Flaws (20 62%) - ..

Obstruction Rostncton (1 65%)

Loose Parts (6 51%)

-210-
Figure 4-16: All Models: Number of Tubes Plugged Per Year

250-

225-

200-

175-

a.

1)150-

125-

0 100

.075

E

~50- z

25-

0

Pre-Op 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001

Year

on Model D5

Z Replacement Models

Model F

All Models

-211-
Figure 4-17: All Models: Percentage of Tubes Plugged Per Year

0.0014 -

a 0.0012 -

X 0.001 - CD

fl 0.0008 -

o 0.0006 - CD

= 0.0004 -

0) a)

(3

X 0.0002 -

0-

, . . . . .

T T T rT T .

.

-T

...4- - - -I

I I I I I I .

I I I I I -

I 

, , 

I , , , ., , ., , . ~~~~ I 1 - Pre-Op 1 98 1985 1988 , _1991 I I I I I 1994 1997 I 2 2000

Year

* Model D5

D Replacement Models

Model F

All Models

-212-
Figure 4-18: All Models: Causes of Tube Plugging Per Year

1.0

0.8

laI-

(t

L_0.2 -

0

._

m

IL

00.4 -

0.-

19801981 19821983198419851986198719881989199n1qq1 1lqq919319941995199619971998199920002001

Year

* Wear m Loose Parts mm Restnctions E Manufacturing

7 Inspection Issues 7 Other E SCC

-213-
APPENDIX A: ACRONYMS

ADI absolute drift indication

ADS absolute drift signal

AVB anti-vibration bar

AVT all volatile treatment

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

CLP confirmed loose part

EFPM Effective Full Power Month

EFPY Effective Full Power Year

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

FS freespan

gpd gallons per day

gpm gallons per minute

ID inside diameter

MAI multiple axial indication

MBM manufacturing burnishing mark

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

psi pounds per square inch

PWR pressurized-water reactor

PWSCC primary water stress corrosion cracking

RFO refueling outage

SAI single axial indication

SG steam generator

TSP tube support plate

TT thermally treated

UT ultrasonic testing

-214-
APPENDIX B: BIBLIOGRAPHY

General

Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes"

Generic Letter 91-04 "Changes in Technical Specification Surveillance Intervals to

Accommodate a 24-Month Fuel Cycle," April 2, 1991

NUREG-0966, "Safety Evaluation Report Related to the D2/D3 Steam Generator Design

Modification"

NUREG-1014, "Safety Evaluation Report Related to the D4/D5/E Steam Generator Design

Modification"

Generic Letter 95-03, "Circumferential Cracking of Steam Generator Tubes"

Bulletin 89-01, "Failure of Westinghouse Steam Generator Tube Mechanical Plugs"

U.S. Nuclear Regulatory Commission Information Notice 2001-016, "Recent Foreign and

Domestic Experience with Degradation of Steam Generator Tubes and Internals," October 31,

2001.

U.S. Nuclear Regulatory Commission, "Steam Generator Tube Failures," NUREG/CR-6365,

April 1996.

U.S. Nuclear Regulatory Commission, 'Circumferential Cracking of Steam Generator Tubes,"

NUREG-1604, April 1997.

U.S. Nuclear Regulatory Commission Information Notice 2002-21, "Axial Outside-Diameter

Cracking Affecting Thermally Treated Alloy 600 Steam Generator Tubing" June 25, 2002.

-215-
Braidwood 2

Letter from S.C. Hunsader, Commonwealth Edison, to the NRC, dated May 7, 1990,

"Braidwood Station Unit 2, First Fuel Outage, Steam Generator Inservice Inspection Results,

NRC Docket No. 50-457." NUDOCS Accession No.

Letter from A.R. Checca, Commonwealth Edison, to the NRC, dated April 22, 1991, "CECo

Braidwood Unit 2 First Outage, Steam Generator Inservice Inspection Results, NRC Docket No.

50-457." NUDOCS Accession No.

Letter from T.W. Simpkin, Commonwealth Edison, to the NRC, dated November 19, 1991,

"Braidwood Station Unit 2, Second Refueling Outage, Steam Generator Inservice Inspection

Results, NRC Docket No. 50-457." NUDOCS Accession No. 9112020194

Letter from T.W. Simpkin, Commonwealth Edison, to the NRC, dated August 25, 1992,

"Braidwood Station Unit 2, Second Refuel Outage Steam Generator Inservice Inspection

Results, NRC Docket No. 50-457." NUDOCS Accession No.

Letter from K.L. Kofron, Commonwealth Edison, to the NRC, dated April 12, 1994, "Braidwood

Station Unit 2, Steam Generator Tube Inservice Inspection Report, Docket No. STN 50-457."

NUDOCS Accession No. 9404180410

Letter from K.L. Kofron, Commonwealth Edison, to the NRC, dated October 27, 1994,

"Braidwood Station Unit 2, Cycle 4 Refuel Outage, Steam Generator Tube Inservice Inspection

Report, Docket No. STN 50-457." NUDOCS Accession No.

Letter from T.J. Tulon, Commonwealth Edison, to the NRC, dated October 24, 1995, "ComEd

Braidwood Station Unit 2 Fourth Refuel Outage, Steam Generator Inservice Inspection Report,

Docket No. STN 50-457." NUDOCS Accession No. 9510270004

Letter from T.J. Tulon, Commonwealth Edison, to the NRC, dated April 23, 1996, 'Braidwood

Station Unit 2, Fifth Refuel Outage, Steam Generator Inservice Inspection Report, NRC Docket

No. STN 50-457." NUDOCS Accession No. 9605070344

Letter from T.J. Tulon, Commonwealth Edison, to the NRC, dated January 15, 1997, "ConEd

Braidwood Station Unit 2 Fifth Refuel Outage, Steam Generator Inservice Inspection Report,

Docket No. STN 50-457." NUDOCS Accession No. 9701280276

Letter from T.J. Tulon, Commonwealth Edison, to the NRC, dated October 23, 1997,

"Braidwood Unit 2, Sixth Refuel Outage, Steam Generator Inservice Inspection Report, NRC

Docket No. STN 50-457." NUDOCS Accession No. 9710290024

Letter from T.J. Tulon, Commonwealth Edison, to the NRC, dated October 23,1997, "ComEd

Braidwood Station Unit 2 Sixth Refuel Outage, Steam Generator Inservice Inspection Report,

Docket No. STN 50-457." NUDOCS Accession No. 9710300202

-216-
Letter from T.J. Tulon, Commonwealth Edison, to the NRC, dated May 13, 1999, "Steam

Generator Tube Inspection Report from Braidwood Station Unit 2 Refueling Outage

Inspections." NUDOCS Accession No. 9905190243

Letter from T.J. Tulon, Commonwealth Edison, to the NRC, dated April 13, 2000,

"Commonwealth Edison (ComEd) Braidwood Unit 2 Cycle 7 Steam Generator Eddy Current

Examination 12 Month Summary Report." ADAMS Accession No. ML003704386

Letter from T.J. Tulon, Commonwealth Edison, to the NRC, dated November 9, 2000, "Eighth

Refuel Outage Steam Generator Tube Inspection Report." ADAMS Accession No.

ML003769511

Letter from G.K. Schwartz, Exelon Generating Company, LLC, to the NRC, dated January 26,

2001, "Braidwood Station, Unit 2 Inservice Inspection Summary Report." ADAMS Accession

No. ML010360111

Letter from J.D. von Suskil, Exelon Generating Company, LLC, to the NRC, dated October 18,

2001, "Braidwood Station, Unit 2 Eighth Refueling Outage Steam Generator Tube Inspection

Report." ADAMS Accession No. ML020150065

Byron 2

Letter from R. Pleniewicz, Commonwealth Edison, to the NRC, dated February 9, 1989, "Steam

Generator Tube Plugging From Byron Unit 2, Cycle 1 Refueling Outage (B2RO1)." NUDOCS

Accession No.

Letter from R. Pleniewicz, Commonwealth Edison, to the NRC, dated April 3,1989,

"Commonwealth Edison Byron Unit 2 Eddy Current Inspection." NUDOCS Accession No.

Letter from M.H. Richter, Commonwealth Edison, to the NRC, dated June 16, 1989, "Byron

Station Units 1 and 2, Braidwood Station Units 1 and 2, Zion Station Units 1 and 2, Response to

NRC Bulletin 89-01, Failure of Westinghouse Steam Generator Tube Mechanical Plugs, NRC

Docket Nos. 50-454/455, 50-456/457, and 50-295/304." NUDOCS Accession No. 8906210005

Letter from R. Pleniewicz, Commonwealth Edison, to the NRC, dated December 26, 1990,

'Commonwealth Edison Byron Unit 2 Steam Generator Eddy Current Examination During the

Cycle 2 Refueling Outage." NUDOCS Accession No. 9101240226

Letter from D.J. Chrzanowski, Commonwealth Edison, to the NRC, dated August 9, 1991,

"Byron Station Units 1 and 2, Braidwood Station Units 1 and 2, Zion Station Units 1 and 2,

Response to NRC Bulletin 89-01, Supplement 2, Failure of Westinghouse Steam Generator

Tube Mechanical Plugs, NRC Docket Nos. 50-454/455, 50-456/457, and 50-295/304."

NUDOCS Accession No. 9108120228

-217-
I

Letter from D.J. Chrzanowski, Commonwealth Edison, to the NRC, dated October 3, 1991,

"Clarification to Response to NRC Bulletin 89-01, Supplement 2, Failure of Westinghouse

Steam Generator Tube Mechanical Plugs, Byron Units 1 and 2, Braidwood Units 1 and 2, Zion

Units 1 and 2, NRC Docket Nos. 50-454/455, 50-456/457, and 50-295/304." NUDOCS

Accession No. 9110100128

Letter from R. Pleniewicz, Commonwealth Edison, to the NRC, dated April 1, 1992, "Steam

Generator Tube Plugging From Byron Unit 2, Cycle 3 Refueling Outage." NUDOCS Accession

No.

Letter from R. Pleniewicz, Commonwealth Edison, to the NRC, dated June 5, 1992,

"Commonwealth Edison Byron Unit 2 Steam Generator Eddy Current Examination During the

Cycle 3 Refueling Outage." NUDOCS Accession No.

Letter from D.E. St. Clair, Commonwealth Edison, to the NRC, dated October 4, 1993, "Steam

Generator Tube Plugging From Byron Unit 2 Cycle 4 Refueling Outage (September

3-November 2, 1993)." NUDOCS Accession No.

Letter from D.E. St. Clair, Commonwealth Edison, to the NRC, dated January 4,1994,

"Commonwealth Edison Byron Unit 2 Steam Generator Eddy Current Examination During the

Cycle 4 Refueling Outage." NUDOCS Accession No.

Letter from T.W. Simpkin, Commonwealth Edison, to the NRC, dated January 31, 1995, "Byron

Station Units 1 and 2, Braidwood Station Units 1 and 2, Update on Status of Alloy 600 TT

Steam Generator Mechanical Tube Plug Replacement, NRC Docket Nos. 50-454, 50-455,

50-456 and 50-457 ." NUDOCS Accession No. 9502060090

Letter from D.E. St. Clair, Commonwealth Edison, to the NRC, dated March 16, 1995, "Steam

Generator Tube Plugging from Byron Unit 2 Cycle 5 Refueling Outage (Beginning February 9,

1995)." NUDOCS Accession No.

Letter from D.E. St. Clair, Commonwealth Edison, to the NRC, dated June 9, 1995, "CornEd

Byron Unit 2 Steam Generator Eddy Current Examination During the Cycle 5 Refueling

Outage." NUDOCS Accession No.

Letter from J.B. Hosmer, Commonwealth Edison, to the NRC, dated August 2, 1996,

"Application for Amendment to Facility Operating Licenses: 'Elimination of Corrosion Testing

Requirement for Steam Generator Tube Sleeving'." NUDOCS Accession No. 9608060231

Letter from D.B. Wozniak, Commonwealth Edison, to the NRC, dated September 11, 1996,

"Steam Generator (SG) Tube Repairs Resulting from Byron 2 Forced (B2F17) and Refueling

(B2R06) Outages, Byron Nuclear Power Station Unit 2, Facility Operating License NPF-66,

NRC Docket No. 50-455." NUDOCS Accession No. 9609170587

Letter from D.B. Wozniak, Commonwealth Edison, to the NRC, dated December 17, 1996,

"ComEd Byron Station Unit 2 Steam Generator Eddy Current Examination During B2F17 &

B2RO6 - 90 Day Summary Report, Byron Nuclear Power Station, Unit 2, Facility Operating

License NPF-66, NRC Docket No. 50-455." NUDOCS Accession No. 9612270082

-218-
Letter from K.L. Kofron, Commonwealth Edison, to the NRC, dated September 27,1996,

"Steam Generator Tubes Not Inspected During Outage." NUDOCS Accession No. 9610080408

Letter from K.L. Graesser, Commonwealth Edison, to the NRC, dated May 8, 1998, "Steam

Generator Tube Repairs Resulting from Byron Unit 2 Cycle 7 Refueling Outage, Byron Nuclear

Power Station Unit 2, Facility Operating License NPF-66, NRC Docket No. 50-455." NUDOCS

Accession No. 9805180062

Letter from K.L. Graesser, Commonwealth Edison, to the NRC, dated July 27,1998, "ComEd

Byron Unit 2 Cycle 7 Steam Generator Eddy Current Examination 90 Day Summary Report,

Byron Nuclear Power Station, Unit 2, Facility Operating License NPF-66, NRC Docket No.

50-455." NUDOCS Accession No. 9807300182

Letter from R.M. Krich, Commonwealth Edison, to the NRC, dated December 30, 1998, "Byron

Station, Units 1 and 2, Facility Operating License Nos. NPF-37 and NPF-66, NRC Docket Nos.

STN 50-454 and STN 50-455; Braidwood Station, Units 1 and 2, Facility Operating License

Nos. NPF-72 and NPF-77, NRC Docket Nos. STN 50-456 and STN 50-457; Steam Generator

Laser Welded Sleeves." NUDOCS Accession No. 9901110021

Letter from W. Levis, Commonwealth Edison, to the NRC, dated November 15, 1999, "Steam

Generator Tube Repairs Resulting from Byron Unit 2 Cycle 8 Refueling Outage (B2RO8)."

ADAMS Accession No. ML993270004

Letter from W. Levis, Commonwealth Edison, to the NRC, dated February 8, 2000, "Steam

Generator Inservice Inspection Summary Report." ADAMS Accession No. ML003684433

Letter from R.M. Krich, Commonwealth Edison, to the NRC, dated July 31, 2000, "Steam

Generator Laser Welded Sleeves." ADAMS Accession No. ML003738467

Letter from R.P. Lopriore, Exelon Generation Company, LLC, to the NRC, dated April 23, 2001,

"Steam Generator Tube Repairs Performed During the Byron Station Unit 2, Cycle 9 Refueling

Outage." ADAMS Accession No. ML01 1200063

Letter from R.P. Lopriore, Exelon Generation Company, LLC, to the NRC, dated July 12, 2001,

'Steam Generator Inservice Inspection Summary Report." ADAMS Accession No.

MLO011980298

Callaway

Letter from J.D. Blosser, Union Electric, to the NRC dated April 28,1987, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 87-03,

Number of Tubes Plugging During Second Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 8705040301

Letter from J.D. Blosser, Union Electric, to the NRC dated March 4, 1988, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 87-04,

Results of Second Steam Generator Tube Inservice Inspection." NUDOCS Accession No.

8803150025

-219-
Letter from J.D. Blosser, Union Electric, to the NRC dated October 15, 1987, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 87-11,

Number of Tubes Plugged During Third Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 8710230217

Letter from J.D. Blosser, Union Electric, to the NRC dated August 2, 1988, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 87-12,

Results of Third Steam Generator Tube Inservice Inspection." NUDOCS Accession No.

8808090082

Letter from J.D. Blosser, Union Electric, to the NRC dated May 1, 1989, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 89-04,

Number of Tubes Plugged During Third Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 8905150199

Letter from D.F. Schnell, Union Electric, to the NRC dated June 15, 1989, "Docket Number

50-483, Callaway Plant, Failure of Westinghouse Steam Generator Tube Mechanical Plugs."

NUDOCS Accession No. 8906260308

Letter from J.D. Blosser, Union Electric, to the NRC dated March 30, 1990, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 89-05,

Results of the Fourth Steam Generator Tube Inservice Inspection." NUDOCS Accession No.

9004110012

Letter from J.D. Blosser, Union Electric, to the NRC dated November 5, 1990, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 90-03,

Number of Tubes Plugged During Fourth Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 9011090110

Letter from J.D. Blosser, Union Electric, to the NRC dated August 12, 1991, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 90-04 (SOS

90-3060), Results of the Fifth Steam Generator Tube Inservice Inspection." NUDOCS

Accession No. 9108150051

Letter from D.F. Schnell, Union Electric, to the NRC dated July 24, 1991, "Docket Number

50-483, Callaway Plant, Failure of Westinghouse Steam Generator Tube Mechanical Plugs."

NUDOCS Accession No. 9107300032

Letter from J.D. Blosser, Union Electric, to the NRC dated May 13, 1992, uDocument Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 92-02,

Number of Tubes Plugged During Sixth Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 9205210002

Letter from D.F. Schnell, Union Electric, to the NRC dated March 11, 1992, "Docket Number

50-483, Callaway Plant, Failure of Westinghouse Steam Generator Tube Mechanical Plugs."

NUDOCS Accession No. 9203170366

-220-
Letter from D.F. Schnell, Union Electric, to the NRC dated July 2, 1992, "Docket Number

50-483, Callaway Plant, Failure of Westinghouse Steam Generator Tube Mechanical Plugs."

NUDOCS Accession No. 9207090165

Letter from W.R. Campbell, Union Electric, to the NRC dated January 29,1993, "Docket

Number 50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report

92-03 (SOS 92-1293), Results of the Sixth Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 9302120086

Letter from J.D. Blosser, Union Electric, to the NRC dated November 8, 1993, 'Document

Number 50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report

93-02, Number of Tubes Plugged During Sixth Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 9311150219

Letter from C.D. Naslund, Union Electric, to the NRC dated February 11, 1994, "Docket

Number 50-483, Callaway Refuel 6 Inservice Inspection Summary Report." NUDOCS

Accession No. 9403010178

Letter from J.D. Blosser, Union Electric, to the NRC dated September 29, 1994, "Docket

Number 50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report

93-03 (SOS 93-1622), Results of the Sixth Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 9410050108

Letter from J.D. Blosser, Union Electric, to the NRC dated May 11, 1995, "Document Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 95-01,

Number of Tubes Plugged During the Eighth Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 9505190314

Letter from C.D. Naslund, Union Electric, to the NRC dated August 3,1995, "Docket Number

50-483, Callaway Refuel 7 Inservice Inspection Summary Report." NUDOCS Accession No.

9508150261

Letter from R.D. Affolter, Union Electric, to the NRC dated April 1, 1996, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 95-02 (SOS

95-1138), Results of the Eighth Steam Generator Tube In-Service Inspection." NUDOCS

Accession No.-9604080153

Letter from D.F. Schnell, Union Electric, to the NRC dated February 1, 1995, "Callaway Plant,

Docket Number 50-483, Interim Report on Westinghouse Alloy 600 Steam Generator

Mechanical Plugs." NUDOCS Accession No. 9502070285

Letter from D.F. Schnell, Union Electric, to the NRC dated September 26, 1995, "Callaway

Plant, Docket Number 50-483, Westinghouse Alloy 600 Steam Generator Mechanical Plugs."

NUDOCS Accession No. 9510030346

Letter from D.F. Schnell, Union Electric, to the NRC dated January 12,1996, "Callaway Plant,

Docket Number 50-483, Circumferential Cracking of Steam Generator Tubes." NUDOCS

Accession No. 9601170033

-221-
Letter from R.D. Affolter, Union Electric, to the NRC dated November 19, 1996, "Docket

Number 50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report

96-003, Number of Tubes Plugged During the Ninth Steam Generator Tube Inservice

Inspection." NUDOCS Accession No. 9611260198

Letter from R.D. Affolter, Union Electric, to the NRC dated October 9, 1997, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 96-02 (SOS

96-1706), Results of the Ninth Steam Generator Tube In-Service Inspection." NUDOCS

Accession No. 9710170069

Letter from R.D. Affolter, Union Electric, to the NRC dated May 18, 1998, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 98-001,

Number of Tubes Plugged During the Tenth Steam Generator Tube Inservice Inspection."

NUDOCS Accession No. 9805260013

Letter from J.A. McGraw, Union Electric, to the NRC dated July 29, 1998, "Docket Number

50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, Interval

2, Period 1 Inservice Inspection Summary Report." NUDOCS Accession No. 9808050141

Letter from R.D. Affolter, Union Electric, to the NRC dated March 25, 1999, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 98-03,

Results of the Tenth Steam Generator Tube In-Service Inspection." NUDOCS Accession No.

9904230071

Letter from R.D. Affolter, Union Electric, to the NRC dated April 28, 1999, "Docket Number

50-483, Callaway Plant Unit 1, Facility Operating License NPF-30, Special Report 98-03,

Results of the Tenth Steam Generator Tube In-Service Inspection." NUDOCS Accession No.

9905050080

Letter from R.D. Affolter, Union Electric, to the NRC dated November 5, 1999, "Docket Number

50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, Special

Report 99-02, Inservice Inspection Results for Steam Generator Tube Inspections - Number of

Tubes Plugged or Repaired." ADAMS Accession No. ML993160189

Letter from R.D. Affolter, Union Electric, to the NRC dated June 1, 2000, "Docket Number

50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, Special

Report 2000-01, Results of the Eleventh Steam Generator Tube In-Service Inspection."

ADAMS Accession No. ML003721791

Letter from W.A. Witt, Union Electric, to the NRC dated May 10, 2001, "Docket Number 50-483,

Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, Special Report

2001-01, Inservice Inspection Results for Steam Generator Tube Inspections - Number of

Tubes Plugged or Repaired." ADAMS Accession No. ML01 1350341

Letter from W.A. Witt, Union Electric, to the NRC dated January 29, 2002, "Docket Number

50-483, Callaway Plant Unit 1, Union Electric Co., Facility Operating License NPF-30, Special

Report 2001-02, Results of Twelfth Steam Generator Tube In-Service Inspection." ADAMS

Accession No. ML020460331

-222-
Catawba 2

Letter from H.B. Tucker, Duke Power Company, to the NRC dated February 26,1988,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, Licensee Event Report 414/88-02,

Technical Specification Violation Because of Steam Generator Tube Degradation Due to a

Personnel Error and a Management Deficiency." NUDOCS Accession No. 8906290143

Letter from H.B. Tucker, Duke Power Company, to the NRC dated February 29, 1988,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, Steam Generator Tube Inspections."

NUDOCS Accession No. 8803080052

Letter from H.B. Tucker, Duke Power Company, to the NRC dated March 11, 1988, "Catawba

Nuclear Station, Unit 2, Docket No. 50-414, Licensee Event Report 414/88-04, Foreign Objects

on Steam Generator Tubesheet Result in Tube Damage due to a Manufacturing Deficiency."

NUDOCS Accession No. 8906290090

Letter from H.B. Tucker, Duke Power Company, to the NRC dated May 6,1988, "Catawba

Nuclear Station, Unit 2, Docket No. 50-414, Inservice Inspection Report, End-of-Cycle 1

Refueling Outage." NUDOCS Accession No. 8805240073

Letter from H.B. Tucker, Duke Power Company, to the NRC dated February 28, 1989,

uCatawba Nuclear Station, Unit 2, Docket No. 50-414, End of Cycle 1 Steam Generator

Inspection." NUDOCS Accession No. 8903150459

Letter from H.B. Tucker, Duke Power Company, to the NRC dated May 15, 1989, "Catawba

Nuclear Station, Unit 2, Docket No. 50-414, End of Cycle 2 Steam Generator Inspection."

NUDOCS Accession No. 8905240517

Letter from H.B. Tucker, Duke Power Company, to the NRC dated April 25, 1990, "Catawba

Nuclear Station, Unit 2, Docket No. 50-414, Steam Generator Inspection Report." NUDOCS

Accession No. 9005040194

Letter from H.B. Tucker, Duke Power Company, to the NRC dated July 26, 1990, "Catawba

Nuclear Station, Unit 2, Docket No. 50-414, Inservice Inspection Report, End-of-Cycle 3 Steam

Generator Inspection." NUDOCS Accession No. 9007310218

Letter from M.S. Tuckman, Duke Power Company, to the NRC dated August 21, 1991,

"Catawba Nuclear Station, Docket No. 50-414, Unit 2 EOC-3 Refueling Outage, Steam

Generator Inspection." NUDOCS Accession No. 9108260279

Letter from M.S. Tuckman, Duke Power Company, to the NRC dated December 18, 1991,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, End of Cycle 4 Refueling Outage, 15 Day

Steam Generator Tube Inservice Inspection Report." NUDOCS Accession No. 9112270088

Letter from M.S. Tuckman, Duke Power Company, to the NRC dated November 18, 1992,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, Special Report, 12 Month Steam

Generator Inspection Report, End of Cycle 4." NUDOCS Accession No. 9211250148

-223-
Letter from M.S. Tuckman, Duke Power Company, to the NRC dated March 17, 1993,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, End of Cycle 5 Refueling Outage, 15 Day

Steam Generator Tube Inservice Inspection Report." NUDOCS Accession No. 9303220201

Letter from M.S. Tuckman, Duke Power Company, to the NRC dated March 15, 1993[1994],

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, Special Report, End of Cycle 5 Refueling

Outage, Steam Generator Tube Inspection Report." NUDOCS Accession No. 9403220254

Letter from D.L. Rehn, Duke Power Company, to the NRC dated June 13, 1994, "Catawba

Nuclear Station, Unit 2, Docket No. 50-414, Special Report, End of Cycle 6 Refueling Outage,

15 Day Steam Generator Tube Inservice Inspection Report." NUDOCS Accession No.

9406220294

Letter from D.L. Rehn, Duke Power Company, to the NRC dated September 20, 1994,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, Special Report, End of Cycle 6 Refueling

Outage, Steam Generator Tube Inspection Report - 12 Month." NUDOCS Accession No.

9409270323

Letter from M.S. Tuckman, Duke Power Company, to the NRC dated January 31, 1995,

"McGuire Nuclear Station Units 1 & 2, Docket Nos. 50-369, 370, Catawba Nuclear Station Units

1 & 2, Docket Nos. 50-413, 414, Oconee Nuclear Station Units 1, 2, & 3, Docket Nos. 50-269,

270, 287, Interim Report on Westinghouse Alloy 600 SG Mechanical Plugs Installed at Duke

Power Plants." NUDOCS Accession No. 9502070326

Letter from M.S. Tuckman, Duke Power Company, to the NRC dated September 19, 1995,

"Catawba Nuclear Station, Units 1 & 2, Docket Nos. 50-413, 414, Response to Request for

Additional Information Concerning Generic Letter 95-03." NUDOCS Accession No.

9509250289

Letter from W.R. McCollum, Jr., Duke Power Company, to the NRC dated November 14, 1995,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, Special Report, End of Cycle 7 Refueling

Outage, Steam Generator Tube Inspection Report." NUDOCS Accession No. 9511210058

Letter from W.R. McCollum, Jr., Duke Power Company, to the NRC dated April 24, 1997,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, Special Report, End of Cycle 8 Refueling

Outage, Steam Generator Tube Inspection Report." NUDOCS Accession No. 9705070030

Letter from G.R. Peterson, Duke Power Company, to the NRC dated October 8, 1998,

"Catawba Nuclear Station, Unit 2, Docket No. 50-414, Special Report - Steam Generator Tube

Plugging." NUDOCS Accession No. 9810190294

Letter from G.R. Peterson, Duke Energy, to the NRC dated February 9, 1999, "Catawba

Nuclear Station, Unit 2, Docket No. 50-414, Special Report - Steam Generator Tube

Inspection." NUDOCS Accession No. 9902160167

Letter from G.R. Peterson, Duke Energy, to the NRC dated June 18, 1999, "Catawba Nuclear

Stations, Units 2, Docket Nos. 50-414, Steam Generator Tube Inspection Report." NUDOCS

Accession No. 9906290060

-224-
Letter from G.R. Peterson, Duke Power, to the NRC dated April 13, 2000, "Catawba Nuclear

Stations, Unit 2, Docket Nos. 50-414, Steam Generator Tube Inspection Report." ADAMS

Accession No. ML003705897

Letter from G.R. Peterson, Duke Power, to the NRC dated June 29, 2000, "Duke Energy

Corporation, Catawba Nuclear Station, Unit 2, Docket Nos. 50-414, Inservice Inspection Report,

Steam Generator Outage Summary Report for Unit 2 End of Cycle 10 (2EOC10) Refueling

Outage." ADAMS Accession No. ML0037313280

Letter from G.R. Peterson, Duke Power, to the NRC dated September 11, 2000, "Duke Energy

Corporation, Catawba Nuclear Station, Docket Nos. 50-413, 50-414, Steam Generator Tube

Inspection Summary Reports." ADAMS Accession Nos. ML003751571, ML003751594,

ML0037511637, ML0037511640, and ML003751742

Letter from G.R. Peterson, Duke Power, to the NRC dated October 23, 2001, "Catawba Nuclear

Station, Unit 2, Docket No. 50-414, Steam Generator Inservice Inspection." ADAMS Accession

No. ML020150410

Letter from G.R. Peterson, Duke Power, to the NRC dated October 24, 2001, "Catawba Nuclear

Station, Unit 2, Docket No. 50-414, Steam Generator Tube Inspection Report." ADAMS

Accession No. ML013410150

Letter from G.R. Peterson, Duke Power, to the NRC dated January 17, 2002, "Duke Energy

Corporation, Catawba Nuclear Station, Unit 2, Docket Number 50-414, Inservice Inspection

Report and Steam Generator Outage Summary Report for End of Cycle 11 Refueling Outage."

ADAMS Accession Nos. ML020420187, ML020420198, ML020420293

Comanche Peak 2

Letter from C.L. Terry, TU Electric, to the NRC dated November 7, 1994, "Comanche Peak

Steam Electric Station (CPSES) - Unit 2, Docket No. 50-446, Special Report on the Unit 2, First

Refueling Outage, Steam Generator Inservice Inspection Tube Plugging." NUDOCS Accession

No.

Letter from C.L. Terry, TU Electric, to the NRC dated February 17, 1995, "Comanche Peak

Steam Electric Station (CPSES) - Unit 2, Docket No. 50-446, Submittal of Unit 2 First Refueling

Outage Inservice Inspection (ISI) Summary Report (Unit 2: 1986 Edition of ASME Code,

Section Xl, No Addenda, Interval Start Date - August 3, 1993, First Interval)." NUDOCS

Accession No. 9502210330

Letter from C.L. Terry, TU Electric, to the NRC dated March 6, 1995, "Comanche Peak Steam

Electric Station (CPSES) - Unit 2, Docket No. 50-446, Special Report on the Unit 2, First

Refueling Outage, Steam Generator Inservice Inspection Tube Plugging and Summary Report."

NUDOCS Accession No.

-225-
Letter from C.L. Terry, TU Electric, to the NRC dated March 25, 1996, "Comanche Peak Steam

Electric Station (CPSES) - Unit 2, Docket No. 50-446, Unit 2, Second Refueling Outage, Steam

Generator Inservice Inspection Tube Plugging, Special Report No. 2-SR-96-001-00." NUDOCS

Accession No.

Letter from M.R. Blevins, TU Electric, to the NRC dated July 23,1996, "Comanche Peak Steam

Electric Station (CPSES) - Unit 2, Docket No. 50-446, Submittal of Unit 2 Second Refueling

Outage Inservice Inspection (ISI) Summary Report (Unit 2: 1986 Edition of ASME Code,

Section Xl, No Addenda, Interval Start Date - August 3, 1993, First Interval)." NUDOCS

Accession No. 9607250109

Letter from C.L. Terry, TU Electric, to the NRC dated August 30, 1996, "Comanche Peak

Steam Electric Station (CPSES) - Unit 2, Docket No. 50-446, Special Report on the Unit 2,

Second Refueling Outage, Steam Generator Inservice Inspection Tube Plugging, Special

Report No. 2-SR-96-002-00.' NUDOCS Accession No.

Letter from C.L. Terry, TU Electric, to the NRC dated July 10, 1997, "Comanche Peak Steam

Electric Station (CPSES), Docket No. 50-445 and 50-446, NRC Inspection Report Nos.

50-445/97-09 and 50-446/97-09, Supplement to Response to Notice of Violation." NUDOCS

Accession No. 9707180059

Letter from C.L. Terry, TU Electric, to the NRC dated November 20, 1997, "Comanche Peak

Steam Electric Station (CPSES) - Unit 2, Docket No. 50-446, Unit 2, Third Refueling Outage,

Steam Generator Inservice Inspection Tube Plugging, Special Report No. 2-SR-97-002-00."

NUDOCS Accession No.

Letter from C.L. Terry, TU Electric, to the NRC dated December 23, 1997, "Comanche Peak

Steam Electric Station (CPSES) - Unit 2, Docket No. 50-446, Special Report on the Unit 2,

Third Refueling Outage, Steam Generator Inservice Inspection Tube Plugging Special Report

No. 2-SR-97-003-00." NUDOCS Accession No. 9712310299

Letter from C.L. Terry, TU Electric, to the NRC dated April 15, 1999, 'Comanche Peak Steam

Electric Station (CPSES) - Unit 2, Docket No. 50-446, Unit 2, Fourth Refueling Outage

(2RF04), Steam Generator Inservice Inspection Tube Plugging, Special Report No.

2-SR-99-001-00." NUDOCS Accession No. 9904210175

Letter from C.L. Terry, TU Electric, to the NRC dated July 16, 1999, "Comanche Peak Steam

Electric Station (CPSES) - Unit 2, Docket No. 50-446, Submittal of Unit 2 Fourth Refueling

Outage (2RF04) Inservice Inspection (ISI) Summary Report, 1986 Edition of ASME Code,

Section Xl, No Addenda, and Containment Inservice Inspection (CISI) Summary Report, 1992

Edition of ASME Section Xl 1992 Addenda." NUDOCS Accession No. 9907200177

Letter from C.L. Terry, TXU Electric, to the NRC dated January 28, 2000, "Comanche Peak

Steam Electric Station (CPSES) Unit 2, Docket Nos. 50-446, Unit 2 Fourth Refueling Outage,

Condition Monitoring Report Special Report 446/00-001-00." ADAMS Accession No.

ML003679671

-226-
Letter from C.L. Terry, TXU Electric, to the NRC dated October 20, 2000, "Comanche Peak

Steam Electric Station (CPSES) - Unit 2, Docket No. 50-446, Unit 2, Fifth Refueling Outage

(2RF05), Steam Generator Inservice Inspection Tube Plugging, Special Report No.

2-SR-00-001 -00." ADAMS Accession No.

Letter from C.L. Terry, TXU Electric, to the NRC dated February 2, 2001, "Comanche Peak

Steam Electric Station (CPSES)-Unit 2, Docket Nos. 50-446, Submittal of Unit 2 Fifth Refueling

Outage (2RF05) 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. ML01 0370402

Letter from C.L. Terry, TXU Electric, to the NRC dated November 7, 2000, "Comanche Peak

Steam Electric Station (CPSES)-Unit 2, Docket No. 50-446, Unit 2 Fifth Refueling Outage,

Condition Monitoring Report, Special Report 446/00-002-00." ADAMS Accession No.

ML003768963

Indian Point 2

Letter from J.S. Baumstark, Consolidated Edison Company of New York, Inc., to the NRC

dated December 11, 2000, "Proposed Technical Specification Amendment - Changes to

Primary to Secondary Leakage Limits and Steam Generator Tube Inservice Surveillance

Requirements." ADAMS Accession No. ML003779281

Letter from P.D. Milano, NRC to M.R. Kansler, Entergy Nuclear Operations, Inc., dated April 2,

2002, "Indian Point Nuclear Generating Unit No. 2 - Amendment Re: Technical Specification

Changes to Secondary Leakage Limits and Steam Generator Tube Inservice Surveillance

Requirements (TAC No. MB0770)." ADAMS Accession No. ML020590148

Millstone 3

Letter from S.E. Scace, Northeast Utilities, to the NRC dated December 14, 1987, "Steam

Generator Tube Plugging." NUDOCS Accession No. 8712210219

Letter from E.J. Mroczka, Northeast Utilities, to the NRC dated May 3,1988, "Millstone Nuclear

Power Station Unit No. 3, In-Service Inspection Summary Report." NUDOCS Accession No.

8805060165

Letter from S.E. Scace, Northeast Utilities, to the NRC dated June 13, 1989, "Millstone Nuclear

Power Station, Unit 3 Steam Generator Tube Plugging." NUDOCS Accession No. 8906200377

Letter from E.J. Mroczka, Northeast Utilities, to the NRC dated June 16, 1989, "Haddam Neck

Plant, Millstone Nuclear Power Station, Unit Nos. 2 and 3, NRC Bulletin No. 89-01, Failure of

Westinghouse Steam Generator Tube Mechanical Plugs." NUDOCS Accession No.

8906270273

Letter from E.J. Mroczka, Northeast Utilities, to the NRC dated June 29, 1989, "Haddam Neck

Plant, Millstone Nuclear Power Station, Unit No. 3, Proposed Revision to Technical

-227-
Specifications, Steam Generator Tube Inspection Acceptance Criteria." NUDOCS Accession

No. 8907050418

Letter from S.E. Scace, Northeast Utilities, to the NRC dated April 2, 1990, "Millstone Nuclear

Power Station, Unit No. 3 Steam Generator Tube Inservice Inspection Report.' NUDOCS

Accession No. 9004180368

Letter from S.E. Scace, Northeast Utilities, to the NRC dated March 6,1991, "Millstone Nuclear

Power Station, Unit No. 3 Steam Generator Tube Plugging." NUDOCS Accession No.

9103130123

Letter from E.J. Mroczka, Northeast Utilities, to the NRC dated July 30, 1991, "Haddam Neck

Plant, Millstone Nuclear Power Station, Unit Nos. 2 and 3, NRC Bulletin No. 89-01, Supplement

2, Failure of Westinghouse Steam Generator Tube Mechanical Plugs." NUDOCS Accession

No. 9108060084

Letter from S.E. Scace, Northeast Utilities, to the NRC dated February 18, 1992, "Millstone

Nuclear Power Station, Unit No. 3 Steam Generator Tube Inservice Inspection Report."

NUDOCS Accession No. 9202260164

Letter from J.F. Opeka, Northeast Utilities, to the NRC dated April 15, 1993, "Millstone Nuclear

Power Station, Unit No. 3, Proposed Revision to Technical Specifications, Steam Generator

Surveillance Requirements." NUDOCS Accession No. 9304220155

Letter from D.B. Miller Jr., Northeast Nuclear Energy, to the NRC dated August 11, 1994,

"Millstone Nuclear Power Station, Unit No. 3, Steam Generator Tube Inservice Inspection

Report." NUDOCS Accession No. 9408170294

Letter from J.F. Opeka, Northeast Utilities System, to the NRC dated May 1, 1995, "Millstone

Nuclear Power Station, Unit No. 3, Proposed Revision to Technical Specifications, 24-Month

Fuel Cycle - Containment Type B and Type C Testing and Steam Generator Tube Inspections

and Request for Exemption from 1 OCFR50, Appendix J." NUDOCS Accession No.

9505050189

Letter from D.B. Miller Jr., Northeast Nuclear Energy, to the NRC dated May 18, 1995,

"Millstone Nuclear Power Station Unit No. 3, Steam Generator Tube Plugging." NUDOCS

Accession No. 9505250204

Letter from D.B. Miller Jr., Northeast Nuclear Energy, to the NRC dated November 14, 1995,

"Millstone Nuclear Power Station, Unit No. 3, Steam Generator Tube Inservice Inspection

Report." NUDOCS Accession No. 9511210250

Letter from M.H. Brothers, Northeast Utilities System, to the NRC dated October 16, 1996,

"Millstone Nuclear Power Station Unit 3, Steam Generator Tube Plugging." NUDOCS

Accession No. 9610180012

-228-
Letter from M.H. Brothers, Northeast Nuclear Energy, to the NRC dated September 30, 1997,

"Millstone Nuclear Power Station Unit No. 3, Steam Generator Tube Inservice Inspection

Report." NUDOCS Accession No. 9710060421

Letter from M.H. Brothers, Northeast Nuclear Energy, to the NRC dated August 6,1998,

"Millstone Nuclear Power Station, Unit No. 3, Proposed Revision to Technical Specification,

Steam Generator Tube Inspection Interval (TSCR 3-17-98)." NUDOCS Accession No.

9808120261

Letter from M.L. Bowling Jr., Northeast Nuclear Energy, to the NRC dated September 21, 1998,

"Millstone Nuclear Power Station, Unit No. 3, Proposed Revision to Technical Specification,

Steam Generator Tube Inspection Interval (TSCR 3-17-98), Request for Additional Information."

NUDOCS Accession No. 9809250362

Letter from J.W. Andersen, NRC to M.L. Bowling Jr., Northeast Nuclear Energy, dated

September 23,1998, "Issuance of Amendment - Millstone Nuclear Power Station, Unit No. 3

(TAC No. MA2463)." NUDOCS Accession No. 9809250236

Letter from R.P. Necci, Northeast Nuclear Energy, to the NRC dated March 11, 1999, 'Millstone

Nuclear Power Station, Unit No. 3, Schedule for Responding to NRC Request for Additional

Information Pertaining to Steam Generator Tube Inspection." NUDOCS Accession No.

9903180110

Letter from R.P. Necci, Northeast Nuclear Energy, to the NRC dated June 2, 1999, "Millstone

Nuclear Power Station, Unit No. 3, Steam Generator Tube Plugging." NUDOCS Accession No.

9906100051

Letter from R.P. Necci, Northeast Nuclear Energy, to the NRC dated October 5, 1999,

"Millstone Nuclear Power Station, Unit No. 3, Withdrawal of 24 Month Steam Generator Tube

Inspection Surveillance Extensions." NUDOCS Accession No. 9910130068

Letter from R.P. Necci, Northeast Nuclear Energy, to the NRC dated November 9, 1999,

"Millstone Nuclear Power Station, Unit No. 3, Withdrawal of 24 Month Steam Generator Tube

Inspection Surveillance Extensions-Reference Revision." ADAMS Accession No.

ML993280010

Letter from C.J. Schwarz, Northeast Nuclear Energy, to the NRC dated February 17, 2000,

"Millstone Nuclear Power Station Unit No. 3, Special Report - Steam Generator Tube

Examination." ADAMS Accession No. ML0036874250

Letter from R.G. Lizotte, Northeast Nuclear Energy, to the NRC dated March 5, 2001, "Millstone

Nuclear Power Station, Unit No. 3, Steam Generator Tube Plugging." ADAMS Accession No.

ML010720282

Letter from C.J. Schwarz, Dominion Nuclear Connecticut, Inc., to the NRC dated February 15,

2002, "Millstone Nuclear Power Station, Unit No. 3, Special Report - Steam Generator Tube

Inservice Inspection." ADAMS Accession No. ML020630236

-229-
Point Beach 1

Wisconsin Electric Power Company, "Annual Results & Data Report, 1984." NUDOCS

Accession No. 8503140252

Letter from C.W. Fay, Wisconsin Electric Power Company, to the NRC dated March 11, 1985,

"Docket Nos. 50-266 and 50-301, Annual Results and Data Report, Point Beach Nuclear Plant,

Units 1 and 2." NUDOCS Accession No. 8503250347

Wisconsin Electric Power Company, "Annual Results & Data Report, 1985." NUDOCS

Accession No. 8603130049

Wisconsin Electric Power Company, "Annual Results & Data Report, 1986." NUDOCS

Accession No. 8703030170

Wisconsin Electric Power Company, "Annual Results & Data Report, 1987." NUDOCS

Accession No. 8803040258

Wisconsin Electric Power Company, "Annual Results & Data Report, 1988." NUDOCS

Accession No. 8903080484

Letter from C.W. Fay, Wisconsin Electric Power Company, to the NRC dated February 28,

1990, "Docket Nos. 50-266 and 50-301, Annual Results and Data Report 1989, Point Beach

Nuclear Plant, Units 1 and 2." NUDOCS Accession No. 9003080460

Letter from C.W. Fay, Wisconsin Electric Power Company, to the NRC dated June 27, 1991,

"Dockets 50-266 and 50-301, Addendum to Annual Results and Data Report for 1987, 1988,

and 1989, Point Beach Nuclear Plant Units 1 and 2." NUDOCS Accession No. 9107100105

Letter from C.W. Fay, Wisconsin Electric Power Company, to the NRC dated February 27,

1991, "Docket Nos. 5[0]-266 and 50-301, Annual Results and Data Report 1990, Point Beach

Nuclear Plant, Units 1 and 2." NUDOCS Accession No. 9103070072

Wisconsin Electric Power Company, "Annual Results & Data Report, 1990." NUDOCS

Accession No. 9103060210

Letter from C.W. Fay, Wisconsin Electric Power Company, to the NRC dated May 17,1991,

Docket 50-266, Licensee Event Report 90-002-00, Degradation of Steam Generator Tubes,

Point Beach Nuclear Plant, Unit 1." NUDOCS Accession No. 9105280190

Letter from J.J. Zach, Wisconsin Electric Power Company, to the NRC dated February 28,

1992, "Docket Nos. 50-266 and 50-301, Annual Results and Data Report - 1991, Point Beach

Nuclear Plant, Units 1 and 2." NUDOCS Accession No. 9203030345

Letter from B. Link, Wisconsin Electric Power Company, to the NRC dated February 25, 1993,

"Dockets 50-266 and 50-301, Annual Results and Data Report - 1992, Point Beach Nuclear

Plant, Units 1 and 2." NUDOCS Accession No. 9303020493

-230-
Letter from B. Link, Wisconsin Electric Power Company, to the NRC dated March 17, 1993,

"Dockets 50-266 and 50-301, Annual Results and Data Report - 1992, Point Beach Nuclear

Plant, Units 1 and 2." NUDOCS Accession No. 9303230146

Letter from B. Link, Wisconsin Electric Power Company, to the NRC dated February 25,1994,

"Dockets 50-266 and 50-301, Annual Results and Data Report - 1993, Point Beach Nuclear

Plant, Units 1 and 2." NUDOCS Accession No. 9403080197

Letter from B. Link, Wisconsin Electric Power Company, to the NRC dated March 30,1994,

"Docket 50-266, Steam Generator Inspection Plan, Point Beach Nuclear Plant, Unit 1."

NUDOCS Accession No. 9404060014

Letter from G.M. Krieser, Wisconsin Electric Power Company, to the NRC dated February 23,

1995, "Dockets 50-266 and 50-301, Annual Results and Data Report - 1994, Point Beach

Nuclear Plant, Units 1 and 2." NUDOCS Accession No. 9503020244

Letter from G.M. Krieser, Wisconsin Electric Power Company, to the NRC dated February 28,

1996, "Dockets 50-266 and 50-301, Annual Results and Data Report - 1995, Point Beach

Nuclear Plant, Units 1 and 2." NUDOCS Accession No. 9603050276

Letter from D.F. Johnson, Wisconsin Electric Power Company, to the NRC dated February 27,

1997, "Dockets 50-266 and 50-301, Annual Results and Data Report - 1996, Point Beach

Nuclear Plant, Units 1 and 2." NUDOCS Accession No. 9703050035

Letter from D.F. Johnson, Wisconsin Electric Power Company, to the NRC dated February 27,

1998, "Dockets 50-266 and 50-301, 1997 Annual Results and Data Report, Point Beach

Nuclear Plant, Units 1 and 2." NUDOCS Accession No. 9803040445

Letter from V.A. Kaminskas, Wisconsin Electric Power Company, to the NRC dated February

25,1999, "Dockets 50-266 and 50-301, 1998 Annual Results and Data Report, Point Beach

Nuclear Plant, Units 1 and 2." NUDOCS Accession No. 9903100033

Letter from A.J. Cayia, Wisconsin Electric Power Company, to the NRC dated February 28,

2000, "Dockets 50-266 and 50-301, 1999 Annual Results and Data Report, Point Beach

Nuclear Plant, Units 1 and 2." ADAMS Accession No. ML003689804

Letter from A.J. Cayia, Nuclear Management Company, LLC, to the NRC dated February 28,

2001, "Dockets 50-266 and 50-301, 2000 Annual Results and Data Report, Point Beach

Nuclear Plant, Units 1 and 2." ADAMS Accession No. ML010670316

Letter from T.J. Webb, Nuclear Management Company, LLC, to the NRC dated March 9, 2001,

"Dockets 50-266, 50-301, and 72-005,1999 Annual Results and Data Report Errata, Point

Beach Nuclear Plant, Units 1 and 2." ADAMS Accession No. ML010790116

Letter from T.J. Webb, Nuclear Management Company, LLC, to the NRC dated May 2, 2001,

"Docket 50-301, Steam Generator Tube Plugging, Point Beach Nuclear Plant, Unit 1." ADAMS

Accession No. ML01 1280137

-231-
Letter from T.J. Webb, Nuclear Management Company, LLC, to the NRC dated September 4,

2002, "Docket 50-266, Point Beach Nuclear Plant, Unit 1, Summary of the Spring 2001 Unit 1

(Ul R26) Steam Generator Eddy Current Examinations." ADAMS Accession Number not

available as of date of preparation.

Robinson 2

Letter from R.E. Morgan, Carolina Power & Light Company, to the NRC dated September 11,

1987, "H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No.

DPR-23; 90-Day Inservice Inspection Report." NUDOCS Accession No. 8709230338

Letter from R.E. Morgan, Carolina Power & Light Company, to the NRC dated December 16,

1988, "H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No.

DPR-23; 14-Day Special Report - Plugged Steam Generator Tube." NUDOCS Accession No.

8812200340

Letter from R.E. Morgan, Carolina Power & Light Company, to the NRC dated April 27,1989,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No. DPR-23;

90-Day Inservice Inspection Report." NUDOCS Accession No. 8905050159

Letter from R.E. Morgan, Carolina Power & Light Company, to the NRC dated March 10, 1989,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No. DPR-23;

Monthly Operations Report." NUDOCS Accession No. 8903200181

Letter from R.E. Morgan, Carolina Power & Light Company, to the NRC dated May 11, 1989,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No. DPR-23;

Monthly Operations Report." NUDOCS Accession No. 8905180153

Letter from R.E. Morgan, Carolina Power & Light Company, to the NRC dated May 11, 1989,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No. DPR-23;

Monthly Operations Report." NUDOCS Accession No. 8905180158

Letter from D.M. Verrelli, NRC to Lynn W. Eury, Carolina Power & Light Company dated May

18,1989, "Notice of Violation, NRC Inspection Report No. 50-261/89-08." NUDOCS Accession

No. 8906050174

Letter from A.B. Cutter, Carolina Power & Light Company, to the NRC dated June 14,1989,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Response to NRC Bulletin 89-01, Failure of Westinghouse Steam Generator Tube Mechanical

Plugs." NUDOCS Accession No. 8906270150

Letter from A.B. Cutter, Carolina Power & Light Company, to the NRC dated June 26, 1990,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Request for License Amendment, Steam Generator Tube Inspection." NUDOCS Accession

No. 9007050031

-232-
Letter from J.J. Sheppard, Carolina Power & Light Company, to the NRC dated June 3,1991,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No. DPR-23;

90-Day Inservice Inspection Report." NUDOCS Accession No. 9106070289

Letter from G.E. Vaughn, Carolina Power & Light Company, to the NRC dated July 31,1991,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Response to NRC Bulletin 89-01 Supplement 2, Failure of Westinghouse Steam Generator

Tube Mechanical Plugs." NUDOCS Accession No. 9108070023

Letter from R.H. Chambers, Carolina Power & Light Company, to the NRC dated May 11, 1992,

UH.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No. DPR-23;

Inservice Inspection: Steam Generator Tube Plug." NUDOCS Accession No. 9205210003

Letter from R.H. Chambers, Carolina Power & Light Company, to the NRC dated September

21, 1992, "H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261:; License No.

DPR-23; 90-Day Inservice Inspection Report." NUDOCS Accession No. 9209290226

Letter from M.P. Pearson, Carolina Power & Light Company, to the NRC dated October 15,

1993, 'H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No.

DPR-23; Inservice Inspection: Steam Generator Tube Plug." NUDOCS Accession No.

9310210196

Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated February 11, 1994,

UH.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261; License No. DPR-23;

90-Day Inservice Inspection Report." NUDOCS Accession No. 9402220131

Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated March 10, 1994,

UH.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Monthly Operations Report." NUDOCS Accession No. 9403150515

Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated April 11, 1994,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Monthly Operations Report." NUDOCS Accession No. 9404190210

Letter from C.A. Julian, NRC to C.S. Hinnant, Carolina Power & Light Company dated April 8,

1994, "NRC Inspection Report No. 50-261/94-10." NUDOCS Accession No. 9404200130

Letter from H. Christensen, NRC to S. Hinnant, Carolina Power & Light Company dated April

15,1994, "Notice of Violation; NRC Inspection Report No. 50-261/94-08." NUDOCS Accession

No. 9405230016

Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated February 23, 1995,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Response to Request for Information by NRC Made in December 22, 1994, Meeting With

Westinghouse Owners Group Regarding Steam Generator Tube Plugs." NUDOCS Accession

No. 9503010209

-233-
Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated September 15,

1995, "H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No.

DPR-23; Submittal of Steam Generator Tube Inservice Inspection Report and 90 Day Inservice

Inspection Report." NUDOCS Accession No. 9509220287

Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated June 27, 1995,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Response to NRC Generic Letter 95-03, 'Circumferential Cracking of Steam Generator Tubes'."

NUDOCS Accession No. 9507060083

Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated July 22,1996,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Response to Request for Additional Information Regarding Response to Generic Letter 95-03,

'Circumferential Cracking of Steam Generator Tubes'." NUDOCS Accession No. 9507300165

Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated July 31, 1996,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Response to Request for Additional Information Regarding Response to Generic Letter 95-03,

'Circumferential Cracking of Steam Generator Tubes'." NUDOCS Accession No. 9508080233

Letter from R.M. Krich, Carolina Power & Light Company, to the NRC dated October 11, 1996,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Special Report Regarding Inservice Inspection Steam Generator Tube Plug." NUDOCS

Accession No. 9610160372

Letter from H.K. Chernoff, Carolina Power & Light Company, to the NRC dated January 20,

1997, "H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No.

DPR-23; Submittal of 90 Day Inservice Inspection Report." NUDOCS Accession No.

9701240314

Letter from T.M. Wilkerson, Carolina Power & Light Company, to the NRC dated May 14,1998,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Monthly Operating Report." NUDOCS Accession No. 9805200189

Letter from T.M. Wilkerson, Carolina Power & Light Company, to the NRC dated July 9, 1998,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Submittal of 90 Day Inservice Inspection Report." NUDOCS Accession No. 9807150082

Letter from R. Subbaratnam, NRC to D.E. Young, Carolina Power & Light Company dated

November 18, 1999, "H.B. Robinson Steam Electric Plant, Unit No. 2 (HBRSEP2) - Closeout of

Generic Letter 97-06, 'Degradation of Steam Generator Internals' (TAC No. MA0939)." ADAMS

Accession No. ML993310066

Letter from R.L. Warden, Carolina Power & Light Company, to the NRC dated November 15,

1999, "H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No.

DPR-23; Monthly Operating Report." ADAMS Accession No. ML993300069

-234-
Letter from R.L. Warden, Carolina Power & Light Company, to the NRC dated January 20,

2000, "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.

ML003677701

Letter from B.L. Fletcher Ill, Carolina Power & Light Company, to the NRC dated May 6, 2001,

"H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No. DPR-23;

Steam Generator Tube Plugging During Refueling Outage 20." ADAMS Accession No.

ML011300085

Letter from B.L. Fletcher Ill, Carolina Power & Light Company, to the NRC dated June 12,

2001, "H.B. Robinson Steam Electric Plant, Unit No. 2; Docket No. 50-261/License No.

DPR-23; Monthly Operating Report." ADAMS Accession No. ML01 1690318

Letter from B.L. Fletcher Ill, Carolina Power & Light Company, to the NRC dated August 10,

2001, "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.

ML012270378

Letter from B.L. Fletcher Ill, Carolina Power & Light Company, to the NRC dated July 3, 2002,

"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. ML021900019

Salem 1

Letter from L.F. Storz, Public Service Electric and Gas Company, to the NRC dated August 12,

1996, "Steam Generator Tube Inspections and Testing; Salem Generating Station Unit No 1;

Docket No. 50-272." NUDOCS Accession No. 9608190065

Letter from A.C. Bakken 1II, Public Service Electric and Gas Company, to the NRC dated

December 30, 1997, "LER 272/95-023-01, Salem Generating Station - Unit 1; Facility Operating

License No. DPR-70; Docket No. 50-272." NUDOCS Accession No. 9801130415

Letter from D.R. Powell, Public Service Electric and Gas Company, to the NRC dated February

26,1998, "Technical Specification 6.9.1.5 Annual Reports; Salem and Hope Creek Generating

Stations; Docket Nos. 50-272, 50-311 and 50-354." NUDOCS Accession No. 9803060081

Letter from D.R. Powell, Public Service Electric and Gas Company, to the NRC dated March 1,

1999, 'Technical Specification 6.9.1.5 Annual Reports; Salem and Hope Creek Generating

Stations; Docket Nos. 50-272, 50-311 and 50-354." NUDOCS Accession No. 9903100217

Letter from G. Salamon, Public Service Electric and Gas Company, to the NRC dated October

20,1999, "Steam Generator Tube Plugging Report; Technical Specification 4.4.6.5.a; Salem

Generating Station Unit No. 1; Facility Operating License DPR-70; Docket No. 50-272."

ADAMS Accession No. ML993070029

-235-
Letter from G. Salamon, Public Service Electric and Gas Company, to the NRC dated February

28, 2000, "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. ML003691698

Letter from G. Salamon, PSEG Nuclear LLC, to the NRC dated February 27, 2001, "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. ML01 0800160

Letter from D.F. Garchow, PSEG Nuclear LLC, to the NRC dated March 28, 2001, 'Response

to Request for Additional Information in Regards to Request for License Amendment; Increased

Licensed Power Level; Salem Generating Station, Unit Nos. 1 and 2; Facility Operating License

DPR-70 and DPR-75; Docket Nos. 50-272 and 50-311." ADAMS Accession No. ML01 1000129

Letter from D.F. Garchow, PSEG Nuclear LLC, to the NRC not dated, "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. ML01 1420106

Letter from G. Salamon, PSEG Nuclear LLC, to the NRC dated February 26, 2002, '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. ML020710732

Seabrook

Letter from G.S. Thomas, New Hampshire Yankee, to the NRC dated June 15, 1989,

"Response to NRC Bulletin 89-01: Failure of Westinghouse Steam Generator Tube Mechanical

Plugs." NUDOCS Accession No. 8906230144

Letter from T.C. Feigenbaum, New Hampshire Yankee, to the NRC dated July 30, 1991,

"Response to NRC Bulletin 89-01, Supplement 2: Failure of Westinghouse Steam Generator

Tube Mechanical Plugs." NUDOCS Accession No. 9108050310

Letter from T.C. Feigenbaum, New Hampshire Yankee, to the NRC dated September 9, 1991,

"Steam Generator Tubes Plugged During First Inservice Inspection." NUDOCS Accession No.

9109110217

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

August 28, 1992, "1991 Steam Generator Inservice Inspection." NUDOCS Accession No.

9209010003

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

October 9, 1992, "Steam Generator Tube Plugging Report for the Second Inservice Inspection."

NUDOCS Accession No. 9210160230

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

August 25,1993, "1992 Steam Generator Inservice Inspection." NUDOCS Accession No.

9309020251

-236-
Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

June 23,1994, "Steam Generator Tube Plugging Report for the Third Inservice Inspection."

NUDOCS Accession No. 9406270329

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

April 26,1995, "1994 Steam Generator Inservice Inspection." NUDOCS Accession No.

9505020200

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

January 30,1995, "Response to Request for Additional Information Regarding Steam

Generator Tube Mechanical Plugs." NUDOCS Accession No. 9502060335

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

August 25, 1995, "Action Plan to Respond to Steam Generator Tube Mechanical Plug

Removal." NUDOCS Accession No. 9508290157

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

December 1, 1995, "Steam Generator Tubes Plugged During Fourth Inservice Inspection."

NUDOCS Accession No. 9512070142

Letter from W.A. DiProfio, North Atlantic Energy Service Corporation, to the NRC dated

November 27, 1996, 'Seabrook Station, Steam Generators A and D Inservice Inspection."

NUDOCS Accession No. 9612110327

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

June 18, 1997, "Seabrook Station, Steam Generator Tubes Plugged During Fifth Inservice

Inspection." NUDOCS Accession No. 9706250388

Letter from W.A. DiProfio, North Atlantic Energy Service Corporation, to the NRC dated May

15, 1998, "Seabrook Station, Steam Generators Inservice Inspection." NUDOCS Accession

No. 9805210123

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

May 5,1999, "Seabrook Station, Steam Generator Tubes Plugged During Sixth Inservice

Inspection." NUDOCS Accession No. 9905120192

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

February 25, 2000, "Seabrook Station, Steam Generators Inservice Inspection." ADAMS

Accession No. ML003687027

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

November 17, 2000, "Seabrook Station, Steam Generator Tubes Plugged During Seventh

Inservice Inspection." ADAMS Accession No. ML003770486

Letter from T.C. Feigenbaum, North Atlantic Energy Service Corporation, to the NRC dated

August 14, 2001, "Seabrook Station, Steam Generators Inservice Inspection." ADAMS

Accession No. ML012320140

-237-
Surrv 1 and 2

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated January 27,

1984, No Title. NUDOCS Accession No.

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated December

31,1984, No Title. NUDOCS Accession No.

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated March 4,

1986, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1985 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No.

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated July 15,

1986, "Virginia Electric and Power Company; Surry Power Station Unit Nos. 1 and 2; Monthly

Operating Report." NUDOCS Accession No. 8609120169

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated August 12,

1987, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1986 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 8708170367

Letter from W.R. Cartwright, Virginia Electric and Power Company, to the NRC dated March 1,

1989, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1988 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 8903090151

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated May 26,

1989, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; North Anna

Power Station Units 1 and 2; Steam Generator Tube Leak Event Corrective Action and

Response to NRC Bulletin No. 89-01." NUDOCS Accession No. 8906020254

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated March 1,

1990, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1989 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 9003120200

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated December

27, 1990, "Virginia Electric and Power Company; Surry Power Station Unit 1; Steam Generator

Tube Inspection Report." NUDOCS Accession No. 9.101080347

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated February 25,

1991, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1990 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 9103040071

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated May 21,

1991, "Virginia Electric and Power Company; Surry Power Station Unit 2; Steam Generator

Tube Inspection Report." NUDOCS Accession No. 9105300131

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated August 23,

1991, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; North Anna

-238-
Power Station Units 1 and 2; Response to NRC Bulletin 89-01, Supplement 2." NUDOCS

Accession No. 9108290211

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated February 28,

1992, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1991 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 9203060254

Letter from W.L. Stewart, Virginia Electric and Power Company, to the NRC dated May 8, 1992,

"Virginia Electric and Power Company; Surry Power Station Unit 1; Steam Generator Tube

Inspection Report." NUDOCS Accession No. 9205190266

Letter from M.L. Bowling, Virginia Electric and Power Company, to the NRC dated February 9,

1993, 'Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1992 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 9302160132

Letter from M.L. Bowling, Virginia Electric and Power Company, to the NRC dated April 19,

1993, "Virginia Electric and Power Company; Surry Power Station Unit 2; Steam Generator

Tube Inspection Report." NUDOCS Accession No. 9304220166

Letter from M.L. Bowling, Virginia Electric and Power Company, to the NRC dated February 23,

1994, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1993 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 9403070251

Letter from M.L. Bowling, Virginia Electric and Power Company, to the NRC dated March 15,

1994, "Virginia Electric and Power Company; Surry Power Station Unit 1; Steam Generator

Tube Inspection Report." NUDOCS Accession No. 9403220234

Letter from M.L. Bowling, Virginia Electric and Power Company, to the NRC dated February 20,

1995, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1994 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 9502240297

Letter from J.P. O'Hanlon, Virginia Electric and Power Company, to the NRC dated June 8,

1995, 'Virginia Electric and Power Company; Surry Power Station Units 1 and 2; Core Uprate -

Materials and Chemical Engineering Branch Follow-Up Questions to Previous Request for

Additional Information." NUDOCS Accession No. 9506130151

Letter from J.P. O'Hanlon, Virginia Electric and Power Company, to the NRC dated June 27,

1995, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; North Anna

Power Station Units 1 and 2; Response to NRC Generic Letter 95-03; Circumferential Cracking

of Steam Generator Tubes." NUDOCS Accession No. 9507030144

Letter from J.P. O'Hanlon, Virginia Electric and Power Company, to the NRC dated October 5,

1995, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; North Anna

Power Station Units 1 and 2; Response to NRC Request for Additional Information Regarding

Our Response to Generic Letter 95-03; Circumferential Cracking of Steam Generator Tubes."

NUDOCS Accession No. 9510110311

-239-
Letter from J.P. O'Hanlon, Virginia Electric and Power Company, to the NRC dated October 12,

1995, "Virginia Electric and Power Company; Surry Power Station Unit 1; Steam Generator

Tube Inspection Report." NUDOCS Accession No. 9510240292

Letter from M.L. Bowling, Virginia Electric and Power Company, to the NRC dated March 1,

1996, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; 1995 Annual

Steam Generator Inservice Inspection Report." NUDOCS Accession No. 9603110250

Letter from S.P. Sarver, Virginia Electric and Power Company, to the NRC dated February 10,

1997, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; Annual Steam

Generator Inservice Inspection Summary Report." NUDOCS Accession No. 9702180383

Letter from S.P. Sarver, Virginia Electric and Power Company, to the NRC dated April 8, 1997,

"Virginia Electric and Power Company; Surry Power Station Unit 1; Steam Generator Tube

Inspection 15 Day Report." NUDOCS Accession No. 9704150140

Letter from R.F. Saunders, Virginia Electric and Power Company, to the NRC dated July 21,

1997, "Virginia Electric and Power Company; Surry Power Station Unit 1; 90 Day Inservice

Inspection Summary Report For the 1997 Refueling Outage." NUDOCS Accession No.

9707290048

Letter from J.H. McCarthy, Virginia Electric and Power Company, to the NRC dated February 5,

1998, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; Annual Steam

Generator Inservice Inspection Summary Report." NUDOCS Accession No. 9802180075

Letter from J.H. McCarthy, Virginia Electric and Power Company, to the NRC dated February

12, 1999, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; Annual

Steam Generator Inservice Inspection Summary Report." NUDOCS Accession No.

9902240436

Letter from G.E. Edison, NRC, to Virginia Electric and Power Company dated August 23, 1999,

"Closure of Review of Response to Generic Letter 97-05, 'Steam Generator Tube Inspection

Techniques' for the Surry Power Station, Units 1 and 2 (TAC Nos. MA0501 and MA0502)."

NUDOCS Accession No. 9908300113

Letter from J.H. McCarthy, Virginia Electric and Power Company, to the NRC dated May 17,

1999, "Virginia Electric and Power Company; Surry Power Station Unit 2; Steam Generator

Tube Inspection Report." NUDOCS Accession No. 9905210220

Letter from D.A. Christian, Virginia Electric and Power Company, to the NRC dated February

28, 2000, 'Virginia Electric and Power Company; Surry Power Station Units 1 and 2; Annual

Steam Generator Inservice Inspection Summary Report." ADAMS Accession No.

ML003692154

Letter from J.H. McCarthy, Virginia Electric and Power Company, to the NRC dated May 8,

2000, "Virginia Electric and Power Company; Surry Power Station Unit 1; Steam Generator

Tube Inspection Report." ADAMS Accession No. ML003715079

-240-
Letter from W.F. Renz, Virginia Electric and Power Company, to the NRC dated October 19,

2000, "Virginia Electric and Power Company; Surry Power Station Unit 2; Steam Generator

Tube Inspection Report." ADAMS Accession No. ML003762349

Letter from S.P. Sarver, Virginia Electric and Power Company, to the NRC dated February 28,

2001, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; Annual Steam

Generator Inservice Inspection Summary Report." ADAMS Accession No. ML010650310

Letter from S.P. Sarver, Virginia Electric and Power Company, to the NRC dated November 5,

2001, "Virginia Electric and Power Company; Surry Power Station Unit 1; Steam Generator

Tube Inspection Report." ADAMS Accession No. ML020090607

Letter from S.P. Sarver, Virginia Electric and Power Company, to the NRC dated February 28,

2002, "Virginia Electric and Power Company (Dominion); Surry Power Station Units 1 and 2;

Annual Steam Generator Inservice Inspection Summary Report." ADAMS Accession No.

ML020710707

Turkey Point 3

Letter from J.W. Williams, Jr., Florida Power and Light Company, to the NRC dated June 17,

1985, 'Turkey Point Unit 3; Docket No. 50-250; Steam Generator Inspection." NUDOCS

Accession No.

Letter from J.W. Williams, Jr., Florida Power and Light Company, to the NRC dated October 16,

1985, 'Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." NUDOCS

Accession No. 8510210046

Letter from J.W. Williams, Jr., Florida Power and Light Company, to the NRC dated September

3, 1985, 'Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; 1 0 CFR 50.59 Report."

NUDOCS Accession No.

Letter from C.O. Woody, Florida Power and Light Company, to the NRC dated June 23, 1987,

'Turkey Point Unit 3; Docket No. 50-250; Technical Specification 4.2.5.5.a. Report." NUDOCS

Accession No. 8706260344

Letter from C.O. Woody, Florida Power and Light Company, to the NRC dated December 15,

1987, 'Turkey Point Unit 3; Docket No. 50-250; 1987 Inservice Inspection Summary Report."

NUDOCS Accession No. 8712210013

Letter from C.O. Woody, Florida Power and Light Company, to the NRC dated August 31,

1987, 'Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; 1 0 CFR 50.59 Report."

NUDOCS Accession No.

Letter from C.O. Woody, Florida Power and Light Company, to the NRC dated June 19,1989,

'Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; NRC Bulletin No. 89-01; Failure

of Westinghouse Steam Generator Mechanical Plugs." NUDOCS Accession No. 8906230148

-241-
Letter from K.N. Harris, Florida Power and Light Company, to the NRC dated April 6,1990,

'Turkey Point Unit 3; Docket No. 50-250; Technical Specification 4.2.5.5.a." NUDOCS

Accession No. 9004170137

Letter from K.N. Harris, Florida Power and Light Company, to the NRC dated September 7,

1990, "Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." NUDOCS

Accession No. 9009170013

Letter from K.N. Harris, Florida Power and Light Company, to the NRC dated August 30,1990,

"Turkey Point Units 3 and 4; Docket No. 50-250 and 50-251; 10 CFR 50.59 Report." NUDOCS

Accession No.

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated December 30,

1991, "Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." NUDOCS

Accession No. 9201070255 and 9201080229

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated October 28,

1992, "Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging." NUDOCS

Accession No.

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated March 10, 1993,

"Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." NUDOCS Accession

No. 9303160060

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated November 18,

1993, "Turkey Point Units 3 and 4; Docket No. 50-250 and 50-251; 1 0 CFR 50.59 Report."

NUDOCS Accession No. 9312020007

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated May 2, 1994,

'Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging." NUDOCS

Accession No.

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated August 15,

1994, 'Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." NUDOCS

Accession No. 9408260153

Letter from W.H. Bohlke, Florida Power and Light Company, to the NRC dated June 22,1995,

"Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; Response to Generic Letter

95-03, Circumferential Cracking of Steam Generator Tubes." NUDOCS Accession No.

9506300133

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated October 11,

1995, "Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; Response to Request for

Additional Information - Generic Letter 95-03, Circumferential Cracking of Steam Generator

Tubes." NUDOCS Accession No. 9510190030

-242-
Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated September 29,

1995, 'Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging." NUDOCS

Accession No. 9510060358

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated January 3, 1996,

"Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." NUDOCS Accession

No. 9601110198

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated January 17, 1996,

"Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging Inservice Inspection

Report." NUDOCS Accession No. 9601220367

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated March 27, 1997,

'Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging - 15 Day Special

Report." NUDOCS Accession No. 9704030004

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated July 10, 1997,

'Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." NUDOCS Accession

No. 9707160093

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated March 5, 1998,

'Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging; Inservice Inspection

- 12 Month Special Report." NUDOCS Accession No. 9803170401

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated October 14, 1998,

'Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging 15-Day Report."

NUDOCS Accession No. 9810200272

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated January 20, 1999,

'Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." NUDOCS Accession

No. 9902120286

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated March 16, 1999,

"Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging; Inservice Inspection

- 12 Month Special Report." NUDOCS Accession No. 9903250292

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated March 27, 2000,

"Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging 15-Day Report."

ADAMS Accession No. ML003715540

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated April 6, 2000,

'Turkey Point Unit 3; Docket No. 50-250; Reportable Event: 2000-001-00; Date of Event:

March 11, 2000; Steam Generator Tube Plugging Places Steam Generator 3B in Category

C-3." ADAMS Accession No. ML003705889

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated June 22, 2000,

"Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." ADAMS Accession No.

MIL0037261844

-243-
Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated September 27,

2000, "Turkey Point Unit 3; Docket No. 50-250; Steam Generator Inspection Information."

ADAMS Accession No. ML003756946

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated March 5, 2001,

"Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging; Inservice Inspection

12-Month Special Report." ADAMS Accession No. ML021760011

Letter from J.P. McElwain, Florida Power and Light Company, to the NRC dated October 20,

2001, "Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging 15-Day

Report." ADAMS Accession No.

Letter from J.P. McElwain, Florida Power and Light Company, to the NRC dated January 24,

2002, "Turkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report." ADAMS

Accession No. ML020330094

Letter from J.P. McElwain, Florida Power and Light Company, to the NRC dated February 28,

2002, "Turkey Point Unit 3; Docket No. 50-250; Steam Generator Tube Plugging Inservice

Inspection 12-Month Special Report - Revision." ADAMS Accession No. ML020720442

Letter from J.P. McElwain, Florida Power and Light Company, to the NRC dated June 25, 2002,

uTurkey Point Unit 3; Docket No. 50-250; Inservice Inspection Report - Revision." ADAMS

Accession No.

Turkey Point 4

Letter from R.E. Uhrig, Florida Power and Light Company, to the NRC dated August 12, 1983,

'Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS Accession

No. 8308180180

Letter from J.W. Williams Jr., Florida Power and Light Company, to the NRC dated September

4,1984, "Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS

Accession No. 8409100191

Letter from J.W. Williams Jr., Florida Power and Light Company, to the NRC dated June 18,

1985, "Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; Generic Letter 85-02."

NUDOCS Accession No. 8506240503

Letter from C.O. Woody, Florida Power and Light Company, to the NRC dated December 1,

1986, "Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS

Accession No. 8612090435

Letter from W.F. Conway, Florida Power and Light Company, to the NRC dated March 18,

1988, "Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; NRC Bulletin 88-02:

Rapidly Propagating Fatigue Cracks in Steam Generator Tubes." NUDOCS Accession No.

8803250093

-244-
Letter from W.F. Conway, Florida Power and Light Company, to the NRC dated December 7,

1988, "Turkey Point Unit 4; Docket No. 50-251; Technical Specification 4.2.5.5.a." NUDOCS

Accession No. 8812140198

Letter from C.O. Woody, Florida Power and Light Company, to the NRC dated September 15,

1989, 'Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS

Accession No. 8909220142

Letter from W.H. Bohike, Florida Power and Light Company, to the NRC dated July 30,1991,

"Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; NRC Bulletin 89-01, Supplement

2; Failure of Westinghouse Steam Generator Mechanical Plugs." NUDOCS Accession No.

9108050317

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated January 27,

1992, "Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS

Accession No. 9202030140

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated May 4, 1993,

"Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging." NUDOCS

Accession No. 9305140226

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated August 20,

1993, "Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS

Accession No. 9308260306

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated October 24,

1994, "Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging." NUDOCS

Accession No. 9411010123

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated February 9,

1995, 'Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS

Accession No. 9502210127

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated October 6,

1995, "Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging Inservice

Inspection Report." NUDOCS Accession No. 9510110118

Letter from T.F. Plunkett, Florida Power and Light Company, to the NRC dated January 31,

1995, "Turkey Point Units 3 and 4; Docket Nos. 50-250 and 50-251; Alloy 600 Steam Generator

Mechanical Tube Plugs." NUDOCS Accession No. 9502070106

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated January 16, 1996,

'Turkey Point Unit 4; Docket No. 50-251; Generic Letter 95-03 - Circumferential Cracking of

Steam Generator Tubes." NUDOCS Accession No. 9601220369

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated February 27,

1996, 'Turkey Point Unit 4; Docket No. 50-251; Generic Letter 95-03 - Circumferential Cracking

of Steam Generator Tubes." NUDOCS Accession No. 9603040329

-245-
Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated July 1, 1996,

'Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS Accession

No. 9607170072

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated October 1, 1997,

"Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging." NUDOCS

Accession No. 9710100290

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated January 7, 1998,

"Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS Accession

No. 9801130203

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated December 30,

1997, "Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging Inservice

Inspection Report." NUDOCS Accession No. 9801060277

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated June 30, 1999,

"Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." NUDOCS Accession

No. 9907080066

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated October 16, 2000,

'Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging 15-Day Report."

ADAMS Accession No. ML003762437

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated January 19, 2001,

"Turkey Point Unit 4; Docket No. 50-251; Inservice Inspection Report." ADAMS Accession No.

ML010250129

Letter from R.J. Hovey, Florida Power and Light Company, to the NRC dated August 10, 2001,

"Turkey Point Unit 4; Docket No. 50-251; Steam Generator Tube Plugging; Inservice Inspection

12-Month Special Report." ADAMS Accession No. ML021760007

Voatle 1

Letter from J.A. Bailey, Georgia Power Company, to the NRC dated June 13, 1986, "NRC

Docket Numbers 50-424 and 50-425, Construction Permit Numbers CPPR-108 and CPPR-109,

Vogtle Electric Generating Plant - Units 1 and 2, SER Confirmatory Item 18: Examination of

Steam Generator Tubes." NUDOCS Accession No. 8606180002

Letter from W.G. Hairston III, Georgia Power Company, to the NRC dated November 7, 1988,

"Plant Vogtle - Unit 1, NRC Docket 50-424, Operating License NPF-68, Technical Specification,

Special Report 88-007, Steam Generator Tube Plugged." NUDOCS Accession No.

8811150487

Letter from W.G. Hairston III, Georgia Power Company, to the NRC dated February 22, 1989,

"Plant Vogtle - Unit 1, NRC Docket 50-424, Operating License NPF-68, Inservice Inspection

Summary Report." NUDOCS Accession No. 8903010197

-246-
Letter from W.G. Hairston lll, Georgia Power Company, to the NRC dated June 16,1989,

"Plant Vogtle - Units 1, 2, NRC Dockets 50-424, 50-425, Operating Licenses NPF-68, NPF-81,

NRC Bulletin 89-01: Failure of Westinghouse Steam Generator Tube Mechanical Plugs."

NUDOCS Accession No. 8906200329

Letter from W.G. Hairston Ill, Georgia Power Company, to the NRC dated March 22, 1990,

"Vogtle Electric Generating Plant, Special Report, Number of Steam Generator Tubes Plugged

During 1 R2." NUDOCS Accession No. 9003280482

Letter from W.G. Hairston ll, Georgia Power Company, to the NRC dated July 5, 1990, "Vogtle

Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession No.

9007130318

Letter from W.G. Hairston l1l, Georgia Power Company, to the NRC dated July 31, 1991,

'Vogtle Electric Generating Plant, Response to NRC Bulletin 89-01 Supplement 2, Failure of

Westinghouse Steam Generator Tube Mechanical Plugs." NUDOCS Accession No.

9108060366

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated February 13, 1992,

"Vogtle Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession

No. 9202260291

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated November 5, 1992,

"Vogtle Electric Generating Plant, Correction to Inservice Inspection Summary Report."

NUDOCS Accession No. 9211160103

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated April 22, 1993, 'Vogtle

Electric Generating Plant, Special Report 1-93-3, Number of Steam Generator Tubes Plugged

During 1 R4." NUDOCS Accession No. 9304270197

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated May 6,1993, "Vogtle

Electric Generating Plant, Special Report 1-93-3, Number of Steam Generator Tubes Plugged

During 1R4." NUDOCS Accession No. 9305130223

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated July 21, 1993, "Vogtle

Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession No.

9307270164

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated October 6, 1994, "Vogtle

Electric Generating Plant, Technical Specifications Special Report - Unit 1, Number of Steam

Generator Tubes Plugged During 1 R5." NUDOCS Accession No. 9410120113

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated January 10, 1995, "Vogtle

Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession No.

9501230321

-247-
Letter from C.K. McCoy, Georgia Power Company, to the NRC dated January 25, 1995, "Vogtle

Electric Generating Plant, Steam Generator Mechanical Tube Plugs." NUDOCS Accession No.

9502010150

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated April 1, 1996, "Vogtle

Electric Generating Plant, Special Report 1-96-1, Number of Steam Generator Tubes Plugged

During 1 R6." NUDOCS Accession No. 9604050023

Letter from J.D. Woodard, Georgia Power Company, to the NRC dated July 17,1996, "Vogtle

Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession No.

9607230176

Letter from J.D. Woodard, Georgia Power Company, to the NRC dated June 10, 1996, "Vogtle

Electric Generating Plant, Confirmed loose Part 14-Day Report." NUDOCS Accession No.

9606140081

Letter from C.K. McCoy, Southern Nuclear Operating Company, Inc., to the NRC dated October

13, 1997, "Vogtle Electric Generating Plant, Technical Specification Report 1-97-2, Number of

Steam Generator Tubes Plugged During 1R7." NUDOCS Accession No. 9710200005

Letter from C.K. McCoy, Southern Nuclear Operating Company, Inc., to the NRC dated

November 21, 1997, "Vogtle Electric Generating Plant, Confirmed Loose Part 14-Day Report -

Revision 1." NUDOCS Accession No. 9712010215

Letter from C.K. McCoy, Southern Nuclear Operating Company, Inc., to the NRC dated January

16,1998, "Vogtle Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS

Accession No. 9801260450

Letter from J.B. Beasley Jr., Southern Nuclear Operating Company, Inc., to the NRC dated

March 29,1999, 'Vogtle Electric Generating Plant, Technical Specification Report 1-99-1,

Number of Steam Generator Tubes Plugged During 1 R8." NUDOCS Accession No.

9904070055

Letter from J.B. Beasley Jr., Southern Nuclear Operating Company, Inc., to the NRC dated

June 21, 1999, 'Vogtle Electric Generating Plant, Inservice Inspection Summary Report."

NUDOCS Accession No. 9907010009

Letter from J.B. Beasley Jr., Southern Nuclear Operating Company, Inc., to the NRC dated

January 12, 2001, 'Vogtle Electric Generating Plant, Inservice Inspection Summary Report."

ADAMS Accession No. ML010170148

Vootle 2

Letter from J.A. Bailey, Georgia Power Company, to the NRC dated October 27, 1988, "Plant

Vogtle - Unit 2, NRC Docket Number 50-425, Construction Permit Number CPPR-109, SER

Confirmatory Item 18: Examination of Steam Generator Tubes." NUDOCS Accession No.

8811030150

-248-
Letter from W.G. Hairston 1II, Georgia Power Company, to the NRC dated January 25,1991,

"Vogtle Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession

No. 9102010137

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated August 5,1992, uVogtle

Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession No.

9208100159

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated October 14, 1993, "Vogtle

Electric Generating Plant, Special Report, Steam Generator Tubes Plugged During Third Unit 2

Refueling Outage." NUDOCS Accession No. 9310190094

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated January 11, 1994, "Vogtle

Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession No.

9401260247

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated March 24, 1995, uVogtle

Electric Generating Plant, Special Report 2-95-2, Number of Steam Generator Tubes Plugged

During 2R4." NUDOCS Accession No. 9504040208

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated June 26,1995, "Vogtle

Electric Generating Plant, Inservice Inspection Summary Report." NUDOCS Accession No.

9507070399

Letter from C.K. McCoy, Georgia Power Company, to the NRC dated October 10, 1996, "Vogtle

Electric Generating Plant, Special Report 2-96-3, Number of Steam Generator Tubes Plugged

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9701170027

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Accession No. ML012890479

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NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1 REPORT NUMBER

(2.89) (Assigned by NRC, Add Vol , Supp. Rev,

NRCM11 BIBLIOGRAPHIC DATA SHEET and Addendum Numbers, if any) 3201. 3202 BBIGAHCDT HE

(See instrhuchons on the reverse)

2 TITLE AND SUBTITLE NUREG-1771

U.S. Operating Experience With Thermally Treated Alloy 600 Steam Generator Tubes

3 DATE REPORT PUBLISHED

MONTH YEAR

April 2003

4 FIN OR GRANT NUMBER

N/A

5 AUTHOR(S) 6 TYPE OF REPORT

Kenneth J Karwoski Technical

7 PERIOD COVERED (Inclusive Dates)

1/1 980 through 1212001

8 PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Drvision, Office or Region. US NuclearRegutatoryCommission and mairing eddress if contractor

provide name and mailing address)

Division of Engineeering

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington DC 20555-0001

9 SPONSORING ORGANIZATION - NAME AND ADDRESS (ffNRC, type 'Same as above, ifcontractor provide NRC Division, Office orRegion, US NucdearRegulatory Commission,

and mailing address)

Same as above

10 SUPPLEMENTARY NOTES

11 ABSTRACT (200 words or less)

Steam generators placed in service in the 1960s and 1970s had tubes primarily fabricated from mill-annealed Alloy 600. 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

numerous facilities, 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. Because of the safety significance of steam generator tube integrity, this paper evaluates the operating experience

of thermally treated Alloy 600 by looking at the extent to which it is used and results from steam generator tube examinations

12 KEY WORDS/DESCRIPTORS (List words or phrases that wilt assist researchers in locating the report) 13 AvAILABILITY STATEMENT

PWR unlimited

steam generator (SG) 14 SECURITY CLASSIFICATION

steam generator tube (This Page)

Alloy 600, Inconel 600 unclassified

thermally treated (This Report)

eddy current testing unclassified

nondestructive evaluation

15 NUMBER OF PAGES

260

16 PRICE

NRC FORM 335 (2-89) This form was electronically pro duc~ed by Elite Federal Forms Inc
Federal Recycling Program
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NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

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