NUREG/CR-6754 

BNL-NUREG-52646

Review of Industry 

Responses to NRC 

Generic Letter 97-06 on 

Degradation of Steam 

Generator Internals 

Brookhaven National Laboratory 

U.S. Nuclear Regulatory Conunission 

Office of Nuclear Reactor Regulation 

Washington, DC 20555-0001
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NUREG/CR-6754 

BNL-NUREG-52646 

Review of Industry 

Responses to NRC 

Generic Letter 97-06 on 

Degradation of Steam 

Generator Internals 

Manuscript Completed: December 2001 

Date Published: December 2001 

Prepared by 

M. Subudhi, J. C. Higgins, BNL 

S. M. Coffin, NRC 

Brookhaven National Laboratory 

Upton, NY 11973-5000 

E. J. Sullivan, NRC Project Manager 

Prepared for 

Division of Engineering 

Office of Nuclear Reactor Regulation 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

NRC Job Code J2831
NUREG/CR-6754 has been reproduced 

from the best available copy.
ABSTRACT 

This report presents the results of an assessment of the nuclear power industry's responses to NRC 

Generic Letter (GL) 97-06 on the degradation of steam generator (SG) internals experienced at 

Electricite de France (EdF) plants in France and at a United States (U.S.) Pressurized Water Reactor 

(PWR). Before issuing the GL, with the exception of a few licensees, there were no formal inspection 

programs, nor any industry guidelines for monitoring the secondary side internals of steam generators. 

Nonetheless, all licensees have been performing some inspection and maintenance on their steam 

generator internals and have found no significant degradation in them. Most of the steam generators in 

U.S. plants do not appear susceptible to the degradation found at EdF and in the U.S. PWR. 

The Westinghouse (W) Models 44, 51, 5IM, and D3 and the Combustion Engineering Model 67 with 

carbon steel eggcrates potentially could experience degradation similar to that found at EdF plants and 

the U.S. PWR. Recent inspections showed that replacement steam generators made by Babcock & 

Wilcox International of Canada may be vulnerable to tube proximity problems. The owners groups 

identified possible degradation mechanisms for these models in their assessments and have evaluated 

their potential causes. Recommendations were made to monitor for these types of degradation. 

During this assessment, each owners group identified for its steam generator models all the potential 

internal components that are vulnerable to degradation while in service. They provided inspection- and 

monitoring-guidance and recommendations for their particular SG models. The Nuclear Energy Institute 

(NEI), who has been coordinating the industry's response to this GL, has incorporated in NEI 97-06, 

"Steam Generator Program Guidelines" a requirement to monitor secondary side SG components if their 

failure could prevent the SG from fulfilling its intended safety-related function. Licensees plan to 

implement their owners group recommendations to address the long-term effects of the potential 

degradation mechanisms associated with the SG internals. Overall, the licensees' submittals have met 

the intent of the GL and provide reasonable assurance that the SG internals comply with, and conform to, 

the licensing basis.

iii
TABLE OF CONTENTS 

Page 

ABSTRACT OFF .................................................................... ii 

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

LIST OF TABLES.............................................................. viii 

EXECUTIVE SUMMARY ........................................................... ix 

ACRONYM S ...................................................................... xi 

ACKNOW LEDGMENTS ........................................................... xiii 

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

1.1 H istorical Background ..................................................... 1-1 

1.2 NRC Generic Letter 97-06 .................................................. 1-3 

1.3 Industry Activities in Response to GL 97-06 .................................... 1-4 

1.4 Objectives and Scope ...................................................... 1-4 

2 INDUSTRY GUIDELINES FOR AN INSPECTION PROGRAM FOR 

STEAM GENERATOR INTERNALS ............................................ 2-1 

2.1 Plants with Babcock & Wilcox Steam Generators ................................ 2-1 

2.1.1 B&W Once-through Steam Generators .................................. 2-2 

2.1.2 B&W Replacement Steam Generators .................................. 2-4 

2.2. Plants with Combustion Engineering Steam Generators ........................... 2-6 

2.3 Plants with W estinghouse (W__) Steam Generators ................................ 2-7 

2.3.1 Feed Ring Steam Generators with Carbon Steel Support Plates 

(Models 44, 51, and 51M) ................................. 2-8 

2.3.2 Preheat Steam Generators with Carbon Steel Support Plates 

(M odels D3, D4, and E2-TGX) ........................................ 2-9 

2.3.3 Preheat Steam Generators with Stainless Steel Support Plates 

(M odels D5 and E2-THX) ........................................... 2-10 

2.3.4 Feedring Steam Generators with Stainless Steel Support Plates 

(Models F, 44F, 5 IF, 54F, and Delta Series) ............................ 2-11 

2.4 Summary and Conclusions ................................................. 2-13 

3 EVALUATION OF RESPONSES BY PLANTS WITH BABCOCK & WILCOX 

STEAM GENERATORS ....................................................... 3-1 

3.1 Plants with B&W-Designed Once Through Steam Generators ...................... 3-2 

3.1.1 Susceptibility of the OTSG Relative to the EdF and SONGS Experience ....... 3-4 

3.1.2 Responses to NRC's Generic Letter 97-06 ............................... 3-8 

3.1.3 Summary and Conclusions .......................................... 3-10 

3.2 Plants with B&W-Designed Recirculating Steam Generators ...................... 3-11

v
TABLE OF CONTENTS 

(continued) 

3.2.1 Susceptibility of B&W RSGs Relative to EdF and SONGS Experience ....... 3-12 

3.2.2 Responses to NRC's Generic Letter 97-06 ........................... 3-14 

3.2.3 Summary and Conclusions .......................................... 3-16 

4 EVALUATION OF RESPONSES BY PLANTS WITH COMBUSTION ENGINEERING 

STEAM GENERATORS ....................................................... 4-1 

4.1 Plants with CE-Designed Steam Generators .................................... 4-2 

4.1.1 Susceptibility of the CE SGs Relative to EdF and SONGS Experience ......... 4-5 

4.1.2 Responses to NRC's Generic Letter 97-06 ............................... 4-8 

4.1.3 Summary and Conclusions .......................................... 4-13 

5 EVALUATION OF RESPONSES BY PLANTS WITH WESTINGHOUSE STEAM 

GENERATORS ............................................................... 5-1 

5.1 Plants with W-Designed Steam Generators, Models 51, 51 M, 51 F, 

54F, A47, and A75 ........................................................ 5-4 

5.1.1 Susceptibility of the W SGs Relative to EdF and SONGS Experience ......... 5-6 

5.1.2 Responses to NRC's Generic Letter 97-06 ............................... 5-8 

5.1.3 Summary and Conclusions ......................................... 5-11 

5.2 Plants with W-Designed Steam Generators, Models 44F, F, D3, D4, 

D 5, E 2 ................................................................. 5-11 

5.2.1 Susceptibility of the W SGs Relative to EdF and SONGS Experience ........ 5-17 

5.2.2 Responses to NRC's Generic Letter 97-06 .............................. 5-20 

5.2.3 Summary and Conclusions .......................................... 5-23 

5.3 Indian Point 2 with W-Designed Steam Generators ............................. 5-24 

5.3.1 Evaluation of Licensee's Responses to GL 97-06 ........................ 5-26 

5.3.2 Evaluation of Recent SG Tube Failure ................................. 5-27 

5.3.3 Summary and Conclusions .......................................... 5-28 

6 SUMMARY AND CONCLUSIONS .............................................. 6-1 

6.1 Sum m ary of Results ....................................................... 6-1 

6.2 C onclusions ............................................................. 6-3 

7 REFERENCES ............................................................... 7-1 

APPENDIX A: GL 97-06 - DEGRADATION OF STEAM GENERATOR INTERNALS . A-1 

APPENDIX B: LICENSEES RESPONDED TO GL 97-06 ........................... B-1

vi
LIST OF FIGURES 

No. Title Page 

3.1 Three Mile Island 1 Reactor Coolant System Showing Location of Components ............ 3-18 

3.2 B&W 177 Plant Once-through Steam Generator ..................................... 3-19 

3.3 Arrangements of B&W Replacement Steam Generator ................................ 3-20 

4.1 Reactor Coolant System for CE Plants ............................................. 4-14 

4.2 Combustion Engineering Recirculating Steam Generator (Typical for 2-Loop 

System 69 Plants) ............................................................. 4-15 

4.3 Combustion Engineering Recirculating Steam Generator (Typical for System 80 Plants) ...... 4-16 

5.1 Braidwood Unit 1 Reactor Coolant System (4 Loops) ................................. 5-29 

5.2 Beaver Valley 2 Reactor Coolant System (3 Loops) ................................... 5-30 

5.3 Westinghouse Recirculating Steam Generator (Typical of Models 44 and 51) .............. 5-31 

5.4 Westinghouse Recirculating Steam Generator (Typical of Model F) ...................... 5-32 

5.5 Westinghouse Recirculating Steam Generator (Typical of Model E Preheat Unit) ........... 5-33

vii
LIST OF TABLES 

No. Title Page 

1.1 Number of Plants for Different SG Owners Groups .................................... 1-5 

2.1 Recommended SG Internals Inspection Program for B&W OTSGs ........................ 2-2 

2.2 Recommended SG Internals Inspection Program for B&W RSGs ......................... 2-4 

2.3 Recommended SG Internals Inspection Program for CE SGs ............................ 2-7 

2.4 Recommended SG Internals Inspection Program for W Feed Ring Models 

with Carbon Steel Support Plates ............................... .................. 2-8 

2.5 Recommended SG Internals Inspection Program for W Preheat Models 

with Carbon Steel Support Plates .................................................. 2-9 

2.6 Recommended SG Internals Inspection Program for W Preheat Models 

with Stainless Steel Support Plates ................................................ 2-10 

2.7 Recommended SG Internals Inspection Program for W Feedring Models 

with Stainless Steel Support Plates ................................................ 2-12 

3.1 Plants with B&W -Designed Steam Generators ........................................ 3-1 

3.2 Plant-specific SG Inspections for B&W OTSGs ....................................... 3-9 

3.3 Plant-specific SG Inspections for B&W RSGs ...................................... 3-15 

4.1 Plants with CE-Designed Steam Generators .......................................... 4-1 

4.2 Plant-specific SG Inspections For CE SGs .......................................... 4-10 

5.1 Plants with W -Designed Steam Generators ........................................... 5-2 

5.2 Distribution of SG Models 51, 51M, 5IF, 54F, A47, and A75 ............................ 5-5 

5.3 Plant-specific Inspections For W SGs, Models 51, 51M, 51F, 54F, A47, and A75 ............ 5-9 

5.4 Distribution of SG Models 44F, F, D3, D4, D5, and E2 ................................ 5-12 

5.5 Plant-specific Inspections For W SGs, Models 44F, F, D3, D4, D5, and E2 ................ 5-21

viii
EXECUTIVE SUMMARY

The staff of the U.S. Nuclear Regulatory Commission (NRC) issued Generic Letter (GL) 97-06 on 

December 30, 1997 to alert licensees of Pressurized Water Reactors (PWRs) to the findings of damage to 

steam generator (SG) internals, namely, tube support plates and tube bundle wrappers, at foreign PWR 

facilities. The GL also addressed recent findings of damage to the tube lattice bar-type supports of SGs 

at the San Onofre Nuclear Generating Station (SONGS) and emphasized the importance of 

comprehensively examining SG internals to ensure that the structural integrity of the steam generator 

tubes is maintained in accordance with the requirements of Appendix B to 10 CFR Part 50. The GL 

required all licensees to submit information that would enable the NRC staff to verify whether the steam 

generator internals in U.S. Nuclear Power Plants comply with, and conform to, the licensing basis for 

their respective facilities. 

The results presented in this report are based on the following information: the licensees' submittals in 

response to GL 97-06, Electric Power Research Institute (EPRI) report on the modes of degradation 

detected in SG internals, owners groups' reports on the evaluation of the foreign PWR degradation and 

that at SONGS, responses of owners groups to NRC's requests for additional information (RAls), and 

limited discussions with steam generator (SG) manufacturers. The technical work on this review was 

largely completed in the Fall of 1998. At that time, the owners groups' assessments, while completed in 

some cases, were still listed as interim; in other cases, they had not been completed. The Westinghouse 

owners group evaluation of its SG models F, 44F, D and E2 was completed in December 1998. The 

Babcock & Wilcox owners group report on once-through steam generator internals was completed in 

February 1999. Thus, the final evaluations of all degradation identified in the GL for these SGs became 

available during the Spring of 1999. Most plant submittals are based on the owners group reports and 

past inspections of their steam generators. The Nuclear Energy Institute (NEI), who has been 

coordinating the industry's response to this GL, has incorporated in NEI 97-06, "Steam Generator 

Program Guidelines" a requirement to monitor secondary side SG components if their failure could 

prevent the SG from fulfilling its intended safety-related function. 

Degradation of steam generator tubes has been known in the nuclear industry from the mid-seventies and 

there are several guidelines from the EPRI on maintaining the structural integrity of and preventing 

leakage from SG tubes. However, there were no explicit industry guidelines for an SG secondary side 

internals inspection program. Many of the reported activities in this area by the licensees resulted from 

self-identified problems over the past 25 years of service. In response to the GL, the owners groups have 

identified additional SG internal components that could be vulnerable to degradation, and have suggested 

inspection guidelines to address these concerns. 

The evaluations of the degradation at foreign PWRs and that at SONGS, which are the subject of this 

GL, were undertaken by the owners groups in conjunction with NEI. Westinghouse (W) SGs involving 

models 44, 51, 5 1M, and D3 and Combustion Engineering (CE) SGs with carbon steel eggcrate tube 

supports appear to be the most susceptible to the types of degradation identified in the GL. The 

replacement SGs by Babcock & Wilcox (B&W) are susceptible to peripheral tubes coming into contact 

during operation and so may incur fretting wear from flow-induced vibration at the point of contact. 

Specific recommendations were made by the W owners group, the CE owners group, and the B&W 

owners group to address these potential concerns. All licensees have reported no significant degradation 

in their SG internals at this time. Appropriate corrective and preventive measures have been 

implemented to mitigate any significant past problems associated with SG internals. None of the

ix
EXECUTIVE SUMMARY

existing degradation has been progressing based on sequential inspection data. Therefore, there are no 

near-term problems nor are there needs for any immediate change in the current SG internals inspections. 

However, plants have either implemented or are planning, as appropriate to their SGs, the 

implementation of the recommendations of its owners group and/or by the industry to address the long

term effects of the potential degradation mechanisms associated with the SG internals. 

All SGs indicated that some program (formal or informal) for monitoring degradation of SG internals is 

in place and that inspections are typically carried out at each refueling outage (although not usually for 

all SGs at each refueling outage). Several plants with a history of problems similar to that described in 

the GL had already performed, or had plans to perform, comprehensive inspection of their SG internals 

during the next scheduled refueling outage. Further, several plants had replaced their SGs with new, 

improved designs. These improved designs included the use of corrosion-resistant materials and better 

monitoring techniques which had significantly contributed to industry-wide enhanced management 

programs for SG internal components. Overall, the licensees' submittals have met the intent of the GL 

and provide reasonable assurance that the SG internals comply with, and conform to, the licensing basis.

X
ACRONYMS

AFW Auxiliary Feedwater 

ANO Arkansas Nuclear One 

ASME American Society of Mechanical Engineers 

AVB Anti-Vibration Bars 

AVT All Volatile Treatment 

BOP Balance of Plant 

BRSG Babcock & Wilcox Recirculating Steam Generator 

B&W Babcock & Wilcox 

B&WOG Babcock & Wilcox Owners Group 

BWI Babcock & Wilcox International (of Canada) 

BNL Brookhaven National Laboratory 

cm Centimeter 

CC Chemical Cleaning 

CFR Code of Federal Regulations 

CE Combustion Engineering 

CEOG Combustion Engineering Owners Group 

CR Crystal River 

CS Carbon Steel 

DHR Decay Heat Removal 

EC Eddy Current 

ECT Eddy Current Testing 

EdF Electricite de France 

EFPY Effective Full Power Year 

EFW Emergency Feedwater 

EPRI Electric Power Research Institute 

FAC Flow-Accelerated Corrosion 

FIV Flow-Induced Vibration 

FOSAR Foreign Objects Search and Removal 

FTI Framatome Technologies Inc. 

FW Feedwater 

gpd Gallons per day 

GDC General Design Criterion 

GL Generic Letter 

ID Inside Diameter 

IGA Intergranular Attack 

IGSCC Intergranular Stress Corrosion Cracking 

ISI In-Service Inspection 

lpd Liters per day 

LOCA Loss of Coolant Accident 

MS Moisture Separator 

NDE Non-Destructive Examination 

NEI Nuclear Energy Institute 

NPP Nuclear Power Plant

xi
ACRONYMS

NRC Nuclear Regulatory Commission 

OD Outside Diameter 

ODSCC Outside Diameter Stress Corrosion Cracking 

OEM Original Equipment Manufacturer 

OG Owners Group 

OTSG Once-Through Steam Generator 

PPC Pressure Pulse Cleaning 

PSI Possible Support Indication 

PWR Pressurized Water Reactor 

PWSCC Primary Water Stress Corrosion Cracking 

RAI Request for Additional Information 

RFO Refueling Outage 

RPC Rotating Pancake Coil 

RSG Replacement Steam Generator 

SG Steam Generator 

SGMP Steam Generator Management Project 

SID Support Plate Inspection Device 

SL Sludge Lancing 

SONGS San Onofre Nuclear Generating Station 

SS Stainless Steel 

SSE Safe Shutdown Earthquake 

TMI Three Mile Island 

TSP Tube Support Plate 

U.S. United States 

UT Ultrasonic Testing 

W Westinghouse 

WOG Westinghouse Owners Group 

WS Water Slapping (or Lancing)

xii
ACKNOWLEDGMENTS 

The authors of this report would like to acknowledge the support from Steve Lurie and his staff at 

Combustion Engineering, and from John Houtman and Gary Whiteman of Westinghouse. Technical 

review by Edmund Sullivan of NRC is greatly appreciated. We thank Kathleen Nasta of BNL for 

developing the database for sorting the licensees' submittals. Technical editing by Avril Woodhead of 

BNL is also appreciated. 

We also thank Anna Seda and Barbara Roland, BNL, for preparing this report.

xiii
1 INTRODUCTION

The staff of the U.S. Nuclear Regulatory Commission (NRC) issued Generic Letter (GL) 97-06, 

"Degradation of Steam Generator Internals" (Ref. 1) on December 30, 1997 to alert licensees of 

pressurized water reactors (PWRs) to findings of damage to steam generator (SG) intemals at foreign 

PWR facilities, namely, tube support plates and tube bundle wrappers. The GL also addressed recent 

findings of damage to steam generator tube lattice bar-type supports at a U.S. PWR facility and 

emphasized the importance of comprehensively examining SG internals to ensure that structural integrity 

of the steam generator tube is maintained in accordance with the requirements of Appendix B to 10 CFR 

Part 50. The GL required all licensees to submit information that would enable the NRC's staff to verify 

whether the steam generator internals in U.S. Nuclear Power Plants comply with, and conform to, the 

licensing basis for their respective facilities. 

The NRC requested Brookhaven National Laboratory (BNL) to assist the staff in determining the 

adequacy of the responses by the nuclear power licensees to GL 97-06. BNL evaluated the adequacy of 

each licensee's program in meeting the intent of GL 97-06 in separate technical reports for each group of 

SGs. BNL assessed two types of SGs manufactured by Babcock and Wilcox (B&W), three types of SGs 

manufactured by Combustion Engineering (CE), and four types of SGs manufactured by Westinghouse 

(W). Since each plant either has a program in place (formal or informal) to detect SG internals 

degradation or has plans to establish such a program, an evaluation of licensees' rationale to conclude 

that no such program is needed was not necessary. A final report summarizing the results and 

identifying the actions by each licensee to develop and implement an effective inspection program for 

SG internals to meet the intent of the GL 97-06 was issued on January 26, 1999 (Ref. 2). 

During the Spring of 1999, the Westinghouse evaluation of a second group of its SG models and the 

B&W assessment of its once-through steam generators became available for review. This report 

contains the findings from the review of these two reports as well as the results of the post-shutdown 

evaluation of the recent SG failure at Indian Point 2. CE's response to NRC's requests for additional 

information (RAIs) on the topical reports addressing the issues identified in the GL 97-06 also is 

included. 

1.1 Historical Background (Refs. 3-5) 

For over a quarter of a century, the nuclear power industry has focused on managing and repairing steam 

generator tubing, and has expended considerable resources to meet the challenges posed by their 

continuing degradation. During the mid-seventies, licensees experienced tube wastage degradation in 

their SGs and were forced to plug tubes at a rate that would exceed the SG's 40-year-life design margins. 

Sodium phosphate, employed in the conventional water-treatment process, concentrated in crevices and 

other areas of localized boiling, leading to aggressive corrosion and wastage (generalized tube thinning) 

in those regions. The industry corrected this by changing to an All-Volatile Treatment (AVT) by adding 

ammonia to water that had been highly purified to maintain near neutral pH. However, this approach 

resulted in conditions conducive to corrosion of the carbon steel support plates. The corrosion products 

built up in the holes where tubes passed through the plates, eventually squeezing and denting the tubes. 

At some plants, impurities from external condensers leaked into the secondary water, contributing even 

more corrosive materials to sludge piles and leading to severe pitting of the tubes. The industry, in

1-1
1 INTRODUCTION

collaboration with Electric Power Research Institute (EPRI), implemented SG programs by improving 

the control of secondary-side water chemistry, taking steps to prevent in-leakage of condenser cooling

water or air, and upgrading secondary-side equipment, and thus, essentially eliminated wastage, denting, 

and pitting as active degradation mechanisms. 

The most pervasive type of tube degradation in PWR steam generators today is intergranular corrosion, 

in which the chemical attack tends to follow grain boundaries in the tube metal. Without significant 

stress, the grain boundaries degrade more or less uniformly, beginning at the surface (known as 

intergranular attack - IGA). IGA has been a major problem in the crevices between the tubes and the 

tubesheet, where piles of sludge tend to build up. If the metal has relatively high residual stresses from 

fabrication or generated by operation, cracks may propagate into the metal along grain boundaries (called 

intergranular stress corrosion cracking - IGSCC). IGSCC is common at the top of the tubesheet where 

the tubes are expanded to achieve a tight seal, and also in the U-bend region of tubes in recirculating SGs 

which are exposed to considerable stress during fabrication. Once-through SGs, which contain only 

straight tubes, have experienced generically similar types of problems but at different locations. 

Licensees have prevented the buildup of corrosion products in several ways, thereby reducing 

deterioration of the tubes: crevice flushing to remove caustic materials; using tube materials with greater 

corrosion resistance; using thermal treatments at lower temperatures and for longer than those involved 

in mill annealing in U-bend regions; and using broached (as opposed to drilled) holes or lattice bar-type 

tube supports ("eggcrate" supports) to allow free flow around the tubes. Recently, organic amines were 

used in the secondary water to reduce the transport of iron and copper, which contribute to sludge 

buildup. Also, other volatile chemical additives (ammonia, morpholine, and boric acid) are being tested 

as chemical buffers to maintain neutral pH in crevices. 

In addition to tube degradation experienced in PWR steam generators, other secondary side internal 

components in certain SG designs have deteriorated during their service life. The majority of damage to 

the feedwater system was caused by the erosion-corrosion of carbon steel components, including the 

sparger, liner, and the distribution box, or by waterhammer events. In W-designed SG models 

mechanical wear has caused fretting at anti-vibration bars (AVBs) and at baffle plates in preheater 

models. CE-designed SGs have experienced erosion of the carbon steel feedwater components. B&W

designed once-through steam generators (OTSGs) had problems with their internal auxiliary feedwater 

(AFW) headers, and in replacement steam generators (RSGs) the peripheral tubes in contact during SG 

operation may be subjected to flow-induced vibration fretting wear at their points of contact. 

The industry has taken actions to control the degradation of tubes and secondary side internal 

components to within manageable levels, and maintenance and monitoring programs are in place at each 

plant to assure that the safety significance of the SGs has not been compromised. These approaches 

include eddy current inspection, visual/video camera inspections, periodic sludge-lancing (SL)/water

slapping (WS) or pressure-pulse cleaning (PPC)/chemical cleaning (CC) of tubesheets and tube bundles, 

and undertaking routine foreign objects search and removal (FOSAR) at each refueling and/or 

maintenance outage(s). Most such guidelines developed by the industry are primarily focused on the 

tube bundle region of the steam generators, except the ASME Section XI In-Service Inspection (ISI) for 

welds in ASME pressure vessel components. Very little industry guidance for inspecting secondary side 

SG internal components to detect and monitor degradation was available until issuance of GL 97-06.

1-2
1 INTRODUCTION

1.2 NRC Generic Letter 97-06 

Visual inspections conducted by Electricite de France (EdF) in June 1994 and eddy current examinations 

in April 1995 found six types of degradation in the SG internals in their PWR plants. They include (1) 

erosion of the top tube-support-plate (TSP) associated with chemical cleaning, (2) ligament cracking at 

the top TSPs due to mechanical loading, (3) FAC-induced thinning of the periphery of the top TSP due to 

ammoniated water, (4) wrapper drop, (5) fatigue cracks emanating from the wrapper-support blocks, and 

(6) TSP wedge-block cracking (Ref. 6). Based on the French experience, the NRC issued Information 

Notice 96-09 (Ref. 7) and a later supplement, Information Notice 96-09, Supplement 1 (Ref. 8) to alert 

U.S. licensees to these kinds of degradation in SG internals. During the Spring 1997 refueling outage 

(RFO) at SONGS 3, the licensee identified the seventh type of degradation associated with SG internals. 

This includes erosion-corrosion degradation of the eggcrate supports in the periphery region, and in the 

untubed staywell region of the tube bundle. In response to both the foreign and U.S. experience, the 

NRC issued the subject Generic Letter 97-06, "Degradation of Steam Generator Internals" (Ref. 1), to all 

PWR licensees on December 30, 1997. 

GL 97-06 required each PWR licensee to submit the following information: 

(1) A discussion of any program in place to detect degradation of steam generator internals, and a 

description of the inspection plans, including the inspection's scope, frequency, methods, and the 

equipment used. 

The discussion should include the following information: 

(a) Whether inspection records at the facility have been reviewed for indications of signal 

anomalies from tube support plates during eddy current testing of the steam generator tubes 

that may suggest that the support plates are damaged or ligaments are cracking. If the 

licnesee has made such a review, the findings should be discussed. 

(b) Whether visual or video camera inspections on the secondary side of the steam generators 

have been done at the facility to gain information on the condition of the steam generator 

internals (e.g., support plates, tube bundle wrappers, or other components). If such 

inspections were made, they should be discussed. 

(c) Whether degradation of steam generator internals was detected at the facility, and how it 

was assessed and remedied. 

(2) If the licensee currently has no program to detect degradation of steam generator internals, a 

discussion and justification of the plans should be given along with a schedule for establishing such 

a program; otherwise the reasons should be given why no program is needed.

1-3
1 INTRODUCTION

1.3 Industry Activities in Response to GL 97-06 

The U.S. industry, coordinated through the NEI's SG Internals Task Force in January 1997, developed a 

program to address the NRC's concerns about the French and SONGS experience. Participants on NEI's 

task force included the Electric Power Research Institute (EPRI), licensees, and representatives of the SG 

owners groups for each domestic manufacturer and supplier (i.e., Westinghouse, Combustion 

Engineering, and Babcock & Wilcox). 

EPRI's topical report (GC-109558, December 1997), "Steam Generator Internals Degradation: Modes of 

Degradation Detected in EDF Units," (Ref. 6) describes the seven modes of degradation detected in SG 

internals and includes preliminary evaluations of their causal factors. This assessment was made by 

meeting with EdF, Framatome, and representatives from US licensees, NEI, and EPRI on April 9 and 10, 

1997, and by reviewing supporting information in EdF reports on their SG experience (Ref. 9). The 

EPRI report corroborated the NRC staff's understanding of the issues as they were related to them by the 

foreign regulatory authorities. 

Each owners group then initiated programs to assess safety concerns encompassing the susceptibility to 

tube damage or loss of decay heat removal (DHR) capability due to degradation of SG internal 

components on the secondary side. The groups used the EPRI report (Ref. 6) on the EdF causal factors 

to gain insights into the applicability of the French experience to their SG designs and operating history. 

In developing the susceptibility assessment, each owners group considered the following attributes of 

their SGs: design elements, fabrication and manufacturing techniques used, and the plant's operating 

history. Additionally, through industry-wide surveys, the owners groups compiled and evaluated 

information on eddy current testing, visual/video inspection of internals, and pertinent experience from 

non-destructive examinations (NDE) for their SGs currently in service at U.S. nuclear power plants. 

The safety and susceptibility assessments on the design and operating history of plants by the Babcock & 

Wilcox Owners Group (B&WOG), the Combustion Engineering Owners Group (CEOG), and the 

Westinghouse Owners Group (WOG) were used by respective members in their submittals. In addition 

to the guidelines provided by the NEI 97-06, "Steam Generator Program Guidelines" (Ref. 10), each 

owner's group recommended inspection guidelines for SG internals degradation specific to their designs. 

These latter guidelines are very comprehensive and are the only available documents identifying the SG 

internal components vulnerable to degradation. 

1.4 Objectives and Scope 

The primary objectives of this review are (1) to assess the adequacy of each licensee's responses to GL 

97-06, and (2) to identify the inspection programs that are in place to detect the degradation of steam 

generator internals in each plant. 

Westinghouse (W), Combustion Engineering (CE), and Babcock & Wilcox (B&W) are the three 

domestic manufacturers who supply steam generators to all U.S. PWR nuclear power plants. At the time 

of this review, B&W International (BWI) of Canada fabricated the replacement SGs (RSGs) in nine 

reactor units with its recirculating SGs, CE at one reactor system with its newer model, and

1-4
1 INTRODUCTION

Westinghouse in eighteen reactor units with its enhanced models during the last two decades. By the end 

of 2007, owners of six reactor units plan to replace their SGs with BWI recirculating SGs, three reactor 

units with enhanced Westinghouse SGs, one reactor system with ABB/Ansaldo-designed SGs, one 

reactor system with Framatome-designed SGs, and two other reactor units had not decided their 

replacement SG models. Thus, a total of thirteen additional reactor units are scheduled to replace their 

original SGs. BNL received and reviewed 41 individual licensee submittals involving 69 PWR units, 

and five sets of owners group's reports for the Westinghouse 51-series and D-series SGs, B&W once

through SGs and replacement RSGs, and the Combustion Engineering SGs. This report summarizes the 

review of these licensee submittals and evaluates their adequacy in meeting the intent of GL 97-06. 

At the time of this review, the steam generators currently operating in 69 PWR units were grouped by 

their manufacturers or the owners groups, B & W, CE, and W. The B&W Owners Group is divided into 

two groups: the B & W models with once-through SGs (OTSGs) supplied domestically by B & W, and 

the B & W replacement SGs by B&W International (of Canada). The three types of CE Owner's Group 

SGs are considered in one group. The Westinghouse Owner's Group SGs are divided in two groups 

containing four types of SG models: Westinghouse feed ring models with carbon steel tube support 

plates (TSPs), preheat models with carbon steel TSPs, feed ring models with stainless steel TSPs, and 

preheat models with stainless steel TSPs. Indian Point 2 had the only model 44 SGs in service at the 

time GL 97-06 was issued and in December 2000 they were replaced with model 44F units. Table 1.1 

lists the number of plant units in each of these groups. 

Table 1.1 Number of Plants for Different SG Owners Groups 

I •.SGM ianufacturer SG Qwners Group Model Description No.-of Plant Units I 

Babcock & Wilcox B&W Owners Group - Once Through SGs 7 S.................................................................................................. t............................................... 

B&W Owners Group - Replacement SGs 9 

Combustion Engineering CE Owners Group - SGs with three different Tube 12* 

Support Plate designs 

Westinghouse W Owners Group - Feed Ring SGs with Carbon 12 

Steel Tube Support Plates S.................................... ..... ......................................................... ......................... ,.o................. . 

W Owners Group - Preheat SGs with Carbon Steel 4 

Tube Support Plates 

W Owners Group - Preheat SGs with Stainless 5 

Steel Tube Support Plates 

W Owners Group - Feed Ring SGs with Stainless 20 

Steel Tube Support Plates 

Total number of plants 69 

* This includes ANO-2 that replaced its original CE SGs with W model D109 SGs in December 2000. Note that W 

model D109 is not discussed as one of the W D-series SG models in this report.

1-5
1 INTRODUCTION

The total number of steam generators in each group depends on the number of primary loops in each 

PWR unit, and varies from two to four per reactor unit. 

Section 2 summarizes NEI's guidelines to its member licensees and outlines recommendations by the 

three SG Owners Groups to their member utilities for addressing the issues identified in the NRC's GL. 

Sections 3, 4, and 5 of this report respectively cover BNL's evaluations of licensee responses to the GL 

for plants with B&W, CE, and W steam generators. Section 6 summarizes the findings and conclusions 

of this review. Appendix A contains the GL 97-06 and Appendix B provides a list of licensees whose 

responses to GL 97-06 are evaluated in this report.

1-6
2 INDUSTRY GUIDELINES FOR AN INSPECTION PROGRAM 

FOR STEAM GENERATOR INTERNALS 

In response to GL 97-06, the U.S. commercial nuclear power industry established guidelines for SG 

internals inspection programs. NEI issued general program guidelines in NEI 97-06, and the various SG 

owners groups have published specific technical information and guidelines related to their SG models. 

NEI 97-06, "Steam Generator Program Guidelines," (Ref. 10) establishes a framework for structuring 

and strengthening existing steam generator programs, and refers licensees to EPRI guidelines for the 

detailed development of programmatic attributes. Section 3.9 of this document on the maintenance of 

steam generator secondary-side integrity states the following: 

"Secondary-side steam generator components shall be monitored if their failure could prevent 

the steam generatorfrom fulfilling its intended safety-related function. The monitoring shall 

include design reviews, an assessment ofpotential degradation mechanisms, industry 

experience for applicability, and inspection, as necessary, to insure degradation of these 

components does not threaten the structural and leakage integrity or the ability of the plant to 

achieve and maintain safe shutdown." 

The guidelines for an SG internals inspection program outlined by each SG owners group are 

comprehensive and intended to assist utilities in addressing the potential concerns in GL 97-06 on 

degradation. The guidelines are specific to each SG type and are targeted to inspect those portions of the 

SG internals judged to be susceptible to deterioration. The B&WOG developed inspection 

recommendations for their OTSGs for specific internal components and locations, while BWI of Canada 

outlined a very comprehensive program for their replacement RSGs at the first refueling outage (RFO) 

inspection. The CEOG presented recommendations for SG internals in their assessment reports. Finally, 

WOG included inspection guidelines for all its models currently in service. With these guidelines and 

findings from individual plants or industry-wide activities, licensees already have developed, or are 

developing, the requisite inspection programs. 

To meet the high-level performance criteria of NEI 97-06, each SG owners group has recommended 

inspection programs for detecting and monitoring degradation in SG internals, in response to recent 

findings in foreign PWRs and SONGS, as delineated in the GL. This section summarizes these 

recommendations for the three SG manufacturers. 

2.1 Plants with Babcock & Wilcox Steam Generators 

Two groups of plants have steam generators manufactured by B&W. The first group contains five sites 

and seven plants whose nuclear steam supply systems (NSSS) were designed and supplied by B&W. All 

of them have two Reactor Coolant System loops, each with two Reactor Coolant Pumps and one once

through steam generator (OTSG). At the time of this review, the second group includes eight sites and 

nine plants. All have replaced their original steam generators with enhanced steam generators designed 

and manufactured by B&W International (BWI) of Canada. Unlike the first group, these replacement 

steam generators are B&W recirculating steam generators. The RSGs include design features to mitigate 

many problems experienced with the original steam generators.

2-1
2 INDUSTRY GUIDELINES FOR SG INTERNALS

2.1.1 B&W Once-Through Steam Generators 

Plants: Arkansas Nuclear One 1, Crystal River 1, Davis Besse 1, Oconee 1 ,2 , & 3, Three Mile Island I 

Review of data from secondary-side visual inspections and eddy current tests has shown no generic degradation problems with SG internals in this group of B&W plants. The only internal degradation found was related to the auxiliary feedwater (AFW) headers. At Davis Besse Unit 1 and Oconee Unit 3, 

these internal headers were stabilized and functionally replaced with external feedwater headers in the 

early 80s. No further damage associated with the internal AFW header was detected during subsequent 

tube inspections at these two plants. 

For each of the seven modes of degradation described in the EPRI report (Ref. 6) at the foreign PWRs 

and SONGS, the B&WOG concluded that the OTSGs are not significantly at risk for the same 

degradation, in the near term. The future susceptibility of the OTSG to these or other forms of 

degradation was evaluated as part of the B&WOG process to develop a formal SG internals program 

(Ref. 11). 

The B&W owners group, with technical assistance from Framatome Technologies Inc. (FTI), evaluated 

all potential internal degradation to determine if a formal inspection program is necessary for these steam 

generators. The FTI report on the OTSG Internals Degradation Evaluation (Report No. 77-5003013-00, 

February 1999) summarizes the method and the findings of this review (Ref. 12). It discusses all areas of 

the OTSG identified as being potentially susceptible to degradation, along with recommended inspection procedures, frequencies, and disposition criteria. Each licensee committed to develop a formal 

inspection program for the SG internals, as appropriate. 

Based on the recommendations and conclusions given in the FTI report, the scope and methodology of 

inspections in Table 2.1 to monitor possible secondary side degradation in the OTSGs are summarized. 

This is followed by two plant-specific inspection recommendations. 

Table 2.1 Recommended SG Internals Inspection Program for B&W OTSGs 

I SG Components Degradation Inspection 

Tube support plate ligament ECT to verify that the broached hole design TSPs are located properly. Pre

erosion/corrosion and cracking and Post-cleaning visual inspection, especially the 3d through the 6 h , the 9th 

and 10t TSPs. Fiberscopic inspections following tube-pull operations include 

secondary side inspections for FAC on the top TSP. The open path left by the 

pulled tube can be used to visually inspect the condition of the TSPs. 

Inspections encompass the lower tubesheet through either the 7", 8t', or 9" 

TSPs. 

Wrapper drop/cracking Visual inspection of shroud (wrapper or baffle plate) degradation, shift, or 

drop

2-2
2 INDUSTRY GUIDELINES FOR SG INTERNALS

Plant-Specific Inspection Recommendations 

Inspection of AFW Internal Headers Davis Besse 1 and Oconee 3

Steam generators at Davis Besse 1 and Oconee 3 are left with stabilized internal AFW headers which 

were replaced with functional external AFW headers. 

(a) At Davis Besse, eddy current examinations of peripheral tubes are performed at each RFO to 

monitor the tube's integrity. Following Technical Specifications, these headers are inspected every 

10 years. Inspections in 1990 and 1998 showed no evidence of movement or degradation of the 

AFW header nor deterioration of the AFW's supply nozzles and thermal sleeves. One AFW nozzle 

was stuck in 1998, and was to be inspected again in 2000. Thus, inspection every 10 years should 

be adequate. 

(b) At Oconee 3, eddy current examinations of the peripheral tubes are performed at each RFO to 

monitor tube's integrity. In 1982, as part of the commitment to the NRC, the internal AFW headers 

were inspected. Visual inspections were made during the two subsequent RFOs and during the 2nd 

10-year ISI outage. Since 1995, 100% eddy current bobbin-coil inspections have been done in 

peripheral areas that are susceptible to damage. Oconee should develop an inspection schedule for 

the AFW internal header based on the results of the 3rd 10-year ISI; no specific problems associated 

with them have been observed to date. 

Insmection of Oconee 1 Tube Dings

Dented tubes should continue to be monitored during future outages to determine if either the number of 

tubes affected is increasing or the severity of denting in those already affected. A suggested severity 

threshold is to assess by inspecting the plate either visually or with ECT, whether the denting prevents 

the passage of a 0.5 10 bobbin probe. Visual inspection could be made by pulling the main feedwater

2-3

:SG- Components Degradation I Inspection 

Upper wrapper welds Visually inspect upper wrapper welds from above, through the hand hole. If 

the main FW nozzle is removed for some other reasons, these welds should be 

visually inspected from below 

Feedwater nozzle Except Davis Besse 1 and Oconee 3, all other plants have external AFW 

headers requiring no SG internals inspections. At Davis Besse internal 

headers are visually inspected every 10-years and at Oconee 3 should develop 

an inspection schedule based on the results of the 3rd 10-year in-service 

inspection. 

Visual inspection of feedwater header/spray nozzles at each RFO 

Other SG internal components Visual inspection of AFW, MFW, and EFW nozzles, upper and lower 

tubesheets, and all kinds of small pipes and pipe fittings
2 INDUSTRY GUIDELINES FOR SG INTERNALS

nozzle and looking at the 10" TSP from below through the aspirator port. Tube dings are monitored at 

all other OTSG plants and included in the ECT data, so that the development of similar patterns could be 

recognized and assessed. 

2.1.2 B&W Replacement Steam Generators 

Plants: Byron 1, Braidwood 1, Catawba 1, Cook 1, Ginna, McGuire 1&2, Millstone 2, and St. Lucie 1 

At the time of this review eight plants had replaced their original steam generators with the enhanced 

recirculating SGs manufactured and supplied by B&W International of Canada. Cook 1 replaced its 

existing Westinghouse SGs with these SGs in the December 2000. The new RSGs were inspected at 

various points during manufacture and installation, and after final positioning in each plant. In addition, 

SGs at Millstone 2, Ginna, and Catawba 1 have completed their first fuel cycle and the tubes have been 

inspected via eddy current examinations, and the upper bundle and tubesheet regions either visually or 

with a video camera. 

For each of the seven categories of degradation at the foreign PWRs and SONGS, the B&WOG 

concluded that these RSGs are not significantly at risk for the same degradation in the near-term. 

However, B&W RSGs are uniquely vulnerable to positioning problems with the U-bend components, in 

which contact could be made between peripheral tubes. The assessment of this situation confirmed that 

peripheral tubes in contact during SG operation may wear due to flow-induced vibration fretting at their 

point of contact. Based on further assessment, B&W stated that fretting wear will not unacceptably 

reduce the tube's walls over a normal 40- or 60-year operating life. Another mechanism assessed due to 

this situation is tube bundle deposition and the potential for bridging of deposits between tubes in close 

proximity. Assuming a minimum gap and no vibratory contact, tubes could be bridged in approximately 

10 years. However, based on corrosion studies on thermally treated alloy 690 tubing, the B&WOG 

concluded that no other damage of the tubes will result from bridging in the U-bends. 

The B&WOG stated that since these SGs are new, then, after the first outage inspection, each utility 

should decide upon the need, frequency, timing, focus, and extent of individual inspections. The 

recommended inspection program in the B&W document (Ref. 13) is comprehensive, covering most SG 

internal components. Visual inspections are recommended for one SG (of the two to four) in each 

reactor unit. Inspections are recommended at the first refueling outage (RFO), and from "time to time" 

thereafter on a rotating basis. All visual inspections include several sample points or a sample region. 

Table 2.2 shows B&WOG's recommended plan for an SG internals inspection program, and is the same 

as that carried out at Millstone 2, Ginna, and Catawba 1. 

Table 2.2 Recommended SG Internals Inspection Program for B&W RSGs 

I SG Internal Region I Feature Inspection 

Primary side Tubes for defects, secondary expansion transition, Eddy current/ 

(via Man-ways) confirmation of support location, sludge accumulation, Ultrasonic testing as 

indication of support deposition, and proximity of peripheral per site program 

tubes

2-4
2 INDUSTRY GUIDELINES FOR SG INTERNALS

InenlRiegon. F eatre..n~ct 

Secondary side Tubes within bundle for surface deposits Visual and swab 

tubesheet region (via sampling 

tubesheet inspection ports) Tubesheet within bundle for sludge-pile zone Visual (Fiber optic) 

Tubesheet within bundle for sludge deposits and tube/ Visual and sampling 

tubesheet crevice region 

Lattice grid (underside of#1) for tube contacts, flow passages, Visual 

and sludge deposits 

Lattice grid rim for support blocks and span breaker ends 

Lattice grid normal tube location 

Tubesheet periphery for normal tube location, drain channel, 

and blowdown entrance ports 

Shroud lower end support blocks 

Secondary side (via Steam drum head for venturi fixity and flow effects. Visual 

steam drum man- Secondary separators from above for integrity of seal skirt, 

way) outlet ports, vent holes, skimmer vanes and gaps, inlet vanes, 

drain tubes between primary and secondary, and internal man

way/cover/fasteners 

Primary separators for upper can vent holes and rim, flow 

arms, secondary drain tubes (lower end), and riser tube to deck 

joint area 

Primary separator deck for deposition on upper surface, 

internal man way/cover/fasteners, structural members, 

deck/shell lugs, AFW header (as applicable) 

Riser cone for cone/deck joint, slip ring joint, and recire. 

nozzle exit 

Feedwater header for goose neck, header pipe, header support 

brackets, J-tubes, J-tube/header welds, J-tube entrance (header 

inside diameter), flow impingement locations, shroud slip 

joint, down comer entrance, and shroud pin assembly/weld 

Secondary side Tube deposition Visual, swab sample 

U-bend region (via 

drum) U-bend support structure, tube surface condition, J-tab Visual 

condition, tube/J-tab contact locations, flat bar U-bend support 

bars, flat bar/tube contact locations, upper lattice rim, upper 

lattice rim for visible ends of bars

2-5
2 INDUSTRY GUIDELINES FOR SG INTERNALS

[mSG Internal;Regionu I Feadture- Inpeto I 

Secondary side (via FW header outside diameter, J-tubes, J-tube/header weld, Visual 

cone access port) impingement zones, FW header inside diameter (video probe) 

Secondary side (via Lattice grid for normal tube locations, lattice grid rim Visual 

inspection ports) structure, lattice bar ends at rim, tubes within bundle, lattice 

bars tube contacts (from above), and lattice bars tube contacts 

(from below with special tooling) 

These are relatively new model steam generators. Visual inspections at Millstone 2, Ginna, and Catawba 

1 after one fuel cycle of operation found no adverse trends. 

2.2 Plants with Combustion Engineering Steam Generators 

Plants: Type 1: Calvert Cliffs 1&2, Fort Calhoun; Type 2: St. Lucie 2, San Onofre 2 & 3, Waterford 

3; Type 3: Palisades, Palo Verde 1, 2, & 3. 

Based on the design differences in the tube supports of the 12 CE-designed plants, the CE-manufactured 

steam generators are categorized into three different types: Type 1 - SGs with carbon steel eggcrates and 

drilled carbon steel plates at upper elevations; Type 2 - SGs with carbon steel eggcrates only; and 

Type 3 - SGs with stainless steel eggcrates only. 

All licensees with CE-designed SGs have agreed with the following conclusions reached by the CEOG 

about the degradation identified in the GL (Refs. 14-20). All mechanisms recently found in the foreign 

PWRs are generally not applicable to CE-designed steam generators; the only current applicable one that 

could have safety significance is flow-assisted corrosion of the peripheral regions of eggcrates at 

uppermost elevations as recently found at SONGS 3. Further, none of these degradation mechanisms 

threaten the integrity of the reactor's coolant system pressure boundary nor the heat removal function of 

the steam generator. The FAC of the peripheral region is primarily the result of secondary fluid-flow 

redistribution caused by severe bundle fouling of the tubes, exacerbated by using ammonia to control the 

pH of secondary fluid. Based on operating experience, these steam generators, except those at SONGS, 

have not encountered a significant amount of internal degradation. Appropriate mitigating action has 

been taken to minimize the effect of any degradation that has occurred. Plants with stainless steel 

eggcrates are judged not to be susceptible to FAC degradation. 

Based on the licensee submittals, inspection plans for secondary side internal components at CE plants 

are discussed here. The scope and frequency of inspection may be adjusted based on a site-specific 

experience and evaluation of the results from other industry inspections. Table 2.3 summarizes the 

inspection program plan included in licensee submittals as part of the responses to the GL. However, 

CEOG recommended that owners of SGs with carbon steel eggcrates and severe tube-bundle fouling 

should inspect peripheral eggcrate locations during each RFO. Preferentially, inspections should be to 

the hot leg side and include, as a minimum, the uppermost full eggcrate and all tube supports above it. In 

addition, owners of SGs with severe tube-bundle fouling should make a one-time inspection of the 

peripheral eggcrate locations.

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2 INDUSTRY GUIDELINES FOR SG INTERNALS

Table 2.3 Recommended SG Internals Inspection Program-for CE SGs

[SG:omponentSegradation,. I. Inspection I 

Tube support plate ligament ECT for ligament cracking in carbon steel plates in Type 1 plants and for its 

erosion/corrosion and cracking presence in eggcrates. For Type 2 and 3 plants, perform ECT for the presence 

of TSPs only 

Wrapper drop/cracking ECT to detect potential tube deformation resulting from misalignment of 

wrapper. If interference with the sludge lance equipment or deformation of 

periphery tubes is detected, the lower wrapper support blocks will be visually 

inspected 

Transition cone girth weld Inspect according to ASME Section XI Inservice Inspection Program 

requirements for the SG shell 

Feedwater nozzle Inspect according to ASME Section XI Inservice Inspection Program 

requirements. Loose parts monitoring to detect potential degradation of the 

FW nozzle 

Upper package Inspection of steam separators and feed-ring equipment. Secondary side 

visual inspections of feed ring assembly (ring, attachments and nozzles), FW 

distribution box and thermal liner, upper tube-bundle assembly, cyclone 

separators, various drain lines and couplings, internal sample lines, internal 

man-way, Chevron separators, deflection plate, and miscellaneous bolts. 

NOTE: All visual inspections involve a Welch Allyn probe, remote camera, or fiber optics. 

2.3 Plants with Westinghouse Steam Generators 

Westinghouse designed two basic types of SG: feed ring and preheat. Each type is made with carbon 

steel TSPs and stainless steel TSPs. Thus, the following four categories envelop all W-designed SGs: 

(1) Feed ring units with carbon steel TSPs - Models 44, 51, and 51M 

(2) Preheat units with carbon steel TSPs - Models D3, D4, and E2-TGX 

(3) Preheat units with stainless steel TSPs - Models D5 and E2-THX 

(4) Feed ring units with stainless steel TSPs - Models F, 44F, 51F, 54F, and Delta Series 

WCAP-15002 (Ref. 21) and WCAP-15031 (Ref. 22) include consensus guidelines for inspecting the SG 

internals in four groups of W models; specifics about the degradation of SG internal components and the 

kind of recommended inspections are presented in Tables 2.4 to 2.7. Later, WOG completed an 

assessment of steam generators which included W models F, 44F, D-series and E2. Final inspection 

guidelines for these SG models are given in the WCAP-15093 (Ref.23) and WCAP-15104 (Ref. 24) 

reports. They focus on the types of degradation that each SG model may exhibit during normal service2-7
2 INDUSTRY GUIDELINES FOR SG INTERNALS

life. Most of these recommended inspections should be performed each RFO, unless noted otherwise by 

the owners group recommendations. The scope and frequency of inspections rfay be adjusted based on 

site-specific experience and evaluation of industry results. 

Typically, most plants undertake eddy current examinations of tubes, FOSARs, sludge lancing/water 

slapping, and visual examination of SG internals during each RFO. WCAP-15104 makes the following 

recommendations for licensees for developing their own inspection programs commensurate with their 

SG models and existing SG inspection and surveillance programs at their plants.

2.3.1 Feed Ring Steam Generators with Carbon Steel Support Plates 

(Models 44, 51, and 51M)

Plants: Beaver Valley 1&2, Diablo Canyon l&2, Farley 1&2, Kewaunee, Prairie Island 1&2, Salem 2, 

Sequoyah l&2 

For this group of SGs, the TSP flow hole/ligaments are susceptible to erosion-corrosion type of 

degradation. There exists low susceptibility for cracking of wrapper near supports and eventual wrapper 

drop. Erosion-corrosion in moisture separator and feed ring/J-tubes, and cracking of TSP ligaments and 

transition cone girth welds have been observed in some SGs. Table 2.4 provides recommended 

inspection program suggested by the manufacturer. 

Table 2.4 Recommended SG Internals Inspection Program for W Feed Ring Models with 

Carbon Steel Support Plates 

ISG Components Degradation Inspection .1 

Tube support plate ligament Establish a baseline employing low-frequency bobbin results from a past or 

erosion/corrosion and cracking the current outage (Ref. EPRI SG-96-05-003, 5/96). 

Inspect critical area for TSP cracking in the 3 rows around the periphery and 2 

rows around the patch plate region and for ligament erosion-corrosion in the 

entire tube-bundle (an initial sample of 20% of the tubes is recommended) 

Wrapper drop If interference with the sludge lance equipment is detected, visually inspect 

the lower wrapper support blocks 

Wrapper cracking Unless there is evidence of wrapper's mis-position or tube damage in the 

periphery at the first TSP, no inspection is recommended. If detected, visually 

inspect the lower wrapper's support blocks 

Transition cone girth weld Inspect according to ASME Section XI Inservice Inspection Program 

requirements for the SG shell 

Feedwater nozzle Inspect according to ASME Section XI Inservice Inspection Program 

requirements. Monitor loose parts to detect potential degradation of the FW 

nozzle

2-8
2 INDUSTRY GUIDELINES FOR SG INTERNALS 

Upper package Inspect primary and secondary moisture separators and feed ring equipment 

(J-tubes, CS feedring adjacent to J-tubes, T-section, reducer, backing ring, and 

thermal sleeve). A loose part is of primary significance to tube integrity as a 

result of degradation of these components.

2.3.2 Preheat Steam Generators with Carbon Steel Support Plates 

(Models D3, D4, and E2-TGX) 

Plants: Comanche Peak 1, Shearon Harris, South Texas 1, Watts Bar 

For this group of SGs, the moisture separator and the TSP flow hole/ligaments are susceptible to erosion

corrosion. TSP ligaments are also susceptible to cracking. There exist low susceptibility for cracking of 

the wrapper near supports and eventual wrapper drop, and cracking of transition cone girth welds. 

Cracking of the waterbox has been observed in some SGs. Table 2.5 provides the recommended 

inspection program suggested by the manufacturer. 

Table 2.5 Recommended SG Internals Inspection Program for W Preheat Models 

with Carbon Steel Support Plates 

I:SG ComponentsDegradation . Inspection . 

Tube support plate ligament Establish a baseline employing low-frequency bobbin results from a past or 

erosion/corrosion and cracking the current outage (Ref. EPRI SG-96-05-003, 5/96). 

Inspect critical area for TSP cracking in the 3 rows around the periphery and 2 

rows around the patch plate region and for ligament erosion-corrosion in the 

entire tube-bundle (an initial sample of 20% of the tubes is recommended) 

In-service inspection should be conducted in accordance with Rev. 5 of the 

EPRI PWR SG Examination Guidelines 

Models D3 and D4 

Eddy current examination employing EPRI-recommended low-frequency 

bobbin results from a past outage or current outage should establish a base 

line. If indications are found, their history should be tracked to establish if 

this is an active degradation mechanism 

Experience of Model D4 degradation should be considered to be a precursor 

to any indication of cracking in the D5 SG due to their longer service-life and 

CS construction 

Model E2-TGX 

Eddy current examination employing EPRI recommended low frequency 

bobbin results from a past outage or current outage should establish a base 

line. If indications are found, their history should be tracked to establish if

2-9
2 INDUSTRY GUIDELINES FOR SG INTERNALS

2.3.3 Preheat Steam Generators with Stainless Steel Support Plates 

(Models D5 and E2-THX)

Plants: Byron 2, Braidwood 2, Catawba 2, Comanche Peak 2, South Texas 2 

For this group of SGs, both the moisture separator and the water box are susceptible to erosion-corrosion 

type of degradation. There exists low susceptibility for cracking of TSP ligaments, wrapper near 

supports and eventual wrapper drop, and transition cone girth welds. Table 2.6 provides recommended 

inspection program suggested by the manufacturer. 

Table 2.6 Recommended SG Internals Inspection Program for W Preheat Models with Stainless 

Steel Support Plates 

SG Components Degradation [ Inspection 

Tube support plate ligament Since the plates are stainless steel and with a quatrefoil broached-hole support 

erosion/corrosion and cracking design, ECT can not detect TSP cracking. However, it can detect the absence 

of a TSP. Model D4 would be considered as the precursor to any indication 

of cracking in D5, and hence no inspection is recommended unless 

degradation is detected in D4 inspections

2-10

[SG- ComponentseýDgradation. Inspection 

this is an active degradation mechanism 

Wrapper drop If interference with the sludge lance equipment is detected, visually inspect 

the lower wrapper's support blocks 

Wrapper cracking Unless there is evidence of wrapper's mis-position or tube damage in the 

periphery at the first TSP, no inspection is recommended. If detected, visually 

inspect the lower wrapper's support blocks 

Transition cone girth weld Inspect according to ASME Section XI Inservice Inspection Program 

requirements for the SG shell 

Preheater (Model D3) Inspect integrity of baffle plate by eddy current testing (ECT) 

Waterbox (Model D4 & E) Review ECT data for presence of loose parts in the periphery and T-slot 

region. If possible, make a baseline visual inspection, with subsequent ones at 

every fourth RFO (e.g., inspect one SG each RFO, or all four at every fourth 

RFO) 

Upper package Inspect primary and secondary moisture separators. The significance to tube 

integrity when these components deteriorate is primarily a loose part. 

FOSARs should continue. Eddy current inspections of peripheral and T-slot 

tubes within the preheat region should be made at each scheduled outage.
2 INDUSTRY GUIDELINES FOR SG INTERNALS

[ S--Co p•nentsýgrad0#64k. .. Inspection. 

Model D5 

All models have round tube holes in the baffle plates and round flow-holes. 

In model D5, flow holes are utilized in flow-slot regions. Inspections are not 

recommended with regard to the possibility of hole alignment resulting in 

separated ligaments, unless tube's eddy current inspections indicate a potential 

separation 

Model E2-THX 

Similar ECT techniques should be used as are recommended for TGX for 

detecting deterioration of ligaments 

This model has round tube-holes in the baffle plates and round flow-holes. 

Inspections are not recommended with regard to the possibility of hole 

alignment resulting in separated ligaments, unless tube eddy current 

inspections indicate a potential separation 

Wrapper drop If interference with the sludge lance equipment is detected, visually inspect 

the lower wrapper's support blocks 

Wrapper cracking Unless there is evidence of wrapper's mis-position or tube damage in the 

periphery at the first TSP, no inspection is recommended. If detected, visually 

inspect the lower wrapper's support blocks 

Transition cone girth weld Inspect according to ASME Section XI Inservice Inspection Program 

requirements for the SG shell 

Waterbox Review ECT data for the presence of loose parts in the periphery and T-slot 

region. If possible, make a baseline visual inspection with subsequent ones at 

every fourth RFO (e.g., inspect one SG each RFO or all at every fourth RFO) 

Upper package Inspect primary and secondary moisture separators. The significance to tube 

integrity when these components deteriorate is primarily a loose part. 

FOSARs should continue. Eddy current inspections of peripheral and T-slot 

tubes within the preheat region should be made at each scheduled outage. 

2.3.4 Feedring Steam Generators with Stainless Steel Support Plates 

(Models F, 44F, 51F, 54F, and Delta Series) 

Plants: Callaway, Cook 2, Indian Point 2&3, Millstone 3, North Anna l&2, Point Beach 1&2, Robinson 

2, Salem 1, Seabrook 1, Summer 1, Surry 1&2, Turkey Point 3&4, Vogtle l&2, Wolf Creek 

For this group of SGs, there exists low susceptibility for cracking of the TSP ligaments and the wrapper 

near supports (which may lead to wrapper drop). Erosion-corrosion in moisture separator and feed 

ring/J-tubes, and cracking of transition cone girth welds have been observed in some SGs. Table 2.7 

provides the recommended inspection program suggested by the manufacturer.

2-11
2 INDUSTRY GUIDELINES FOR SG INTERNALS

Table 2.7 Recommended SG Internals Inspection Program for 

W Feedring Models with Stainless Steel Support Plates

Tube support plate ligament Since the plates are stainless steel and quatrefoil broached hole support 

erosion/corrosion and cracking design, ECT is not applicable. A sample visual inspection of TSP region is 

recommended 

Models F and 44F 

Due to quatrefoil broached-hole design, ECT is not applicable. For early 

model F SGs, a sample inspection of patch plate and plug weld regions should 

be made. For all model F SGs, a sample visual inspection is recommended of 

the top TSP, tube-lane region (where flow holes are provided instead of 

elongated slots). Flow holes are used for strengthening the top TSP for U

bend support. If initial drilling produced a separated ligament, the effect on 

U-bend support should be evaluated 

If degradation representative of the tube's wear is indicated near TSP 

elevations, subsequent visual inspections are recommended 

Wrapper drop If interference with the sludge lance equipment is detected, visually inspect 

the lower wrapper support blocks 

Wrapper cracking Unless there is evidence of wrapper's mis-position or tube damage in the 

periphery at the first TSP, no inspection is recommended. If detected, visually 

inspect the lower wrapper's support blocks 

Transition cone girth weld Inspect according to ASME Section XI Inservice Inspection Program 

requirements for the SG shell 

Feedwater Nozzle Inspect according to ASME Section XI Inservice Inspection Program 

requirements. Monitor loose parts to detect potential degradation of the FW 

nozzle 

Upper package Inspect primary and secondary moisture separators and feed ring equipment 

(J-tubes, CS feedring adjacent to J-tubes, T-section, reducer, backing ring, and 

thermal sleeve). Inspect replacement SGs with older upper package more 

frequently. The significance to tube integrity if these components degrade is 

primarily a loose part. FOSARs should continue

2-12
2 INDUSTRY GUIDELINES FOR SG INTERNALS

2.4 Summary and Conclusions 

All plants indicated in their submittals that some program (formal or informal) for monitoring 

degradation of SG internals is in place and that inspections are typically carried out at each refueling 

outage (although not usually for all SGs at each refueling outage). Several plants with a history of 

problems similar to that described in the GL had already performed, or had plans to perform, 

comprehensive inspection of their SG internals during the next scheduled refueling outage. Further, 

several plants had replaced their SGs with new, improved designs. These improved designs included the 

use of corrosion-resistant materials, and better monitoring techniques which had significantly contributed 

to industry-wide enhanced management programs for SG internal components. 

The existing SG internals inspection programs are plant-specific and generally include the following: 

(1) Eddy current examinations of tubes that detect TSP degradation or presence of loose parts. 

(2) Visual/video inspections of tubesheets, TSPs, tube bundle, steam drum, feedwater nozzles 

including thermal liners, feedwater distribution components, waterbox, and moisture separators. 

(3) ASME Section XI In-Service Inspection of welds. 

(4) FOSAR activities. 

(5) Sludge-lancing, water-slapping or -lancing, chemical or pressure pulse cleaning. 

From the results presented in the licensees' submittals and owners group assessments, there are no near

term problems nor are there needs for any immediate change in the existing SG internals inspection 

activities. However, licensees plan to upgrade the existing inspection activities by implementing their 

owners group recommendations to address the long-term effects of the potential degradation mechanisms 

associated with the SG internals.

2-13
3 EVALUATION OF RESPONSES BY PLANTS WITH 

BABCOCK & WILCOX STEAM GENERATORS 

This section discusses the two groups of plants that have steam generators manufactured by B&W. The 

first group contains five sites and seven reactor units whose nuclear steam supply systems (NSSS) were 

designed and supplied by B&W. All of these B&W plants have two Reactor Coolant System loops, each 

with two Reactor Coolant Pumps, and one once-through steam generator (OTSG). A typical 

arrangement is shown in Figure 3.1. Thus each unit has two OTSGs. Figure 3.2 shows a diagram of a 

B&W OTSG. 

The second group of plants includes eight sites and nine reactor units. All have replaced their original 

steam generators with enhanced ones designed and manufactured by B&W International of Canada. 

Unlike the first group, these replacement steam generators (RSGs) are B&W recirculating steam 

generators. Figure 3.3 illustrates the RSGs used in U.S. plants. They incorporate design features to 

mitigate many problems experienced with the original models. Based on the licensee submittals at the 

time of this review, this report addresses the seven plants (except Braidwood 1 and Cook 1) in this group 

with RSGs in-service. Table 3.1 below lists all the plants included in these two groups. 

Table 3.1 Plants with B&W-Designed Steam Generators 

SPlants with:OneeThrough SGs Plants with:Replacement SGs

;. :.(Model 177) ____(ModeCFR-80) _ 

S• ~Original .. .. Replatedi~fit: 

-- Commercial • Commercial ONumber Repl.ceme.t "Plant Name Plant Name f SG SG"-1nservice I Start•Date Start Date ofS•s .s ______________________[Models _____ L@te 

ANO 1 12/74 Braidwood 1 7/88 W D4 4 11/98 

Crystal River 3 3/77 Byron 1 9/85 W D4 4 2/98 

Davis Besse 1 7/78 Catawba 1 6/85 W D3 4 10/96 

Oconee 1 7/73 Cook 1 8/75 W 51 4 12/00 

Oconee 2 9/74 Ginna 7/70 W 44 2 6/96 

Oconee 3 12/74 McGuire 1 12/81 W D2 4 5/97 

TMI 1 9/74 McGuire 2 3/84 W D3 4 12/97 

Braidwood 1 and Cook 1 GL 97-06 Millstone 2 12/75 CE 67 2 1/93 

responses are based on their original 

SG models. St. Lucie 1 12/76 CE 67 2 1/98 

The original B&W OTSGs have been in service for over 20 years, the oldest being at Oconee 1. The 

B&W RSGs presently in service have been used to replace four models of Original Equipment Steam 

Generators (OESGs). Millstone 2 and St. Lucie 1 replaced CE model 67 SGs; Ginna replaced 

Westinghouse model 44 SGs; Cook 1 replaced Westinghouse model 51 SGs; and Catawba 1, McGuire 

l&2, Braidwood 1, and Byron 1 replaced Westinghouse model D-series SGs. Thirty B&W designed

3-1
3 BABCOCK & WILCOX STEAM GENERATORS

RSGs are inservice in nine units. Out of the nine units with RSGs, three (i.e., Millstone 2, Ginna, and 

Catawba 1) have completed first inspections during their first refueling outage (RFO). 

The following two sections discuss the results of evaluating the licensee submittals to GL 97-06 for the 

two groups of plants with B&W steam generators. 

3.1 Plants with B&W-Designed Once Through Steam Generators 

Each of the seven units in the United States with Babcock & Wilcox (B&W) reactors was originally built 

with two B&W, model 177, once-through steam generators (OTSGs). These steam generators use 

straight heat-exchanger tubes with a tubesheet at both the top and bottom of the straight tube-bundle. 

Primary coolant is pumped through the tubes from the top to bottom of the OTSG. Feedwater 

(secondary water) enters in the middle of the OTSG and is preheated as it flows down around the shroud. 

The secondary water then flows up around the tubes, creating a counter-flow heat exchanger, where it is 

converted to steam. Near the top of the tube-bundle the steam is superheated before it leaves the OTSG. 

The OTSG has 15,500 alloy-600 tubes; the tube pattern inside the steam generator is triangular. There 

are 15 broached, trefoil tube-supports in between the two tubesheets that are made from either carbon or 

manganese-molybdenum (MnMo) carbon steel. An untubed lane provides access for secondary-side 

inspections. Two configurations of auxiliary feedwater (AFW) header assemblies are used in the 

OTSGs. Five plants use an external distribution header mounted outside the OTSG with nozzles 

penetrating the shell and the shroud. Oconee 3 and Davis Besse 1 originally used an internal distribution 

header mounted inside the OTSG; this was later replaced with external distribution headers. 

SG Internals Degradation Experience and Evaluation 

The B&WOG performed safety and susceptibility assessments relative to the design and operating 

history of the once-through steam generators. These assessments provide reasonable assurance that 

steam generator tube's integrity and DHR capability are not compromised by degradation of SG 

internals. The B&W owners group, with technical assistance from Framatome Technologies Inc. (FTI), 

evaluated all potential internal degradation mechanisms to determine if a formal inspection program is 

necessary. The FTI report on OTSG Internals Degradation Evaluation (Report No. 77-5003013-00, 

February 1999) summarizes the method and the findings of this review (Ref. 12). -All areas of the OTSG 

identified as being potentially susceptible to degradation are discussed in the FTI report, along with 

recommended inspection procedures, frequencies, and disposition criteria. 

The approach used included evaluations of degradation modes for structural components, chemical 

cleaning, and thermal-hydraulics factors associated with the OTSG design, manufacturing and 

operations. Degradation at EdF, operating experience in U.S. plants, and indications of damage or 

susceptibility to other potential damage mechanisms that have not yet been seen by the industry, or that 

may be unique to the OTSGs were considered. Chemistry data from licensees to determine the 

chemistry's impact on flow-accelerated corrosion (FAC) and other damage mechanisms were part of this 

evaluation. Finally, the report contains FTI's recommendations for inspecting SG internals to monitor 

any future potential degradation.

3-2
3 BABCOCK & WILCOX STEAM GENERATORS

The scope of the FTI's evaluation encompassed all components of OTSG internals including tubes and 

shell. These tubes and shell are regularly inspected as part of the pressure boundary, and any degradation 

is addressed by the OTSG tube-integrity program. The shell vessel welds are considered in the plant in

service inspection (ISI) program. Other SG internal components include 24" steam outlet nozzle, baffle 

plate (shroud), tubesheets, tube support plates, feedwater header/spray nozzles, auxiliary feedwater 

nozzle, all kinds of small pipes and fittings, and other miscellaneous parts. Almost all internal 

components are made of either carbon steel or forged carbon steel. Notable exceptions are the SG tubes 

which are made of Alloy 600, and the tubesheets which are made Mn-Mo carbon steel. 

Some peripheral tubes were damaged at Davis Besse 1 in 1981 and Oconee 3 in 1982 and leaked. This 

damage was caused by movements of the AFW internal headers and the brackets attaching these headers 

to the wrapper during operation. The AFW internal headers were subsequently stabilized, and 

functionally replaced by external headers at these two plants. No movements or new indications of tube 

degradation have been observed at either plant since the internal AFW supply headers were stabilized. 

The original internal headers were left inside the steam generators; eddy current examinations are 

performed at each refueling outage to evaluate the status of peripheral tubes. The internal header also is 

visually inspected for movement inside the steam generators. So far, no further evidence of movement 

or degradation of the internal AFW header or peripheral tubes has been noted. The internal header is 

visually inspected at Davis Besse 1 every 10 years as part of the plant technical specification 

requirements. Oconee 3 inspects the internal AFW header as part of a commitment made to the NRC in 

1982. In addition, visual inspections of these internal headers and 100% eddy current bobbin coil 

inspections of the peripheral OTSG tubes have been conducted since 1995. No new degradation of the 

SG internals have been noted. Another visual inspection of the internal header is planned for the 3 M 10

year ISI schedule. 

Based on the operating experience data, a significant number of secondary side inspections have been 

made at each of the B&WOG member plants, spanning from pre-service to 17 effective full-power years 

(EFPYs). These inspections have included all 15 TSPs, the upper and lower tubesheets, and one recent 

inspection of the upper wrapper welds at Oconee 1 (with the oldest SGs). Many were carried out in 

conjunction with an SG cleaning process, tube repairs, or other maintenance work. The SG cleaning 

process included water slap (WS), pressure pulse (PP), sludge lancing (SL), and chemical cleaning (CC). 

During each secondary side cleaning, visual inspections were made during both pre-cleaning and post

cleaning typically on the 3rd through the 6t" TSPs, and on the 9t' and 10t' TSPs. In all cases, pre-cleaning 

inspection revealed some deposits and post-cleaning inspection verified that all were removed. In recent 

years, fiberscopic inspections of the secondary side have been conducted following tube-pull operations. 

Since tubes are typically pulled from the lower tubesheet, most inspections encompassed the lower 

tubesheet through either the 7"b, 8h', or 9h TSPs. In one case, the tube hole was inspected from the upper 

tube end to the 11' TSP. None of these inspections revealed any damage to, or degradation of the TSPs. 

Oconee 2 experienced higher corrosion rates during chemical cleaning than at the other three plants, 

possibly due to higher concentration of magnetite in solution due to heavier deposit loading in the SGs. 

In response, FTI made an evaluation in 1996 to predict tube wear, TSP land wear, and operational 

corrosion rate as a function of increasing diametrical clearance due to chemical cleaning, operational

3-3
3 BABCOCK & WILCOX STEAM GENERATORS

corrosion, and through operational fretting-wear. The effects of increasing the gap on tube wear-rates 

and the margin to fluid elastic instability were evaluated using a combination of analytical and empirical 

techniques. The critical diametrical clearance was determined from the initiation of flow-induced 

vibration or fluid-elastic instability. Since chemical cleaning removes a small amount of base metal 

from the surface of each TSP and will affect the land areas of the broached tubes, the FTI evaluation 

determined that the diametrical clearance for up to six chemical cleanings would have no significant 

effects on fluid-elastic instability nor random turbulent response. Although corrosion allowances were 

not exceeded at Oconee 2, an increase in the corrosion allowance for the TSP land is necessary should a 

second cleaning be required. 

In 1997, the oldest OTSG at Oconee 1 was visually inspected for upper wrapper welds after 17.7 EFPYs. 

Two of the main feedwater nozzles were removed to obtained access and to examine the upper wrapper 

welds from below. No damage was found. 

FTI assessed other potential degradation mechanisms of OTSGs' internals that have not yet been 

observed in operating plants, and were not considered in the original design. 

(1) At Oconee 1 in 1979, there was an unusual pattern of tube dings at the 9"h and 10' TSP level. 

Those dings at the 9t" TSP appear to be in line with the wedge blocks, and at the 10', they are 

offset slightly clockwise from the alignment pins and wedge blocks. The actual cause of these 

dings is unknown. However, recent inspections do not show any appreciable increase in the 

number of tubes affected nor growth in the magnitude of the dings. FTI recommends monitoring 

of these affected regions during future inspections. 

(2) The manway covers in the TSPs are made of the same material as the TSPs (SA-515, Gr. 70 CS 

or SA 212-B CS). They are assembled using six 1.27 cm (1⁄2/2 inch) cap-screws that are tack

welded at final assembly. Should these covers become loose, they could cause wear which 

would be detected by eddy current inspection of the tubes. 

(3) There are four 1.27 cm (/2 inch) hex bolts in the shroud access cover (elliptical). On all of the 

OTSGs except Crystal River 3, the bolts are tack-welded. Since there are no loads that would 

directly cause these bolts to back out at Crystal River, no potential damage mechanisms are 

associated with the shroud cover. 

(4) The tie rod to nut-lock welds in an OTSG serve the same function as in the EdF SGs. No 

structural mechanisms in the OTSG design were identified that would contribute to failure of the 

tie-rod to lock-nut weld. 

3.1.1 Susceptibility of the OTSG Relative to the EdF and SONGS Experience 

All seven OTSG plants joined with the B&W Owners Group (B&WOG) to assess the susceptibility to 

tube damage and loss of decay heat removal (DHR) capability due to deterioration of secondary-side 

components. EPRI's report, GC-109558, "Steam Generator Internals Degradation: Modes of 

Degradation Detected in EDF Units," (Ref. 6) was used to evaluate the causal factors of the degradation 

in the EdF units. From it the B&WOG gained insights into the applicability of the French experience to

3-4
3 BABCOCK & WILCOX STEAM GENERATORS

their steam generator designs and operating history. In developing the susceptibility assessment, other 

attributes considered were design factors, fabrication and manufacturing techniques, and plant's 

operating history, including chemistry and related damage, such as denting. In addition, the B&WOG 

compiled and assessed information on their respective eddy current examinations, visual, video and other 

pertinent non-destructive examinations (NDE) as part of the in-service inspection (ISI) experience to 

improve their evaluations of vulnerability of OTSGs to internals degradation. 

The B&WOG member utilities have assembled and summarized design documentation relating to SG 

secondary side components. Existing analyses on possible degradation mechanisms were collected. 

Also, recent internal damage at the San Onofre Nuclear Generating Station (SONGS) was assessed for 

the OTSG design. The internals of the OTSGs were evaluated for each degradation mode experienced at 

EdF plants and at SONGS; this included structural mechanisms, chemistry, and thermal-hydraulic 

factors. These assessments are discussed here. 

(1) Erosion of the top TSP due to improper placement of hoses during chemical cleaning: 

The following provisions are included in the chemical cleaning process for OTSGs: (a) any 

residual solvent must decompose and volatilize without deleterious effects to structural materials 

at operating temperatures and pressures, (b) the solvent has to be compatible with both carbon 

steel and Alloy 600, (c) the solvent vapors can not cause a corrosive environment, should the 

uninhibited vapors condense in the upper tubesheet's crevice regions during cleaning, and (d) 

solvent velocities and solvent impingement have to be such that erosion of structural materials 

does not occur. Tests performed by B&W confirmed the effectiveness and non-aggressiveness 

of the selected solvent and process. B&W provided a Chemical Cleaning Guide Specification 

with the OTSGs. 

In 1978, EPRI initiated a program to qualify solvents and procedures for use in SGs. The fill

soak-drain method was recommended since it provided a means of replenishing the solvent with 

the assurance that all portions of the SG that were being cleaned would periodically see fresh 

solvent. Areas that were identified as sensitive to dimensional changes during chemical cleaning 

are TSPs, TSP wedges, spacer rods, spacer sleeves, alignment pins, feedwater headers, partial

penetration attachment welds, shell, and tubesheets. 

Four (ANO-1, Oconee 1 & 2, and TMI-1) of the seven plants have had their steam generators 

chemically cleaned using an EPRI-qualified cleaning solvent. This solvent differs from that used 

by EdF. Both Oconee 1 and 2 were cleaned more than 7 EFPYs ago; no adverse conditions have 

been observed by eddy current or visual inspections since that time. 

(2) Ligament cracking of carbon steel with drilled hole TSPs due to mechanical loads during 

manufacturing, shipping, or early operations: 

The in-plane TSP loads in an OTSG are produced by the lateral restraint from eight alignment 

pins evenly spaced around the shroud at each TSP. These pins are threaded to the shroud on one 

end, while the other ends are contacted with the shell (at room temperature). Wedge blocks near

3-5
3 BABCOCK & WILCOX STEAM GENERATORS

the alignment pins provide radial connections between the shroud and the TSP. Two keys 

(block-welded to the shroud with a notch cut in the outer rim of the associated TSP) are located 

180 degrees apart, and serve for initial alignment during fabrication. The TSP man-way is 

secured to the TSP with threaded fasteners, as opposed to the plug welds in the EdF SGs. 

The stress analysis of OTSG internals revealed that the loads on the alignment pins due to 

seismic and differential thermal expansion between the internals and shell are relatively small 

during plant operation, and the design margins are large for the components that transmit these 

loads. Lifting loads during fabrication and thermal stresses during stress relief were carefully 

monitored and kept within the predetermined limits. During transportation, the movements or 

vibration of the SG unit were monitored to detect any significant shock forces. Final inspection 

of OTSG internals indicated that there was no damage similar to the degradation seen in the EdF 

plants. 

The B&W OTSGs have broached-hole TSPs and are made of either carbon steel or MnMo 

carbon steel. Since no eddy current techniques (ECT) are qualified to detect degradation in 

broached hole design TSPs, ECT was used only to verify that the TSPs are located properly. 

Numerous visual inspections were performed at all seven plants over the last 25 years, and no 

deterioration of TSPs was observed in any steam generator. 

(3) FAC-induced thinning of the top TSP's periphery due to ammonia water chemistry: 

FAC was detected in EdF SGs with ammonia water chemistry, but not in those with morpholine 

water chemistry. The thinning due to FAC was aggravated by the lower pH of the ammoniated 

water. Ligament thinning at EdF units was seen in the TSP 8 regions, with velocities of about 7 

m/s and quality of 33%, but not in adjacent regions with somewhat lower velocities and qualities. 

This finding indicates that there is a relatively sharp threshold for triggering FAC at the 

operating temperature (5230 F), pH, and electrochemical potential involved. Also, EdF stated 

that high hydrazine concentration (>100 ppb) might accelerate FAC. However, this was not 

experienced in Japanese plants where hydrazine concentrations of 100 to 600 ppb have been used 

in the feedwater since 1984. 

All seven OTSG plants have operated on All Volatile Treatment (AVT) feedwater chemistry. 

Early in the plant's life, hydrazine for oxygen control and ammonia for pH control were used. 

Later, the pH control additive was switched to morpholine (an amine) to reduce FAC in the 

balance-of-plant systems' piping where such problems were observed. Based on NDE 

inspections, tube-pull evaluations, and the secondary side inspections, FAC has not been noted 

on the top TSP of any SGs in U.S. plants. 

(4) Wrapper-drop due tofatiguefailure of supports: 

The OTSG shroud (wrapper) consists of two shells, one upper and one lower, separated by a 

small gap. The upper part is supported by a flange welded to the bottom of the upper shroud and 

to the shell. The lower shroud is welded to a flange that, in turn, is bolted to the lower tubesheet.

3-6
3 BABCOCK & WILCOX STEAM GENERATORS

B&W indicated that their analysis demonstrated adequate structural strength for seismic and 

thermal loads due to differential expansion loads between the shroud and the shell. This design 

is very different from that in EdF plants. Recently, the upper wrapper assembly, welds, and 

internal components in the vicinity of the welds of the oldest OTSGs at Oconee 1 were visually 

inspected. There were no signs of wrapper degradation, shift, or drop. 

(5) Fatigue cracks from support blocks due to flow-induced vibration of wrapper: 

Alignment pins at TSP elevations prevent significant radial motion due to interference or small 

gaps between the pin and shell. Thus, large amplitude vibration is prevented, and fatigue cracks 

or wear due to flow-induced vibration are not expected to occur at these locations. 

As noted above, inspections of the secondary side at Oconee 1 revealed no degradation or crack 

on the support blocks. 

(6) TSP wedge block cracking: 

Fabrication, thermal stress relief operations, and shipping of the OTSGs to plant sites were 

carefully monitored to prevent excessive mechanical and/or thermal loads. The TSP stress 

analysis for SGs lying on their side during shipping, and subsequent inspections of SG internals 

have assured that there was no damage similar to the degradation experienced at the EdF plants. 

As noted above, inspections of the secondary side at Oconee 1 found no deterioration or cracking 

of the support welds. 

(7) Eggcrate support degradation at SONGS due to FA C associated with fouling: 

There are few design and performance similarities between the CE SGs at SONGS and the 

OTSGs. Suspected contributing factors to FAC at SONGS are ammonia chemistry and SG 

fouling due to iron loading. FTI's assessment of fouling conditions in OTSGs considering water 

chemistry and thermo-hydraulics indicates that there should not be any problem, even with 90% 

of the flow area blocked by fouling during normal operation. The maximum estimated TSP FAC 

for an OTSG that has not been chemically cleaned is 13.4 mils for Oconee 3 after 17.8 EFPYs. 

FTI evaluated the susceptibility of the OTSG TSP to FAC during operation. FAC is a function 

of, and is limited by, the solubility of magnetite in water and the rate at which ferrous ions are 

transported from the metal's surface. Solubility also is a function of temperature, pH, and 

hydrogen concentration. In recirculating SGs, quality increases as the water/steam mixture rises 

in the tube-bundle (50% or more in fouled units), somewhat faster in the hot leg than in the cold 

leg. In an OTSG, saturated liquid enters the bottom of the straight tube-bundle and is heated 

through the entire quality range to 100% by the 7'" TSP; it leaves the OTSG as superheated steam 

above the 15" TSP. OTSGs now use morpholine (or amine) water to control pH. The pH will 

vary depending on the distribution of the amine between the steam and the liquid, and the

3-7
3 BABCOCK & WILCOX STEAM GENERATORS

ionization of amine. Distribution varies with the concentration of amine, temperature, and 

quality; while ionization varies with amine concentration and temperature. 

FTI analyzed all seven plants with OTSGs for normal operation and a 90% blocked flow-area 

due to fouling. For the latter, the maximum estimated TSP FAC is 14 mils in the tube region at 

Oconee 1 after 18.7 EFPYs. Typically, the OTSGs are chemically cleaned when 50% of the 

flow area is blocked by fouling. The geometry of the broached hole in the TSP is such that the 

flow that might cause FAC is in the broached opening. Any metal loss would be from the 

broached side of the opening, since the other side is the land area in contact with the tube where 

there is essentially no flow. Thus, corrosion of the land area and broached area may occur 

during chemical cleaning, while the broached area will become corroded where there is 

significant flow. 

In summary, these assessments provide reasonable assurance that the integrity of the steam generator 

tubes and DHR capability are not compromised by degradation of SG internals. 

3.1.2 Responses to NRC's Generic Letter 97-06 

At the time of this review, no OTSG plant had a formal inspection program to detect degradation of the 

intemals of their steam generators. All plants have been operating since their commercial start-dates 

during seventies, and their informal inspections of the secondary side components during sludge lancing, 

chemical cleaning, water slapping, or tube repair/maintenance outages have not shown degradation of 

any internal component that may challenge the tube's integrity. The only internals degradation found 

was to the internal AFW headers in Davis Besse and Oconee 3. After replacing them with external 

headers, and abandoning the internal headers inside the SGs in the early eighties, these two licensees 

have committed to the NRC (Davis Besse via technical specifications, and Oconee 3 as part of a 1982 

commitment to NRC) to inspect for any future damage caused by the movement of the abandoned AFW 

internal headers. 

All plant submittals addressed the intent of GL 97-06. Plant-specific data on past inspection experiences 

were submitted in one table as part of the B&WOG evaluation. Details on the specific type of 

inspections (e.g., using ECT or visual/video camera), internal components inspected, the results, and the 

disposition of findings were generally not provided. 

All plants have been inspected during maintenance or refueling outages. The scope of most inspections 

includes the nozzles of the main feedwater (MFW), auxiliary feedwater (AFW), and emergency 

feedwater (EFW), the upper and lower tubesheets, and several intermediate TSPs. Steam generators at 

ANO- 1, Oconee 1 &2, and TMI- 1 were chemically cleaned once, while those at Crystal River 3 

underwent sludge lancing and water slapping. ANO- 1 steam generators have not been inspected for a 

long period (1A since 1990 and lB since 1981), while Davis Besse units were inspected three times 

during the last 8 years. 

Table 3.2 summarizes the inspection findings from all plants in this group based on information from the 

licensee's responses to the GL. Since OTSGs have broached-hole tube supports, the eddy current

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3 BABCOCK & WILCOX STEAM GENERATORS

technique is not effective in detecting cracks in tube supports. However, each plant typically performs 

100% bobbin coil inspections on SG tubes during each RFO to detect any absence of the tube support. 

ANO 1, Crystal River 3, and TMI 1 have not mentioned such inspections in their submittals, while the 

other four plants indicated that they routinely perform them on their SG tubes. 

Table 3.2 Plant-specific SG Inspections for B&W OTSGs 

Plant. Steam;Generator 0per'tig Eýperience 

Name Eddy Current Examination Visual/Video Inspection Remarks Nam e.. ..... -• 

Methods .. Findings Methods 1 :Findings •_.......... 

ANO 1 Not stated During No SG 1A internals was inspected 4 

maintenance degradation times, the last being in 1990; SG 1B 

outages noted internals inspected once in 1981. 

Deposits were noted on tubes and 

TSPs before cleaning and none 

afterwards 

CR 3 Not stated During No Both SGs inspected almost every 

maintenance degradation RFO. Since their initial operation 

outages. Used noted SG 3A has been inspected six times 

remote camera and SG 3B seven times 

once 4/96 

DB I Performed on No damage Visual MFW nozzle No movement of the abandoned 

periphery tubes noted since inspection replaced in internal AFW header was noted. No 

at each RFO 1981 each 10 yr per 1993. No deg. cleaning activities reported 

(TS) TS noted 

ONS 1 100% bobbin No missing During No Both inspected regularly. Recent 

coil exam. TSPs noted maintenance degradation inspection of the wrapper welds 

during last RFO outages noted indicated no degradation. No shifting 

(10/97) or edge wear on wrappers was noted 

ONS 2 100% bobbin No missing During No Both SG internals inspected regularly 

coil exam. TSPs noted maintenance degradation but less frequently than unit 1 

during last RFO outages noted 

ONS 3 100% bobbin No missing Visual No No movement of the abandoned 

coil exam. TSPs noted. inspection degradation internal AFW header was noted 

during last No damage each 10 yr per noted 

RFO. on periphery ISI schedule 

Performed on tubes noted 

periphery tubes 

at each RFO 

since 1995 

TMI I Not stated Visual EFW and Deposits were noted on tubes and 

I I inspections. MFW nozzles TSPs before cleaning and none

3-9
3 BABCOCK & WILCOX STEAM GENERATORS

Steam GeneratorOperating Experience 

Plant Eddy Current Examinatioi VisUlideoInspection Remarks 

Name__ Methods [y Finding Metho-ds, [0 Findings _ 

During 1/87, replaced. No afterwards 

used video other 

camera degradation 

noted 

3.1.3 Summary and Conclusions 

Past inspections showed no degradation of the OTSG internals, except for the internal AFW headers at 

Davis Besse 1 and Oconee 3, which were stabilized and functionally replaced with external AFW 

headers. The structural evaluation of SG internals relative to EdF and SONGS experience showed that 

OTSG internals are not susceptible to the same types of degradation. 

Each licensee indicated that they have no formal inspection program to detect degradation of SG 

internals. However, OTSGs at each plant have undergone inspections and cleaning. During this work, 

some licensees inspected other secondary side components and found no notable degradation. 

The B&WOG, with assistance from Framatome Technologies Inc. (FTI), assessed the effects on the 

OTSG design of various causal factors identified by the EdF units and by SONGS. Based on the 

recommendations in the FTI report, each licensee will evaluate the need for developing a comprehensive formal inspection program to monitor the degradation of secondary side components, commensurate 

with existing programs (e.g., ASME Section XI ISI program, each RFO inspections, prior NRC 

commitments, SG cleaning schedules). 

From the results in the FTI report, it is concluded that no additional short-term inspections of the OTSG 

internals are required; however, guidelines were recommended for inspecting and documenting the 

condition of the OTSG internals in the future. 

FTI recommends pre-cleaning and post-cleaning visual inspections of OTSG internals and fiberscopic examination of the secondary side in all tube-pull operations. The conditions noted should be properly documented to assess the scope of future inspections. Assessments of the cause of the damage at EdF 

provide reasonable assurance that the integrity of the steam generator tubes and DHR capability are not 

compromised by degradation of SG internals. 

Steam generator internals in each plant in this group, except ANO SG IB, Davis Besse SGs 1A & 1B, 

were inspected more than 3 times during their operating lifetime. While the inspections were not 

comprehensive nor formalized, the results were good, showing no degradation. 

From the results presented in the licensees' submittals, there are no near-term problems nor are there 

needs for any immediate change in the current SG internals inspections. Licensees plan to implement

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3 BABCOCK & WILCOX STEAM GENERATORS

their owners group recommendations to address the long-term effects of the potential degradation 

mechanisms associated with the SG internals. Overall, the licensees' submittals have met the intent of 

the GL and provide reasonable assurance that the SG internals comply with, and conform to, the 

licensing basis. 

3.2 Plants with B&W-Designed Replacement Steam Generators 

At the time of this review, seven plants had replaced their original steam generators with the enhanced 

recirculating SGs manufactured and supplied by B&W International of Canada (Table 3.1). Later, 

Braidwood 1 replaced its Westinghouse SGs during November 1998, and Cook 1 replaced its 

Westinghouse SGs with B&W RSGs in December 2000. Because of this, Cook 1 submitted its GL 

responses as one of the Westinghouse SG groups. However, Braidwood 1 submitted its GL responses as 

one of the B&W RSGs. Both these plants included their SG experiences based on their original 

Westinghouse SG models. The new RSGs were inspected at various times during manufacture and 

installation, including after their final positioning in each plant. In addition, SGs at Millstone 2, Ginna, 

and Catawba 1 have completed their first fuel cycle of operation and the tubing was surveyed via ECT 

examinations, and the upper-bundle and tubesheet regions visually or by video camera. 

In general, these B&W RSGs differ in size since they are replacements for units of a different original 

equipment manufacture (OEM). However, they are identical in concept and in almost all construction 

materials, including the critically important tubing and tube supports. 

The tube supports are made with a 410S stainless steel lattice-bar configuration in contrast to the OEM's 

carbon steel drilled-hole plates in Westinghouse SGs, or eggcrate supports in CE units. U-bend supports 

are made of 410S stainless steel flat-bars. The bundle wrapper is supported to the main shell by robust 

lugs with full penetration welds at the lower end, and by radial pins at various tube support elevations 

along the wrapper's height. These lugs and pins, along with the tube supports, are arranged to 

accommodate thermal motions during operation and accidents, as was verified. Thermal loads during 

manufacturing do not apply since all needed (lower shell) post-weld heat treatment is performed before 

installing the internals. No post-weld heat treatment of the full vessel is performed. 

Several design improvements in the RSGs by BWI address a number of SG internals degradation. Tube 

to tubesheet crevice IGA is avoided by selection and control of the tube alloy andt development and 

implementation of the tube expansion tooling and procedures which minimize the crevice at the 

tubesheet secondary face. Tube to tubesheet crevice and primary side stress corrosion cracking is 

avoided by using tube expansion techniques which minimizes residual stresses. Tube sensitization is 

avoided by stress relieving the pressure boundary of SG. The tubesheet sludge pipe is minimized 

through achievement of a high circulation ratio, creating high volume cross flow, high capacity 

blowdown capability, water chemistry limits, and provision of multiple access ports for sludge lancing. 

Tube support crud accumulation increases the pressure drop across tube supports through the use of 

"11open-flow" lattice grids. Denting at tube support locations is precluded by open-flow lattice grid 

supports. Tube vibration fretting wear at lattice grid and U-bend supports is avoided by maintaining 

optimum tube-to-support contact/clearance, installing U-bend supports, and selecting tube support

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3 BABCOCK & WILCOX STEAM GENERATORS

material that resists wear with Inconel 690 interface. U-bend cracking of inner row tubes is avoided by 

using large minimum radius bends and application stress relief in the tightest bends. 

SG Internals Degradation Experience and Evaluation 

These B&W RSGs are inspected during and after manufacture, in-situ before operation (typically in the 

U-bend region when temporary restraints are removed and inspections made for foreign objects), and 

after one fuel cycle. Very extensive inspections are performed of the tube supports at several locations, 

of the wrapper assembly, and in the proximity of peripheral tubes. These inspections are made during 

and after manufacture, and have shown no degradation in these areas. After removing the temporary U

bend restraints, and installing the SGs in an upright position, the U-bend region and the tubesheet 

annulus region are inspected for foreign objects. Finally, the SGs at Millstone 2 (10/94), Ginna (10/97), 

and Catawba 1 (12/97) were inspected after they completed their first fuel cycles. These inspections 

included ECT examinations, visual inspections of the secondary side tubesheets, and of the U

bend/steam drum region. All three upper vessel inspections were similar and took the same approach, 

including inspecting a comprehensive list of internal components. Inspections were visual, by direct 

access, by video camera, or by flexible video probe. 

B&W RSGs are uniquely vulnerable to positioning of the U-bend components which could cause contact 

between peripheral tubes. The U-bend structure, which is free to move with the U-bend during operating 

transients, is supported by the peripheral tubes by "L" and "J" shaped elements called J-tabs. It was 

determined that the positioning of some of the J-tabs during manufacture may cause contact between 

certain pairs of vertically adjacent peripheral tube U-bends. It was confirmed that peripheral tubes in 

contact during SG operation may be subject to flow-induced vibration fretting wear at their point of 

contact. However, based on further assessment, B&W stated that fretting wear will not result in 

unacceptable tube-wall reduction over a normal 40- or 60-year operating life. Another mechanism 

assessed relates to build up of deposition of corrosion products on the tubes and the potential for bridging 

of deposits between nearby tubes. Assuming a minimum gap and no vibratory contact, bridging could 

occur in approximately 10 years. Based on corrosion studies on thermally treated alloy 690 tubing, the 

B&W OG concluded that no additional damage will result from bridging in the U-bends. 

Inspections conducted at three plants have indicated that unfavorable proximity exists (less than desired 

clearance or possible contact) for a few tubes on several RSGs. Therefore, monitoring the proximity of 

tubes in this region during subsequent inspections should be performed until the effects of this 

degradation mechanism on the tube's integrity is better understood. The routine ongoing outage cycle 

inspections by eddy current tests and secondary side visual inspections can be used. 

3.2.1 Susceptibility of B&W RSGs Relative to EdF and SONGS Experience 

Seven plants, except Braidwood 1 and Cook 1, with inservice B&W RSGs at the time of this review 

submitted the assessment findings reported in the B&W report BWC-TR-98-03, Rev. 1, 3/18/98 (Ref. 

13), on the susceptibility of tube damage or loss of DHR capability due to secondary side component 

degradation. The degradation mechanisms described in GL 97-06 are all related to tube support 

structures or wrappers. The RSG designs all use wrappers with lower restraint-lugs, radial shroud pins

3-12
3 BABCOCK & WILCOX STEAM GENERATORS

and upper slip joint-rings. Also, all RSG designs contain lattice grid tube support structures and a flat

bar U-bend restraint system. These supports restrict flow-induced vibration of-tubing and provide 

structural support for lateral tube bundle loads such as those originating during seismic events. Material 

qualification for tubing and tube supports includes identifying corrosion allowances for structural 

analysis, including the effects of general corrosion, flow-assisted corrosion, and chemical cleaning 

allowances. Also, fretting wear of 410S stainless steel supports and alloy 690 tubing was quantified 

under typical PWR water conditions. 

The B&W report BWC-TR-98-03 (Ref. 13) assesses the potential degradation mechanisms described in 

GL 97-06. It discusses the major design differences between the cited units and the RSGs and then 

evaluates whether a similar condition could occur, even though the exact condition may not be relevant. 

In addition, the report described the U-bend support's positioning mechanism and the resultant effect on 

inter-tube spacing between certain peripheral, vertically adjacent tubes. This configuration is unique to 

these RSGs, and was discovered during recent inspections of the tube bundle assembly. 

(1) Erosion of the top TSP due to improper placement of hoses during chemical cleaning: 

Steam generators at all seven plants presently have not undergone chemical cleaning. Also, their 

materials and designs were pre-qualified for multiple chemical cleanings in the future. 

(2) Ligament cracking of carbon steel with drilled hole TSPs due to mechanical loads during 

manufacturing, shipping, or early operations: 

RSG TSPs are lattice bar type and not susceptible to ligament cracking. The tube bundles, tube 

supports, wrapper and related structures are installed after heat treatment of the lower vessel, 

thereby avoiding high thermal stresses during manufacturing. The shell closure weld, which is 

performed after tubing and is located at the conical shell, is carefilly isolated from internal 

components and carefully heat treated afterwards. Local flexibilities within the wrapper design 

accommodate differential thermal expansions during operating transients. 

(3) FAC-induced thinning of the top TSP periphery due to ammonia water chemistry: 

The 410S stainless steel material is conditioned to resist corrosion while providing structural 

strength. 

(4) Wrapper-drop due tofatiguefailure of supports: 

Wrapper support lugs are installed after thermal treatment of the vessel. Robust shell lugs with 

full penetration welds support the lower edge of the wrapper, and accommodate radial/vertical 

wrapper growth versus shell growth during operation by providing the necessary flexibility. 

(5) Fatigue cracks from support blocks due to flow-induced vibration of wrapper: 

Anti-vibration support at numerous points (including each of the fixed lower shroud lugs and by

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3 BABCOCK & WILCOX STEAM GENERATORS

the many levels of wrapper (to shell) lateral support pins) limit the wrapper's vibratory motion. 

Also, the lattice-grid support ring to the wrapper wedge points providCadditional restraint. 

(6) TSP wedge block cracking: 

The stresses and displacements calculated for the lattice grids, shroud, and related support 

components from thermal interactions and flow-loading are safely below design allowable limits. 

Their basic design readily accommodates thermal interactions during normal operation. This 

particular degradation mechanism is caused by the same loads which cause the ligament cracking 

of TSPs, whose resolution is addressed in item 2, above. 

(7) Degradation of Eggcrate support at SONGS due to FAC associated with fouling: 

Lattice bars are made out of 410S stainless steel, which is resistant to flow and corrosion effects. 

In summary, these assessments provide reasonable assurance that the integrity of the steam generator 

tubes and DHR capability are not compromised by degradation of SG internals. 

3.2.2 Responses to NRC's Generic Letter 97-06 

Byron 1 and Braidwood 1 have a formal, comprehensive inspection program for their older SGs, and the 

utility indicated that a similar program for the new BWI SGs will be developed for both in accordance to 

NEI 97-06 guidelines. The remaining RSG plants, excluding Cook 1, do not have a formal inspection 

program to detect degradation of internals of their steam generators. However, plants completing their 

first operating cycle have been inspected using the vendors's recommendations. The inspection program 

as outlined in the technical report BWC-TR-98-03, Rev.1, 3/18/98 is comprehensive, and includes almost 

all internal components important to maintaining the tube's integrity and SG's DHR capability (see 

Section 2.2.1.2, Table 2.1). 

All plant submittals addressed the intent of the GL 97-06 request for information. Details on the specific 

types of inspections (e.g., use of ECT or visual/video camera), internal components inspected, the 

inspection results, and the disposition of findings were generally not provided. 

Since the original seven plants and Braidwood 1 have replaced their original steam generators with the 

B&W RSGs, most have not developed a comprehensive formal inspection program involving the internal 

components and degradation mechanisms for the replacement RSGs. Some have not had their SGs 

installed long enough to have done an inservice inspection. Table 3.3 summarizes the inspection results 

submitted by all plants in this group in response to GL 97-06. Data relating to their original SG was 

submitted by Byron 1 and St. Lucie 1; this historical information may be useful to the NRC, but is not 

discussed here. 

Of the original seven units with B&W RSGs, four (Byron, McGuire 1 & 2, and St. Lucie) installed their 

new SGs in 1997, and thus, have not yet had an inservice inspection. Inspections were made at the first

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3 BABCOCK & WILCOX STEAM GENERATORS

refueling outages at Millstone 2, Catawba 1, and Ginna. All units generally showed very good results, 

but identified some tube proximity in the U-bend region. Millstone 2 also found minor indications of 

degradation, such as pitting at the bottom of the steam separators, and discoloration of feedwater rings 

and the shroud cones caused by oxide films. Braidwood 1 replaced its SGs in November 1998 and Cook 

1 replaced its SGs in December 2000. 

Table 3.3 Plant-specific SG Inspections for B&W RSGs 

-Steam Generator Operating Experience 

lant Name EddyaCurrent Visual/Video Inspection Remarks 

Plant NameExamiation •.: 

Methods Findings Methods I Findings .. 

Braidwood 1 Braidwood 1, Byron 1, and St. Lucie 1 submitted inspection data Braidwood (Fall 98) and Byron 

relating to their original SG (now replaced). This information may (Fall 97) replaced the original W 

be useful to the NRC for historical purposes, but is not discussed SGs with B&W RSGs. The new SGs 

here. have not been inspected. 

Byron I Braidwood 1, Byron 1, and St. Lucie 1 submitted inspection data Braidwood and Byron replaced the 

relating to their original SG (now replaced). This information may original W SGs with B&W RSGs. 

be useful to the NRC for historical purposes, but is not discussed The new SGs have not been 

here. inspected. 

Catawba 1 First ECT Tube Visual and No The full 11/97 RSG inspection report 

inspection proximity video degradation was not provided. 

during 11/97 was observed inspections noted 

on RSGs. during 11/97 

Ginna First ECT Tube Visual and No Based on the 9/97 RSG inspections, 

inspection proximity video degradation the licensee is developing a 

during 9/97 was observed inspections noted comprehensive inspection program. 

on RSGs. during 9/97 

McGuire 1 States will use Pre-service No Original SGs replaced with B&W 

ECT for visual and degradation RSGs in 3/97. They have are not 

detecting TSP video noted been inspected since in operation. 

presence inspections 

McGuire 2 states will use Pre-service No Original SGs replaced with B&W 

ECT for visual and degradation RSGs in 12/97. They have not been 

detecting TSP video noted inspected since in operation. 

presence inspections 

Millstone 2 First ECT Tube Visual and Some minor The full 10/94 RSG inspection report 

inspection proximity video indications of was not provided. 

during 10/94 was observed inspections degradation 

on RSGs. during 10/94 noted

3-15
3 BABCOCK & WILCOX STEAM GENERATORS

Steam GeneratorOperating Experience 

Plant Name Eddy Current Visual/Video Inspection Remarks Examination 

Methods Findings Methods Findings 

St. Lucie 1 Braidwood I, Byron 1, and St. Lucie 1 submitted inspection data St. Lucie replaced the original CE 

relating to their original SG (now replaced). This information may SGs in 12/97 with B&W RSGs. The 

be useful to NRC for historical purposes, but is not discussed here. new SGs have not been inspected. 

The inspection program in the B&W technical report is very comprehensive, and includes all SG internal 

components that are susceptible to degradation. Although there is no specific information on the 

frequency of inspections, it notes that after the first outage inspection, the frequency and the extent of 

subsequent ones will be reassessed by the licensee, based on experiences from their own RSGs, and those 

from other plants. 

3.2.3 Summary and Conclusions 

All 30 steam generators in this group of nine plants were installed during the last ten years. Braidwood I 

replaced its 4 SGs in November 1998 and Cook 1 replaced its SGs in December 2000. Three plants with 

eight SGs in total have completed an operating cycle and were inspected during their first refueling 

outages. No significant degradation was noted in any internal components, except the tube proximity 

problem in the U-bend region. That problem is still within the design tolerance limits. However, future 

inspection of these tubes is warranted and is planned by the licensees. Four other plants had their SGs 

replaced in 1997, Braidwood I in 1998, and Cook 1 in 2000; and they all have not completed their first 

operating cycle. For the near-term, based on the inspection findings at all B&W RSGs, it is proper to 

assume that no change is necessary in current plant practices. 

Based on the operating experience of these newly designed SGs, the support plate wastage due to 

chemical cleaning is not currently relevant as none of these units have been chemically cleaned. The 

cracking of tube support plate ligaments is also not directly relevant because tube supports are lattice bar 

type rather than drilled plates. The 410S stainless steel material for the TSPs provides corrosion 

resistance as well as structural strength. Wrapper support lugs are with full penetration welds to support the lower edge of the wrapper and the wrapper design accommodate radial/vertical shell growth during 

operation by providing the necessary wrapper flexibility. The wrapper vibration is avoided by providing 

anti-vibration support at numerous points including each of the fixed lower shroud lugs and by many levels of wrapper (to shell) lateral support pins. Finally, degradation of eggcrate supports due to 

flow/corrosion effects is addressed by the selection of 410S stainless steel for the lattice bars. 

During SG internal inspections in three plants after their first service period, it was determined that 

positioning of the U-bend support components could result in contact between peripheral tubes. The 

routine ongoing outage cycle inspections (by eddy current test and/or secondary side visual) will monitor 

the condition over time. No evidence of degradation in the steam drum, upper bundle (U-bend) and 

tubesheet regions was observed.

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3 BABCOCK & WILCOX STEAM GENERATORS

With the exception of Byron 1 and Braidwood 1, none of these plants has established a formal SG 

secondary side inspection program. However, the current program at Byron 1 and Braidwood 1 

correspond to that of the previous SG model. For the new BWI SGs, it may be necessary to modify the 

existing program. Over time, visual inspections similar to those already completed (as well as ECT 

inspection) should be performed to confirm the continued integrity of the SG internal components. 

From the results presented in the licensees' submittals, there are no near-term problems nor are there 

needs for any immediate change in the current SG internals inspections. Licensees plan to implement 

their owners group recommendations to address the long-term effects of the potential degradation 

mechanisms associated with the SG internals. Overall, the licensees' submittals have met the intent of 

the GL and provide reasonable assurance that the SG internals comply with, and conform to, the 

licensing basis.

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3 BABCOCK & WILCOX STEAM GENERATORS

CO aar I 

Figure 3.1 Three Mile Island 1 Reactor Coolant System Showing Location of Components

3-18
3 BABCOCK & WILCOX STEAM GENERATORS

Reactor Coolant 

Inlet

Baffle 

Steam Outlet 

Bypass Steam for 

Feedwater Heating

Section

Lower Tube 

Sheet Reactor Coolant Outlet

Figure 3.2 B&W 177 Plant Once-through Steam Generator

3-19
3 BABCOCK & WILCOX STEAM GENERATORS

i I i I

i I I

J0

CV 

U1 

L

z 

Ds 

cc

C 

0 

0-.

-i-,

Figure 3.3 Arrangements of B&W Replacement Steam Generator

3-20

.1-89

I--

Lr

I

Lt•! IE
4 EVALUATION OF RESPONSES BY PLANTS WITH 

COMBUSTION ENGINEERING STEAM GENERATORS 

Out of the 15 plants with CE-designed Nuclear Steam Supply Systems, 11 plants still have CE-designed 

steam generators; they are listed Table 4.1. ANO-2 replaced both of its SGs with Westinghouse D109 in 

December 2000. However, at the time of this review the GL responses by ANO-2 correspond to its 

original CE-designed SGs. Of the other three plants, Maine Yankee is permanently shutdown, and both 

Millstone 2 and St. Lucie 1 replaced their original steam generators with new steam generators 

manufactured by B&W International of Canada. Of the 11 still using CE SGs, Palisades replaced its 

original SGs with newer models of CE-designed units in March 1991. 

Based on the differences in the tube support design of the 12 CE-designed plants (including ANO-2), the 

CE-manufactured steam generators fall into three categories: Type 1 - SGs with both carbon steel 

eggcrates and drilled plates; Type 2 - SGs with carbon steel eggcrates only; and Type 3 - SGs with 

stainless steel eggcrates only (Table 4.1). 

As Table 4.1 shows, steam generators currently operating at CE nuclear power plants are from three 

specific vintages. All early vintage (Type 1) CE-designed SGs have been in commercial operation since 

the period from 1974 to 1980; the next group (Type 2 or Models 67, 70) began operation between 1983 

to 1985; and finally, the most recent group of SGs (Model 80) were installed between 1986 to 1990. 

Palisades is the only older plant which has replaced its SGs with the newer System 80 model units. 

Thus, Calvert Cliffs 1&2, and Fort Calhoun have the oldest steam generators with carbon steel eggcrate 

supports and drilled hole plates at upper elevations. ANO-2 also had two of these CE-designed SGs until 

December 2000, when these older CE units were replaced with Westinghouse D109 model SGs. St. 

Lucie, San Onofre 2&3, and Waterford 3 have SGs with all carbon steel eggcrate tube supports, and 

Palisades, and Palo Verde 1, 2, and 3 have all stainless steel eggcrate tube supports. 

Table 4.1 Plants with CE-Designed Steam Generators 

Tube.Support Plate Design 

Plant Name Commercial (seenotesbelow) Comments 

Sta.rtDate 

Replaced with Westinghouse model D 109 

in December 2000. However, the GL 97

ANO 2 3/80 X 06 responses correspond to its original CE

designed SGs. 

Plan to install replacement SGs with 

Calvert Cliffs 1 5/75 X stainless steel eggcrate supports in Spring 

2002 

Plan to install replacement SGs with 

Calvert Cliffs 2 4/77 X stainless steel eggcrate supports in Spring 

2003 

Fort Calhoun 6/74 X _1

4-1
4 COMBUSTION ENGINEERING STEAM GENERATORS

Tube Support Plate Design 

Plant Name Commercial (see notes below) Comments 

Start Date1 

Start____ TTypel Type I2 Type_3 

St. Lucie 2 8/83 X 

San Onofre 2 8/83 X 

San Onofre 3 4/84 X 

Waterford 3 9/85 X 

Palisades 12/71 X Replaced its original SGs in Fall 1990 

Palo Verde 1 1/86 X 

Palo Verde 2 9/86 X 

Palo Verde 3 1/88 X 

NOTES: TSP Type 1: Carbon steel eggcrates and drilled plates at upper elevations 

TSP Type 2: Carbon steel eggcrates only 

TSP Type 3: Stainless steel eggcrates only 

The following sections discuss the evaluations of the licensee's submittals to GL 97-06 for plants with 

CE-manufactured SGs still in service. 

4.1 Plants with CE-Designed Steam Generators 

The CE steam generators have a vertical U-tube design, with integral moisture separators and steam 

dryers. All current CE plants contain two primary loops, each with one steam generator and two reactor 

coolant pumps (Figure 4.1). The most recent CE plant design is Palo Verde, and is called CE System 80. 

In the pre-System 80 plants, the feedwater inlet nozzle enters the SG above the level of the tube bundle 

(Figure 4.2). These SGs do not have an economizer. The System 80 SG unit is larger than the pre

System 80 designs, with feedwater entering both the downcomer and the economizer of the SG (Figure 

4.3). 

The CE steam generators are designed and fabricated as ASME Code Section III Class 1 vessels. The 

secondary structure supports 8,500 to 11,000 tubes in each SG unit, and consists of tubesheet, shroud, 

seven full horizontal eggcrates, three partial eggcrates, two "batwings" (anti-vibration bars) and seven 

vertical eggcrate supports. The eggcrate tube supports of early models were made out of carbon steel. 

Some older models have a combination of carbon steel eggcrates with solid drilled support plates. The 

newer System 80 models have eggcrate supports of 409 ferritic stainless steel. The bend and horizontal 

regions of the tubes in all models are supported by the batwing supports and vertical lattice supports, 

respectively. To minimize sludge accumulation on the tubesheet, the newer models include flow

distribution plates designed from 405 ferritic stainless steel plates with holes sized to provide a sweeping 

action across the tubesheet. They reduce the particle dropout that causes sludge to form.

4-2
4 COMBUSTION ENGINEERING STEAM GENERATORS

SG Internals Degradation Experience and Evaluation 

During the late 1960s and early 1970s steam generators manufactured by CE had drilled hole carbon 

steel tube support plates (TSPs) in the tube bundle at upper elevations. The TSPs became corroded in 

these early models, and this was attributed to water chemistry and ingress of balance-of-plant (BOP) 

contaminants, such as copper. Corrosion of the carbon steel TSPs resulted in tube denting, TSP swelling, 

damaged supports, and damaged tubes. Analyses showed that removing the outer portion of the drilled 

TSP, and cutting the plate loose from the shroud would minimize the possibility of denting and 

damaging the tubes, by relieving the stresses in the TSPs. Therefore, the outer rims of the TSPs were 

removed, and the plates were detached from the shroud at all the plants with drilled TSPs, except Calvert 

Cliffs 2 (since denting was not significant there). Eliminating the stress concentrations in the TSPs 

delayed the onset of ligament cracking in the TSP. The only way to eliminate ligament cracking in these 

plants is to prevent denting of the tubes by removing the cause of support plate corrosion. Other 

mitigating actions taken at the time included reducing the ingress of contaminants, reducing in-leakage 

of air, replacing copper-containing components, and treating with boric acid. These actions, together 

with staking or plugging some damaged tubes, essentially halted denting. 

Flow-accelerated corrosion (FAC) was identified as an operational damage mechanism for the eggcrate 

tube supports and was observed at the San Onofre Nuclear Generating Station (SONGS) Unit 3. FAC 

was attributed to changes in secondary side fluid parameters caused by the buildup of deposits on the SG 

tubes (i.e., fouling of tube bundles). This buildup increased fluid velocities and lowered pH to levels 

where rapid FAC (erosion-corrosion) occurred. The fouling of the tube supports appeared related to iron 

transport into the unit through the feedwater (FW) system. At SONGS 3, major FAC effects were found 

in the peripheral regions of tube support strips of the uppermost eggcrate supports during the 1997 

refueling outage (RFO). The thin tube support strips (.09" thick) expose a large surface area to the fluid 

flow and are vulnerable to corrosion. 

The CE-designed SG has a shroud (or baffle) which separates the incoming feedwater and recirculating 

flow from the heat transfer tubing area. The shroud is thicker than EdF SGs and also serves as the main 

load path for the eggcrate and tube support plates. The cylindrical shroud can handle the lateral loadings 

due to seismic forces on the tubes and tube supports. The shroud is welded to 16 lower shell lugs above 

the tubesheet and thus it expands from the bottom similar to the tubes. The shroud has additional lateral 

restraint supports located near the bundle's center and at the top, which are designed to allow its axial 

expansion. 

The CEOG developed several documents with safety and susceptibility assessments pertinent to the 

design and operating history of this group of steam generators. These assessments conclude reasonable 

assurance that the integrity of the steam generator tubes and DHR capability are not compromised by 

degradation of SG internals. Based on these reports, each licensee has addressed both the EdF causal 

factors and the operating experience at SONGS. Based upon the submitted documents and analyses, the 

following three areas were further discussed with CE engineers (in a conference call) and were the 

subject of a staff's requests for additional information (RAIs) to CE. Based on the CE's responses (Ref. 

20), the following discussions address the concerns raised:

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4 COMBUSTION ENGINEERING STEAM GENERATORS

(1) The CEOG stated that bounding safety analyses performed for Calvert Cliffs 2 and SONGS 3 

show that potential degradation of peripheral eggcrate supports will not adversely affect safety. 

The SONGS 3 LOCA+SSE analysis and the Calvert Cliffs 2 flow induced vibration (FIV) 

analysis bound the remainder of the CE fleet based on the tube support design (e.g., all eggcrate 

type supports versus support plate/eggcrate combinations) and assumptions on degradation. 

For the LOCA+SSE event, the majority of the load is applied to the top two supports. The 

SONGS 3 steam generators are 3410 MWt design, whose LOCA loads are limiting for all CE 

plants. Details of the design of the tube support structure are analogous to all SG designs and the 

seismic condition at SONGS bound all other CE plants. SGs with drilled plates for the top two 

support plates which are assumed to be intact, are bounded by SGs with all eggcrates. Because 

of these conditions, the SONGS 3 safety evaluation bounds the remaining CE fleet. 

The analysis of FIV in drilled support plates is limiting for all CE SG designs because of the 

radial flow near a drilled plate compared to that near an eggcrate. At Calvert Cliffs, the SGs 

have tube bundle and drilled support plates for the top two tube supports. The fouling on the 

tube bundle diverts some of the flow to its periphery regions, and the drilled plates (also assumed 

to be fouled) provide more resistance to axial flow (i.e., they cause more cross-flow). Those 

with tube bundles with little or no fouling (such as in the original design) or with eggcrates the 

full length of the tube bundle are not as susceptible to FIV. 

Iron transport values presented in the CEOG report for all CE plants were used only as a first 

level indicator of the amount of sludge loading and the potential for fouling, not as the sole 

justification for being the bounding analysis. In fact, iron transport rates can vary over a 

refueling cycle by a factor of 2 or 3, and can vary from plant to plant because of differences in 

the condition of SG internals due to chemical cleaning, sludge lancing, and blowdown pressure. 

Other parameters that were considered for the bounding issue include secondary side pressure 

losses and the results of secondary side inspections. CEOG member units with less fouling 

expected than the bounding cases (based on iron transport and pressure loss) have completed 

inspections, and no degradation of the support plates was discovered. 

(2) Analyses of flow-induced vibrations (FIVs) for CE-designed SGs were based on the 

Calvert Cliffs 2 SG model, as follows: Calvert Cliffs 2 has heavier support plates at the upper 

elevations. A vibration stability ratio of 1.2 was determined for the critical locations with one 

ineffective eggcrate support. A stability ratio above 1.0 denotes unstable tube vibrations. The 

CEOG stated that these above 1.0 values are based on very conservative assumptions in certain 

input parameters. Moreover, since the long spans vibrate at stresses below the fatigue endurance 

limit, fatigue is not a concern. Tube wear at the supports or at the mid-span is considered to be a 

non-safety issue because of the length of time to develop the defect, and its leak-before-break 

characteristics. Potential tube failures due to unacceptable tube vibrations do not represent a risk 

to the safe operation or shutdown of the plant. CEOG stated that these results do not indicate 

that Calvert Cliffs currently has a vibration problem in the tube bundle.

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4 COMBUSTION ENGINEERING STEAM GENERATORS

Some conservatisms in the FIV analysis can be found in the "ATHOS" assumptions (e.g., all 

cross flow is in the worst case direction, and no credit taken for axial flow). No credit was taken 

for "whole bundle" behavior, when, in fact, a single tube acting unstably is not enough to cause 

degradation; rather two or more tubes together need to be unstable to cause tube wear. Also, no 

wear was detected either at SONGS 3 or at Calvert Cliffs 2 during recent eddy current 

inspections. 

(3) FAC of the peripheral regions of eggcrates is the only significant degradation mechanism 

applicable to the CE-designed SGs with carbon steel TSPs that could have safety significance. 

This is primarily the result of redistribution of secondary fluid flow caused by severe fouling of 

the tube bundles, exacerbated by using ammonia to control pH. 

The CEOG determined (Ref. 16) that FAC can occur over a relatively short time once a threshold 

in level of TSP fouling is reached. Therefore, at plants with carbon steel eggcrates and severe 

tube bundle fouling in peripheral eggcrate locations, the licensee should inspect these locations 

during each refueling outage, specifically the uppermost full eggcrate and all tube supports 

above it in the hot leg side. The licensees of plants without a severe fouling problem should 

inspect these locations once, and plan a future program for monitoring the fouling of the tube 

bundles at subsequent outages. The licensees of plants with a low susceptibility for FAC can 

credit inspections made at other units, provided the SG's geometry and operating conditions are 

similar. 

CE cited other factors besides fouling that may cause a loss in secondary side steam pressure 

from the design pressure of 900 psia. These other factors are a decrease in temperature (hot 

side), and/or an increase in the number of plugged tubes. Since the threshold in level of TSP 

fouling depends on many other factors, a prescriptive inspection criterion for all plants is not 

possible. Plant-specific engineering evaluations may be needed to develop an inspection 

guideline. However, CEOG indicates that, once all factors have been corrected, a pressure 

reduction of more than 5% from the design condition is significant. 

4.1.1 Susceptibility of the CE SGs Relative to EdF and SONGS Experience 

All 12 CE plants joined the effort by the CE Owners Group (CEOG) to assess the- susceptibility of tube 

damage or loss of decay heat removal (DHR) capability due to deterioration of secondary-side 

components. EPRI's report, GC-109558, "Steam Generator Internals Degradation: Modes of 

Degradation Detected in EDF Units, "(Ref. 6) was used to evaluate the causal factors involved in the 

modes of degradation experienced in the EdF units, and to gain insights into its applicability to their 

steam generator designs and operating history. In developing the susceptibility assessment, they 

considered other attributes: design factors, fabrication and manufacturing techniques, and operating 

history including chemistry and related degradation, such as denting. In addition, the CEOG compiled 

and assessed information on eddy current examinations, visual & video inspections, and pertinent 

nondestructive examinations (NDE) performed as part of the in-service inspection program.

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4 COMBUSTION ENGINEERING STEAM GENERATORS

The CEOG undertook an operability assessment for all CE-designed and fabricated steam generators 

based on the EdF experiences and those at Maine Yankee and SONGS 3. The -assessment also 

incorporated data on the SG internals inspections of CE-designed steam generators. CE submitted five 

reports (Refs. 14-18) for this review addressing the issues experienced at EdF plants and at SONGS. 

The operability of the steam generators relates to their capability to maintain safety functions: (a) the 

structural integrity of the SG tube pressure boundary, and (b) the SG heat-removal function. 

The following assessments of the degradation mechanisms identified in the GL are based on information 

from the CEOG reports. 

(1) Erosion of the top TSP due to improper placement of hoses during chemical cleaning: 

The lower flow velocities of the chemical cleaning processes used (i.e., fill and soak versus 

forced circulation) and less harmful cleaning agents minimize the potential for erosion from 

chemical cleaning in CE SGs. Full bundle chemical cleaning has been done with no reported 

damage in SGs at SONGS and Palo Verde. 

(2) Ligament cracking of carbon steel with drilled hole TSPs due to mechanical loads during 

manufacturing, shipping, or early operations: 

The CEOG states that this degradation mechanism, described in GL 97-06, is generally not 

applicable to CE SGs at the present time. The relevant design features are as follows: the steam 

generator is designed to accommodate differences in normal operating temperature without 

imposing excessive loads. The fabrication process did not include heat treatment of the complete 

assembly (with the tube supports attached to the shroud). Two closing girth welds (primary head 

to tubesheet extensions and steam drum head to upper shell) are heat treated in a local furnace. 

During the early years of CE SG operation, ligament cracking of carbon steel TSPs (in Type 1 

CE SGs) had resulted from denting, TSP swelling, and damage to both supports and tubes, 

caused by corrosion. Ligament cracks were observed at ANO-2 and Millstone 2. This 

degradation was brought under control by several actions, including cutting the TSP rim, 

reducing the ingress of contaminants and changing the water chemistry and additives. Plants 

with ligament cracks have noted no growth in the cracks since taking corrective actions. 

(3) FAC-induced thinning of the top TSP periphery due to ammonia water chemistry: 

This degradation mechanism described in GL 97-06 is generally applicable to CE SGs. With 

severe tube bundle fouling, CE-designed SGs with carbon steel tube supports may experience 

loss of secondary side pressure. Using ammonia to control pH in heavily fouled SGs increases 

the susceptibility to FAC. This is discussed further in item 7, below.

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4 COMBUSTION ENGINEERING STEAM GENERATORS

(4) Wrapper-drop due to fatiguefailure of supports: 

The primary mechanism of damage related to failures of the wrapper support in the EdF units is 

not directly applicable to the CE-designed SGs because of the robust design of the shroud and 

provisions to accommodate thermal expansions. 

(5) Fatigue cracks from support blocks due to flow-induced vibration of wrapper: 

This degradation mechanism described in GL 97-06 is generally not applicable to CE SGs. The 

shroud in CE-designed SG is adequately supported and thicker than those at EdF plants. 

Therefore, there should not be any excessive flow-induced vibration of the wrapper. No 

evidence of shroud support cracking was identified in the records. 

(6) TSP wedge block cracking: 

The CEOG stated that this degradation mechanism described in GL 97-06 is generally not 

applicable to CE SGs. They did not specifically address this issue, however, wedge block 

cracking in CE units was not identified in the experience data. 

(7) Eggcrate support degradation at SONGS due to FAC associated with fouling: 

The two most influential factors causing FAC in CE SGs are fouling and secondary chemistry. 

Severe fouling significantly changes the internal SG flow distribution. SONGS 3 had 

approximately 20% more fouling deposits by weight that SONGS 2. Further, Unit 3 experienced 

significant degradation of eggcrates, while Unit 2 did not. Analyses concluded that fluid 

dynamics and detailed local hydraulic conditions were the dominant contributors to the FAC at 

SONGS 3. 

In addition to increasing fluid velocity in the eggcrate periphery, severe fouling reduces the 

overall circulation ratio in the SG. The lower recirculating flow rates increase steam quality, 

which causes ammonia (used at SONGS 3 to control pH) to leave the liquid phase thereby 

lowering the local pH. The increased steam quality may also increase fluid velocity further, 

raising susceptibility to FAC (p. 18 of CE-NPSD-l 103, Ref. 16). 

The higher iron transport rates in the secondary water at Calvert Cliffs 2 implies potentially 

greater tube bundle fouling and eggcrate degradation than was seen at SONGS 3. However, the 

additional evaluation shows acceptable results for the potential degradation of Calvert Cliffs 2. 

During the recent RFO at Calvert Cliffs 2, the licensee visually inspected the secondary side of 

the eggcrate tube supports in the periphery of the #21 and #22 steam generators on both the hot 

and cold leg sides (Ref. 19). In the #21 SG, minor degradation of the eggcrate tube supports was 

apparent on the hot leg side at the 6th, 7th, and 8' support elevations. In the #22 SG, more 

extensive degradation of the eggcrate supports on the hot leg side at the 7"' and 8h support 

elevations was found as well as on the cold side at the 6' support elevation. However, all the

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4 COMBUSTION ENGINEERING STEAM GENERATORS

tubes in both SGs were adequately supported. The licensee preventively plugged 4 tubes in the 

#21 SG and 98 tubes in the #22 SG to prevent any continued degradation over the next operating 

cycle. Based on the location and nature of the degradation, the licensee concluded its cause is 

erosion-corrosion, similar to, but much less extensive than, that seen at SONGS 3. The licensee 

performed an upper bundle flush and sludge lancing of the SGs, and at the time of this review 

planned to adjust chemistry levels to improve resistance to erosion-corrosion. The licensee 

performed similar inspections of the secondary side at Calvert Cliffs I in 1996 and 1998, and 

found no degradation of the eggcrates. 

Based on the bounding analyses (SONGS 3 for LOCA conditions and Calvert Cliffs 2 for flow

induced vibration), tube stresses for LOCA+SSE conditions would have a significant margin 

assuming two ineffective eggcrate supports. The CEOG evaluations indicate that as long as the 

fouling of tube bundles is minimal, degradation of the type experienced at SONGS can be 

managed within the safety limits for CE-designed SGs. 

The CEOG addressed the issues identified in the GL for three specific degradation mechanisms: 

misapplication of chemical cleaning, differential thermal expansion between the components of support 

structures, and corrosion or erosion/corrosion. The CEOG made the following determinations: 

(1) Chemical cleaning of CE-designed SGs is not likely to produce damage because less harmful 

cleaning agents approved by EPRI are used. The pH was maintained between 6-8 versus a low 

value of 3.3 used at the EdF plants. Further, the processes used in cleaning did not allow 

excessive impingement of the agents on the SG supports. 

(2) Since the fabrication of CE-designed SGs did not include heat treatment of the complete 

assembly, thermal expansion is not considered to be a damage mode. The SG can accommodate 

normal differences in operating temperature without imposing excessive loads. Additionally, the 

conservatively designed supports for the tube bundle shroud (or wrapper) are not susceptible to 

the damage to them experienced by EdF. 

(3) Corrosion and corrosion/erosion are the only mechanisms that directly apply to the CE-designed 

steam generators. 

In summary, the CEOG evaluations indicate that as long as the fouling of tube bundles is minimized, 

degradation of the type experienced at SONGS can be managed within the safety limits for CE-designed 

SGs. These assessments provide reasonable assurance that the integrity of the steam generator tubes and 

DHR capability are not compromised by degradation of SG internals. 

4.1.2 Responses to NRC's Generic Letter 97-06 

During the early years of CE plant operation, the most common form of degradation of SG internals was 

from water hammer events, erosion of components within the FW system, and TSP distortions from 

denting in the tubes which led to ligament cracking. These FW system's degradation mechanisms were 

addressed and CEOG no longer considers them to be safety problems. Removing the rim of the distorted 

TSPs to relieve stresses on the plates, and injecting boron into the secondary water essentially halted any

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4 COMBUSTION ENGINEERING STEAM GENERATORS

further progression of ligament cracking. All plants with early model SGs had denting at their carbon 

steel tube supports with drilled holes and eggcrates at upper elevations. Ligament cracking on TSPs, 

however, was only found at ANO 2 (since replaced), Fort Calhoun, and Maine Yankee (no longer in 

service). Fort Calhoun monitors TSP cracking to ensure that the cracks are not lengthening. Except for 

Calvert Cliffs 2, all SGs of this vintage have undergone upper TSP rim cutting. All plants with the next 

vintage SGs, using carbon steel eggcrates only, experienced denting of the eggcrates during their early 

years. Improvements in the secondary water chemistry have mitigated this particular damage. 

All licensees with CE-designed SGs agreed with the following conclusions that the CEOG reached about 

the degradation identified in the GL. All mechanisms recently found in EdF units are generally not 

applicable to CE-designed steam generators. The only one applicable to the CE units that could affect 

safety is FAC of the peripheral regions of eggcrates at uppermost elevations, as found at SONGS 3. 

Further, none of these mechanisms pose a threat to the integrity of the RCS pressure boundary or the heat 

removal function of the steam generator. The FAC of the peripheral region is primarily the result of 

redistribution of secondary fluid flow caused by severe fouling of the tube bundles in the carbon steel 

TSPs, exacerbated by using ammonia to control secondary fluid pH. Based on operating experience, 

these steam generators have not encountered significant internal degradation and, of the degradation that 

has occurred, appropriate mitigating action has been taken to minimize its effects. Plants with stainless 

steel eggcrates are judged not susceptible to FAC degradation. 

After a comprehensive inspection at SONGS 3, it was confirmed that FAC was primarily limited to the 

upper eggcrates and was confined to the periphery. The degradation was characterized by thinning of the 

lattice bars, with a scalloped surface indicative of FAC. Since significant fouling of the tubes that 

increases fluid velocities, causing FAC degradation and the buildup of deposits on them is directly 

related to iron transport into the SG unit through the FW system, Calvert Cliffs 2 SGs (with the highest 

iron transport rates) were analyzed for FAC. The LOCA evaluation indicated a significant margin in the 

allowable tube stresses, even with two ineffective eggcrate supports, bounded by the SONGS model. 

However, the Calvert Cliffs model for flow-induced vibration indicated unstable vibrations of the tube 

bundle even with only one ineffective eggcrate support. Nevertheless, the CEOG concluded that fatigue 

degradation in tubes is not a concern since the flow-induced vibration stresses are within the fatigue 

endurance limit for the material. CEOG considers tube wear at the supports or at the tube's mid-span is a 

non-safety issue because of the long duration for developing defects and the leak-before-break 

characteristics. The staff disagrees with the CEOG conclusion that wear is a non-safety issue because of 

leak-before-break characteristics. However, routine ECT would be expected to identify tube wear at 

supports or other locations and prevent this mode of degradation from becoming a safety issue. 

The licensee stated that the primary damage mechanisms causing the wrapper supports to fail in the EdF 

units are not directly applicable to the CE-designed SGs, because of the robust design of the shroud and 

provisions to accommodate thermal expansions. 

For FAC damage observed in the SONGS 3 eggcrates, CEOG's analyses indicate adequate margin 

against failures. The CEOG concludes that plants with appreciable degradation of eggcrate TSPs can 

continue to operate safely, and any damage to tubes can be detected in the normal ECT examinations.

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4 COMBUSTION ENGINEERING STEAM GENERATORS

All plant submittals addressed the intent of GL 97-06. Plant-specific data on past inspection experiences 

were submitted in one table as part of the CEOG evaluation. Details on the specific type of inspections 

(e.g., using ECT or visual/video camera), internal components inspected, the results, and the disposition 

of findings were generally not provided. 

Because there is no qualified eddy current technique to detect degradation of eggcrate design tube 

supports, many licensees gave no information about its use in their inspections. Nevertheless, it is 

known that essentially all plants use ECT to examine SG tubes (which were not the subject of this GL). 

Some plants with carbon steel drilled hole TSPs in their SGs have found ligament cracking, although it is 

not clear if this was detected visually or by ETC. Some plants indicated using ECT for determining the 

presence of tube supports or any loose parts inside the steam generator. 

Almost all plants have performed some kind of visual and/or video camera inspections of the SG 

internals during their normal RFO tasks. Details on the actual techniques used and the specific findings 

of the inspections generally are not given in their GL submittals. All licensees provided some results of 

the last inspection of the SG internals, and had not found notable degradation of internal components. 

Calvert Cliffs 1 was planning to review all its ECT data during the next RFO inspection. Table 4.2 

summarizes the information on inspections from all plants in this group based on their submittals. 

Out of the four plants with the earliest vintage of SGs, the licensee replaced both ANO 2 SGs in 

December 2000, and the licensee of Fort Calhoun planned at the time of this review to perform a more 

comprehensive SG inspection during their next RFOs. For Calvert Cliffs 1, the licensee inspected SG 

internals in 1996 and 1998, and found no significant damage to the eggcrates. For Calvert Cliffs 2, the 

licensee comprehensively inspected its two SGs in early 1999 and plugged 4 tubes in SG #21 and 98 

tubes in SG #22 to mitigate the potential for continued degradation over the next operating cycle. 

Replacement SGs, with stainless steel eggcrate supports, will be installed in the Spring 2002 for Calvert 

Cliffs I and Spring 2003 for Calvert Cliffs 2. 

Table 4.2 Plant-specific SG Inspections For CE SGs 

Steam Generator Operating Experience 

Plant Name Eddy Current Examination Visual/Video Inspection Remarks 

Methods Findings Methods Findings 

ANO 2 Performed each Fouling and Visual and FW (see note 1) Replaced SGs in December 2000. 

RFO for loose denting in video component Last inspection during 5/97 

parts eggcrates inspections degradation, included TSPs and other structural 

ligament cracks, components 

and loose parts 

Calvert Performed to TSP crevices- Visual and FW component Last inspection made during 96 and 

Cliffs 1 detect denting fouling and video degradation plans for a detailed one during 98 

denting inspections RFO. 

Calvert Performed to TSP crevices- Visual and FW component Last inspection made during 97 and 

Cliffs 2 detect denting fouling and video degradation plans for a detailed one during 99 

denting inspections RFO.

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4 COMBUSTION ENGINEERING STEAM GENERATORS

Steam GeneraitOperatingExperience" 

Name" 

Plant Eddy Current Examina iiw Vis~ualWideo Inspection Remarks 

Methods__ ]F.idigs- Methods, 'Findings ______ -----------

Ft. Performed each TSP crevice Visual FW component Plans to perform a more 

Calhoun RFO for TSP fouling and inspections degradation, comprehensive inspection during 

conditions denting each RFO and one TSP next RFO 

crack per SG 

St. Lucie Performed each No Visual and FW component Has been inspecting SG internals 

2 RFO for TSP degradation video degradation, each RFO since 1986 

conditions noted inspections some minor 

fouling, and 

loose parts 

San Performed No reported Visual and Minor lattice More comprehensive inspection 

Onofre 2 during last results video thinning and performed during 2/98. Secondary 

inspection 2/98 inspections pitting side components are in good 

condition 

San Not stated ----- Visual and Upper eggcrates More comprehensive inspection 

Onofre 3 video periphery performed during 3/98. No results 

inspections degraded are available 

Waterford Performed for Loose nuts Visual and No degradation Has a formal inspection program for 

3 loose parts video Some minor SG internals 

inspections sludge deposits 

and loose parts. 

Palisades Performed for No Visual and No degradation Has a formal inspection program for 

TSP conditions degradation video noted SG internals 

noted inspections 

Palo Performed each No Visual and No degradation Has an informal inspection program 

Verde 1 RFO for TSP degradation video noted for SG internals 

conditions noted inspections 

Palo Performed each No Visual and No degradation Has an informal inspection program 

Verde 2 RFO for TSP degradation video noted for SG internals 

conditions noted inspections 

Palo Performed each No Visual and No degradation Has an informal inspection program 

Verde 3 RFO for TSP degradation video noted for SG internals 

_ _ conditions noted inspections III 

Note 1: FW in this table refers to feedwater system components located within the SG, such as J-nozzles, the 

feedring, distribution box, and thermal liner. 

The San Onofre 2 & 3 SGs have undergone comprehensive NRC reviews during the year after degraded 

eggcrate supports were found at SONGS 3. The licensee's submittal for these two plants in response to 

the GL cites many other submittals to the NRC. The NRC technical monitor for this project stated that 

the NRC has already reviewed them and concluded that the licensee had taken appropriate corrective 

actions. Therefore, this evaluation drew no conclusions on the adequacy of the inspection programs at 

San Onofre.

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4 COMBUSTION ENGINEERING STEAM GENERATORS

Palisades and Waterford 3 have formal programs to inspect their SG internals. All other plants (except SONGS 2 & 3) have informal inspection programs. For St. Lucie 2, the licensee has been inspecting the 

separator and feedring equipment of both SGs since 1984. No significant degradation of SG internals 

components were identified at these plants during their recent inspections. 

In addition to the plant specific GL submittals, the CEOG provided partially complete Tables (Tables 2

1, 2-2, & 2-3 of Ref, 16), that summarize the inspection results for the FW system, tube-bundle 

assembly, and steam drum region. There is additional discussion of the degradation of SG internals in 

CE-NPSD- 1092 (Ref. 15). The new SG models installed in Palisades and Palo Verde are not included in 

this documentation, but the earlier models at Palisades, Millstone 2, St. Lucie 1, and Maine Yankee are 

included. In these earlier models, FW components found degraded in the past were either replaced with 

better design and materials, or repaired at the time to bring the SGs back into service; these components involved FW spargers, liners, distribution box, AFW nozzles, and pipes. Degradation of the tube bundle 

assembly involved fouling and denting in eggcrates causing FAC of the peripheral supports, and 

distortion of some early model TSPs with drilled hole tube supports. The blowdown pipe at SONGS 2 

was used to remove tubesheet contaminants. Erosion just above the tubesheet caused a large through wall hole that makes it ineffective. Finally, in some SGs the steam deflectors and the separators in the 

steam drum region were damaged. 

Palo Verde and SONGS are the only plants which have chemically cleaned their steam generators. ANO 

2 and St. Lucie 2 sludge lanced their tube supports at each RFO. The Palisades and Palo Verde plants are 

the only ones who indicated using FOSAR equipment during their scheduled inspections. 

At all Palo Verde Nuclear Generating Station (PVNGS ) units, the secondary water is treated with boric 

acid, and all SGs were chemically cleaned, further reducing the buildup of corrosion product at 

tube/support intersections. Consequently, feedwater iron transport rate were reduced to 2-5 ppb, which 

should avoid conditions leading to FAC. Finally, these plants will continue monitoring operational 

chemistry, using the results of eddy current testing, and gathering industry information to determine if 

future actions are required. 

Overall, all CE plants have been inspecting their SG internals since their commercial start and 

appropriate mitigating actions were taken for identified degradation in SG internal components. 

Therefore, licensees have concluded that no near-term inspections of the internals are required, and they 

have maintained compliance with the current licensing bases. 

Since CE-designed steam generators with carbon steel supports are susceptible to FAC at their peripheral TSPs due to excessive tube bundle fouling. All plants in this group should monitor the fouling levels 

(which can lead to a drop in secondary side pressure) associated with these SGs, and also wear in the 

tubes due to unstable flow-induced vibrations of the tube bundles. CEOG's evaluation does not clearly 

define the threshold for tube bundle fouling, beyond which eggcrate supports are vulnerable to FAC, 

because it depends on plant-specific attributes. Plant-specific engineering evaluations may be needed to 

develop an inspection guideline. However, CEOG indicates that, once all factors have been corrected, a 

pressure reduction of more than 5% from the design condition is significant.

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4 COMBUSTION ENGINEERING STEAM GENERATORS

4.1.3 Summary and Conclusions 

The plants (Calvert Cliffs l&2, Fort Calhoun) with early vintage (Type 1. or Models 67/70) 

CE-designed SGs, with carbon steel eggerates and drilled hole TSPs at upper elevations, have been 

inspecting their SG internals since their commercial start. The inspections included the tube bundle area, 

FW system components, and steam drum region of the steam generator. The next group of plants (St. 

Lucie 2, SONGS 2&3, and Waterford 3) contain Type 2 SGs with carbon steel eggcrate tube supports 

only. Their SG internal components have been inspected, similar to the first group of plants. Both 

SONGS units were separately reviewed by the NRC after reporting degradation of the eggcrate's 

periphery during the 4/97 RFO. St. Lucie has inspected its SG internals at each RFO since 1984. The 

final group of plants (Palisades and Palo Verde 1,2,&3) have Type 3, the most advanced CE-designed 

steam generators, which contain stainless steel eggcrate tube supports only. All plants at Palo Verde 

have undergone chemical cleaning, while Palisades inspects its SG internals regularly. 

Historically, plants with older CE-designed SGs experienced the industry-wide problems of tube denting, 

degradation of FW system components within the SG, and within the steam drum region of the SG. The 

licensees appear to have taken appropriate corrective actions to alleviate these problems when they were 

discovered. Although the inspections at these plants are not formalized (except at Palisades and 

Waterford 3), the summary results, as reported, have been good, showing no notable degradation (except 

at SONGS 3). NRC separately reviewed SONGS 3 in detail. 

The steam generator internals degradation mechanisms described in GL 97-06 are generally not 

applicable to CE-designed SGs. The only degradation mechanism applicable to the CE fleet that could 

have safety significance is FAC of the peripheral regions of eggcrates. This occurs primarily due to the 

secondary flow distribution caused by severe tube bundle fouling. A secondary cause of FAC, which is 

exacerbated by severe fouling, is the use of ammonia for secondary fluid pH control. 

One significant degradation mechanism is currently applicable to the CE-designed SGs with carbon steel 

TSPs that could have safety significance, namely flow-accelerated corrosion (FAC) of the peripheral 

regions of eggcrates. A pressure reduction of more than 5% from the design condition due to internal 

fouling is considered significant. Plant-specific limits on this pressure loss must be determined to 

properly monitor the amount of fouling in the SG tube bundles. 

From the results presented in the licensees' submittals, there are no near-term problems nor are there 

needs for any immediate change in the current SG internals inspections. Licensees plan to implement 

their owners group recommendations to address the long-term effects of the potential degradation 

mechanisms associated with the SG internals. Overall, the licensees' submittals have met the intent of 

the GL and provide reasonable assurance that the SG internals comply with, and conform to, the 

licensing basis.

4-13
4 COMBUSTION ENGINEERING STEAM GENERATORS

A

8

Figure 4.1 Reactor Coolant System for CE Plants

4-14
4 COMBUSTION ENGINEERING STEAM GENERATORS

Figure 4.2 Combustion Engineering Recirculating Steam Generator 

(Typical for 2-Loop System 69 Plants)

4-15

Primary 

Inlet
4 COMBUSTION ENGINEERING STEAM GENERATORS

Steam 

Outlets

Primary Feedwater Lv 

Inlet Economizer Tube Sh( 

Sb Support -- •Up 

Feed 

Econc 

FTube 

FeedwaterF 

Primary/ Tube 

Outlet HadSheet 

(typ. of 2) Hole 

Primar Primary 

Inlet Divider Outlet 

Plate 

Figure 4.3 Combustion Engineering Recirculating Steam Generator 

(Typical for System 80 Plants)

4-16
5 EVALUATION OF RESPONSES BY PLANTS WITH 

WESTINGHOUSE STEAM GENERATORS 

Over forty reactor units currently have Westinghouse (W) steam generators, involving about a dozen 

different W-designed SG models. The earlier W-designed models (e.g., Models 24, 27, 33, 44) were 

followed by 51-series and D-series SGs. Several licensees have replaced their original SGs with 

enhanced models (44F, 51 F, and 54F). These enhanced models use hydraulically expanded, thermally 

treated Alloy 600 tubing and 405 stainless steel tube support plates (TSPs) [except for model 54F, used 

at Cook 2 and Indian Point 3 which has thermally treated Alloy 690 tubing]. The replacement models 

generally match the heat transfer area of the SGs they replace except for the model 54F units with Alloy 

690 tubing, which are slightly larger than the original model 51 units, due to the lower thermal heat 

transfer properties of the Alloy 690 material vis-a-vis the Alloy 600 material. 

Westinghouse SG models in service at nuclear power plants in the United States can be categorized by 

two basic designs: feed ring and preheat. Models 44, 44F, F, 51-series, 54F, Delta 47 and Delta 75 are 

feed ring SGs, and Models D-series and E2 are preheat SGs. The feed ring design utilizes a feed ring 

and J-nozzles while the preheat design uses a waterbox to supply feed water to the SGs. The most recent 

W-designed SG models include D5, E2-THX, F, Delta 47 (or A47), and Delta 75 (or A75) units, with 

stainless steel broached (quatrefoil or trefoil) TSPs in place of the older models' carbon steel drilled hole 

TSPs with flow holes. The delta-series models are larger and have broached trefoil TSPs made out of 

405 stainless steel. Most of them, and some later 51-series models, are equipped with flow-distribution 

baffles. The tubes are fabricated from thermally treated alloy 690. 

At the time of the GL issuance, Indian Point 2 was the only plant with four W model 44 steam generators 

still in service. The SGs had experienced significant denting during last 25 years of service. The EdF 

experiences are not related to TSP degradation and tube denting; therefore, W model 44 SGs are not 

included in either of the two separate W Owners Group evaluations. However, the model 44 SGs at 

Indian Point 2 had similar features to the 51-series steam generators. On February 15, 2000, after 

excessive leakage from a failure in a low row U-bend in one of the SGs, Indian Point 2 was shutdown. 

The licensee replaced all four of its model 44 SGs with model 44F in December 2000, prior to restart. 

Since the original SGs are not covered by the WOG evaluations, it is evaluated separately in Section 5.3. 

Section 5.3.1 discusses the evaluation of the plant-specific submittal in response to GL 97-06 relative to 

the old SGs. Section 5.3.2 discusses the results of the post-shutdown evaluation of the February 15, 2000 

event as it relates to SG internals degradation. 

WOG evaluated all its SG models in two groups. The first group includes the 51-series SGs consisting 

of Westinghouse models 51, 5IM, 5 IF, and 54F discussed in WCAP-15002 (Ref. 21) and WCAP-15031 

(Ref. 22). These evaluations address the EdF causal factors in the GL. The 51-series SG designs are the 

most similar to the EdF units described in the GL. Westinghouse also included two other replacement 

SG designs, the Delta 47 and Delta 75 in these evaluations because of a stated "similarity in design." 

The second group includes W SG models 44F, F, D3, D4, D5, and E2, discussed in WCAP-15093 (Ref. 

23) and WCAP-15104 (Ref. 24). Table 5.1 lists the PWRs having Westinghouse steam generators and 

gives the model, number of SGs, and pertinent comments. Depending on the number of loops in reactor 

primary system design, each plant may have two to four SGs in service (see Figures 5.1 and 5.2 for 

examples of the primary system design).

5-1
5 WESTINGHOUSE STEAM GENERATORS

WCAP-15031 includes inspection guidelines for all W-design SG models as consensus recommendations 

of the WOG SG Internals Task Team. These guidelines provide the.minimum scope inspection for an 

SG secondary side internals inspection program. The guidelines are specific to each W SG type, and are 

targeted to inspect those portions of the SG internals judged to be susceptible to degradation. WCAP

15093 and WCAP-15104 contain the final inspection guidelines both for W 51-series SGs and W models 

F, 44F, D-series and E2 SGs. 

Table 5.1 Plants with W-Designed Steam Generators 

Plants with Westinghouse SG Models Plants with Westinghouse SG Models 

(51, 51M, 51F, 54F, A47, A75) (44, 44F, F, D3, D4, D5, E2) 

Plant Comm. Comm. SG #of Name Model SGs Comments Start Model SGs Comments Date Date Model___ 

Beaver 10/76 51 3 Byron 2 8/87 D5-3 4 

Valley 1 

Beaver 11/87 51M 3 Braidwood:.. 7/88 D4 4 Rplaced.:: Valley 2 1 in 11/98' 

wvith. 

_____"_..__BRSGs 

Cook..1 -8/75 51 4 -1 Rekplaced. Braidwood 10/88 D5-3 4 

.With B&WJ 

Cook 2 7/78 54F 4 Replaced Callaway 12/84 F 4 

lower Early 

section in Model 

1988-89 

Diablo 5/85 51 4 Catawba 2 8/86 D5-2 4 

Canyon 1 

Diablo 3/86 51 4 Comanche 8/90 D4-2 4 

Canyon 2 Peak I 

Farley 1 12/77 51 3 Comanche /92 D5-2 4 

Peak 2 

Farley 2 7/81 51 3 Shearon 5/87 D4-2 3 

Harris 

Kewaunee 6/74 51 2 Indian 8/74 44 4 Not 

Point 2 evaluated 

for EdF 

causal 

factors. 

Replaced

5-2
5 WESTINGHOUSE STEAM GENERATORS

Plants with Westinghouse SG, Models Plants with Westinghouse SG Models 

(51, 51M, 51F, 54F, A47, A75) (44, 44F, F, D3, D4, D5, E2) 

Pat COMM. SG # Of Plant comm. SG # of Plant Star ICComm.tsGStaof Comments 

Name Com. Model SGs Comments Name Dat Model SGs 

Date Date 

North 6/78 54F 3 Replaced Indian 8/76 44F 4 Replaced 

Anna I lower Point 3 Late in 1989 

section in Model 

1993 

North 12/80 54F 3 Replaced Millstone 3 4/86 F 4 

Anna 2 lower Late 

section in Model 

1994-95 

Point 10/72 Delta 2 Replaced Point 12/70 44F 2 Replaced 

Beach 2 47 in 1996 Beach 1 lower 

section in 

1983 

Prairie 12/73 51 2 Robinson 2 3/71 44F 3 Replaced 

Island 1 lower 

section in 

1984 

Prairie 12/74 51 2 Salem 1 6/77 F 4 

Island 2 Late 

Model 

Salem 2 10/81 51 4 Seabrook 1 /90 F 4 

Late 

Model 

Sequoyah 7/81 51 4 South 8/88 E2 - 4 

1 Texas 1 TGX 

Sequoyah 6/82 51 4 South 6/89 E2 - 4 

2 Texas2 THX 

Summer 1 1/84 Delta 3 Replaced Turkey 12/72 44F 3 Replaced 

75 in 1994 Point 3 First lower 

Model section in 

1981 

Surry I 12/72 51F 3 Replaced Turkey 9/73 44F 3 Replaced 

lower Point 4 lower 

section in section in 

1980 1982

5-3
5 WESTINGHOUSE STEAM GENERATORS

Plants with Westinghouse SG Models Plants with Westinghouse SG Models 

(51, 51M, 51F, 54F, A47, A7 5) (44, 44F, F, D3, D4, D5, E2) 

Plant Comm. Comm. Start SG # of Comments Plant Com. SG # of Comments 

Name Date Dae Model _ _ 

SGs _ _ Name Start Date Model _ _de __ SGs _ 

Surry 2 5/73 51F 3 Replaced Vogtlie 1 6/87 F 4 

lower Late 

section in Model 

1979 

NOTES: Vogtle 2 5/89 F 4 

(I) Models 44, 51, & 5IM have Feed Rings and Carbon Late 

Steel TSPs. Model 

(2) Models D3, D4, & E2-TGX have Preheat and Carbon 

Steel TSPs. Watts Bar 6/92 D3 4 

(3) Models F, 44F, 5 iF, 54F, A-47, & A-75 have Feed 

Rings and Stainless Steel TSPs. 

(4) Models D5 & E2-THX have Preheat and Stainless Steel Wolf 9/85 F 4 

TSPs. Creek Early 

_ 1 _ 1_ Model 

Shaded plants submitted GL responses corresponding to their original SG models. 

The following sections discuss BNL's evaluations of the licensee responses to GL 97-06. Section 5.1 

evaluates the responses for models 51, 51 M, 5 IF, 54F, A47, and A75 and Section 5.2 for models 44F, F, 

D3, D4, D5, and E2. Section 5.3 evaluates the response for Indian Point 2 model 44 steam generators, 

which were replaced with model 44F SGs in December 2000. 

5.1 Plants with W-Designed Steam Generators, Models 51, 51M, 51F, 54F, 

A47, and A75 

This group of SGs are the most similar among the Westinghouse models to the EdF units described in the 

GL (see Figure 5.3). The 51 series SGs include W models 51, 51M, 51F, and 54F and, because of a 

stated similarity in design, WOG also included models A47 and A75 for evaluating the susceptibility to 

degradation types outlined in the GL. Table 5.1 lists 20 plants which are currently using one of these W

models. These models all have the feed ring design. Since this evaluation took place, Cook 1 replaced its model 51 SGs with B&W recirculating SGs in 2000. Out of the 19 plants (excluding Cook 1), 12 have 

W models 51 and 51M which are designed with carbon steel drilled round hole TSPs, with flow holes. 

The remaining 7 plants have models 5 IF, 54F, A47, and A75 with stainless steel and trefoil or quatrefoil broached type TSPs. One additional plant, Indian Point 2 had W model 44 SGs which have similar TSPs 

and feed ring components to that of the model 51 and 51M. 

Table 5.2 shows the distribution of the six different steam generator models consisting of 59 individual 

SGs. There are 38 Model 51 or 51 M SGs in 12 NPP Units; these are the original W models with carbon 

steel (CS) TSPs. Cook 1 replaced its four model 51 SGs in 2000. The licensee for Kewaunee replaced its original equipment (model 51 SGs) in Fall 2001. There are 21 SGs with stainless steel (SS) TSPs

5-4
5 WESTINGHOUSE STEAM GENERATORS

(Models 5 IF, 54F, A47, or A75). These are replacement SGs that were installed in 7 NPP units between 

.1980-1995. 

Table 5.2 Distribution of SG Models 51, 51M, 51F, 54F, A47, and A75 

SSG:esign:Type :I Model# I # of NP Units - #ofSGs, 

51 11* 35 

Feed Ring Models with CS TSPs: 

51M 1 3 

51F 2 6 

54F 3 10 

Feed Ring Models with SS TSPs: 

A47 1 2 

A75 1 3 

TOTALs 6 Models 19 59 

* This excludes Cook I that replaced its 4 model 51 SGs with B&W RSGs in December 2000. 

SG Internals Degradation Experience and Evaluation 

The WOG sent out surveys to all WOG licensees requesting the results of all secondary side inspections 

and relevant tube inspections for TSP conditions. Most, but not all, licensees responded. These data 

were summarized in WCAP-15031. Based on the responses to this survey, erosion-corrosion of moisture 

separators and the feed ring/J-tubes and cracking of transition cone girth welds were observed in some 

SGs. Cracking of TSP ligaments associated with models 51 and 51M (with carbon steel TSPs) was also 

observed in some SGs. The TSP flow holes and ligaments are found to be susceptible to erosion

corrosion damage for models 51 and 5 1M SGs, while the TSP ligaments in models with stainless steel 

TSPs (5 IF, 54F, A47, or A75) do not experience corrosion in the tube-to-tube support plate intersections 

and, hence, have low susceptibility to cracking. Because of the design, the wrappers in all SGs in this 

group have low susceptibility to cracking near the wrapper supports and, hence, are unlikely to 

experience wrapper drop. 

Overall, WOG's conclusions on the 51-series SGs include the following: 

(1) SG designs secured by patch plates and plug welds are susceptible to inspection indications, 

(2) The TSPs are not susceptibility to TSP ligament cracking near the wedge supports, 

(3) The TSPs are not susceptibility to wrapper drop or cracking of the wrapper at the lower supports, 

(4) The potential for TSP flow hole erosion-corrosion does not exist in SGs with stainless steel TSPs 

and is very low in units with carbon steel TSPs, and

5-5
5 WESTINGHOUSE STEAM GENERATORS

(5) Missing pieces of carbon steel TSP ligament and ligament indications (cracks) are likely the 

result of out-of-tolerance drilling alignment during manufacturing. 

WCAP-15031 concludes that the causal factors identified by EdF do not jeopardize the continued 

operability of this group of SGs. Eddy current inspections of tubes would detect any detrimental effects 

on the tubing due to wear caused by TSP ligament degradation, loose parts, or changes in secondary flow 

distribution. They further state that foreign object search and retrievals (FOSARs) are routinely 

performed to uncover loose parts inside the SGs. 

5.1.1 Susceptibility of the W SGs Relative to EdF and SONGS Experience 

All plants in this group joined the effort by the Westinghouse Owners Group (WOG) to assess the 

susceptibility to tube damage or loss of decay heat removal (DHR) capability due to degradation of the 

secondary-side components. EPRI report, GC-109558, "Steam Generator Internals Degradation: Modes 

of Degradation Detected in EDF Units," (Ref. 6) was used to evaluate the causal factors involved in the 

modes of degradation experienced in the French units. The WOG used this report to assess the 

applicability of the French experience to their SG designs and operating history. They also considered 

other attributes: design factors, fabrication and manufacturing techniques, and operating history, 

including chemistry and related degradation, such as denting. In addition, the WOG compiled an 

industry-wide survey and assessed information on their eddy current examinations, visual, video and 

pertinent nondestructive examinations (NDE) made as part of the in-service inspection (ISI) experience. 

WOG performed the evaluation of the impact on this group of W SGs of the EdF causal factors using a 

process that included the following: extracting the events, chemistry implications, loading conditions, 

materials and geometric features that constitute the EdF causal factors; reviewing the results of the 

inspection survey; evaluating the modes of degradation; establishing the evaluation criteria; reviewing 

modes of operation and design features of the SGs, establishing which criteria are satisfied or not, and 

identifying recommendations for continuing to establish SG operability. 

The following assessments of the degradation mechanisms identified in the GL are based on the 

information in the WOG report (WCAP-1503 1). 

(1) Erosion of the top TSP due to improper placement of hoses during chemical cleaning: 

There has been no evidence of post-chemical cleaning inspections discovering any significant 

material losses in TSPs. 

(2) Ligament cracking of carbon steel with drilled hole TSPs due to mechanical loads during 

manufacturing, shipping, or early operations: 

According to WOG, the only models susceptible to this deterioration are 51 and 5 1M because of 

the unique design of their wrapper, tube support plate, and associated attachments that could 

generate additional tensile loads and may cause TSP ligament cracking. Also, W indicated that 

TSP ligament cracking or missing pieces of ligaments were observed, but only in units with CS

5-6
5 WESTINGHOUSE STEAM GENERATORS

TSPs (both 51 and 51M models) with drilled round holes and flow holes. Sequential inspections 

showed that the damage generally is traceable back to the initial inspections and is not 

progressing. Many are related to drilling misalignment during manufacturing. There are cases 

of indications in TSPs that have been linked to patch plate plug welds. WOG stated that for W 

models 51 and 5 IM which have patch plates, indications of cracking near the patch plate plug 

welds is possible. The WOG also stated that if sections of the TSPs were missing, this would be 

readily detectable by eddy current testing (ECT) performed at each refueling outage (RFO). 

Therefore, ligament cracking identified at various plants with W models 51 and 51M SGs is 

postulated to be associated with either the patch plate rejoining process or possible misdrilling of 

flow holes. Recent inspections at all such plants found no change in ligament degradation. 

The wrapper and tube support plate design in the other four W SG models, 51F, 54F, A47, and 

A75 ensure efficient load transferring without causing tensile overload. Therefore, these SG 

models are not susceptible to ligament cracking at, or near, the wedges and the plug welds. 

(3) FAC-induced thinning of the top TSP periphery due to ammonia water chemistry: 

The water chemistry at French plants, with low hydrazine concentration and with ammonia at 

low pH, are the primary causes for early TSP degradation. U.S. plants have been using EPRI 

guidelines since 1982 where the secondary water is maintained near neutral which is less 

harmful to carbon steel TSPs. Also, FAC has not been observed in 51 series SGs with CS TSPs 

in W steam generators in service at U.S. nuclear power plants. 

(4) Wrapper-drop due tofatiguefailure of supports: 

Because of the design of the wrapper supports (e.g., inclined wedges and through-wall welds) 

that resist wrapper drop, W models are not susceptible to this failure mechanism. Moreover, no 

obstructions of FOSAR equipment with the wrapper were identified during routine inspections; 

thus, there has been no evidence of wrapper drop in any plant. 

(5) Fatigue cracks from support blocks due to flow-induced vibration of wrapper: 

The tendency for W designed wrappers to vibrate due to flow-induced vibration is stated to be 

much less than that in the EdF units. 

(6) TSP wedge block cracking: 

Configurations of the wedge block welding joints promote full penetration welds at the lower 

support. Routine ASME Section XI ISI of shell welds indicated no degradation at any plant, 

except in a feed ring type replacement SG with stainless steel TSPs whose original upper shell 

was not replaced. As stated above, because of the design of the wrapper supports (e.g., inclined 

wedges and through-wall welds) that resist wrapper drop, W models are not susceptible to this 

failure mechanism.

5-7
5 WESTINGHOUSE STEAM GENERATORS

(7) Eggcrate support degradation at SONGS due to FAC associated with fouling: 

No specific discussion was included in the WOG report about the TSP degradation experienced 

at CE designed SGs at SONGS. However, FAC associated with fouling has not been reported in 

any W SGs. 

In summary, some of these SGs, specifically models 51 and 51M, are vulnerable to TSP flow 

hole/ligament erosion-corrosion, TSP ligament indications near the patch plates, and TSP ligament 

cracking in random areas. These types of degradation that occurred early in the operating life of the SGs, 

are not progressing. ECT examination at each RFO will monitor them. Therefore, these assessments 

provide reasonable assurance that the integrity of the steam generator tubes and DHR capability are not 

compromised by degradation of SG internals. 

5.1.2 Responses to NRC's Generic Letter 97-06 

Most responses by the licensees for this group of plants provided the information requested by the GL. 

The EdF causal factors were addressed by the WOG's evaluation discussed above. No plant discussed 

the SONGS experience relating to FAC at the periphery of TSPs. However, WOG evaluated this causal 

factor and stated that the plant data indications at the first three TSPs are not progressive and continuing. 

ECT examinations at each RFO will continue monitoring them. Most plants in this group perform 

FOSAR and sludge lancing every RFO, very few have chemically cleaned their SGs, even after over 20 

years of service life. However, most have been monitoring several TSP indications using eddy current 

examinations at each RFO as part of the inspection for tube support cracking. 

All plants employ visual and/or remote camera examinations of the upper package of the SG internals 

which includes the steam drum, moisture separators, feed ring with associated components (e.g., J-tubes, 

CS feed ring adjacent to the J-tubes, T-section, reducers, backing rings, and the thermal sleeve). The 

transition cone girth weld and other FW nozzle welds are regularly inspected in accordance with the 

ASME Section XI requirements. The degradation mechanisms associated with wrapper drop and 

wrapper cracking are examined only if there is any interference to the sludge lancing equipment when 

inserting it to clear the SG internals. No inspection is scheduled unless there is evidence of the 

wrapper's misposition or tube damage in the periphery of the first TSP. If detected, the lower wrapper 

support blocks are visually examined. 

Based on the WOG's survey of these plants, there is no evidence of post-chemical cleaning inspections 

discovering any significant material losses, nor evidence of any wrapper drop. The TSP ligament 

cracking or missing pieces of ligaments were observed only in units with carbon steel TSPs which have 

drilled round holes and flow holes. However, these conditions generally are traceable to initial 

inspections or are not progressing based on sequential inspections. Many of these conditions are 

believed to be related to drilling misalignment during manufacturing. Many cases of indications detected 

by the eddy current examinations are linked to patch plate plug welds. 

All plants in this group have undertaken visual/video inspections of their tube bundles and other SG 

internals and found no existing significant degradation in any component. Some plants have replaced

5-8
5 WESTINGHOUSE STEAM GENERATORS

their carbon steel J-tubes with replacement parts that are more resistant to erosion-corrosion damage. 

Although it was not clearly mentioned, all plants appear to perform FOSAR and sludge lancing 

operations on each SG unit during every RFO as part of their maintenance work. Some found loose 

objects which were either removed from the SG (if possible) or left inside in such a manner as to 

mitigate their potential effect on other internal components. 

Eddy Current Testing (ECT) is used to examine the TSPs. Seven of the W plants have stainless steel 

TSPs with either trefoil and quatrefoil broached hole designs. ECT cannot detect indications of ligament 

cracking with these designs, but can ascertain the correct position of TSPs. The other 13 plants in the 

group have carbon steel TSPs with dirlled holes and have indicated they use ECT to monitor their 

existing indications, and that none have progressed. At the time of this study the licensees for Beaver 

Valley 2 and Kewaunee had not completed reviewing their past ECT data, and planed to complete ECT 

and reviews during the next RFO. Table 5.3 summarizes the inspection findings from all plants in this 

group based on the information in their submittals. 

Table 5.3 Plant-specific Inspections For W SGs Model 51, 51M, 51F, 54F, A47, and A75 

Steafm Generator Operating Expe ience 4 

Eddy Current1Examination[ VisualN/Vid~eo.IIMpection -1 -Remarks iiMethods Fid ._ Mthpds Findings ___________ 

Beaver Performed for 21 indications Visual and No significant FOSAR/Sludge lancing each RFO 

Valley 1 TSP video degradation 

degradation inspections noted 

Beaver Not stated -- Visual and No significant FOSAR/Sludge lancing each RFO. 

Valley 2 video degradation Plan to screen ECT data during 

inspections noted next RFO in 9/98 

Cook 1 Performed for 1 indication Visual No degradation Replaced all SGs with B&W RSGs 

TSP inspection noted in 2000. GL responses correspond 

degradation to the W model 51 SGs. 

Cook 2 Performed for No abnormal Visual No degradation No plan for next RFO inspections. 

TSP locations condition inspection noted However, subsequent ones will 

noted include SG internals 

Diablo Performed for 244 Visual No degradation Has a formal program for SG 

Canyon 1 TSP indications inspection noted internals 

degradation 

Diablo Performed for 126 Visual No degradation Has a formal program for SG 

Canyon 2 TSP indications inspection noted internals 

degradation 

Farley 1 Performed for 39 indications Visual and No degradation Has a program for SG internals 

TSP remote noted 

degradation camera

5-9
5 WESTINGHOUSE STEAM GENERATORS

Steam Generato erating Experience 

Name lame Eddy "-•.., Current Examination 1 Visual'Video Inspection Remarks 

Methods -. Findings-. Methods [ Findings 

Farley 2 Performed for 29 indications Visual and No degradation Has a program for SG internals 

TSP remote noted 

degradation camera 

Kewaunee Performed for 94 indications Visual and No degradation Has a program for SG internals. 

TSP remote noted Plan to review ECT data during 

degradation camera next RFO on 10/17/98 

North Performed to No Visual and No degradation Has a program for SG internals 

Anna 1 detect missing degradation video noted 

TSP or parts noted inspections 

North Performed to No Visual and Replaced two Has a program for SG internals 

Anna 2 detect missing degradation video feed rings 

TSP or parts noted inspections 

Point Not stated Visual No degradation Will develop an inspection Beach 2 inspections noted program for SG internals 

Prairie Performed for 6 indications Visual and No degradation Has a formal inspection program Island I TSP video noted for SG internals 

conditions inspections 

Prairie Performed No Visual and Damage noted to Has a formal inspection program Island 2 TSP degradation video wrapper support for SG internals 

conditions noted inspections block ligament 

Salem 2 Performed for 12 indications Visual and Loose parts Has a formal inspection program TSP video retrieved for SG internals 

conditions inspections 

Sequoyah Performed for Indications Visual and No degradation Has a formal inspection program I TSP tracked since video noted for SG internals 

conditions 1990 inspections 

Sequoyah Performed for Indications Visual and No degradation Has a formal inspection program 2 TSP tracked since video noted for SG internals 

conditions 1990 inspections 

Summer 1 Performed for No Visual and No degradation Replaced SGs in 1994 with Delta 

TSP locations degradation video noted 75 models. Plans secondary side 

noted inspections inspection during next RFO 

Surry I Performed for No Visual and No degradation Has a formal inspection program TSP locations degradation video noted for SG internals 

noted inspections 

Surry 2 Performed for No Visual and No degradation Has a formal inspection program

5-10
5 WESTINGHOUSE STEAM GENERATORS

Steam GenerrO at ig-xp eience 

Plant. f 

N Eddy Msame Current Examinaion Visual"-Video Inspection Remarks am e.. . ......... Methods Findings, i ,.Meftids.. I Findings A 

TSP locations degradation video noted for SG internals 

noted inspections 

5.1.3 Summary and Conclusions 

All plants in this group have programs to inspect for degradation of SG tubes and SG internal 

components. Many have adopted the WOG's recommendations for inspecting SG internals to address 

the relevant EdF causal factors, or are planning to adopt them as appropriate to their SGs. 

Based on the licensee's submittals, the 12 plants (excluding Cook 1) with Model 51 and 51M SGs which 

have carbon steel drilled holes and flow holes have TSP ligament indications or missing pieces of 

ligaments. These ligament indications were observed near the patch plates and randomly elsewhere. 

None of this ligament degradation has progressed since its discovery. The other 7 plants with stainless 

steel broached trefoil or quatrefoil TSPs have not found any evidence of degradation. All reported no 

significant degradation in any of their SG internal components, except a few who earlier replaced their 

degraded carbon steel J-nozzles with newer nozzles made of more corrosion-erosion resistant materials. 

Although all have not so confirmed, each plant appears to perform FOSAR and sludge lancing operations 

during each RFO. In addition, plants with carbon steel TSPs perform eddy current testing routinely each 

RFO to detect any new TSP degradation or to monitor the existing indications. Plants with stainless steel 

broached hole TSPs carry out eddy current testing for the presence of a TSP at all intersections. 

In summary, all W plants have inspected their SG internals since their commercial start, and have taken 

mitigating actions for identified degradation in SG internal components. Licensees, therefore, concluded 

that no additional inspections of the internals are required at this time, and that they have maintained 

compliance with the licensing bases. 

From the results presented in the licensees' submittals, there are no near-term problems nor are there 

needs for any immediate change in the current SG internals inspections. Licensees plan to implement 

their owners group recommendations to address the long-term effects of the potential degradation 

mechanisms associated with the SG internals. Overall, the licensees' submittals have met the intent of 

the GL and provide reasonable assurance that the SG internals comply with, and conform to, the 

licensing basis. 

5.2 Plants with W-Designed Steam Generators, Models 44F, F, D3, D4, D5, 

and E2 

The second group of W-designed steam generators includes SG models F, 44F, D3, D4, D5, and E2. 

Unlike the first group (51-series W models) which contain only the feed ring type, this group contains

5-11
5 WESTINGHOUSE STEAM GENERATORS

both feed ring and preheat design SGs. Table 5.4 lists which models have stainless steel and which have 

carbon steel TSPs, and which are feed ring and which are preheat type models-At the time of this study 

twenty-one plants were using one of these W-models in their primary system loops. Braidwood 1 

replaced all four SGs with Babcock & Wilcox Replacement RSGs. Indian Point 2 also recently replaced 

its four model 44 SGs with model 44F SGs. These two plants were not assessed by the WOG as part of 

this group. 

Twelve of the 2 lplants in Table 5.1 have feed ring design SGs, with a total of 43 total individual SGs. 

The remaining 9 plants have preheat type SGs, with 35 individual SGs in service (Table 5.4). Seven 

plants (Callaway, Millstone 3, Salem 1, Seabrook 1, Vogtle 1 & 2, and Wolf Creek) have had model F 

units since their commercial start dates during 1977 - 1989. The original Salem 1 Model F mill-annealed 

600 tube SGs were replaced in 1997 with Model F thermally treated 600 tube SGs removed from the 

cancelled Seabrook 2 plant. Another 12 plants (5 plants with replacement model 44F units, and 7 with 

original model F units) have quatrefoil broached hole type stainless steel TSPs. 

Table 5.4 Distribution of SG Models 44F, F, D3, D4, D5, E2 

SG Design Type Model # # of NPP Units :#ofSGs 

Model 44F 5* 15 

Feed Ring Models with SS TSPs: 

Model F 7 28 

Model D3 1 4 

Preheat Models with CS TSPs: Model D4 2 7 

Model E2-TGX 1 4 

Model D5 4 16 

Preheat Models with SS TSPs: 

Model E2-THIX 1 4 

TOTAL 7 Models 21 78 

* Excluding Indian Point 2, whose four model 44 SGs were replaced with model 44F in December 2000. 

All nine plants with preheat design SGs have been operating since between 1986 to 1992. Watts Bar is 

the only plant which has model D3 SGs, and South Texas 1 & 2 are the only ones with model E2 SGs. 

At the time of this study Comanche Peak 1 and Shearon Harris had model D4 SGs (recently Braidwood 1 

replaced its Model D4 SGs with B&W replacement RSGs). These three models (D3, D4, E2-TGX) have 

drilled hole carbon steel TSPs. Four other plants (Byron 2, Braidwood 2, Comanche Peak 2, and 

Catawba 2) with model D5 SGs have quatrefoil broached hole stainless steel TSPs. South Texas 2, with 

model E2-THX SGs, has round hole stainless steel TSPs. Sorted another way, there were four plants 

with drilled hole carbon steel TSPs, and 17 plants with stainless steel quatrefoil broached TSPs. All 

carbon steel TSPs had drilled holes, and all stainless steel TSPs, except at South Texas 2, have quatrefoil 

broached holes.

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5 WESTINGHOUSE STEAM GENERATORS

WCAP-15093 (Proprietary) and WCAP-15104 (Non-proprietary) present the WOG's evaluation of the 

impact of the causal factors of EdF SG Internals degradation on the W modelsgin this group. In addition, 

these reports have a final assessment of these W models' susceptibility to deterioration of the secondary 

side internals and specific recommendations for future SG inspections to monitor internal components. 

Model F (Ref. 25) 

Seven plants have 28 Model F SGs. The feed ring type Model F steam generators with stainless steel 

TSPs started with the Callaway model F (Early Model) and ended with the Vogtle model F (Late Model) 

whose design included the following significant improvements: 

(1) The Early Model has a flow baffle plate with patch plates incorporating rim cutouts for anti

rotation bars to be installed, while the Late Model has neither patch plates nor rim cutouts. 

(2) The TSPs in the Early Model have patch plates and the Late Model does not. However, the 

Model F at Seabrook (and at Salem 1) has a single patch plate in the TSPs that is mechanically 

fastened; 

(3) Although the wrappers of both models have similar forms, functions, and materials, there are 

significant differences on how they are assembled and supported within the vessel shell. The 

Early Model has long channel supports used to attach the wrapper to the SG shell; but, the Late 

Models do not have channel supports; and 

(4) The wrapper cone assemblies are welded to the wrapper shell differently for these two models. 

Model 44F (Ref. 26) 

Model 44F is a feed ring type with stainless steel TSPs. Five plants have 15 Model 44F SGs. In 

addition, Indian Point 2 replaced its original model 44 SGs with model 44F units in December 2000. 

The first of the Model 44F designs was installed at Turkey Point 3 (1979) and the last at Indian Point 3 

(1988). The significant change between them is that the flow distribution baffle ('A' Plate) at Turkey 

Point has two halves, while that for Indian Point is one piece. The tube holes in the flow distribution 

baffle also differ. The Turkey Point SGs has patch plates at one end of the tube lane but the plates are 

mechanically fastened to the TSPs. Other differences in design of the internal parts include variations in 

quantities, locations, length, and other such dimensions. 

Model D (Ref. 27) 

Seven plants have 27 Model D SGs. The Model D SGs (preheat design) include Westinghouse model 

designations D3, D4, and D5. The D4 and D5 SGs are sometimes further divided into D4-2 and D4-3, 

and D5-2 and D5-3. These designations were used to identify the variations in the design/manufacturing 

changes within the D-series and have no impact on this review. Both D3 and D4 models have carbon 

steel TSPs with round tube holes and utilize long channel supports. D5 models have stainless steel TSPs 

with broached tube holes and no channel support. Also, both D3 and D4 models have patch plates

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5 WESTINGHOUSE STEAM GENERATORS

attached to TSPs with plug welds; D5 models do not have patch plates. Model D3 wedges are fillet 

welded to both the TSPs and wrapper on the top side of plates; Model D4 and D5 wedges are fillet 

welded to the wrapper alone on plate's top side. 

Model E2 (Ref. 28) 

The Model E2 SGs (preheat design) are used only at South Texas Unit 1 (model E2-TGX) and Unit 2 

(model E2-THX). The former SGs have carbon steel TSPs and baffle plates, while the latter SGs have 

stainless steel TSPs and baffle plates. The TGX SGs have a flow baffle plate with patch plates, but the 

THX SGs have no patch plates. Both model wrappers are similar and use long channels, but the THX 

wrappers have many cutouts located over the segmented channel supports and the wrapper block 

openings. 

For SG models with preheat design, the main feedwater is directed downward as it enters the water box 

area and is turned by the B baffle plate to enter the preheater. As the flow radiates from the impingement 

plate, the carbon steel support ribs are directly in the path of the flow. Four vertical support ribs are used 

in line with the SG vertical axis. The side ribs are perforated with two rows of 2.54 cm (1-inch) round 

holes on a 3.81 cm (1.5-inch) pitch while the top and bottom ribs have three rows of holes. The top and 

bottom ribs are taller than the side ribs since the distance from the impingement plate to the wrapper is 

the largest at the nozzle centerline. A perforated cap plate lies at the top of the impingement plate, 

perpendicular to the vertical support ribs, and closes the water box at the top. 

SG Internals Degradation Experience and Evaluation 

For the SG models in this group, 18 plants responded to the W survey; 17 of them have inspected or 

reviewed inspection data for TSP ligament crack indications for all 52 of their SGs. Sixteen plants have 

performed SG secondary side entries confirming no wrapper drop in 47 SGs. There is no report of any 

ligament damage nor indications in either the carbon steel (CS) or the stainless steel (SS) TSPs. The SGs 

with longer periods of operation have had more inspections and more opportunities for observation of 

indications. The surveys did not detect any of the several modes of degradation experienced in the EdF 

plants: no significant material losses after chemical cleaning, no wrapper drop, nor ligament cracking or 

thinning that is progressive and continuing either directly observed or implied by tube indications. 

At Shearon Harris, tube wear was detected on several tubes in row 49 just above the B plate, on the cold 

leg side of one Model D4 SG. The foreign objects responsible for it originated from the 

erosion/corrosion on the vertical support ribs in the water box area where two cylindrical pieces were 

retrieved. No erosion/corrosion of the wrapper, impingement plate, target plate or impingement plate to 

target plate weld was seen. Westinghouse concluded that any rib pieces that separated from the water 

box would be small, and that the erosion/corrosion pattern occurring in the ribs will gradually enlarge the 

original 1" holes, so the affected flow holes would eventually coalesce. 

In the feed ring SG design, thinning of carbon steel J-nozzles prompted some plants to replace them with 

alloy 600 J-nozzles which are more resistant to erosion-corrosion. In the preheat SG design, erosion

corrosion was observed on some vertical support ribs welded to the outside of the SG impingement plate

5-14
5 WESTINGHOUSE STEAM GENERATORS

in the waterbox area. In South Texas Unit 1 about 30 cm (12 inches) of the side ribs were eroded away, 

resulting in loss of the perforated structure with coalescence of the flow holes.-The bottom row of the 

perforated holes was preferentially attacked toward the B plate as opposed to toward the cap plate. The 

circular shapes of the original 2.54 cm (one inch) holes, in the support ribs, were enlarged resulting in 

coalescence of the holes in the eroded missing length. The licensee finally stabilized the affected SGs by 

plugging several tubes. Eddy current testing (ECT) of peripheral and T-slot tubes within the preheater is 

being performed at each refueling outage (RFO). 

At Watts Bar, one end of the blow-down pipe was severed in two Model D3 SGs. Further analysis 

indicated that overstress in the fillet weld where failure occurred was caused during the manufacture and 

hydro-testing of the SGs. Evaluation of the clearances and flow conditions showed that consequential 

damage to adjacent tubes is not expected since the flow velocities in this region are low and the 

clearances are large. We note the unique design of the blow-down pipe for the Model D3 SG; other 

preheat SG designs do not utilize a continuous blow-down pipe extending the length of the tube lane. 

Several plants found small loose objects during FOSARs and removed them when possible. Many 

licensees used eddy current inspections to find loose objects. When loose objects can not be removed, 

their potential effects on the tube's integrity during subsequent operation are evaluated. If it can be 

reasonably determined that tube damage will not exceed the allowable limits of the technical 

specifications, the object may be left in place, and the condition of adjacent tubes checked at subsequent 

inspections. 

Based on the survey results, erosion-corrosion in moisture separators and feed ring/J-tubes of model F 

and 44F and in the waterbox of models D3, D4, and E2-TGX were observed in some SGs. Also, 

cracking in transition cone girth weld of model F and 44F was observed in some SGs. The TSP 

ligaments and wrapper near supports of models F and 44F has low susceptibility to cracking. For models 

D3, D4, and E2-TGX, the moisture separators and the TSO flow holes/ligament are susceptible to 

erosion-corrosion, while the TSP ligaments are susceptible to cracking. The wrapper near supports and 

transition cone girth weld have low susceptibility to cracking. For models D5 and E2-THX, the moisture 

separators and the waterbox are susceptible to erosion-corrosion, while the TSP ligaments, the wrapper 

near supports, and the transition cone girth weld have low susceptibility to cracking. 

The following are the types of SG internals degradation that may have safety concerns: loss of support 

in the tube bundle that potentially could lead to SG tube wear and possibly to primary-to-secondary 

leakage; TSP deformation during a postulated loss-of-coolant accident plus safe- shutdown earthquake 

(LOCA+SSE) event, resulting in a reduction inflow area and potential secondary-to-primary in-leakage; 

and, the generation of loose parts in the secondary side of the steam generator which may cause tube 

wear and possibly, primary-to-secondary leakage. Based on the design and operating experience, 

Westinghouse stated that various indications of TSP degradation may be artifacts of manufacturing 

anomalies related to patch plate plug welds and drilling alignment. Also, various W design features in 

SG internals are beneficial compared to the designs of some foreign manufacturers' SGs. 

TSP ligament cracking, erosion-corrosion of the flow holes, and flow-assisted corrosion are the 

mechanisms of degradation identified in the EdF plants that may cause the loss of TSP integrity. The

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5 WESTINGHOUSE STEAM GENERATORS

potential for tube vibration and wear from mechanical or flow-induced excitation was considered in the 

original design of W SGs. Lack of the presence of the TSP can be readily detettable through evidence of 

degradation in the tubes using eddy current techniques (ECT). For the two feed ring models F and 44F, 

W recommends a sample inspection of the top TSP and tube lane region (where there are flow holes 

instead of elongated- slots). 

W recommends that to preclude secondary-to-primary leakage during a postulated LOCA+SSE event, 

cracked tubes at the TSP intersections in the affected region of the tube bundle should be removed from 

service by plugging (or repaired with sleeves, if possible). Several plants have completed a plant

specific analysis to determine a more exact impact of LOCA+SSE loading on the collapse of tubes and 

the potential for secondary-to-primary in-leakage. 

Loose parts or foreign objects have caused two of the SG tube rupture (SGTR) events in the United 

States. However, the majority of objects found have not seriously threatened tube integrity. NRC agrees 

with industry guidance that loose parts detected at any time should be removed from the SGs, if possible. 

For those that cannot be removed, evaluations should address the maintenance of SG tube integrity 

during subsequent plant operation. Westinghouse recommends planning a FOSAR of the top of the tube 

sheet region of the secondary side of the SG at a minimum. Tubes with visible damage should undergo 

eddy current tests and plugged if found defective. 

Based on the W evaluation, all models of SGs in this group, are susceptible to the following types of 

damage that may cause loss of TSP's integrity: 

(1) erosion-corrosion of the moisture separators and other steam drum components in all SG models, 

(2) the potential to TSP flow hole erosion-corrosion applicable to SG Models D3, D4, and E2-TGX 

with CS TSPs and round flow holes, 

(3) erosion-corrosion of water box internal components in the preheat design models (D3, D4, D5, 

E2-TGX, and E2-THX) and of feed ring and J-tubes in the feed ring design models (F and 44F), 

(4) susceptibility to TSP ligament cracking near the wedge supports in Model D3 SGs, 

(5) TSP ligament cracking near the patch plates in Models D3, D4, Early F, and E2-TGX SGs that 

have patch plates and plug welds securing them on the TSPs, and 

(6) susceptible to cracking in the transition cone girth weld in Model 44F. 

These items can be addressed by following the suggested W inspection guidelines discussed in 

Section 2.2.3.5. 

No W SG models show susceptibility to wrapper drop or cracking at the lower support. W stated that 

there was no reported detection of missing pieces of TSP ligaments, nor instances of ligament indications 

for all the models in this group.

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5 WESTINGHOUSE STEAM GENERATORS

Westinghouse recommends inspecting Model D3 SG tubes every outage with a bobbin probe, and eddy 

current examination to detect any missing TSP. 

Tube wear and primary-to-secondary leakage may occur due to loose object in the secondary side of the 

SG after erosion-corrosion of the moisture separators, of other steam drum components, of TSP flow 

holes, or after cracking of the TSP ligaments. If such leakage should occur due to tube wear from a loose 

object, W stated that the expected consequences would be bounded by a single tube rupture event and, 

therefore, would remain within the plant's licensing bases. 

5.2.1 Susceptibility of the W SGs Relative to EdF and SONGS Experience 

All plants in this group joined Westinghouse Owners Group's (WOG) effort to assess the susceptibility 

of tube damage or loss of DHR capability due to degradation of secondary-side components. EPRI's 

report, GC-109558, "Steam Generator Internals Degradation: Modes of Degradation Detected in EDF 

Units, "was used to evaluate the causal factors involved in the modes of degradation experienced in the 

French units. This report gave the WOG insights into the applicability of the EdF experience to their 

steam generator designs and operating history. Other attributes considered were design factors, 

fabrication and manufacturing techniques, and operating history, including chemistry and related 

degradation, such as denting. In addition, the WOG assessed industry-wide information on eddy current 

examinations, visual, video, and pertinent nondestructive examinations (NDE) made as part of the 

inservice inspection (ISI) experience to farther enhance their evaluations. 

This section presents the WOG's evaluation of the potential for the W Models F, 44F, D, and E2 SGs to 

undergo modes of degradation similar to those experienced in the EdF and SONGS plants. 

(1) Erosion of the top TSP due to improper placement of hoses during chemical cleaning: 

There is no evidence from post-chemical cleaning inspections of any significant material losses 

in the TSPs of the W SGs. 

(2) Ligament cracking of carbon steel with drilled hole TSPs due to mechanical loads during 

manufacturing, shipping, or early operations: 

The first type of ligament cracking was located at the top TSP (and, in one case, at the next to top 

TSP) near the long channel seismic support in EdF Model 5 IM SGs. It was later determined that 

the flow holes near the periphery might have weakened the TSPs in this model. The "one part" 

units, when subjected to stress relief of the vessel shell closure weld might have applied large 

mechanical overloads by the presence of the long channel support. Other possible causes of 

mechanical overloads include mechanical loads applied during fabrication, shipping, or 

installation due to an inadequate number of anti-rotation keys, and thermal expansion induced 

deformation of the full height channel relative to other parts during plant transients early in life. 

The second type of TSP degradation includes indications in the vicinity of the patch plate plug 

welds. These include debonding between the weld material and the patch plate or TSP, and

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5 WESTINGHOUSE STEAM GENERATORS

ligament failures at adjacent locations. In EdF 5 1A SGs, these ligament cracks were randomly 

distributed but in EdF 51M SGs, they were concentrated near the wedge region (primarily at the 

long channel support). The causes of damage are believed to be related to a faulty welding 

process and similar to the ligament cracking. 

Westinghouse stated that no TSP ligament cracking in this series of W SGs is reported as 

progressive and continuing, either directly observed or implied by tube indications. From 

technical evaluation of the plate load carrying capability, Models D3, D4, and E2-TGX SGs have 

TSPs with lower normalized strength than the EdF 51M model, and Models D3, D4, both E2 and 

44F have TSPs with lower normalized strength than the EdF 51A. Model D3 SGs at Watts Bar 

have similar design features as the EdF models (i.e., the wedges are welded to both the wrapper 

and the TSPs) and could be susceptible to TSP cracking away from patch plates, as in the EdF 

51M SG. Other W models (F, 44F, D4, D5, E2) have wedges welded to the wrapper alone and 

therefore, do not appear to be susceptible to cracking near the wedge groups. 

Models Early F, D3, D4, and E2-TGX have patch plates and plug welds and indications near 

patch plate plug welds. The first Model 44F SGs at Turkey Point 3 have patch plates at one end 

of the tube lane, but the plates are mechanically fastened to the TSPs. Also, the Model F SGs at 

Seabrook have a single patch plate in the TSPs that is mechanically fastened. The SGs in Late 

Model F, Model 44F from Turkey Point 4 forward, Model D5, and Model E2-THX do not utilize 

patch plates. 

(3) FA C-induced thinning of the top TSP periphery due to ammonia water chemistry: 

Carbon steel TSP material is known to be subject to FAC-induced degradation. It is considered 

to be associated with a local pH environment (i.e., low hydrazine concentration and operation 

with ammonia at low pH) that is detrimental to the carbon steel material in EdF plants. EdF SGs 

that abandoned ammonia chemistry before about 1985 have suffered no material losses. 

Westinghouse has no reports of TSP ligament thinning that is progressive and continuing, either 

directly observed or implied by ECT indications. With the use of EPRI guidelines since 1982, 

FAC in the Model 51 series with carbon steel TSPs has not been observed. Therefore, WOG 

stated that the models in this group also are not susceptible to this degradation. Moreover, plants 

have not reported FAC-induced thinning in their SGs. 

(4) Wrapper-drop due tofatiguefailure of supports: 

EdF Model 51B and 51BI SGs were the only SG models found to have dislocated wrappers in 

three SGs at two plants. The design of the TSP to wrapper joint of these SGs is unique; they do 

not have an inclined plane in the wedges between the TSPs and the wrapper. The wedges are not 

welded to both the TSPs and the wrapper, as they are in models EdF 5 1A and 5 1M. There are no 

backup bars to transfer vertical loads (weight) to the tie rods. Therefore, these EdF SG models 

experienced wrapper drop when the wrapper to shell supports lost their structural integrity.

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5 WESTINGHOUSE STEAM GENERATORS

Unlike the above EdF models, all W models in- this group have features that prevent any wrapper 

drop if the wrapper supports fail in the U.S. SGs. W noted that if there-was wrapper drop, it 

would be detected during attempts to-insert FOSAR equipment. No obstructions FOSAR or 

sludge lancing equipment by the wrapper have been identified during routine inspections at each 

RFO. Therefore, it was concluded that there is no evidence for wrapper drop in U.S. plants. 

(5) Fatigue cracks from support blocks due to flow-induced vibration of the wrapper: 

The failure of weld joints of the lower wrapper supports are presumed to be caused by thermal 

transients between the wrapper and the shell due to tight clearances between adjoining non

welded parts, to flow-induced vibration of the wrapper assembly, and to poor quality welds. 

Westinghouse stated that the welds in the lower support blocks in all W models in this group are 

of superior quality, and that they have little tendency to exhibit wrapper flow-induced vibration. 

Wrappers have only cracked in those EdF units where the wrappers have dropped. 

Unless there is an indication of a wrapper's misposition by interference with the sludge lancing 

equipment at the entry port, no licensee plans to inspect the wrapper support blocks. Thus, while 

there was no evidence of wrapper cracking or support block wear in any plant, none indicated 

that they specifically inspected for it. 

(6) TSP wedge block cracking: 

The wedges of EdF 51M SGs are welded to both the wrapper and to the TSP with fillet welds 

under the TSP. Similar to the TSP ligament cracking in item (2) above, tensile loads can be 

transmitted from the long channel, or other channel, through the wrapper and wedges to the TSP 

ligaments, and also be reacted to on the opposite periphery. There is a reported trend that where 

the wedge group welds are smaller, there is less tendency for TSP ligament cracking, and more 

tendency for the fillet weld to crack. The converse also is reported to be true. Since this 

cracking has no safety significance, determining a root cause was not considered important. 

Westinghouse has not addressed this particular degradation mechanism; however, only the 

Model D3 SGs (at Watts Bar) have these wedge block welds attached to both the TSPs and the 

wrapper. Therefore, only these SGs will be susceptible to cracking under tensile overloads. This 

is discussed further in the next section. 

(7) Eggcrate support degradation at SONGS due to FAC associated with fouling: 

None of the licensee's submittals nor Westinghouse have addressed this particular damage. 

However, FAC associated with fouling has not been reported in any of the W SGs. 

In summary, these assessments provide reasonable assurance that the integrity of the steam generator 

tubes and DHR capability are not compromised by degradation of SG internals.

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5 WESTINGHOUSE STEAM GENERATORS

5.2.2 Responses to NRC's Generic Letter 97-06 

Table 5.4 shows that the 21 NPP units in this group at the time of this study had 78 SGs spread among 

seven different models. The 15 Model 44F SGs with stainless steel (SS) TSPs are all replacement units 

installed in 5 plants during 1981-1989. The remaining 63 SGs in 16 plants were the original units 

consisting of W models 44, F, D3, D4, D5, and E2. Braidwood 1 replaced its four model D4 SGs with 

BWI design units in November 1998. Salem 1 replaced its SGs with four model F units from the 

canceled Seabrook 2 plant in July 1997. South Texas 1 replaced its four model E units in May 2000. J

nozzles made of more corrosion resistant materials were installed in Turkey Point 3 and 4 during 1989 

and 1990, respectively. 

Most licensee's responses addressed the information requested in the GL. The WOG discussed the 

applicability of the EdF failure modes to these SG models in WCAP-15093 and WCAP-15104. No plant 

has addressed the SONGS experience relating to FAC at the periphery of TSPs since W SGs do not have 

eggcrate TSPs. Most plants in this group appear to perform FOSAR and sludge lancing every RFO; very 

few have chemically cleaned their SGs. The WOG gave recommendations for inspections. All plants 

have performed some secondary side inspections, however, details on the type, scope, and frequency of 

future inspections were not generally provided. 

All plants employ some type of visual and/or remote camera inspection of the upper package of SG 

internals, which includes the steam drum, moisture separators, feed ring with associated components 

(e.g., J-tubes, CS feed ring adjacent to the J-tubes, T-section, reducers, backing rings, and the thermal 

sleeve), and the preheat waterbox area. The transition cone girth weld and other feedwater nozzle welds 

are regularly inspected following ASME Section XI requirements. The degradation mechanisms 

associated with wrapper drop and wrapper cracking are verified only if there is an interference of the 

sludge lance equipment. No inspection is performed unless there is evidence of the wrapper misposition 

or tube damage in the periphery of the first TSP. If detected, the lower wrapper support blocks are 

visually inspected. Plants have either implemented the inspection recommendations delineated in 

WCAP-15031, or are planning to do so, as appropriate to their SGs. 

Based on the WOG survey of these plants and plant-specific inspection findings, there is no evidence of 

post- chemical cleaning inspections discovering any significant material losses. In addition, no evidence 

of any wrapper drop has been noted. Indications of TSP ligament cracking or missing pieces of 

ligaments were observed only in units with carbon steel TSPs which have drilled round holes and flow 

holes. However, these conditions are generally traceable to initial inspections, or are not progressing 

based on sequential inspections. Many of these conditions are believed to be related to drilling 

misalignments during manufacturing. Many cases of indications detected by the eddy current 

examinations are linked to patch plate plug welds. 

All plants have made visual/video inspections of their tube bundles and other SG internals and found no 

significant degradation in any component. The licensee of one plant replaced its CS J-tubes with 

replacement parts more resistant to erosion-corrosion. Although it is not clearly stated, we believe that 

all plants perform FOSAR and sludge-lancing operations on each SG unit during every refueling outage 

(RFO) as part of their maintenance activities. Some have found loose objects that have been either

5-20
5 WESTINGHOUSE STEAM GENERATORS

removed from the SG, or left inside in such a manner as to mitigate their potential effect on tubes or 

other internal components. 

The six plants with carbon steel TSPs stated that they perform eddy current inspections to monitor 

previous indications and have identified none that were progressing. The SGs with stainless steel TSPs 

in the other 17 plants have quatrefoil broached hole design; eddy current detection of potential ligament 

cracking or indications is generally not applicable although ECT can ascertain the correct position of the 

TSPs. Thus, few plants with SS broached hole TSPs have performed any assessment of their past ECT 

data. Only South Texas 1 has completed a one-time inspection of 100% of the tubes to satisfy the WOG 

recommendation. Table 5.5 summarizes the inspection findings from all plants in this group based on 

the information in their submittals. 

Table 5.5 Plant-specific Inspections For W SGs, Models 44F, F, D3, D4, D5, and E2 

Steam Generator Operating Experience 

Plant iuli 

N Name *Eddy CurrentExamination Visual/Video Inspection Remarks am e . . .. . . , '. . . .. 

Methods 1 Fndings.g -. Methods Findings. 

Byron 2 Performed for No missed Visual and No significant FOSAR/Sludge-lancing each RFO. 

TSP location location video degradation Has a program for SG internals. 

inspections noted 

Braidwood Performed for No Visual and No significant FOSAR/Sludge-.ancing eachRFO. 

1 TSP degradation video degradation Has.a program for SG internals. 

degradation noted inspections noted 

Braidwood Performed for No Visual and No significant FOSAR/Sludge-lancing each RFO. 

2 TSP location abnormality video degradation Has a program for SG internals. 

and preheater noted inspections noted 

loose part 

Callaway Not stated Visual and No degradation FOSAR each RFO 

video noted 

inspection 

Catawba 2 Performed for No missed Visual No degradation FOSAR/Sludge-lancing each RFO. 

TSP locations location inspection noted 

Comanche Performed for No No wrapper Sludge-lancing 

Peak 1 TSP degradation misposition 

degradation noted 

Comanche Not stated Visual and No degradation Sludge-lancing performed during 

Peak 2 video noted 3'r RFO 

inspection

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5 WESTINGHOUSE STEAM GENERATORS

Steam Generator Operating-Experience Plant 

Name Eddy Current Examination Visual/Video Inspection Remarks 

Methods Findings, Methods] Findings 

Shearon Performed for No Visual Loose parts in FOSAR/Sludge-lancing each RFO. 

Harris TSP degradation inspection the preheater of 

degradation noted SG-A 

Indian Not stated Visual and No degradation Only two SGs inspected. The other 

Point 3 video noted two are scheduled for next RFO. 

inspections 

Millstone 3 Performed to No missing Visual and No degradation FOSAR/Sludge-lancing performed 

detect missing parts noted video noted 

TSP or parts inspections 

Point Not stated Visual and No degradation FOSAR/Sludge-lancing each RFO. 

Beach 1 video noted 

inspections 

Robinson 2 Not stated Visual No degradation Plan to inspect one SG each RFO 

inspections noted on a rotating bases. 

Salem I Not stated Visual and No degradation FOSAR performed during 

video noted replacement. 

inspections 

Seabrook 1 Not stated Visual and No degradation FOSAR each RFO. 

video noted 

inspections 

South Performed for No Visual and Erosion of flow Has a program for SG internals. 

Texas 1 TSP degradation video holes in the 

conditions noted inspections waterbox area 

South Not stated Visual and No degradation Has a program for SG internals. 

Texas 2 video noted 

inspections 

Turkey Performed for No missing Visual and No degradation FOSAR each RFO. 

Point 3 TSP locations location noted video noted 

inspections 

Turkey Performed for No missing Visual and No degradation FOSAR each RFO. 

Point 4 TSP locations location noted video noted 

inspections 

Vogtle 1 Not stated Visual and No degradation FOSAR each RFO. 

video noted 

inspections 

Vogtle 2 Not stated Visual and No degradation FOSAR each RFO.

5-22
5 WESTINGHOUSE STEAM GENERATORS

Steam Generhj0,igiEoperence 

Name dd Current Examinaitioii._ Yiný Vidw•-fInspection Remafks 

Plant EdMtlids Findnifi ý i ,Wt-(6ds Findings Remarks 

video noted 

inspections 

Watts Bar Performed for No Visual and Blowdown pipe Sludge-lancing performed. 

TSP degradation video severed 

degradation noted inspections 

Wolf Performed for No missing Visual No degradation FOSAR each RFO. 

Creek TSP locations parts noted inspections noted 

and loose parts , ___ I 

NOTE: Shaded plant (Braidwood 1) is not included in the WOG evaluation for this SG group for the reasons stated earlier. 

5.2.3 Summary and Conclusions 

As part of the WOG Steam Generator Internals Degradation Program, Westinghouse undertook a 

detailed evaluation of the potential for the W SG Models F, 44F, D series and E2 to experience modes of 

degradation similar to those in the EdF plants. W used other attributes, such as design details, 

fabrication and manufacturing techniques, and plant's operating history. In addition, the WOG compiled 

an industry-wide survey of SG operating experience and assessed the ECT, FOSAR, and other SG 

cleaning data from licensees. The overall conclusion was that WOG members with W SG models in this 

group can maintain operability through their normal ECTs and FOSARs and defined inspections. The 

causal factors identified by EdF do not affect the continued operation of these W models. Eddy current 

inspection of the tubes would detect detrimental effects on the tubing due to wear caused by TSP 

ligament degradation, loose parts, or changes in secondary flow distribution. The FOSAR inspections 

would discover loose parts that might cause wear in SG tubes. 

W stated that the industry survey did not report finding the several modes of degradation experienced in 

the EdF plants. There was no report of post-chemical cleaning inspections discovering any significant 

material loss. There was no report of TSP ligament cracking or thinning that is progressing and 

continuing, either directly observed or implied by tube indication. Finally, there was no report of any 

wrapper having dropped nor of cracking of the wrapper at the lower supports in W SGs. 

Tube wear and primary-to-secondary leakage due to the presenc'e of a loose object on the secondary side 

of the SG may occur due to erosion-corrosion of the moisture separators, other steam drum components, 

or TSP flow holes, or to TSP ligament cracking. If such leakage should occur due to tube wear from a 

loose object, W stated that the expected consequences would be bounded by a single tube rupture event 

and, therefore, would remain within the licensing bases of a plant. The NRC agrees with industry 

guidance that loose objects should be monitored using eddy current examinations and FOSAR 

inspections to ensure maintenance of tube's integrity during subsequent plant operation.

5-23
5 WESTINGHOUSE STEAM GENERATORS

Inspection guidelines recommended by Westinghouse for each SG Model are comprehensive, address 

these types of degradation, and licensees should consider implementing them. Model D3 SGs at Watts 

Bar are susceptible to wedge block cracking as well as TSP ligament cracking similar to that experienced 

in EdF plants. However, based on the EPRI's evaluation, such cracking does not appear to threaten tube 

integrity. Westinghouse has not recommended any inspection guidelines for these wedge blocks. As 

point of note is that neither the WOG's report nor the individual licensee responses have addressed the 

SONGS experience relating to the FAC associated with fouling. However, there is no indication of 

fouling in any of the W models reported by the licensees and, in contrast to eggcrate TSPs, the robust 

design of TSPs in these models enables them to withstand significant FAC before affecting the safety 

functions of the steam generators. 

All plants in this group have some program in place to inspect for degradation in SG tubes and other 

internal components. Based on the recent WOG effort, many have adopted their recommendations for 

inspecting SG internals to address the EdF causal factors, or are planning to adopt them as appropriate to 

their SGs. 

Based on the licensee submittals for the GL, the four plants with Models D3, D4, and E2 SGs, that had 

carbon steel drilled holes and flow holes, had no TSP ligament cracking nor missing pieces of ligaments. 

The other 17 plants in this group have stainless steel broached quatrefoil TSPs, and have not found any evidence of degradation. All have reported no significant degradation in any of their SG internal 

components, except a few who have replaced their carbon steel J-nozzles with newer ones made of more 

corrosion-erosion resistant materials. Plants with preheat design have found some loose parts caused by 

erosion-corrosion in the waterbox area. 

Although all have not confurmed it, we believe that each plant undertakes FOSARs and sludge-lancings 

during each RFO. In addition, plants with carbon steel TSPs perform eddy current testing routinely each 

RFO to detect any new TSP degradation or to monitor existing TSP indications. Most plants with 

stainless steel broached hole TSPs perform eddy current testing and visual inspections for TSP locations. 

As mentioned earlier, most plants have augmented their existing inspection programs with additional 

examinations as recommended by the WOG. It is concluded that plants perfo•ining the inspection 

activities discussed above each RFO should be able to avoidprboblems stemming from degraded SG 

internals. 

From the results presented in the licensees' submittals, there are no near-term problems nor are there 

needs for any immediate change in the current SG internals inspections. Licensees have implemented or 

plan to implement, as appropriate to their SGs, their owners group recommendations to address the long

term effects of the potential degradation mechanisms associated with the SG internals. Overall, the 

licensees' submittals have met the intent of the GL and provide reasonable assurance that the SG 

internals comply with, and conform to, the licensing basis. 

5.3 Indian Point 2 with W-Designed Steam Generators 

At the time of the GL 97-06 issuance, Indian Point 2 (IP2) had feed ring model 44 SGs which were in 

service since the commercial start of lP2 in 1974. They were manufactured with mill-annealed alloy 600

5-24
5 WESTINGHOUSE STEAM GENERATORS

tubing, carbon steel tube support plates with drilled holes, and partial depth rolled joints in the tubesheet. 

Early in the operating life of the IP2 SGs during the mid-seventies, general corrosion of the carbon steel 

TSPs and tubesheets resulted in a buildup of corrosion products in the annulus between the tubes and the 

TSP, and/or between the tubes and the tubesheet. This buildup squeezed the tubes enough to cause their 

permanent, plastic deformation at the TSP and tubesheet areas. As a result, all four SGs at IP2 

experienced significant deformation of the tubes, commonly referred to as "denting." By enhancing the 

quality of the secondary water and implementing other mitigating actions, the licensee managed to bring 

tube denting largely under control. However, this denting led to extensive in-plane deformation in the 

TSPs and cracking of the TSP ligaments. One manifestation of TSP deformation was the distortion of 

the initially rectangular flow slots located along the open lanes separating the hot- and cold-leg of the 

tube bundle. The deformation in the TSP transformed the shape of the rectangular flow slots into 

hourglass shaped ones, typically referred to as "hourglassing." Much of this deformation process at IP2 

probably occurred before 1984 and was readily visible during each subsequent inspection outage. 

To ensure that the NRC's staff would be alerted to any significant change in the status of denting or 

hourglassing of the uppermost TSPs, several requirements were added to IP2's technical specifications. 

Through several inspection efforts and subsequent staff interactions with the licensee that occurred in the 

late 1970s and early 1980s, some of these added requirements specified that the licensee must (1) 

provide an evaluation to address the long-term integrity of small radius U-bends beyond row 1 within 60 

days of any significant hour-glassing of the upper support plate flow slots, (2) report a significant 

increase in the rate of denting, and (3) plug tubes that do not permit passage of a 1.55 cm (0.610 inch) 

diameter probe. Throughout the 1980s and 1990s, the licensee performed its SG inspections in 

accordance with the above long-standing criteria; section 5.3.1 discusses the results of these inspections 

submitted by the licensee in response to GL 97-06. 

The licensee had been visually inspecting SGs 22 and 23. SGs 21 and 24 did not have access ports 

permitting visual inspection of the uppermost TSP flow slots. Based on the inspection of SGs 22 and 23, 

the licensee reported no significant "hourglassing" of the flow slots in the uppermost TSPs. In addition, 

the licensee inspected the lower TSP flow slots of all four SGs using a video camera through the hand 

holes above the tubesheet and reported no change in the amount of hourglassing present at the lower 

TSPs. However, one flow slot at the second TSP showed closure which the licensee evaluated and 

determined to be acceptable. 

W stated that the EdF experience was not related to TSP degradation at Indian Point 2 that progressed to 

the tube-denting stage in these four model 44 SGs, and so the effects of tube denting have not been 

addressed by either of the two WOG evaluation reports. Another five plants (Indian Point 3, Point Beach 

1, Robinson 2, Turkey Point 3 & 4) used to have the older feed ring SGs from their commercial start date 

in the 1970s. They either replaced them entirely (Indian Point 3), or replaced the tube bundle part of the 

model 44F SGs during the eighties.

5-25
5 WESTINGHOUSE STEAM GENERATORS

5.3.1 Evaluation of Licensee's Responses to GL 97-06 

Susceptibility of the W Model 44 SGs Relative to EdF and SONGS Experience 

Based on the plant submittal, the types of deterioration of secondary side internals found in 

Westinghouse 51 series steam generators with drilled carbon steel support plates are similar to model 44 

SGs at Indian Point 2 because both models have similar design features. Therefore, the susceptibility 

evaluation for secondary side internal degradation in W models given in Section 5.1 is applicable to the 

Model 44 SG design, as well. 

The WOG made a safety assessment of 5 1-series and 44-series SG designs. They recommended all 

utilities with these SGs with carbon steel support plates inspect a significant percentage of SG tubes 

every outage. WOG concluded that eddy current inspection, FOSARs during each RFO, and loose parts 

monitors should ensure that tube integrity is maintained during subsequent plant operation. 

Results of the Examinations Performed during the 1997 RFO for IP2 

Upper Support Plates: Steam generators 22 and 23 were visually inspected using a videoscope through 

the hillside port in the SG shell. There was no significant hour-glassing of the flow slots in the upper 

most TSP. The wedge locations were intact. The tube surfaces, flow holes, and the TSPs appeared to be 

normal. 

Flow Slot and Lower Support Plate: All four SGs were video taped through the lower handholes. 

Compared with previous results, the "hour-glassing" of the flow slots in the lower TSPs had not changed. 

However, the photographs revealed cracks in the TSP at some flow slots. The upper TSPs had new small 

cracks, while there was no significant change in the general flow slot cracking previously observed. 

Wrapper: Baseline measurements of the height of the wrapper above the tubesheet were consistent for 

all four SGs. 

Secondary Side Examination: A Foreign Object Search and Retrieval (FOSAR) was conducted around 

the annulus and within the tube bundle in all SGs. Several items were subsequently removed which 

previously could not be removed. Wear rates on adjacent tubes were evaluated for the remaining objects. 

The growth of eddy current indications from the previous outage were evaluated to assess the 

contribution of loose objects to tube wear. Finally, it was found that SGs could be safely returned to 

service with the remaining loose objects without changing the Technical Specification. 

Inservice Inspection Plan 

The licensee stated that the WOG's inspection plan (Table 2.4) was implemented at Indian Point 2. 

Inspections were conducted every RFO in accordance to EPRI's SG Examination Guidelines (Rev.5). 

The scope and frequency may be adjusted based on site specific experience and evaluation of industry 

results of these inspections. It is presumed that the inspection plan for the replaced W model 44F should 

be updated in accordance with the recommendations given in Table 2.7.

5-26
5 WESTINGHOUSE STEAM GENERATORS

5.3.2 Evaluation of Recent SG Tube Failure 

During the SG inspection in May 1997, IP2 reported the following active degradation mechanisms in the 

SGs: wear at the anti-vibration bars (AVBs); outside-diameter stress corrosion cracking (ODSCC) and 

pitting in the sludge-pile region (i.e., the area above the top of the tubesheet and below the first TSP); 

ODSCC and intergranular attack (IGA) in the tubesheet's crevices; and primary-water stress corrosion 

cracking (PWSCC) at the tubesheet roll transitions and low row U-bend. This was the first time that 

PWSCC was identified in the low row U-bends. During subsequent plant operation the licensee detected 

a primary-to-secondary leak through the SGs by sampling condenser off-gas, tritium surveys, and/or 

other monitoring methods. This leak rate slowly increased from 1.9 liters per day (Ipd) ( 0.5 gallon per 

day (gpd)) in September 1998 to 11 to 15 lpd (3 to 4 gpd) in January 2000. On February 15, 2000, IP2 

was shutdown due to excessive leakage from tube R2C5 in SG 24. After extensive studies on the root 

causes of this incident, the licensee recently replaced all SGs with model 44F containing thermally 

treated alloy 600 tubing (Ref. 30). This section discusses the findings of the post-event investigation by 

the licensee to determine the root cause(s) of the tube failure and the staff s evaluation of, and 

conclusions about, this incident as they relate to SG internals degradation. 

As part of the licensee's post-shutdown evaluation in 2000, eddy current testing was used to examine the 

SGs, in a similar location to failed tube R2C5 in SG 24. Rows 2 to 4 from the sixth (i.e., top) hot leg 

TSP to the sixth (i.e., top) cold leg TSP were examined, and the licensee found seven additional PWSCC 

indications in the apex region of the row 2 U-bends. (Row 1 was plugged prior to 1P2 operation.) 

As discussed earlier, IP2 experienced denting early in its operating life in the mid-1970s. This denting 

led to extensive in-plane deformation of the TSPs and cracking of support plate ligaments. Hourglass 

deformation of the uppermost TSP flow slots was known to have potential tube integrity significance. 

Such deformation causes the legs of the small radius U-bends to displace inward, substantially increasing 

the stress level at the apex of the U-bend and thus causing the potential for stress corrosion cracking at 

that location. This phenomenon led to a rupture of an inner row U-bend at Surry Unit 2 in 1976. The 

amount of hourglass deformation of the adjacent flow slot at Surry Unit 2 was 3.3 cm (1.3 inches). 

Accordingly, the licensee for IP2 had routinely performed visual inspections of the three flow slots in the 

uppermost TSP in SGs 22 and 23. Based on these visual inspections, the licensee did not identify 

hourglassing at the upper TSPs and, therefore, consistently reported through the years that the uppermost 

TSPs were free of significant hourglass deformation. SGs 21 and 24 did not have access ports permitting 

visual inspection of the uppermost TSP flow slots. 

Secondary side visual examinations, including the FOSAR (foreign objects search and retrieval) 

inspection, were performed after the event in 2000 for monitoring the condition of the SG internals. 

Following the failure of R2C5 in SG 24, the licensee installed access ports in SGs 21 and 24 to permit 

visual inspection of three flow slots in each of these SGs, including the flow slot adjacent to R2C5 in SG 

24. The visual inspections, performed with a video camera, did not provide clear indication of hourglass 

deformation of the upper TSP flow slots due to limitations presented by camera angle and lighting. After 

mounting a measuring device to the camera assembly, the licensee determined that hourglass 

deformation was in fact present in the flow slot adjacent to R2C5 in SG 24. The amount of hourglass 

deformation was 1.16 cm (0.47 inch), relative to the nominal flow slot width of 7 cm (2.75 inches). This

5-27
5 WESTINGHOUSE STEAM GENERATORS

amount of hourglassing at the uppermost TSP flow slots displaced the legs of the small radius U-bends 

inwards, and was sufficient to substantially increase the stress level at the apex-of the U-bend, thereby 

enhancing the susceptibility of this location to stress corrosion cracking there. From further 

investigations, the staff concluded that the hourglass deformation of the uppermost TSP flow slots was 

occurring during most of the life of all four SGs at IP2. Previous inspections were inadequate for 

detecting this hourglass deformation. 

Apart from flow slot hourglass deformation, visual inspections were also conducted after the 2000 event 

to assess the general condition of the TSPs and SG wrapper. Where accessible to the video camera, in

plane deformation (growth) of the TSPs, due to denting, was observed to have caused the support plates 

to be in contact with the wrapper, except in the near vicinity of the wedge supports. The reaction loads at 

the periphery of the TSPs maintained the plates in a high state of compressiorl and the licensee, based on 

a detailed structural analysis, demonstrated that they were still capable of providing adequate lateral 

support to all unplugged tubes under operating and postulated accident conditions. All wedges and 

welded connections were observed to be in good condition. The licensee reported that there was no 

visible deterioration of the wrapper and the wrapper had not dropped from its earlier position. 

In summary, the induced stress levels of the uppermost TSP flow slots due to hourglassing of the 

uppermost TSP was a primary contributor to the development of PWSCC in the apex region of seven 

Row 2 steam generator tubes identified during the 2000 inspection. One affected tube (R2C5) failed at 

normal operating temperatures and pressures, causing excessive operational leakage which led to the 

February 2000 shutdown. Past inspections in SGs 22 and 23 are inconclusive regarding how long the 

upper flow slots have experienced significant hourglass deformation. (Significant deformations is used 

here in the context of causing sufficient stress over time and at operating temperatures to cause PWSCC.) 

Therefore, the licensee's inspections of the upper TSP flow slots, dating up to the tube failure in 

February 2000, were inadequate for purpose of detecting significant hourglass deformation. 

5.3.3 Summary and Conclusions 

The licensee replaced its all four model 44 SGs with model 44F SGs in December 2000. The current SG 

internals inspection activities for the model 44 SGs should be updated for the model 44F SGs, as 

discussed earlier in Section 5.2.2.

5-28
5 WESTINGHOUSE STEAM GENERATORS

Figure 5.1 Braidwood Unit 1 Reactor Coolant System (4 Loops)

5-29
5 WESTINGHOUSE STEAM GENERATORS

I

if

I!

Figure 5.2 Beaver Valley 2 Reactor Coolant System (3 Loops)

5-30
5 WESTINGHOUSE STEAM GENERATORS

Steam 

Nozzle

Tube Support 

"Plate

Figure 5.3 Westinghouse Recirculating Steam Generator 

(Typical of Models 44 and 51)

5-31

Positive 

. Entainment 

Steam Dryers 

-.Secondary 

Manway 

-Upper 

Shell 

.Antivibration 

Bars

Transition 

Cone
5 WESTINGHOUSE STEAM GENERATORS

Feedwater . 

Nozzle

Positive 

Entrainment 

Steam Dryers 

Secondary 

Manway 

. Upper Shell 

- Antivibration 

Bars 

- Tube 

Support 

Plate 

Lower Shell 

Divider Plate 

Primary 

Outlet

Figure 5.4 Westinghouse Recirculating Steam Generator 

(Typical of Model F)

5-32
t

PRIMARY FLUID INLET

DRY AND 

SATURATED STEAM 

LEAVES VESSEL

STEAM/WATER 

MIXTURE 

STEAM/WATER 

MIXTURE LEAVES 

TUBE BUNDLE 

/ PREHEATER 

MAIN FEEDWATER 

"NOZZLE 

3 -.

- 16" SCH. 80 

(MAIN FEEDWATER) 

- PRIMARY FLUID 

OUTLET

Figure 5.5 Westinghouse Recirculating Steam Generator 

(Typical of Model E Preheat Unit)

5-33
6 SUMMARY AND CONCLUSIONS

6.1 Summary of Results 

The results presented in this report are based on the following documents: the licensees' submittals in 

response to GL 97-06; EPRI report on the modes of degradation detected in SG internals; owners group 

reports on the evaluation of the EdF causal factors and the degradation at SONGS; owners group 

response to NRC's requests for additional information (RAIs); and limited discussions with steam 

generator (SG) manufacturers. In addition, NEI 97-06, "Steam Generator Program Guidelines," and 

related EPRI documents were reviewed. This report and the summary relate to SG secondary side 

internal components; the report does not focus on the SG tubes themselves. 

The technical work on this review was completed in the Fall of 1998. At that time, the owners groups' 

assessments, while completed in some cases, were still listed as interim; in other cases, they had not been 

completed. The Westinghouse owners group evaluation of its SG models F, 44F, D and E2 were 

completed in December 1998. The Babcock & Wilcox owners group report on once-through steam 

generators internals was completed in February 1999. Thus, the final evaluations of all degradation 

identified in the GL for these SGs became available during the Spring of 1999. Most plant submittals are 

based on the owners group reports and past inspections of their steam generators. The Nuclear Energy 

Institute (NEI), who coordinated the industry's response to this GL, incorporated in its "Steam Generator 

Program Guidelines" a requirement to monitor secondary side SG components if their failure could 

prevent the SG from fulfilling its intended safety-related function. 

Degradation problems in steam generator tubes have been known in the nuclear industry from the mid

seventies and there are several Electric Power Research Institute (EPRI) guidelines on maintaining the 

structural integrity of SG tubes. However, there existed no explicit industry guidelines for an SG 

secondary side internals inspection program. Many of the reported activities in this area by the licensees 

resulted from self-identified problems over the past 25 years of service. In response to the GL, the 

owners groups identified additional SG internal components that could be vulnerable to degradation, and 

suggested inspection guidelines to address these concerns. 

NEI 97-06 describes a program to ensure the operability of steam generators, and includes prevention, 

inspection, evaluation, repair, and leakage monitoring. NEI 97-06 provides an approach for an SG 

secondary side program, which in turn has to be combined with the SG-specific inspection guidelines 

and analyses, as suggested by the SG owners groups. 

The findings from our review of licensees' submittals and associated documents are summarized as 

follows: 

All US PWR plants have, or plan to have, an inspection program to detect and monitor 

degradation of SG internals. 

Many existing programs include sludge-lancing operation, foreign object search and retrieval 

(FOSAR), visual inspection of components in the steam drum section, and visual/eddy current 

analysis for degradation in the tubes or tube support plates. Licensee responses suggest that most

6-1
6 SUMMARY AND CONCLUSIONS

undertake eddy current examinations to detect tube degradation and TSP degradation (if applicable), 

and also visual/video inspections of the tube bundles, the tubesheet, TSPs, and the 

U-bend region. Licensees follow EPRI's guidelines for maintaining both primary and secondary 

water chemistry. 

All licensees perform ASME Section XI Inservice Inspection (ISI) of welds every 5-10 years 

(mostly every 10-year schedule) following the NRC's ISI requirements. 

All licensees endorse the evaluation and recommendations made by their SG owners group about 

the EdF causal factors identified in EPRI GC-109558. Based on the owners groups' 

assessments, U.S. plants are not believed to be susceptible to the causal factors experienced at 

EdF units. 

Essentially all licensees reported no significant degradation in their SG internals caused by the 

mechanisms found in San Onofre. Many noted the potential susceptibility to flow-accelerated 

corrosion (FAC) in carbon steel tube supports with heavily fouled tube bundles. Significant 

repairs to date of SG secondary side components, either voluntary or required, have not been 

made. 

After reviewing the inspection records, each plant concluded that they comply with the current 

licensing bases, and no immediate changes to the current inspection programs are necessary. 

All plants indicated that some program (formal or informal) for monitoring degradation of SG internals 

is in place and that inspections are typically carried out at each refueling outage (although not usually for 

all SGs at each refueling outage). Several plants with a history of problems similar to that described in 

the GL had already performed, or had plans to perform, comprehensive inspection of their SG internals 

during the next scheduled refueling outage. Further, several plants had replaced their SGs with new, 

improved designs. These improved designs included the use of corrosion-resistant materials, and better 

monitoring techniques which had significantly contributed to industry-wide enhanced management 

programs for SG internal components. 

Westinghouse (W) SGs involving models 44, 51, 51 M, and D3 and Combustion Engineering (CE) SGs 

with carbon steel eggcrate tube supports appear to be the most susceptible to the types of degradation 

identified in the GL. The replacement recirculating SGs by Babcock & Wilcox (B&W) are susceptible 

to peripheral tubes coming into contact during operation and so may incur fretting wear from flow

induced vibration at the point of contact. Specific recommendations were made by the W owners group, 

the CE owners group, and the B&W owners group to address these potential concerns. Each licensee has 

either implemented or is planning, as appropriate for its SGs, the implementation of the 

recommendations suggested by its owners group and/or by the industry for an inspection program for the 

SG internal components to address the long-term effects.

6-2
6 SUMMARY OF RESULTS

6.2 Conclusions 

No licensee has reported any significant degradation in their SG internals at this time. Corrective and 

preventive measures were taken to mitigate any significant problems associated with SG internals 

encountered in the past. No observed degradation has progressed, according to sequential inspection 

data. 

The existing SG internals inspection programs are plant-specific and generally include the following: 

(1) Eddy current examinations of tubes that detect TSP degradation or presence of loose parts. 

(2) Visual/video inspections of tubesheets, TSPs, tube bundle, steam drum, feedwater nozzles 

including thermal liners, feedwater distribution components, waterbox, and moisture separators. 

(3) ASME Section XI In-Service Inspection of welds. 

(4) FOSAR activities. 

(5) Sludge-lancing, water-slapping or -lancing, chemical or pressure pulse cleaning. 

From the results presented in the licensees' submittals, there are no near-term problems nor are there 

needs for any immediate change in the current SG internals inspections. Licensees plan to implement 

their owners group recommendations to address the long-term effects of the potential degradation 

mechanisms associated with the SG internals. Overall, the licensees' submittals have met the intent of 

the GL and provide reasonable assurance that the SG internals comply with, and conform to, the 

licensing basis.

6-3
7 REFERENCES 

1. NRC Generic Letter 97-06: Degradation of Steam Generator Internals, December 30, 1997. 

2. "Review of Industry Responses to GL 97-06 on Degradation of Steam Generator Internals," 

M. Subudhi and J. Higgins, BNL Technical Letter Report J2590-6-0199, January 26, 1999. 

3. NUREG/CR-6365, "Steam Generator Tube Failures," P.E. McDonald, V.N. Shah, L.W. Ward, 

and P.G. Ellison, April 1996. 

4. "Better maintenance R&D extend steam generator life," S. E. Kuehn, Power Engineering, Oct. 

1992. 

5. "Solutions for Steam Generators," J. Douglas, EPRI Journal, May/June 1995. 

6. EPRI GC-109558, "Steam Generator Internals Degradation: Modes of Degradation Detected in 

EdF Units," Topical Report, December 1997. 

7. NRC Information Notice 96-09: Damage in Foreign Steam Generator Internals, February 12, 

1996. 

8. NRC Information Notice 96-09, Supplement 1: Damage in Foreign Steam Generator Internals, 

July 10, 1996. 

9. NRC Memo, Sullivan to Strosnider, May 15, 1997, Summary of May 1 Meeting with NEI to 

Discuss Degradation of Steam Generator Internals. 

10. NEI 97-06, Steam Generator Program Guidelines, December, 1997. 

11. B&W Owner's Group Response to GL 97-06 (Submitted to NRC with GL 97-06 responses for 

ANO, Crystal River, Oconee, TMI, and Davis Besse). 

12. "OTSG Internals Degradation Evaluation", The B&W Owners Group Steam Generator 

Committee, Prepared by Framatome Technologies Inc., Report No. 77-5003013-00, February 

1999. 

13. B&W Replacement RSG Internals Degradation Assessment Re GL 97-06, BWC-TR-98-03, Rev. 

1, March 18, 1998, W. Schneider, et al. (Submitted to NRC with Ginna GL 97-06 response). 

14. CE-NPSD-1079-P, Final Report, "Evaluation of NRC Information Notice 96-09 Including 

Supplement 1, Relative to Combustion Engineering Steam Generator Designs," April 1997. 

15. CE-NPSD-1092, Rev. 0, "Evaluation of Degraded Secondary Internals Operability Assessment." 

April 1998. 

16. CE-NPSD- 1103, Rev. 0, "Evaluation of Degraded Secondary Internals Susceptibility 

Assessment." April 1998.

7-1
7 REFERENCES

17. CE-NPSD-1 104-P, Rev. 0, "Evaluation of Degraded Secondary Internals Bounding Analysis," 

April 1998. Proprietary information. Not publicly available. 

18. CE-NPSD-1 104-NP, Rev. 0, "Evaluation of Degraded Secondary Internals Bounding Analysis." 

Non-Proprietary, April 1998. 

19. NRC Memorandum from Stephanie M. Coffin to Edmund J. Sullivan on "Summary of 

April 27, 1999 phone call between NRC Staff and BGE representatives to discuss steam 

generator inspection activities." May 19, 1999. 

20. CE response to NRC RAIs, "Transmittal of Responses to NRC Requests for Additional 

Information on CEOG Topical Reports, Generic Letter 97-06," June 15, 1999. 

21. WCAP- 15002, Rev. 1, "Evaluation of EdF Steam Generator Internals Degradation - Impact of 

Causal Factors on Westinghouse 51 Series Steam Generators," February 1998, Proprietary 

information. Not publicly available. 

22. WCAP- 15031, "Evaluation of EdF Steam Generator Internals Degradation - Impact of Causal 

Factors on Westinghouse 51 Series Steam Generators," February 1998, Non-Proprietary. 

23. WCAP-15093, Rev. 1, "Evaluation of EDF Steam Generator Internals Degradation - Impact of 

Causal Factors on the Westinghouse Models F, 44F, D and E2 Steam Generators," December 

1998, Proprietary information. Not publicly available. 

24. WCAP- 15104, Rev. 1, "Evaluation of EDF Steam Generator Internals Degradation - Impact of 

Causal Factors on the Westinghouse Models F, 44F, D and E2 Steam Generators," December 

1998, Non-Proprietary. 

25. WNEP-9726, Rev.0, "Series F Steam Generator Study," December 1997, Proprietary 

information. 

Not publicly available. 

26. WNEP-9732, Rev.0, "Series D Steam Generator Study," April 1998, Proprietary information. 

Not publicly available. 

27. WNEP-9806, Rev.0, "Series 44F Steam Generator Study," November 1998, Proprietary 

information. Not publicly available. 

28. WNEP-9816, Rev.0, "Series E2 Steam Generator Study," July 1998, Proprietary information. 

Not publicly available. 

29. Memorandum from Jack R. Strosnider to John A. Zwolinski, "Indian Point Nuclear Generating 

Unit No. 2, Technical Evaluation Report on Steam Generator Tube Failure, Category C-3 Steam 

Generator Inspection Results and Steam Generator Operational Assessment," October 10, 2000.

7-2
APPENDIX A 

GL 97-06 - DEGRADATION OF STEAM GENERATOR INTERNALS 

UNITED STATES 

NUCLEAR REGULATORY COMMISSION 

OFFICE OF NUCLEAR REACTOR REGULATION 

WASHINGTON, D.C. 20555 

December 30, 1997 

NRC GENERIC LETTER 97-06: DEGRADATION OF STEAM GENERATOR INTERNALS 

Addressees 

All holders of operating licenses for pressurized-water reactors (PWRs), except those who have 

permanently ceased operations and have certified that fuel has been permanently removed from the 

reactor vessel. 

The U.S. Nuclear Regulatory Commission (NRC) is issuing this generic letter to (1) again alert 

addressees to the previously communicated findings of damage to steam generator internals, namely, tube 

support plates and tube bundle wrappers, at foreign PWR facilities; (2) alert addressees to recent findings 

of damage to steam generator tube support plates at a U.S. PWR facility; (3) emphasize to addressees the 

importance of performing comprehensive examinations of steam generator internals to ensure steam 

generator tube structural integrity is maintained in accordance with the requirements of Appendix B to 10 

CFR Part 50; and (4) require all addressees to submit information that will enable the NRC staff to verify 

whether addressees' steam generator internals comply with and conform to the current licensing bases for 

their respective facilities. 

Background 

The NRC issued Information Notice (IN) 96-09 and IN 96-09, Supplement 1 to alert addressees to 

findings of damage to steam generator internals at foreign PWR facilities. 

Description of Circumstances 

Foreign authorities have reported various steam generator tube support plate damage mechanisms. The 

affected steam generators are similar, but not identical, to Westinghouse Model 51 steam generators. As 

previously documented in IN 96-09 and IN 96-09, Supplement 1, one damage mechanism involved the 

wastage of the uppermost support plate caused by the misapplication of a chemical cleaning process. A 

second damage mechanism involved broken tube support plate ligaments at the uppermost, and 

sometimes at the next lower, tube support plates. The support plate ligaments broke near a radial seismic 

restraint and near an antirotation key; the damage apparently dates back to initial startup of the affected

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APPENDIX A: GL 97-06 - DEGRADATION OF STEAM GENERATOR INTERNALS 

plants. According to foreign authorities, the ligaments may have broken because of excessive stress 

during the final thermal treatment of the monobloc steam generators, which in-turn was caused by 

inadequate clearance for differential thermal expansion between the support plates, wrapper, and seismic 

restraints. 

As previously documented in IN 96-09, Supplement 1, a third damage mechanism involved wastage not 

associated with chemical cleaning and affected tube support plates at various elevations. This damage 

mechanism is active (progressive) and apparently involves a corrosion or erosion-corrosion mechanism 

of undetermined origin. 

The staffs of potentially affected foreign reactors are currently inspecting steam generators for evidence 

of the various damage mechanisms, both visually and with eddy-current testing. Tubes without adequate 

lateral support are being plugged. 

IN 96-09, Supplement 1, also documented that cooling transients involving the injection of large 

quantities of auxiliary feedwater may have been a key factor in the steam generator wrapper drop 

phenomenon observed at a foreign PWR facility. These cooling transients are believed to have been 

particularly severe for two units as a result of the use of a special operating procedure to accelerate the 

transition from hot to cold shutdown. The weight of the wrapper assembly and support plates is borne by 

six tenons mounted on the steam generator shell. The wrapper is nominally free to expand axially 

relative to the shell. However, it is postulated that an interference fit developed between the wrapper and 

the seismic restraints (mounted to the shell) as a result of differential thermal expansion associated with 

the cooling transients at the seventh support plate elevation. This interference fit prevented axial 

expansion of the wrapper, which led to excessive vertical bearing loads at the tenon supports, thus 

causing localized wrapper failure at this location and downward displacement of the wrapper (20 

millimeters maximum). Poor quality wrapper support welds may also have contributed to this failure. 

Repairs have been made at the affected foreign PWR facility. Wrapper dropping is being monitored in 

all steam generators of similar design. The monitoring is performed through both online instrumentation 

and visual inspections during outages. In addition to the wrapper dropping problem, cracking of the 

wrapper above the original upper support was discovered at the same foreign unit. The cause of the 

cracking is not yet known. 

At a U.S. PWR facility, degradation of steam generator tube eggcrate supports was discovered through 

secondary side visual inspections performed during the spring 1997 refueling outage. The licensee 

identified erosion corrosion as the damage mechanism; the cause is not yet known. The damage appears 

to be confined to the periphery and the untubed staywell region of the tube bundle. The eggcrate 

degradation at the periphery extends inward to the first one or two rows of tubes. The degradation at the 

staywell region primarily affects the support structures within the untubed section. Damage to the 

eggcrate supports was found in both steam generators on the hot and cold leg sides although the damage 

was more extensive on the hot leg side. No degradation of eggcrate supports was identified within the 

tube bundle.

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APPENDIX A: GL 97-06 - DEGRADATION OF STEAM GENERATOR INTERNALS 

Discussion 

The reported foreign and U.S. experience highlights the potential for degradation mechanisms that may 

lead to tube support plate and tube bundle wrapper damage. The steam generator tube support plates 

support the tubes against lateral displacement and vibration and minimize bending moments in the tubes 

in the event of an accident. Support plate damage can impair the support plate's ability to perform this 

function and, thus, could potentially lead to the impairment of tube integrity. Vibration-induced fatigue 

could present a potential problem if tube support plates lose integrity, particularly in areas of high 

secondary side cross flows. As previously noted in IN 96-09, tube support plate signal anomalies found 

during eddy-current testing of the steam generator tubes may be indicative of support plate damage or 

ligament cracking. Certain visual and video camera inspections on the secondary side of a steam 

generator may also provide useful information concerning the degradation of steam generator internals. 

The NRC staff will continue to monitor information on tube support plate and tube bundle wrapper 

damage as it becomes available. 

This letter also alerts addressees to the importance of performing comprehensive examinations of steam 

generator internals to ensure steam generator tube structural integrity is maintained in accordance with 

the requirements of Appendix B to 10 CFR Part 50. More specifically, Criterion XVI of Appendix B, 

"Corrective Action," requires, in part, that measures be established to assure that conditions adverse to 

quality are promptly identified and corrected. 

Required Information 

Within 90 days of the date of this generic letter, each addressee is required to provide a written report 

that includes the following information for its facility: 

(1) Discussion of any program in place to detect degradation of steam generator internals and a 

description of the inspection plans, including the inspection scope, frequency, methods, and 

equipment. 

The discussion should include the following information: 

(a) Whether inspection records at the facility have been reviewed for indications of tube 

support plate signal anomalies from eddy-current testing of the steam generator tubes 

that may be indicative of support plate damage or ligament cracking. If the addressee 

has performed such a review, include a discussion of the findings. 

(b) Whether visual or video camera inspections on the secondary side of the steam 

generators have been performed at the facility to gain information on the condition of 

steam generator internals (e.g., support plates, tube bundle wrappers, or other 

components). If the addressee has performed such inspections, include a discussion of 

the findings. 

(c) Whether degradation of steam generator internals has been detected at the facility, and 

how the degradation was assessed and dispositioned.

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APPENDIX A: GL 97-06 - DEGRADATION OF STEAM GENERATOR INTERNALS 

(2) If the addressee currently has no program in place to detect degradation of steam generator 

internals, include a discussion and justification of the plans and schedule for establishing such a 

program, or why no program is needed. Addressees are encouraged to work closely with 

industry groups on the coordination of inspections, evaluations, and repair options for all types of 

steam generator degradation that may be found. 

The NRC is aware that the industry has developed generic guidance on performing steam generator 

inspections, and that this guidance is continually being updated. If an addressee intends to follow the 

guidance developed by the industry for this issue, reference to the relevant generic guidance documents is 

acceptable, and encouraged, as part of the response, as long as the referenced documents have been 

officially submitted to the NRC. However, additional plant-specific information will be needed. 

NRC staff will review the responses to this generic letter and if concerns are identified, affected 

addressees will be notified. 

Address the required written responses to the U.S. Nuclear Regulatory Commission, ATTN: Document 

Control Desk, Washington, D.C. 20555-0001, under oath or affirmation under the provisions of Section 

182a, Atomic Energy Act of 1954, as amended, and 10 CFR 50.54(f). 

Backfit Discussion 

Under the provisions of Section 182a of the Atomic Energy Act of 1954, as amended, and 10 CFR 

50.54(f), this generic letter transmits an information request for the purpose of verifying compliance with 

applicable existing regulatory requirements. Specifically, the requested information will enable the NRC 

staff to determine whether the condition of the addressees' steam generator internals comply with and 

conform to the current licensing bases for their respective facilities. In particular, the information would 

help the staff to ascertain whether the regulatory requirements pursuant to Appendix B to 10 CFR Part 50 

are met. 

No backfit is either intended or approved in the context of issuance of this generic letter. Therefore, the 

staff has not performed a backfit analysis. 

Federal Register Notification 

A notice of opportunity for public comment was published in the Federal Register on December 31, 

1996 (61 FR 69116). 

Paperwork Reduction Act Statement 

This generic letter contains information collections that are subject to the Paperwork Reduction Act of 

1995 (22 U.S.C. 3501 et seq.). These information collections were approved by the Office of 

Management and Budget, approval number 3150-0011, which expires on September 30, 2000. 

The public reporting burden for this collection of information is estimated to average 80 hours per 

response, including the time for reviewing instructions, searching existing data sources, gathering and

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APPENDIX A: GL 97-06 - DEGRADATION OF STEAM GENERATOR INTERNALS 

maintaining the data needed, and completing and reviewing the collection of information. The U.S. 

Nuclear Regulatory Commission is seeking public comment on the potential impact of the collection of 

information contained in the generic letter and on the following issues: 

(1) Is the proposed collection of information necessary for the proper performance of the functions 

of the NRC, including whether the information will have practical utility? 

(2) Is the estimate of burden accurate? 

(3) Is there a way to enhance the quality, utility, and clarity of the information to be collected? 

(4) How can the burden of the collection of information be minimized, including the use of 

automated collection techniques? 

Send comments on any aspect of this collection of information, including suggestions for reducing this 

burden, to the Information and Records Management Branch, T-6F33, U.S. Nuclear Regulatory 

Commission, Washington, DC 20555-0001, and to the Desk Officer, Office of Information and 

Regulatory Affairs, NEOB-10202 (3150-0011), Office of Management and Budget, Washington, DC 

20503. 

The NRC may not conduct or sponsor, and a person is not required to respond to, a collection of 

information unless it displays a currently valid OMB control number. 

If you have any questions about this matter, please contact the technical contact listed below or the 

appropriate Office of Nuclear Reactor Regulation (NRR) project manager. 

signed by D.B. Matthews for 

Jack W. Roe, Acting Director 

Division of Reactor Program Management 

Office of Nuclear Reactor Regulation 

Technical contact: Stephanie M. Coffin, NRR 

301-415-2778 

E-mail: smcl@nrc.gov 

Lead Project Manager: George F. Wunder, NRR 

301-415-1494 

E-mail: gfw@nrc.gov

A-5
APPENDIX B 

LICENSEES RESPONDED TO GL 97-06 

No icneePi~~I1cor Ut #SsReaks, 

PLANTS WITH B&W ONCE-THROUGH STEAM GENERATORS (OTSGs) 

1 Entergy Arkansas Nuclear One - 1 2 

2 Florida Power & Light Crystal River - 3 2 

3 Toledo Edison Davis Besse - 1 2 

4 Duke Power Oconee - 1 2 Planned replacement of B&W 

OTSG with B&W RSG - Fall 2003 

5 Duke Power Oconee - 2 2 Planned replacement of B&W 

OTSG with B&W RSG - Spring 

2004 

6 Duke Power Oconee - 3 2 Planned replacement of B&W 

OTSG with B&W RSG - Fall 2004 

7 GPU Nuclear Three Mile Island - 1 2 

PLANTS WITH B&W REPLACEMENT STEAM GENERATORS (RSGs) 

1 Commonwealth Edison Byron - 1 4 Replaced W D4 with B&W RSG 

2/98 

2 Duke Power Catawba - 1 4 Replaced W D3 with B&W RSG 

10/96 

3 Rochester Gas & Ginna 2 Replaced W 44 with B&W RSG 

Electric 6/96 

4 Duke Power McGuire - 1 4 Replaced W D2 with B&W RSG 

5/97 

5 Duke Power McGuire - 2 4 Replaced W D3 with B&W RSG 

12/97 

6 Northeast Nuclear Millstone - 2 2 Replaced CE 67 with B&W RSG 

1/93 

7 Florida Power & Light St. Lucie - 1 2 Replaced CE 67 with B&W RSG 

1/98 

NOTE: Braidwood - 1 and Cook -1 replaced W D4 (11/98) and W 51 (12/00), respectively. 

PLANTS WITH CE STEAM GENERATORS 

I Entergy Arkansas Nuclear One - 2 2 Replaced CE 2815 with W D109 

12/00

B-I
APPENDIX B: LICENSEES RESPONDED TO GL 97-06

[ No. Licensee Pla n, -Reactokr Unit :I # SGs I Remarks,'. 

2 Baltimore Gas & Calvert Cliffs - 1 2 Planned replacement of CE 67 with 

Electric B&W RSG - Spring 2002 

3 Baltimore Gas & Calvert Cliffs - 2 2 Planned replacement of CE 67 with 

Electric B&W RSG - Spring 2003 

4 Omaha Public Power Fort Calhoun 2 

District 

5 Consumers Energy Palisades 2 Replaced CE with CE - 3/91 

6 Arizona Public Service Palo Verde - 1 2 

7 Arizona Public Service Palo Verde - 2 2 Planned replacement CE 80 with 

ABB/Ansaldo - Fall 2003 

8 Arizona Public Service Palo Verde - 3 2 

9 Florida Power & Light St. Lucie - 2 2 

10 Southern California San Onofre - 2 2 

Edison 

11 Southern California San Onofre - 3 2 

Edison 

12 Entergy Waterford - 3 2 

PLANTS WITH W 51 SERIES STEAM GENERATORS 

1 Duquesne Light Beaver Valley - 1 3 Planned replacement of W 51- 2007 

2 Duquesne Light Beaver Valley - 2 3 

3 Indiana Michigan Cook - 1 4 Replaced W 51 with B&W RSG 

Power 12/00 

4 Indiana Michigan Cook - 2 4 Replaced W 51 with W 54F - 1989 

Power 

5 Pacific Gas & Electric Diablo Canyon - 1 4 

6 Pacific Gas & Electric Diablo Canyon - 2 4 

7 Southern Company Farley - 1 3 Replaced W 51 with W 54F - 5/00 

8 Southern Company Farley - 2 3 Replaced W 51 with W 54F - 5/01 

9 Wisconsin Public Kewaunee 2 Planned replacement of W 51 with 

Service Corp. I 1_ 13YW 54F - Fall 2001

B-2
APPENDIX B: LICENSEES RESPONDED TO GL 97-06

[No. Licensee " Pant:7,-ReactoirUnit 14.# SGs I Remarks. : 

10 Virginia Electric & North Anna - 1 3 Replaced W 51 with W 54F - 1993 

Power 

11 Virginia Electric & North Anna - 2 3 Replaced W 51 with W 54F - 1995 

Power 

12 Wisconsin Electric Point Beach - 2 2 Replaced W 44 with W A47- 1996 

Power 

13 Northern States Power Prairie Island - 1 2 Planned replacement of W 51- 2004 

14 Northern States Power Prairie Island - 2 2 

15 Public Service Electric Salem - 1 4 Replaced W 51 with W F - 7/97 

& Gas 

16 Tennessee Valley Sequoyah - 1 4 Planned replacement of W 51 with 

Authority unknown SG - Spring 2003 

17 Tennessee Valley Sequoyah - 2 4 

Authority 

18 South Carolina Electric Summer - 1 3 Replaced W D3 with W A75 - 1994 

& Gas 

19 Virginia Electric & Surry - 1 3 Replaced W 51 with W 5IF - 1980 

Power 

20 Virginia Electric & Surry - 2 3 Replaced W 51 with W 5IF - 1979 

Power 

PLANTS WITH W 44, 44F, F, D-SERIES, AND E-SERIES STEAM GENERATORS 

1 Commonwealth Edison Byron - 2 4 

2 Commonwealth Edison Braidwood - 1 4 Replaced W D4 with B&W RSGs 

11/98 

3 Commonwealth Edison Braidwood - 2 4 

4 Union Electric Callaway 4 Planned replacement of W F with 

unknown SGs - 10/2005 

5 Duke Power Catawba - 2 4 

6 Texas Utilities Electric Comanche Peak - 1 4 

7 Texas Utilities Electric Comanche Peak - 2 4 

8 Carolina Power & Shearon Harris 3 Planned replacement of W D4 with 

Light I I_ IEW A75 - 9/01

B-3
APPENDIX B: LICENSEES RESPONDED TO GL 97-06

[:Ni Licensee Pant- R•eacltor.iUtt # SGs [ Remark ] 

9 Consolidated Edison of Indian Point 2 4 Not evaluated for EdF causal 

New York factors. Replaced W 44 with W 

44F - 12/00 

10 New York Power Indian Point - 3 4 Replaced W 44 with W 44F - 1989 

Authority 

11 Northeast Nuclear Millstone - 3 4 

12 Wisconsin Electric Point Beach - 1 2 Replaced W 44 with W 44F - 1983 

Power 

13 Carolina Power & Robinson - 2 3 Replaced W 44 with W 44F - 1984 

Light 

14 Public Service Electric Salem - 1 4 

&Gas 

15 North Atlantic Energy Seabrook 4 

Service Corp. 

16 South Texas Project South Texas Project - 1 4 Replaced W E with W D94 - 5/00 

Nuclear Operating 

17 South Texas Project South Texas Project - 2 4 Planned replacement W E with 

Nuclear Operating B&W RSG - Fall 2002 

18 Florida Power & Light Turkey Point - 3 3 Replaced W 44 with W 44F - 1981 

19 Florida Power & Light Turkey Point - 4 3 Replaced W 44 with W 44F - 1982 

20 Southern Nuclear Vogtle - 1 4 

Operating 

21 Southern Nuclear Vogtle - 2 4 

Operating 

22 Tennessee Valley Watts Bar - 1 4 

Authority 

23 Wolf Creek Nuclear Wolf Creek 4 

Operating Corp. 

NOTES: 

(1) The licensee names are in accordance with the GL responses at the time of this review. 

(2) Plants are categorized in accordance with their GL submittals.

B-4
NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER 

(2-89) (Assigned by NRC, Add Vol., Supp., Rev., 

NRCM 1102, and Addendum Numbers, if any.) 

3201,3202 BIBLIOGRAPHIC DATA SHEET 

(See instructions on the rveNUREG/CR-6754 

2. TITLE AND SUBTITLE BNL-NUREG-52646 

Review of Industry Responses to NRC Generic Letter 97-06 on Degradation of Steam 

Generator Internals 3. DATE REPORT PUBLISHED 

MONTH YEAR 

December 2001 

4. FIN OR GRANT NUMBER 

J-2831 

5. AUTHOR(S) 6. TYPE OF REPORT 

M. Subudhhi and J.C. Higgins, Brookhaven National Laboratory 

S. Coffin, NRC 7. PERIOD COVERED (inclusive Dates) 

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor, 

provide name and mailing address.) 

Brookhaven National Laboratory 

Upton, NY 11973-5000

9I. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission, 

and mailing address.)

Divison of Engineering 

Office of Nuclear Reactor Regulation 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

10. SUPPLEMENTARY NOTES 

E. J. Sullivan, NRC Project Manager 

11. ABSTRACT (200 words or less) 

This report presents the results of an assessment of the nuclear power industry's response to NRC Generic Letter (GL) 97-06 

on the degradation of steam generator internals experienced in EdF plants in France and in a U.S. pressurized water reactor 

(PWR). Before issuing the GL, with the exception of a few licensees, there were no formal inspection programs, nor any 

industry guidelines for monitoring the secondary side internals of steam generators. Nonetheless, all licensees have been 

performing some inspection and maintenance on their steam generator internals and have found no significant degradation in 

them. Most of the steam generators in the U.S. plants do not appear susceptible to degradation found in EdF and in the U.S. 

PWR. 

Licensees plan to implement their owners group recommendations to address the long-term effects of the potential degradation 

mechanisms associated with the SG internals. Overall, the licensees' submittals have met the intent of the GL and provide 

reasonable assurance that the SG internals comply with, and conform to, the current licensing basis.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABILITY STATEMENT 

steam generator, steam generator internals, generic letter unlimited 

14. SECURITY CLASSIFICATION 

(This Page) 

unclassified 

(This Report) 

unclassified 

15. NUMBER OF PAGES 

16. PRICE

NRC FORM 335 (2-89)
Federal Recycling Program
NUREG/CR-6754 REVIEW OF INDUSTRY RESPONSES TO NRC GENERIC LETTER 97-06 ON 

DEGRADATION OF STEAM GENERATOR INTERNALS

DECEMBER 2001

UNITED STATES 

NUCLEAR REGULATORY COMMISSION 

WASHINGTON, DC 20555-0001 

OFFICIAL BUSINESS 

PENALTY FOR PRIVATE USE, $300