Steam Generator Tube Failures
Steam Generator Tube Failures
Steam Generator Tube Failures
INEL-95/0383
Prepared by
P. E. MacDonald, V. N. Shah, L. W. Ward, P. G. Ellison
Prepared for
U.S. Nuclear Regulatory Commission
DISCLAIMER
This report was prepared as an account of work sponsored by an agency of the United States
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manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views
and opinions of authors expressed herein do not necessarily state or reflect those of the
United States Government or any agency thereof.
is*
MASTER
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NUREG/CR-6365
INEL-95/0383
Prepared for
Safety Programs Division
Office for Analysis and Evaluation of Operational Data
U.S. Nuclear Regulatory Commission
Washington, DC 20555-0001
NRC Job Code E8238
ABSTRACT
A review and summary of the available information on steam generator tubing failures and the
impact of these failures on plant safety is presented. The following topics are covered: pressurized
water reactor (PWR), Canadian deuterium uranium (CANDU) reactor, and Russian water
moderated, water cooled energy reactor (VVER) steam generator degradation, PWR steam
generator tube ruptures, the thermal-hydraulic response of a PWR plant with a faulted steam
generator, the risk significance of steam generator tube rupture accidents, tubing inspection
requirements and fitness-for-service criteria in various countries, and defect detection reliability
and sizing accuracy.
A significant number of steam generator tubes are defective and are removed from service or
repaired each year. This wide spread damage has been caused by many diverse degradation
mechanisms, some of which are difficult to detect and predict. In addition, spontaneous tube
ruptures have occurred at the rate of about one every 2 years over the last 20 years, and incipient
tube ruptures (tube failures usually identified with leak detection monitors just before rupture) have
been occurring at the rate of about one per year. These ruptures have caused complex plant
transients which have not always been easy for the reactor operators to control. Also, nuclear
power plant design basis accidents, such as a main steam line break, may cause multiple failures
of badly degraded steam generator tubes. Our analysis shows that if more than 15 tubes rupture
during a main steam line break, the system response could lead to core melting. Although
spontaneous and induced steam generator tube ruptures are small contributors to the total core
damage frequency calculated in probabilistic risk assessments, they are risk significant because the
radionuclides are likely to bypass the reactor containment building. The frequency of steam
generator tube ruptures can be significantly reduced through appropriate and timely inspections and
repairs or removal from service. However, a continuing issue has been exactly what constitutes
an appropriate and timely inspection and which degraded tubes are still fit for service. There have
been many different approaches to this problem throughout the world. Also, the most widely used
inspection equipment is not able to detect and size all the degradation of concern.
NUREG/CR-6365
CONTENTS
ABSTRACT
iii
LIST OF FIGURES
xi
LIST OF TABLES
xvi
EXECUTIVE SUMMARY
xix
ACRONYMS
xxix
ACKNOWLEDGMENTS
xxxi
1.
INTRODUCTION
2.
2.1
2.2
2.3
14
2.4
15
2.5
15
2.6
20
20
24
25
28
3.
34
3.1
34
3.2
39
39
48
52
57
59
61
61
NUREG/CR-6365
3.3
64
3.4
64
3.5
65
3.6
67
70
71
3.7
4.
62
62
63
64
71
78
4.1
78
78
79
79
80
80
4.2
Surry Unit 2
4.2.1 Cause of the Tube Rupture
4.2.2 Plant Transient
4.2.3 Operator Actions
4.2.4 Environmental Impact
4.2.5 Remedial Actions
80
80
81
82
82
82
4.3
Doel Unit 2
4.3.1 Cause of the Tube Rupture
4.3.2 Plant Transient
4.3.3 Operator Actions
4.3.4 Environmental Impact
4.3.5 Remedial Actions
83
83
83
83
84
84
NUREG/CR-6365
VI
4.4
Prairie
4.4.1
4.4.2
4.4.3
4.4.4
4.4.5
Island Unit 1
Cause of the Tube Rupture
Plant Transient
Operator Actions
Environmental Impact
Remedial Actions
84
84
84
85
85
85
4.5
Ginna Unit 1
4.5.1
Cause of the Tube Rupture
4.5.2
Plant Transient
4.5.3
Operator Actions
4.5.4
Environmental Impact
4.5.5
Remedial Actions
85
86
89
92
93
93
4.6
Fort Calhoun
4.6.1
Cause of the Tube Rupture
4.6.2
Plant Transient
4.6.3
Operator Actions
4.6.4
Environmental Impact
4.6.5
Remedial Actions
93
93
94
95
95
95
4.7
95
95
96
97
97
97
4.8
McGuire Unit 1
4.8.1
Cause of the Tube Rupture
4.8.2
Plant Transient
4.8.3
Operator Actions
4.8.4
Environmental Impact
4.8.5
Remedial Actions
100
100
100
101
103
103
4.9
Mihama
4.9.1
4.9.2
4.9.3
4.9.4
4.9.5
Unit 2
Cause of the Tube Rupture
Plant Transient
Operator Actions
Environmental Impact
Remedial Actions
103
103
104
104
105
105
105
105
108
109
110
110
vii
NUREG/CR-6365
4.11 Summary and Comparison of the Information from the Ten Steam Generator
Tube Ruptures
4.12 Incipient Tube Rupture Events
5.
114
118
5.1
118
5.2
122
5.3
5.4
5.5
5.6
6.
110
123
131
140
144
5.7
144
5.8
Conclusions
148
149
6.1
Introduction
149
6.2
U.S. Individual Plant Examination Core Damage Frequency and Risk Profile
149
6.3
153
153
6.3.2
154
6.4
157
6.5
Containment Bypass
158
6.6
159
6.7
159
160
161
6.7.3
6.7.4
6.7.5
6.7.6
7.
6.8
Reactor
6.8.1
6.8.2
6.8.3
6.8.4
6.9
Summary
163
165
165
168
170
170
171
173
174
174
176
7.1
176
176
180
181
181
181
181
181
182
182
182
182
7.2
183
183
184
7.3
185
IX
187
189
193
194
194
196
198
198
200
NUREG/CR-6365
7.3.10
7.3.11
7.3.12
7.3.13
7.3.14
7.3.15
8.
9.
in Japan
in Russia
in Slovenia
in Spain
in Sweden
200
201
201
201
202
203
204
8.1
205
205
207
214
8.2
216
216
218
219
220
225
226
8.3
Ultrasonic Testing
226
8.4
230
230
233
233
236
237
237
237
238
8.5
Summary
240
243
10. REFERENCES
253
APPENDIX A
A-l
NUREG/CR-6365
LIST OF FIGURES
1.
2.
3.
4.
12
5.
13
6.
14
7a.
16
7b.
16
8a.
17
8b.
17
9a.
Top view sketch of the tube layout in VVER-440 and VVER-1000 steam generators
18
9b.
Basic arrangement of the heat exchanger tubes and headers used in VVER-1000
steam generators
18
10. Profilometry readings from a typical tube in one of the Siemens/KWU replacement
11.
25
26
12. Typical steam generator tube support layouts used in the United States with tube
13.
27
29
30
31
32
32
35
NUREG/CR-6365
36
40
20.
41
21.
Schematic diagram showing the influence of nickel content on the cracking processes
occurring in three steam generator tubing materials stressed slightly above the yield
point in 350C water
44
45
51
24.
54
25.
56
26.
Weibull analysis of data for PWSCC at hot leg roll transitions and rolled area below
22.
23.
the top of the tubesheet for plants with full depth rolls
68
72
28.
Ginna B steam generator hot leg tubesheet map before event of January 25, 1982
87
29.
88
90
91
30.
31.
32. North Anna Unit 1 reactor coolant system pressure versus time during the first
58 minutes of the transient
33.
34.
35.
98
North Anna Unit 1 pressurizer level versus time during the first 58 minutes
of the transient
98
North Anna Unit 1 reactor coolant system temperature versus time during the
first 55 minutes of the transient
99
99
NUREG/CR-6365
XII
36.
37.
Pressurizer level during the first 39 minutes of the McGuire Unit 1 steam
generator tube rupture event of March 7 and 8, 1989
102
Reactor coolant system and B steam generator secondary side pressure during
the McGuire Unit 1 steam generator tube rupture event of March 7 and 8, 1989
102
38.
Palo Verde Upper Tube Bundle Geometry on the hot leg side
106
39.
Palo Verde steam generator cross section in the region of the tube bundle with
the ruptured tube
107
40.
120
41.
121
42.
124
43.
124
44.
125
45.
126
46.
126
47.
127
48.
128
49.
Failed steam generator wide and narrow range levels vs. time
128
50.
Residual heat removal system inlet and outlet temperatures vs. time
129
51.
129
52.
130
53.
130
54.
132
55.
132
56.
133
57.
133
58.
Break and high pressure safety injection flow rates vs. time
135
59.
135
NUREG/CR-6365
60. Residual heat removal system inlet and outlet temperature vs. time
136
136
137
137
138
138
139
141
141
142
142
71. Break and emergency core cooling injection flow rates vs. time
143
143
73. Residual heat removal system inlet and outlet temperatures vs. time
145
146
146
147
147
78. The U.S. nuclear power plants' core damage frequency distribution as reported to
the U.S. NRC by the IPE programs
150
79. Typical steam generator tube rupture contribution to the total core damage frequency
152
80. Steam generator tube rupture contribution to the total containment bypass fraction
at the Sequoyah nuclear power plant
81. Comparison of two different conditional tube rupture probability screening methods
154
163
82. Estimated steam generator tube failure probability as a function of pressure and
crack depth
169
NUREG/CR-6365
xiv
83.
169
172
207
86. Eddy-current bobbin probe with flexible wafter guides, used for inspection
of steam generator tubesheet rolled joints
208
87. Schematic showing (a) the location of the probe coils in an ac bridge circuit,
(b) an absolute probe configuration, and (c) a differential probe configuration
210
88. Eddy-current signals from a typical calibration tube using (a) an absolute probe
and (b) a differential probe
211
89. A cross section of an eddy-current probe showing how the spring loaded pancake
coil is arranged in an absolute mode
212
213
215
217
217
94. A multiple coil probe for detecting circumferential cracks in steam generator tubing
218
221
222
97. Schematic of a cross wound bobbin coil probe for sleeve inspections
223
98. Schematic of the "I" type motorized rotating pancake coil probe for sleeve inspections
. . . . 224
99. Orientation of the coils in the Zetec Plus-Point probe and typical responses from a weld
scan with the probe configured in the standard differential mode
224
225
227
228
103. Comparison of actual arc length of circumferential cracks in pulled tubes with the
ones estimated using eddy-current inspection
232
NUREG/CR-6365
xv
104. Comparison of actual arc length of circumferential ODSCC cracks in pulled tubes
with the ones estimated using eddy-current inspection
236
A-2
A-3
LIST OF TABLES
1.
2.
their parameters
10
3.
11
4.
19
5.
21
6.
37
7.
PWR plants with more than 2,000 steam generator tubes plugged or sleeved
38
8.
42
9.
43
63
11.
13.
69
and stressor information associated with the ten ruptures discussed in Section 4
Ill
113
116
15.
NUREG/CR-6365
xv l
131
139
17. Steam line break with 15 steam generator tubes failed: sequence of events and key
assumptions
145
151
156
158
164
177
179
186
188
26. Sites, typical characteristics, and inspection of steam generator tube damage
241
xvii
NUREG/CR-6365
EXECUTIVE SUMMARY
defects near, or beyond the limits set by their
country.
Introduction.
The steam generators in the pressurized water
reactor (PWR), Canadian deuterium uranium
(CANDU) reactor, and Russian water moderated,
water cooled energy reactor (VVER) plants are
large heat exchangers that use the heat from the
primary reactor coolant to make steam in the
secondary-side to drive turbine generators. The
primary reactor coolant passes through the tubes
and boils water on the outside of the tubes
(secondary-side) to make steam. The design
confines radioactivity from neutron activation or
fission products to the primary coolant during
normal operation. However, the primary reactor
coolant is at a higher pressure than the secondary
coolant, so any leakage from defects in the tubes
(or in the VVER collectors or PWR tubesheets)
is from the primary to the secondary-side, and
rupture of the heat exchanger tubing can result in
release of radioactivity to the environment
outside the reactor containment through the
pressure relief valves, the condenser off-gas, or
other paths in the secondary system.
NUREG/CR-6365
have experience both expansion-transition and Ubend PWSCC and tubes with PWSCC at dents
have been plugged at, at least five plants.
ODSCC is a degradation mechanism which
includes both intergranular stress corrosion
cracking (IGSCC) and IGA on the outside
surfaces of the tubing. IGSCC requires the same
three conditions as PWSCC: tensile stress,
material susceptibility, and a corrosive environment (in this case, high-temperature water containing aggressive chemicals). IGA is a similar
form of attack but, unlike IGSCC, it can occur
without large tensile stresses present. The cracks
caused by IGSCC can be single cracks or
networks of multiple cracks generally oriented
normal to me maximum principal stress. The
IGA is characterized by a relatively uniform
attack on all the grain boundaries in a particular
area. Often, IGA is a precursor to IGSCC.
Most outside diameter stress corrosion cracks are
primarily oriented in the axial direction, however, significant circumferential cracking has
been observed in the expansion-transition region
of the tubing in some steam generators and
circumferential ODSCC is sometimes found near
dents. Shallow circumferential cracks may sometimes occur in the IGA affected regions producing a grid-like pattern of axial and circumferential cracks termed "cellular corrosion."
NUREG/CR-6365
xx
The major stressor in fretting and wear is flowinduced vibration. Tube vibration can be
induced by fluid cross flow or by parallel flow.
Initiation, stability, and growth characteristics of
damage by these mechanisms may be functions of
a large number of variables, including support
locations, stiffness of the supports, gap size
between tube and support, secondary flow
velocities and directions, and oxide layer
characteristics.
NUREG/CR-6365
NUREG/CR-6365
xxn
xxiii
NUREG/CR-6365
NUREG/CR-6365
XXIV
NUREG/CR-6365
NUREG/CR-6365
xxvi
The rotating pancake coil probe is used for detection of circumferential PWSCC and ODSCC.
This probe can reliably detect circumferential
PWSCC in the expansion-transition region once
it exceeds 50% throughwall depth. Based on the
analyses of pulled tube data at North Anna, the
detection limits of these probes for circumferential cracks in dents is about 50% throughwall
and a 50-degree arc length, or 100% throughwall
and a 23-degree arc length.
No eddy-current methods are qualified at present
for sizing the length and depth of circumferential
cracks. Based on comparisons between measurements from rotating pancake coil probes and
Cecco-5 probes, and metallographic data from
pulled tubes, the nuclear industry has estimated
that the arc lengths of circumferential cracks are
being measured to within 37 to 45 degrees.
The nuclear industry is also currently working on
developing qualified techniques for sizing the
depth of circumferential cracks using Plus-Point
probes, which are sensitive to both circumferential and axial indications.
NUREG/CR-6365
NUREG/CR-6365
xxviii
ACRONYMS
ASDTV
ASME
AVB
antivibration bar
AVT
CANDU
EdF
Electricite de France
EFPY
EPRI
IAEA
IGA
intergranular attack
IGSCC
IPE
LOCA
loss-of-coolant accident
MFEC
multifrequency eddy-current
MPEC
multiparameter eddy-current
MTFS
NDE
non-destructive examination
NPAR
ODSCC
PNL
PORV
PRA
PWR
PWSCC
RCP
RHR
RSG
U.S.
United States
USNRC
VVER
xxix
NUREG/CR-6365
ACKNOWLEDGMENTS
The authors would like to thank Dr. Denwood F. Ross who provided the initial direction for this project
and articulated the need for a comprehensive and integrated evaluation of steam generator tube degradation,
tube rupture, the thermal-hydraulic response of a plant with a defective steam generator, tubing inspection
requirements and fitness-for-service criteria, tube defect detection reliability and sizing accuracy, and plant
risk. The authors would also like to thank the following USNRC staff for their careful review of this report
and helpful comments: J. R. Boardman, J. E. Donoghue, and K. J. Karwoski.
The steam generator design and degradation material (Sections 2 and 3), and the information on steam
generator tubing inspection requirements and fitness-for-service criteria (Section 7), was developed, in part,
during two other projects: the USNRC's Nuclear Plant Aging Research (NPAR) Program and a project
sponsored by the International Atomic Energy Agency (IAEA) to develop guidelines for the aging
management of the major nuclear power plant components. The authors would very much like to thank
the managers of those projects, J. Vora and J. Pachner, for their support and advice. Also, we would like
to acknowledge the support of A. P. L. Turner and J. A. Gorman of Dominion Engineering, on die
original NPAR work. We would also like to acknowledge the technical contributions to the IAEA project
(used mainly in Sections 2 and 7) of J. Bros, Tecnatom, Spain; L. Cizelj, Jozef Stefan Institute, Slovenija;
P. Cornet, Electricite de France, France; Y. G. Dragunov, OKB Gidropress, Russia; G. Fluekiger, NOKBeznau, Switzerland; R. E. Gold, Westinghouse Electric Co., USA; N. Ito, Mitsubishi Heavy Ind., Japan;
C. Maruska, Ontario Hydro, Canada; K. Matocha, Vitkovice, Czech Republic; F. M. Remy, Electricite
de France, France; G. Roussel, Nuclear Safety Institute, Belgium; and T. Schwarz, Siemens/KWU,
Germany.
The authors would also like to acknowledge the work of A. M. Porter who wrote parts of Section 8 and
provided valuable advice on the subject of tube defect detection reliability and defect sizing accuracy.
Finally, the authors would like to thank Paula Olsen who typed the many initial drafts of this report and
Ann Grimes who typed the manyfinalversions of this report and did thefinallayout. Also, we would like
to thank Jim Bryce for providing programmatic guidance, editing and other services to complete the report
in a timely manner.
xxxi
NUREG/CR-6365
NUREG/CR-6365
INTRODUCTION
Certain nuclear power plant design basis
accidents, such as a sudden break in the steam
line, can lead to rapid depressurization of the
secondary coolant system. The pressure difference across the tubing walls generated during
these accidents may result in simultaneous
leakage or rupture of a number of steam generator tubes when an active degradation mechanism
has severely damaged a large number of tubes.
Simultaneous leakage or rupture of several tubes
can lead to a plant transient which is even more
difficult to control than a spontaneous tube rupture transient, and radioactivity levels released to
the environment which may exceed site limits.
The sudden rupture of several steam generator
tubes also results in a rapid depressurization of
the primary coolant system and possibly may
uncover the core and cause core melting.
The frequency and consequences of steam generator tube failures can be significantly reduced
through appropriate and timely inspections and
plugging or sleeving of excessively damaged
steam generator tubing. Most steam generators
are routinely inspected during plant outages,
when their internal structures become accessible
to non-destructive inspection equipment, and the
defective tubes repaired or plugged as necessary.
However, a continuing issue has been exactly
what constitutes an appropriate and timely inspection and which partly defective tubes are still
fit for service. The steam generator tube inspection requirements and fitness-for-service criteria
vary from country to country, and are even
somewhat different at separate plants within certain countries such as the United States (U.S.).
This is because:
NUREG/CR-6365
The frequency and extent of the inspections often increase as problems develop.
INTRODUCTION
Objective. The objective of this report is to put
the issue of steam generator tubing failure, and
its impact on nuclear power plant safety, in
perspective. To do this, we have summarized
much of the available information on the
following topics:
NUREG/CR-6365
Steam outlet
i
Primary inlet
Recirculating
steam generator
RED 0772
NUREG/CR-6365
Primary outlet
Moisture separator
Manway (2) 180 apart
Tube bundle
Tube supports
Lower shell
Divider plate
Feedwater inlet
Tube sheet
Manway
Channel head
Primary coolant outlet
Support foot
Primary coolant inlet
M96 0081
NUREG/CR-6365
NUREG/CR-6365
Main steam
Steam/water
mixture
Water level
Auxiliary feedwater
nozzle
Steam/water
mixture leaves
tube bundle
Preheater
Main feedwater
ozzle
Primary fluid
outlet
RED 0769
NUREG/CR-6365
Westinghouse (recirculating)
24
27
33
44"
51.A-M7
D2/D3,
24,834
27,700
33,340
44,500
51,500
48,000
47,000
No. of tubes
2,604
3,794
2604
3,260
3,388
4,674
4,578
82
100
82
92
94
114
114
Tube pattern
Square
Square
Square
Square
Square
Square
Square
1.2187
1.026 or 1.031
1.25
1.200 or 1.234
1.281
1.063
1.063
Tube dimensions
(in.)
0.875x0.050
0.750x0.055
0.875x0.050
0.875x0.050
0.875x0.050
0.750x0.043
0.750x0.043
Tubing material
Alloy 600
Alloy 600
Alloy 600
Alloy 600
Alloy 600
Alloy 600
Alloy 600
Tubing heat
treatment
Mill-annealed
Mill-annealed
Mill-annealed
Mill-annealed
Mill-annealed
Mill-annealed
Mill-annealed
Tubesheet
expansion method
Part-depth
rolled
Part-depth
rolled
Part-depth
rolled
Part-depth
rolled
Part-depth
rolled
Full-depth
rolled
Full-depth
rolled
Tubesheet crevice
depth(in.)
18.25
18
18
18, 19, or 20
18, 18.75 or
19"
None
None
Drilled hole
Drilled hole
Drilled hole
Drilled hole
Drilled hole
Drilled hole
Drilled hole
Tube support
material
Carbon steel
Carbon steel
Carbon steel
Carbon steel
Carbon steel'
Carbon steel
Carbon steel
Preheater type
None
None
None
None
None
Split flow
Counterflow,
expanded
preheater
tubes
Flow distribution
baffles
None
None
None
None
None"
D2no,
D3yes
Yes
D4'
a. Replacement Models 44F, 51F and 54F use hydraulically expanded, tfiermally treated Alloy 600 tubing and 405 stainless steel tube support plates, except for die
model 54Fs at D.C. Cook and Indian Point Unit 3 which have thermally treated Alloy 690 tubing. The replacement models generally match the heat transfer area of
the steam generators they replaced except for the 54 Fs with Alloy 690 tubing which are slightly larger than the original 51s due to the slightly lower thermal heat
transfer properties at the Alloy 690 material vis-a-vis the Alloy 600 material.
2
b. 1 ft = 0.093 m , 1 in = 25.4mm.
c. Later Model 51s used full-depth rolled or explosively expanded tubes. The tubesheet thickness ranges from 525 to 610 mm.
NUREG/CR-6365
Combustion Engineering
(recirculating)
B&W oncethrough
Westinghouse (recirculating)
A75
177
67
80
50,000
75,180
132,500
90,700
N/A
4,864
5,626
6,307
15,531
8,519
11012
114
120
122
70
167
N/A
Triangle
D5
E'
47,000
50,000
No. of tubes
4,570
Tube pattern
Triangle
Triangle
Triangle
1.063
1.080
0.980
0.980
0.875
0.974, 1.00
1.000
Tube dimensions
(in.)
0.750 X 0.043
0.7S0 x 0.043
0.688 X 0.040
0.688x0.040
0.625 x 0.034
0.750 X 0.048
0.750 X 0.042
Tubing material
Alloy 600
Alloy 600
Alloy 600
Alloy 690
Alloy 600
Alloy 600
Alloy 600
Tubing heat
treatment
Thermally
treated
Mill-annealed or
therm, treated
Thermally
treated
Thermally
treated
Mill-annealed
Mill-annealed
Mill-annealed
Tubesheet
expansion method
Hydraulic
Full-depth rolled
or hydraulic
Hydraulic
Hydraulic
Partial-depth
rolled
Explosive
Explosive
None
None
None
None
22
None
None
Broached
quatrefoil
Drilled
Broached
quatrefoil
Broached
trefoil
Broached
trefoil
Eggcrate/
vertical
Eggcrate/
vertical
Tube support
material
Stainless steel
Carbon or
stainless
405 stainless
steel
405 stainless
steel
Carbon or
MnMo steel
Carbon steel
Stainless steel
Preheater type
Counterflow,
expanded preheater tubes
Counterflow,
expanded
preheater tubes
None
None
None
None
Axial flow
Flow distribution
baffles
Yes
Yes
Yes
Broached
plate
No
None
Yes
NUREG/CR-6365
CO
a
o
w
>
Table 2.
Typical Mitsubishi Heavy Industries recirculating steam generator models and their parameters.
MHI
46F
MM
44
Manufacturer
and Model
MHI
51.51A
MHI
51M
MHI
51F,51FA
MHI
52F.52FA
MHI
54F.54FA
4,300
4,785
4,780
4,780
4,870
5,055
No. of tubes
3,260
3,382
3,388
3,382
3,382
3,382
3,382
92
94
94
94-
94
94
94
Tube pattern
Square
Square
Square
Square
Square
Square
Square
Tube spacing(mm)
31.35
32.54
32.54
32.54
32.54
32.54
32.54
Tube dimensions(mm)
22.23x1.27
22.23x1.27
22.23x1.27
22.23x1.27
22.23x1.27
22.23x1.27
22.23x1.27
Tubing material
Alloy 600
Alloy 690
Alloy 600
Alloy 600
Alloy 600
Alloy 690
Alloy 690
Mill-annealed
Thermally treated
Mill-annealed
Mill-annealed,
Thermally treated
Thermally treated
Thermally treated
Thermally treated
Tubesheet expansion
method
Part-depth rolled
Full-depth rolled,
Full-depth hydraulic Full-depth hydraulic Full-depth hydraulic
Full-depth hydraulic and one step rolled and one step rolled and one step rolled
and rolled
Tubesheet crevice
depth(mm)
497"
(original design)
None
488", None
None
None
None
None
Drilled
Broached eggcrate
Drilled
Drilled,
Drilled chamfer
Broached eggcrate
Broached eggcrate
Broached eggcrate
Carbon Steel
Carbon steel
Carbon steel,
405 stainless steel
Preheater type
None
None
None
None
None
None
None
Flow distribution
baffles
None
Yes
None
Yes
Yes
Yes
Yes
H
O
a
a
GO
o
MAN-GHH
Obriglieim (Repl.)
ltalcke
Stadc
Bnbcock
Biblis A
1,1
Standard with
prehcater
MAN-GHH
Konvo! *>
11
2750
3070
2930
4510
5386
5427
5105/6103/7155
No. of tubes
2605
3010
2993
4060
4086
4118
5130/5428
81
46
49
55
48
54
57/59
Tube pattern
rectangular
triangular
triangular
triangular
triangular
triangular
triangular
27.9 x 28.8
29.0
29.3
30.0
30.0
30.0
26.164
22x1.23
22 x 1.23
Manufacturer
antl model
2
22 x 1.23 (1.5)'>
22 x 1.23
Tubing material
Alloy 600
Alloy 800 M
Mill annealed
Tubesheet expansion
method
Part-depth rolled
(3 locations)
None
eggcrate
stainless steel
Preheater type
None
b)
p)
Alloy 800 M
p)
Alloy 800 M
22 x 1.23
p )
Alloy 800 M
p>
Replacement SGs
for 51C/51M/D3
m)
m>
22x1.23
19.05 x 1.09
8)
8)
e)
s>
8)
Part-depth rolled
(both ends)
Part-depth rolled
(both ends)
Part-depth rolled
(both ends)
Part-depth rolled
(both ends)
Part-depth rolled
(both ends)
None
None
eggcrale "
eggcrate
stainless steel
stainless steel
None
None
None
None
eggcrale "
eggcrate *
eggcrate *>
eggcrate
stainless steel
stainless steel
stainless steel
stainless steel
c)
None
None
None
Split-flow design
None
None
Yes
None
None
Yes
None
Yes
U-Bend Treatment
None
None
None
None
None
None
None
None
None
None
None
None
None
CO
Notes:
S5
C
a)
b)
c)
d)
e)
t)
W
O
g)
h)
n
w
o\
Ux
j)
k)
m)
o)
P)
o
m
a
%
H
O
73
o
m
CO
1*
Periphery
0.875 in.
Interior
Kidney-shaped
region
Inspection lane I
oooooooo
Wedge area
QOOOOOOOO
Untubed
inspection lane
ooooooooo
Support
rods
QOOOOOOOO
ooooooooo
ooooooooo
Triangular pitch OTSG
Blowdown lane
oooooo
OOOOO04
Square pitch RSG
'
Blowdown lane
ogogogogj
3
OMDMCHO
t
1-0382
NUREG/CR-6365
12
Legend
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
Steam drum
Steam generator
Heavy water inlet (2)
H eavy water outlet
Downcommer annulus
Primary cyclones
Secondary cyclones
Blowdown nozzles
Manway
Main steam outlet nozzles
Preheater
Steam generator support
Contaminant seal bar/skirt
Lower lateral restraint lugs
Reheat condensate return nozzle
Feedwater nozzle
Upper lateral restraint lugs
Ring beam
Figure 5. CANDU Recirculating Steam Generator used at the Darlington station. This design is typical
of the current CANDU models. Courtesy of C. Maruska, Ontario Hydro.
13
NUREG/CR-6365
Fourteenth tube
support plate
periphery tube
erosion/corrosion
Aspirating steam
NUREG/CR-6365
NUREG/CR-6365
4. Moisture separator
5. Steam collector
6. Feedwater inlet
Figure 7a. WER-440 steam generator (side view). Courtesy of Y. G. Dragunov, OKB Gidropress.
Steam pipe
Hot
Collector
5.896 m
Tubing
Figure 7b. VVER-440 steam generator (end view). Courtesy of Y. G. Dragunov, OKB Gidropress.
NUREG/CR-6365
16
~-I~<-!1
"V--"i 1&
r
a: ..&$
*$>-,~-.
t
l
: """;
/-->'
// /^1 ~ -v
A
2!
/V
/ -/A
K- ' '/jfrV
NUREG/CR-6365
18
VVER-440
VVER-1000
VVER-1000U
Thermal power, MW
229.2
750
750
125
408.33
408.33
4.61
6.27
6.27
Steam temperature, C
258.9
278.5
278.5
164-223
164-220
164-220
295
267
320
290
320
292
7100
21200
21200
12.26
15.7
15.7
2.71
4.21
4.91
4.7
5.4
6.1
18.7
22.9
24
89.23
123
141
2576.6
6115
5126.6
5536
11000
9157
16x1.4
16x1.5
16x1.5
9.26
11.10
11.14
0.075
0.126
0.169
0.240
0.382
0.382
0.25
0.2
0.2
Vessel material
22K
10GN2MFA
10GN2MFA
10GN2MFA
with inner cladding
08X18N10T
perforated area
Feedwater temperature, C
Coolant temperature, C
- at steam generator inlet
- at steam generator outlet
3
Collector material
08X18N10T
08X18N10T
08X18N10T
08X18N10T
800
136
834
171
with cladded layer
780
198
11.34
77
89
6.93"
110
120
9.75
94
112
19
NUREG/CR-6365
VVER-440
VVER-1000
VVER-1000U
square array
24
29.5
staggered
19
23
staggered
22.1
25, 23
absent
installed
installed
4-6
1.5
1.9
Void fraction, %
0.32
0.493
0.485
This material is also labeled 08Crl8NilOTi which is a titanium stabilized austenitic stainless steel with .08%
carbon, 18% chrome, 10% nickel and less than 1% titamum.
b.
c.
NUREG/CR-6365
Ni
Cr
Fe
Cu
14-17
6-10
<0.15
_<.1.0
_<0.5
^.58
28-31
7-11
0.015-0.025 _<0.5
_<0.5
32-35
20-23
^.39.5
^.0.03
0.4-1.0
0.3-0.7
<0.75
_<2.5
j<0.3
j<2.0
j<0.5
28-34
MoneUOO ^ 6 3 . 0
to
Si
>12
800M
ow
Mn
600'
690
C
jo
Siemens/KWU Specification
<Q.5
-
Al
Co
Ti
^.0.5.
j<0.02
.<0.5
0.15-0.45
j<0.1
.<0.6
S
_<0.015
j<0.01
.<0.024
NUREG/CR-6365
Siemens/KWU Practice.
The first two
Siemens/KWU steam generators were supplied
with Alloy 600 mill-annealed tubing and began
leaking after two years of operation. Thereafter,
all Siemens/KWU steam generators were
fabricated with Alloy 800M tubing (about onehalf as much nickel as Alloy 600). Compared to
the standard Alloy 800 ASTM specification,
Siemens Alloy 800M has a reduced carbon
content to minimize sensitization, an increased
stabilization ratio (Ti/C > 12), and slightly
increased chromium and nickel contents to
achieve a higher resistance to pitting and
transgranular stress corrosion cracking.
23
NUREG/CR-6365
NUREG/CR-6365
24
Hydraulic Expansion
Upper Mechanical
Expansion
Lower Mechanica
Expansion
17.7
17.6 17.5 -
E, 17.4 -
17.3 -
17.2 a>
33 17.1 _= = = =
'</>
c. 17.0 CO
X)
3
16.9
If
!
16.8
16.7
Tubesheet Thickness
ITTS-HL
i
J iii
TE-HL
i i i t i i i i i i i 1 _
...j..
700 650 600 550 500 450 400 350 300 250 200 150 100 50
Tube length (mm)
0
M95 0139
Figure 10. Profilometry readings from a typical tube in one of the Siemens/KWU replacement steam
generators for Ringhals Unit 2. Courtesy of P. J. Meyer, Siemens AG.
The VVER steam generators use two vertical
cylindrical collectors or headers, each with an
inside diameter of 800 mm (VVER-440) or
834 mm (VVER-1000) and a wall thickness of
136 mm (VVER-440) or 171 mm (WER-1000)
rather than a thick-wall tubesheet. As mentioned
above, the WER-440 collectors are made of the
same Ti-stabilized stainless steel as the tubing.
The WER-1000 collectors are made of the same
low alloy pearlitic steel (Type 10GN2MFA) as
the vessel, with stainless steel cladding on the
inside surface. The tubes are embedded against
the collector wall by explosion or hydraulic
expansion and welded at the collector inside
surface using argon-arc welding. Collector-tube
crevices generally do not exist, however, some
25
NUREG/CR-6365
Drilled Plate
(with flow holes)
Broach-Quatrefoil
Broach-Trefoil
Eggcrate
Figure 11. Typical tube support configurations (EPRI 1985a). Copyright 1985 Electric Power Research
Institute; reprinted with permission.
NUREG/CR-6365
26
Vertical
hot/cold leg
supports
Outermost
tube
H10
Diagonal bar
hot leg
Diagonal bar
cold leg
H 9
C8
Innermost
C7 t e
U D
Hot leg
supports H4
m
111*
llllll llllipi !U l | i
Inlet
Outlet
jperheater
sectson
Tubesheet
CTS
HTS
IIUI1H! U I :
Steam-xT
outlet ^
S90 0196
<
| llllllllll 1 \h
fll|illll!lll
hi
ail" &m
lipliiliiii y #
mm m
pi mi |n iII
mrmpin\
*
Broiler
section
f i l l n HIuir
llllllllll 3 1
fjii II i II iJS.JM
itiiiiif nil
ft] PI[ill
wmm ^
Tubesheet
Primary outlet
nozzles
Westinghouse recirculating
steam generator
Tube Support Plate/Tubesheet Nomenclature
B & W once-through
steam generator (3)
S900198
S90 0197
Westinghouse model 51
Figure 12. Typical steam generator tube support layouts used in the United States with tube support plate
and tubesheet nomenclature.
27
NUREG/CR-6365
NUREG/CR-6365
28
Row 73
No. 8 tube support
partial drill hole
support plate
No. 7 tube support
partial egg crate
with drill hole
plate section
CE RSG Anti-vibration
bar arrangement
AVB
%r^py
^SJ5^
Model F Anti-vibration
bar arrangement
11 16
Model 51 Anti-vibration
bar arrangement
0:3083
29
NUREG/CR-6365
Support Plate
Tube -
Plate
High Support
Bar
Low Support
Bar
Tube -
Flow Space
Tube to Support
Clearance
Flow Space
Tube l
Low Support
Bar
Figure 14. Typical CANDU steam generator tube support structures. Courtesy of C. Maruska, Ontario
Hydro.
NUREG/CR-6365
30
J
Feedwaternozzle
- Upper shell
-c
Lower shell
]
N91 0456
Figure 15. PWR steam generator showing shell welds (Westinghouse 1990). Copyright Westinghouse
Electric Corporation; reprinted with permission.
31
NUREG/CR-6365
Feedwater nozzel
Pipe
Thermal sleeve
Weld
Bore cracks
Nozzle blend
radius cracks
N910454
Figure 16a. Typical Westinghouse feedwater nozzle and thermal sleeve design with the sites susceptible
to high-cycle thermal fatigue damage caused by turbulent mixing of leaking feedwater and hot steam
generator coolant identified (Westinghouse 1990). Copyright Westinghouse Electric Corporation; reprinted
with permission.
Weld
21.4 mm
(0.844 in.
Deepcs: ^ ^
crack
^*^
|
\
T
/
S
-
Fiow-^Pipe end
[406 mm (16 in.) Schedule 80]
17 mm
(0.656 in.)
Figure 16b. Westinghouse feedwater piping-to-nozzle weld design at the D.C. Cook plant with crack
locations identified (USNRC 1980)..
NUREG/CR-6365
32
33
NUREG/CR-6365
NUREG/CR-6365
c
<u
H
0
o
0)
O)
O)
-I
Mmr
'v
>
>
?
/,
'/
-[aO
' <
< *
-C\
*,,<'
*',.
$:
\$0
",30
i '.
,23
_ i
.34
i "
...22
Jv
-L
j-17
i <
r '
? *
-I:
u^
i-,
87
88
89
90
GO
91
o
w
z
92
i
o
ON
U)
ON
Figure 17. Percentage of PWR and CANDU steam generator tubes plugged (EPRI 1995a). Copyright 1996 Electric Power Research
Institute; reprinted with permission.
o
z
on
H
PI
>
m
a
n
100%
o
w
z
ffl
>
H
O
ON
o\
?a
O
m
O
>
>
H
O
ON
Year
Figure 18. Worldwide causes of steam generator plugging (EPRI 1995a). Copyright 1996 Electric Power Research Institute;
reprinted with permission.
3/77
8/82
12/94
NO. UNITS:
52
99
240
15
30
37
- Tubesheet Corrosion
12
49
- Wastage
19
28
39
- Pitting
21
- ID Cracking
22
103
- ODSCC/IGA
22
87
- Fretting
15
131
- Fatigue Cracking
16
- Impingement
No Problems
26
32
56
1/14
4/57
28/217
REPORTED PROBLEMS:
Denting
Tubing Corrosion
Mechanical Damage
8/82
12/94
Kewaunee
Mihama 3
Neckarwestheim
Davis Besse
Brokdorf
Chinon B 3
Cook 2(Rpl)
Cruas 3
Cruas 4
Emsland
Genkai l(RpI)
Genkai 2
Grafenrheinfeld
Indian Point 3(Rpl)
Isar2
Loviisa 1
Loviisa 2
Neckarwestheim 2
37
Obrigheim (Rpl)
Philippsburg 2
Pickering A 2
Pickering A 3
Pickering A 4
Pickering B 7
Pickering-B 8
Ringhals 2 (Rpl)
Robinson 2 (Rpl)
Tomari 1
Trillo 1
Ulchin 1
Ulchin 2
Wolsung 1
NUREG/CR-6365
Table 7. PWR plants with more than 2,000 steam generator tubes plugged or sleeved.
PLANT
ASCO-1
1,866
249
Cook-1
1,468
1,840
Doel-4
2,290
12,970
Ginna
648
2,198
Kewaunee
1,017
4,202
Kori-1
1,531
1,544
Maine Yankee
573
-16,536
McGuire-1
2,960
McGuire-2
2,189
Ohi-1
2,647
5,511
Point Beach-2
945
3,674
San Onofre-1
1,456
6,929
1,641
502
Trojan
2,444
1,115
a. All the data except Maine Yankee is for the time period up to the end of December 1994 (EPRI 1995a). The Main Yankee numbers include the
sleeving done in 1995 and 1996.
NUREG/CR-6365
38
3.2.1
Primary Water Stress Corrosion
Cracking
The corrosion behavior of austenitic alloys is
strongly dependent on me nickel and chromium
content. The influence of the nickel content on
the stress corrosion cracking processes in 18%
chromium austenitic alloys when stressed slighdy
above the yield point of the material in
demineralized water or water containing 1 g/i
chloride ions is shown in Figure 21 (Berge
1993). As indicated on the figure, Alloy 600 can
be susceptible to pure (primary) water stress
corrosion cracking, whereas, Alloy 690 and
Alloy 800M are generally not susceptible to
PWSCC. Austenitic stainless steels with a nickel
content below about 15% are susceptible to
transgranular stress corrosion cracking when
exposed to water containing significant amounts
of chlorides (1 gift). The effects of chromium
content on austenitic alloy material release rates
due to corrosion in high temperature, low
oxygen, borated water flowing at 5.5 m/s are
shown in Figure 22. The high chromium alloys
(800 and 690) appear to lose much less material,
probably because of the low solubility of
chromium oxides in low oxygen primary coolant
(Berge and Donati 1981).
The data plotted in Figures 21 and 22 suggest
that Alloy 600 is much more susceptible to
PWSCC than Alloys 800 or 690 and, in fact,
PWSCC of Alloy (Inconel) 600 was identified in
the laboratory as early as 1959, when Coriou et
al. (1959) reported cracking of this material in
"high purity" water at 350C (662F). PWSCC
of Alloy 600 steam generator tubing was first
observed in the hot leg roll-transitions at the
Obrigheim plant in 1971. Subsequent research
showed that this was an intergranular cracking
mechanism requiring at least the following
conditions to be present:
NUREG/CR-6365
Inner row
U-bends
Fretting or
AVB wear
High-cycle
futigue at
>dents
v
IGA/IGSCC
onOD.
Sludge
pile /Wastage/Pitti
IGA/IGSCC
onOD
PWSCC
cracking
on ID
Hot & cold leg
tube-to-tubesheet crevices
Hot leg
tube-to-tubesheet crevice
N91 0406
Figure 19. Locations of known tube wall degradations in recirculating steam generators. (Courtesy of
K. J. Krzywosz of the Electric Power Research Institute NDE Center; modified.)
NUREG/CR-6365
40
Figure 20. Degradation mechanisms and locations in CANDU recirculating steam generators. Courtesy
of C. Maruska, Ontario Hydro.
41
NUREG/CR-6365
55
c!
GO
90
a
a
n
90
Rank"
Degradation
Mechanism
ODSCC
ON
OS
PWSCC
Fretting,
Wear
Degradation Sites
Stressor
ISI Method
Tubc-(o-tubcshcet crevices
Sludge pile
Tube support plate
Free span
Axial or circumferential
crack
Circumferential crack
Axial crack
Axial crack
MRPC
MRPC/Cccco 5
Bobbin coil/Cecco 5
Bobbin coil (in absolute mode)
Temperature, residual
tensile stresses,
sensitive materials
(low mill anneal
temperature)
Mixed Crack
Mixed Crack
Axial Crack
Circumferential Crack
MRPC
MRPC
MRPC
Bobbin coil or MRPC
Flow induced
vibration, aggressive
chemicals
Local wear
Bobbin coil
Bobbin coil
Bobbin coil
High-cycle
fatigue
Transgranular
circumferential cracking
Denting
Pitting
Brackish water,
chlorides, sulfates,
oxygen, copper oxides
Wastage
Phosphate chemistry,
chloride concentration,
resin leakage
General thinning
Bobbin coil
>
Tensile stresses,
impurity
concentrations,
sensitive materials
4
to
Potential Failure
Mode
>
H
O
90
D
am
90
>
D
>
H
II
Degradation
Mechanism
ODSCC
Stressor
Degradation Sites
High stress,
U-bend support
corrosive
intersections
environment due to
deposit build-up
7th support plate
Potential Failure
Mode
ISI Method
Circumferential
cracking
Cecco 3
Predominantly
circumferential,
some axial
Cecco 3
Outside diameter
pitting
Deposits which
cause a corrosive
environment
Tubesheet area
Local tube thinning
under sludge pile
leading to holes
and at lower tube
support
intersections and at
freespan tubes
E/C [carter]
Ultrasonics
Fretting
Flow induced
vibration, loose
supports
U-bend support
intersections
Bobbin coil
Corrosion of
carbon steel
supports
Corrosive
U-bend supports
environment, stress
Visual (secondary
Support
disintegration and
access)
metal loss/may lead
to tube degradation
from flow induced
vibration due to
lack of support
Erosion-corrosion,
high or low cycle
fatigue
Bolt failure
Break up of bolted
plates may lead to
blockage of PHT
inlet
Primary head
Visual and
metallography of
bolts
43
NUREG/CR-6365
Transgranular
Intergranular
Ci-Containing Water
(1000 ppm)
10
20
30
Demineralized Water
40
50
Inconel 800
19...23%Cr
60
Inconel 690
27...31%Cr
70
80
Ni-Content
Inconel 600
14...17%Cr
M95 0140
Figure 21. Schematic diagram showing the influence of nickel content on the cracking processes occurring
in three steam generator tubing materials stressed slightly above the yield point in 350C water (From
Coriou 1971, as reported by Berge 1993). Copyright 1993 Electric Power Research Institute; reprinted
with permission.
NUREG/CR-6365
44
16
Alloy
600
14
*
12
o Descaled metal loss
Corrosion film weight
Material lost to stream
10
8
6
4
Alloy
690
2
20
25
Chromium (%)
30
M96 0143
Figure 22. Effect of austenitic alloy chromium content on material lost due to corrosion in deaerated,
borated water flowing at a velocity of 5.5 m/s (From Sedriks et. al 1979, as reported by Berge and Donati
1981). Copyright 1981 American Nuclear Society, Inc., LaGrange, Illinoise; reprinted with permission.
45
NUREG/CR-6365
2.
3.
NUREG/CR-6365
5.
6.
Q/RT
47
NUREG/CR-6365
NUREG/CR-6365
48
NUREG/CR-6365
NUREG/CR-6365
4 10
40 100 400 1000
NaOH concentration (g//)
M96 0142
Figure 23. Resistance to stress corrosion cracking of mill-annealed or heat treated Alloy 600, Alloy 690,
Alloy 800, and Type 316 stainless steel as a function of sodium hydroxide concentration at 350C (Berge
and Donati 1981). Copyright 1981 American Nuclear Society, Inc., LaGrange, Illinoise; reprinted with
permission.
51
NUREG/CR-6365
NUREG/CR-6365
52
NUREG/CR-6365
Tubes
Scalloped Bars
Figure 24. CANDU recirculating steam generators staggered scallop bar arrangement. Courtesy of C.
Maruska, Ontario Hydro.
region of the longest diagonal support span.
Plants experiencing this AVB wear have plugged
tubes as indicated necessary by NDE wall-loss
evaluations. Vendor analysis of the problem has
concluded that the degradation is self-limiting
since only a relatively smallfraction(3 to 4%) of
the tubes experience the requisite cross flow
force for degradation to occur. As a result,
preventive plugging of all these tubes is possible
without threatening steam generator life
(Harberts 1986).
NUREG/CR-6365
54
NUREG/CR-6365
4-4
11
4-4
U-
4-f 4r4
~>
f-4
ii^)(-M^
t
Lower
tube
sheet
){
^<//y^.
Counter flow
Split flow
Axial flow
(cold leg side)
RED 0777
Figure 25. Preheater cross sections (EPRI 1994a). Copyright 1994 Electric Power Research Institute;
reprinted with permission.
NUREG/CR-6365
56
3.2.4 Pitting
Pitting is a steam generator degradation type
appearing as groups of small-diameter wall
penetrations resulting from local corrosion cells,
probably promoted by the presence of chloride or
sulfate acids. Condenser leaks and leakage of
beads, resin fines, or regeneration chemicals
from ion exchangers can introduce impurities
such as chlorides and sulfates, which result in
local acidic conditions conducive to pitting.
Oxidizing conditions and the presence of copper
are probable accelerators. Any barriers to
diffusion such as sludge accumulation on the tube
wall will accelerate the pitting process by
enhancing the chemical concentrations.
57
NUREG/CR-6365
58
rence of ODSCC and denting. The primary design modification to be considered is the removal
of all copper from the secondary-coolant system.
(four Combustion Engineering and 37 Westinghouse-type plants) had been plugged because of
tubesheet and sludge pile denting and 9,092 RSG
tubes at 17 plants (four Combustion Engineering
and 13 Westinghouse-type plants) had been
plugged because of support plate denting (EPRI
1994). Significant support plate denting occurred
at only five plants: Millstone Unit 2 (796 tubes),
Surry Unit 1 (1,996 tubes), Surry Unit 2 (1,964
tubes), Turkey Point Unit 3 (1,249 tubes), and
Turkey Point Unit 4 (1,835 tubes); all of the
original steam generators at those plants have
since been replaced. The majority of the support
plate denting has occurred on the hot leg side at
plants with seawater or brackish water for condenser cooling.
3.2.5 Denting
The term denting describes the mechanical
deformation or constriction of a tube at a carbon
steel tube support plate intersection or within the
tubesheet caused by the buildup of deposits and
the growth of a voluminous support-plate or
tubesheet corrosion product in the annulus
between the tube and support plate or tubesheet.
Denting has also been reported in the sludge pile
region of certain plants where iron particles were
embedded in the sludge pile. Dents do not
themselves result in tube wall penetration or
reduction in wall integrity. However, denting at
some plants has been sufficiently severe that it
caused structural damage to the tube supports and
denting is a concern because even small dents can
induce tensile stresses above yield strength in the
tube wall. As a result, these tubes may be
subject to PWSCC or IGSCC at the dents during
subsequent operation, (EPRI 1985a, Clark and
Lewis 1985). Also, tubes with dents at the top
tube support plate in the U-bend region of the
RSGs are more susceptible to high-cycle fatigue
failure. Tubes with small dents can be kept
inservice unless subsequently found to have stress
corrosion cracking. Tubes with dents large
enough to restrict calibrated go/no go probes
must be plugged because they are not inspectable
and are expected to crack.
Status. Denting of Alloy 600 tubes at tube-totube support plate intersections was first identified as a significant steam generator degradation
mechanism in about 1975, shortly after the time
when many PWRs switched from phosphate to
AVT secondary-side water chemistry, and this
degradation mechanism became the primary
cause of steam generator tube plugging during
the period 1976 through 1979 (Figure 18). As of
December 1993, 1,471 RSG tubes at 41 plants
59
NUREG/CR-6365
NUREG/CR-6365
NUREG/CR-6365
NUREG/CR-6365
Degradation
site(s)
Degradation
mechanism(s)
Stressors
Potential
failure mode
Inservice inspection
method(s)
Outside surfaces
of the tubes on
the periphery of
the tube bundle
near the 14th
tube support
plate
Erosion-corrosion from
impingement of particles
Wear of material
Eddy-current testing
Tube outside
surfaces near the
upper tubesheet
and the open
lane or near the
uppermost tube
support plate
and the open
lane
Aggressive chemicals,
vibration
Environmentally
assisted high-cycle
fatigue
Circumferential cracks
Eddy-current testing
Inside surfaces
of tubes near the
upper tubesheet
roll transitions
and welds
(primary side)
Low-temperature
primary-side stress
corrosion cracking
Circumferential cracks
Eddy-current testing
63
NUREG/CR-6365
NUREG/CR-6365
F(t) = 1 - exp[-(t/t ) ]
r
where
F(t) = cumulative fraction of tubes
"failed" by a given degradation
mechanism
t
NUREG/CR-6365
where
t
gas constant
constant
determined
from t,,, = A o ' , where
t is the characteristic
time for reference condition T , a .
NUREG/CR-6365
ro
67
NUREG/CR-6365
0.10
-
/
A
/ /
/
0.01
[re
"o
c
.o
7 <'./..
< .-:*
-A
* *
./.
V
Dashed line
= postpeening
.A
.A/
'
'
* *
.-'
-A
'/
'
:x
r;
CO
CO
(0
^s
0.001
Low temperature
mill-annealed tubing
T ot! g=616 Fto619F
(324C to 326C)
//A
.A
- /
c
A''
0.0001
.1
'
10
Service time (EFPY)
0-3076
Figure 26. Weibull analysis of data for PWSCC at hot leg roll transitions and rolled area below the top
of the tubesheet for plants with full depth rolls. Courtesy of A.P.L. Turner, Dominion Engineering.
Table 11 lists, and ranks by importance, the
degradation mechanisms, sites, stressors, failure
modes, consequences, and inspection methods for
the PWR feedwater nozzles and the steam
generator shells. The feedwater nozzle is ranked
highest, because a break at this point would cause
NUREG/CR-6365
68
Table 11. Summary of degradation processes for PWR feedwater nozzles and steam generator shell.
Rank"
0\
Degradation site(s)
Stressors
Degradation mechanism(s)
Inservice inspection
metliod(s)
Ultrasonic testing
radiography
Corrosion-fatigue, stress
corrosion cracking
Ultrasonic testing,
radiography
Ultrasonic testing,
radiography
Erosion-corrosion
Problem remedied,
inspection unnecessary
NUREG/CR-6365
71
NUREG/CR-6365
Oxide-water
interface (E)
Metal-oxide
interface
(A&B)
A. Iron hydroxides are generated: Fe + 2H 0c*Fe(OH)2 + H
B. Magnetite is formed according to the Schikorr reaction:
3Fe(OH) c - Fe 0 + H + 2H O
C. A fraction of the hydroxides formed in step B and hydrogen generated in steps A and
B diffuse along pores in the oxide
D. Magnetite can dissolve in the pores
E. Magnetite dissolves at the oxide-water interface
F. Water flow removes the dissolved species by a convection mass transfer mechanism
G. Solid particles break off porous oxide layer by a mechanical
erosion mechanism
2
N91 0447
NUREG/CR-6365
72
NUREG/CR-6365
(b)
(c)
(d)
The pearlitic steel used for the W E R 1000 collectors undergoes strain aging at
about 290C (554F). It is also more
susceptible to stress corrosion cracking at
temperatures below 280C (536F) than
at higher temperatures.
(e)
NUREG/CR-6365
(f)
74
WER
NUREG/CR-6365
NUREG/CR-6365
77
NUREG/CR-6365
NUREG/CR-6365
78
79
NUREG/CR-6365
NUREG/CR-6365
80
81
NUREG/CR-6365
NUREG/CR-6365
82
4.3 DoelUnit2
83
NUREG/CR-6365
NUREG/CR-6365
84
85
NUREG/CR-6365
NUREG/CR-6365
86
9 7 5 3 1
COLUMNS
# 2 Wedge A r e a ;
00
-J
# 6 Wedge,
Area
>VSK>W\XwX><W^
<
2222^?22 25^i^22$v25222
NOZZLE
MAN WAY
z
C
m
o
JO
I
ON
U>
ON
ROWS
-45
-43
-41
-39
-37
-35
-33
-31
-29
-27
-25
-2 3
-21
-19
-17
-15
-13
-11
-9
-7
-5
I
O
m
so
>
H
O
#
H
C
W
W
^
C!
*r)
H
C!
s
tn
z
H
c/3
Figure 29. Photograph of segment of ruptured tube (R42-C55) removed from the Ginna steam generator
(tubesheet to the right) (USNRC 1982c).
NUREG/CR-6365
inside diameter cracking but had shallow peenlike marks and dings, shallow wall thinning on
the outside, and local distortions including a
bulge. The root cause analyses of the loose parts
damage from 1976 to the time of the tube rupture
were inadequate.
4.5.2 Plant Transient
The Ginna rupture occurred while the plant was
operating at full power. A schematic diagram of
the Ginna plant is shown in Figure 30 (USNRC
1982c). The air ejector radiation monitor, the
pressurizer level and pressure alarms, and the B
steam generator level and steam/feed flow
mismatch alarms indicated to the operators the
existence of a large leak in the B steam generator
(at 9:25 am). The operators began a power
reduction at 1.5 minutes along with an increase
in the number and speed of the operating
charging pumps (the third charging pump was
started at 2.5 minutes). Also at 2 minutes, the
eight main steam dump valves opened
automatically in response to a valid error signal
from the reactor coolant system temperature and
four valves closed automatically at 3 minutes. At
3 minutes there was an automatic reactor scram
(at 12.91 MPa or 1,873 psig) and actuation of all
three safety injection pumps (at 11.88 MPa or
1,723 psig) on low primary system pressure.
This was followed by automatic containment
isolation, main turbine trip (on reactor trip),
automatic start of the auxiliary feed pumps, main
feedwater isolation and trip of the charging
pumps. At 4 minutes, both reactor coolant
pumps were manually tripped as required, the
pressurizer was almost empty, and the steam
supply valves to the turbine-driven auxiliary
feedwater pump opened automatically because of
low water levels in the steam generators. At 5
minutes, the remaining four main steam dump
valves closed automatically and the initial reactor
coolant system depressurization stopped at about
8.27 MPa (1,200 psig), apparently due to the
establishment of saturation conditions in the
reactor vessel upper head along with the effects
NUREG/CR-6365
2
C
00
H
fr)
>
50
M
O
O
O
m
m
50
i
ON
U>
ON
L/>
50
>
H
o
H
G
03
m
G
H
50
Cooling Water
Intake Tunnel
m
m
<
w
2;
H
00
^ |
Condensate
K^t*H Condenser
[j<>a Cooling Water
Charging and
I Lotdown Systems
Figure 30. Schematic diagram of Westinghouse-designed pressurized water reactor of Rochester Gas and Electric Corporation's Ginna
Nuclear Power Plant (USNRC 1982c).
SI PUMPS ON
CHG PUMPS ON
"A" RCP ON
"B"RCP ON
S/G "A" TO ATMOS
S/G "B" TO ATMOS
PRESS. PORV
2000
100
/PRESS.
LEVEL
DATA
RCS
PRESSURE
DATA
1500
O
75
/v
co
0.
a:
z>
co
1000
CO
Ul
cc
CL
25
12:00
NOON
c
o
1:00
PM
Figure 31. Ginna reactor coolant and steam generator parameters as a function of time, January 25, 1982 (USNRC 1982c).
The transient started at 9:25am.
NUREG/CR-6365
92
93
NUREG/CR-6365
NUREG/CR-6365
94
95
NUREG/CR-6365
NUREG/CR-6365
96
97
NUREG/CR-6365
2.2
2.0
1.8-
llliljl
||1||||\
1.61.4
1.2
1.0
0.8
liiiisSiliiisliiiiiii
i||;|Bl|||l;5Msl|$|!llll|;|ll
llllll
III 1 IlllfSi
|||iiijji|fjf
10
20
30
40
Time (2 minute intervals)
iiiiL
50
Figure 32. North Anna Unit 1 reactor coolant system pressure versus time during the first 58 minutes of
the transient (Bowling 1987). The transient started at 6:30am.
Pressurizer level (%)
100
10
20
30
40
Time (2 minute intervals)
50
Figure 33. North Anna Unit 1 pressurizer level versus time during the first 58 minutes of the transient
(Bowling 1987). The transient started at 6:30am.
NUREG/CR-6365
98
Temperature (Degrees F)
570
10
20
30
40
Time (2 minute intervals)
Figure 34. North Anna Unit 1 reactor coolant system temperature versus time during the first 55 minutes
of the transient (Bowling 1987). The transient started at 6:30am.
10
T
1
1
1
-i
1
r
5
Time margin
5hrs I
Reduce
power
to 50%
10"
(0
10*
101 L
J
1000
2000
3000
I
4000
'
5000
'
6000
Time (min)
Figure 35. Time-dependent leakage curve (USNRC 1988).
99
NUREG/CR-6365
NUREG/CR-6365
100
101
NUREG/CR-6365
l I I l l I l I l | I l l I I l I l l l l l I l ) I l l l l l l I I I I [ l l
Secured second charging pump.
Closed NI-9& 10
Leak initiation
Began cutting load at 30 MW/Min
Reduced letdown flow and
started second charging pump
Mainsteam bypass valves
(steam dumps) to
condenser open
Reactor trip and
resulting cooldown
Blocked safety
injection and initiated
rapid depressurizat'ton
\ /
/
Main steam bypass valves
;*
(steam dumps) to condenser opened
, ^ . O p e n e d N.-9&10 , , , , , , , ,
I I I I I I I I I
10
20
30
Time (minutes)
M95 0170
Figure 36. Pressurizer level during the first 39 minutes of the McGuire unit 1 steam generator tube
rupture event of March 7 and 8, 1989 (Sipe 1989). The rupture occurred at 11:38pm.
2.3
2.1
II
TJ
CO 1 7
3
O
Primary pressure
S/G B pressure
1
1
-^1.9
"1
- - - - 1
1
''
Initiated steam
generator cooldown
using the backfill
method
.1.5
<3
CO 1.3
a.
1.1
P
to
CO
0.9
0.7
0.5
0.3
Started cooldown
Continued to cooldown. Evaluating
cooldown method for ruptured S/G
Invalid point resulting from PORV
low temperature overpressure
protection calibration
_1_
4
-46
J_
8
_1_
10
JL
11
M95 0171
Figure 37. Reactor coolant system and B steam generator secondary side pressure during the McGuire
Unit 1 steam generator tube rupture event of March 7 and 8, 1989 (Sipe 1989). The rupture occurred at
11:38 pm.
NUREG/CR-6365
102
103
NUREG/CR-6365
NUREG/CR-6365
104
105
NUREG/CR-6365
58.5"
45"
45"
41"
Next support (06H)
M95 0173
Figure 38. Palo Verde upper tube bundle geometry on the hot leg side (Conway 1993).
NUREG/CR-6365
106
D = Deposit
X = Axial flaw w/deposit
W =Wear
Column
143
144
146
145
148
147
Row
Figure 39. Palo Verde steam generator cross section in the region of the tube bundle with the ruptured
tube (Conway 1993).
107
NUREG/CR-6365
NUREG/CR-6365
108
At 13 minutes, the pressurizer heaters deenergized due to a low water level in the
pressurizer and the reactor was tripped by the
operators, which automatically tripped the
turbine. Twenty-two seconds later, the safety
injection and containment isolation systems were
actuated due to a reactor coolant system pressure
below 12.67 MPa (1,837 psia). The pressurizer
level then dropped below 0% and the pressurizer
pressure dropped to 11.56 MPa (1,677 psia).
However, the high pressure safety injection
quickly restored the pressurizer level to about 4%
and the pressure to about 12.96 MPa (1,880
psia). The reactor coolant pumps IB and 2B
were also manually tripped at about this time. In
the following tens of minutes, the high pressure
safety injection and charging pumps slowly
increased the pressurizer level while the reactor
coolant system pressure was maintained at about
12.9 MPa (1,875 psia). By about 28 minutes, the
high pressure safety injection flow was zero, the
letdown flow was still isolated, the three charging
pumps were in full operation, and the pressurizer
level was still increasing slowly, but was
relatively low.
109
NUREG/CR-6365
NUREG/CR-6365
110
Tabic 12. Sunimary of the leak rate, degradation mechanism, rupture size, rupture location, and stressor information associated with the ten
ruptures discussed in Section 4.
Date
Plant,
SG Model
Maximum
Leak Rate
GPM
Degradation
Mechanism
Rupture
Size
Rupture
Location
Stressors and
Contributing Factors
125
Wastage
Surry-2
W-51
330<"
PWSCC
06/25/79
Doel-2
ACE-44
135
PWSCC
10/02/79
Prairie Is.-l
W-51
336<"
01/25/82
Ginna
W-44
760'"
05/16/84
Fort Calhoun
CE
112
ODSCC
07/15/87
North Anna-1
W-51
637
High-Cycle Fatigue
03/07/89
McGuire-1
W-D2
500
ODSCC
02/09/91
Mihama-2
MHI-44
High-Cycle Fatigue
03/14/93
Palo Vcrde-2
CE-80
ODSCC
02/26/75
Point Bcach-1
W-44
09/15/76
=700
240
,y
<"NRC estimates
"'Estimate based on similarities to the North Anna rupture
Co
?
s
S
H
s
w
H
S
m
tn
<
Power reduction/trip.
NUREG/CR-6365
112
Point Beach-I
Surry-2
Doel-2
Prairie ls.-l
Guina
Fort Calhoun
North Aniia-I
McGuirc-1
Miliama-2
Palo Verdc-2
I2S
330
135
336
76(1
112
637
500
700
240
Yes
Yes
No
Yes
Yes
No
Yes
Yes
Yes
Yes
air ejector
rad.
pressure,
air ejector rad.
pressure
air ejector
rad.
air ejector
rad.
pressure
air ejector
rad.
pressure, M S L rad.
24-28 min.
< 5 min.
"9 min.
5-18.5 min.
< 1 mill.
32 niin.
< 5 niin.
< 1 inin.
"5 min.
< 57 niin.
2, 19
5(2nd)
1.8, < 15
9,10
1,2.5
0 , 0 (increased
flow at 18 niin.)
4(2nd)
5 (3rd)
2 (3rd)
8 min.
5 min.
2.4 min.
3 mill.
24 min.
3 min.
S (reduced)
6 mill.
30 inin
7 inin.
N/A
7 min.
1.5 niin.
N/A
3 niin.
4 min.
8 min.
No
47 min.
(at 25% power)
10 min.
N/A
No
No
N/A
Smin.
8/9 min.
No
13 mill.
10.15 min.
3 min.
N/A
No
No
10 min.
No
5.3 min.
No (blocked at 23 min.)
10.1 min.
13.2 min.
18 min.
16 niin.
5 min.
5.3-16 inin.
0-18 min.
No
No
11 min.
11 min.
* 9 min.
22 m i n .
22 mtn.
10 mill.
2 hr, 54 min.
2 hr, 54 niin.
13 mill.
2 hr, 4 7 milt.
13 niin. (one)
13 min. (one)
At power
No
No
No (blocked at 54 min.)
No, manual
SI at 11 inin.
19.2 min.
10.23 niin.
3 min.
No
58 min.
48 min.
58 inin.
None
No
No
No
18 min.
18 min.
11 min.
18 inin.
9.4 min.
closed
closed
41-50 inin.
No
No
No
27 min.
27 inin.
10.15 min.
15 min.
IS min.
3 inin.
3-7 niin.
4-7 niin.
5 4 , 6 3 . 114, 132 mill.
40 mln.
40 min.
closed
0-32 inin.
51 min.
66 iitiri.
No
N/A
SI min.
21 nun.
II.5 hrs
19 inin. (One)
No
Yes
41 min.
17.4 miii.
2 mln.
4 inin.
4 mill.
116 min.
2-3, 2-5, 75 min.
41 min.
42 niin.
43 mill.
19 min.
43 niin.
43 niin. (one)
14 mill., 3.5 l i r
22 min.
41 min.
19 niin.
22-37 min.
51 min.
Yes (61 mill.)
N/A
1 Mr, 40 inin.
No
73, 79 min.
16 min.
Yes (16 inin.)
"16 mill.
Yes
No
21 min.
68-88 min.
42 min.
14 nitn.
N/A
22 m i n .
S7 mill, (two)
54 min.
No (tried)
1 hr, 3 0 min.
42, 52 min.
No
Yes (43 min.)
30 min.
No
N/A
Yes (72 inin.)
No
27 mill. ( 2 )
16 mln.
68 min.
28 inin.
blocked
2 , 7 3 min.
2 lir, 47 mill.
73 min.
No
42-44 niin.
3 min.
34 min.
47 inin., then
10 lir, 37 mill.
1 lir, 8 niin.
3 to 4 hrs
No
No
No
1-2 sec at scram
1 hr, 36 mln.
12 inin.
13 mill.
7 hours
No
No
Yes
34 min.
37 min. (1)
7hrs
- 1 hr
61 mill.
3 lir, 2 mill.
3 hrs, 5 min.
- 11.5 hr
3 hr, IS niin.
16 hr, 26 min.
21 hr, 35 min.
3 lir, 47 niin.
5 hr, 49 niin.
17 hr
Yes
No
No
No
Yes
Yes
No
No
The high head safety injection pumps are also the charging pumps, one remained in operation.
6hr
No
No
NUREG/CR-6365
114
wall thickness. About 94 other similar indications were found that required tube plugging. An
indication of a crack in the failed tube which may
have been greater than 40% of the tube wall
thickness was measured during the previous 1991
eddy-current inspection, but ignored.
115
NUREG/CR-6365
25
C
so
w
o
J*
Braidwood Unit 1
Date
Maximum Leak
Rale
*47/hr (12.5 gal/lir)
Defect Size
i
Defect Location
Degradation
Mechanism
ODSCC
H
C
W
ffl
March 9, 1992
Hot leg side of the tube in Row 67, Column 109, 4.8 mm
above the tubeshect in the explosive transition region
ODSCC
McGuire Unit 1
37(/lir(IOgal/lir)
ODSCC
Maine Yankee
318</hr(84gal/hr)
ODSCC
March 6, 1990
= U5(/hr(30gal/lir)
June 2 1 , 1989
456l/hr(l20gal/hr)
ON
117
NUREG/CR-6365
NUREG/CR-6365
118
THERMAL-HYDRAULIC RESPONSE
119
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
nsr:
W
X
100
2
// / /
\ 100
\
\ 1
i
222
322, 422"
200,300.
400
\
\
\
\
\
\
\
\
102
N104
x|S
\
\
r
\ 104 \
\ r- 2 \
\ \
\
\ \
\
\ \\
\
\
3 \
\ \
\
\ sS _ _ \
N
\
\
\
\
\
\
\
\ ~ "- ~ ~ \
\ \
\
\ \x b \
\ \
\
_ \\ - - \
\ \
\
\ \^ 6 \
\ \
\
\.
\
v
M
y
\ 104
\
\
07
\
\
SSl-\\\\\\\\v\
NUREG/CR-6365
120
Z595-WHT-695-01
444PORVS
ixi-
449
Containment
to
X
<
o
>
s
a
n
*
ON
u>
ON
Z595-WHT-695-02
s
so
8
z
w
THERMAL-HYDRAULIC RESPONSE
NUREG/CR-6365
122
THERMAL-HYDRAULIC RESPONSE
Throttle emergency core cooling injection while maintaining minimum subcooling of 16.7C (30F).
123
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
0
3000.0
Time (h)
3
20
PZR Pressure (p-440010000)
; Initial depressurization
, HPSI refills and
repressurizes RCS
15
(0
Q.
CO
'55
2
-Pressurizer spray actuated
3
<n
10
3
</>
to
0)
0)
1000.0
0.0
0.0
-Accumulators isolated
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 42. Pressurizer pressure vs. time (steam generator tube rupture).
Time (h)
3
30.0
20.0
I
10.0
5000.0
10000.0
15000.0
Time (s)
Figure 43. Pressurizer level vs. time (steam generator tube rupture).
NUREG/CR-6365
124
20000.0
THERMAL-HYDRAULIC RESPONSE
Time (h)
2
150.0
300
100.0
"1
100
.o
u.
8
5
-50.0.
0.0
5000.0
10000.0
15000.0
-100
20000.0
Time (s)
Figure 44. Break and high pressure safety injection flow vs. time (steam generator tube rupture).
produces a marked increase in the depressurization rate as shown in Figure 42, effectively
terminating the break flow as a result of reducing
reactor coolant system pressure below the
affected steam generator pressure. Figure 46
shows the primary pressure reduction in the
affected steam generator. The reactor coolant
system pressure is finally reduced below the
affected steam generator pressure at about 3,000
seconds, terminating the break flow. The release
of radioactivity through the affected steam
generator is also terminated at this time,
preventing any further releases through the relief
valves at approximately 3,000 seconds, as shown
in Figure 47. As noted in Figure 44, high
pressure safety injection flow is also throttled at
about 2,800 seconds to prevent overfilling of the
125
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
0
1500.0
Time (h)
3
10
Cooldown of intact
SGs initiated
m/
1000.0
Intact SG (p-282010000)
Intact SG(p-382010000)
Affected SG (p-482010000)
eg
CO
to
3
CO
3
CO
CO
CD
to
4 2
500.0
V-0.0
o.o
5000.0
10000.0
Time (s)
15000.0
20000.0
Figure 45. Steam generator secondary pressure vs. time (steam generator tube rupture).
Time (h)
3
3000.0
20
Primary SG pressure (p-408010000)
Sec. SG pressure (p-476010000)
15
2000.0 \','
(0
to
Q.
<D
10
3
co
CD
CO
CO
CD
1000.0
0.0
0.0
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 46. Primary steam generator and secondary pressure vs. time (steam generator tube rupture).
NUREG/CR-6365
126
THERMAL-HYDRAULIC RESPONSE
600.(
Time (h)
3
250
200
^
400.0
150
I
il
I
fa
<r
100
200.0
50
5000.0
10000.0
Time (s)
15000.0
20000.0
Figure 47. Secondary relief valve flow rate vs. time (steam generator tube rupture).
127
NUREG/CR-6365
THERMAL-HYDRAUUC RESPONSE
Time (h)
3
700.0
600
600.0
550
500.0
8.
e
500 g?
0)
Q.
400.0
E
.2
450
300.0
400
200.0
0.0
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 48. Reactor coolant system subcooling vs. time (steam generator tube rupture).
1.0
Q.
CO
o^
c
.2
*o
to
Time (h)
3^
0.8
0.6
1
0.2
0.0
0.0
5000.0
10000.0
Time (s)
15000.0
20000.0
Figure 49. Failed steam generator wide and narrow range levels vs. time (steam generator tube rupture).
NUREG/CR-6365
128
THERMAL-HYDRAULIC RESPONSE
600.0
Time (h)
3
550
500.0
500
_
400.0
450
CO
<D
2
cu
Q.
E
|2
300.0
|2
400
200.0
350
100.0
0.0
5000.0
10000.0
Time (s)
15000.0
20000.0
Figure 50. Residual heat removal system inlet and outlet temperatures vs. time (steam generator tube
rupture).
Time (h)
10000.0
Time (s)
20000.0
Figure 51. Pressurizer spray flow rate vs. time (steam generator tube rupture).
129
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
Time (h)
2
100.0
3
-40
50.0
20
"3T
E
O)
.*:
<D
o &
cr
0.0
o
u.
Li-
-20
-50.0 -
-40
-100.0
0.0
5000.0
10000.0
20000.0
15000.0
Time (s)
Figure 52. Reactor coolant system letdown flow rate vs. time (steam generator tube rupture).
Time (h)
1
1354.5
,-.
E
1354.0
ity
fr
o
a.
E
3
-
1353.5
1353.0
"
1352.5
wio n
0.0
'
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 53. Reactor coolant pump velocity vs. time (steam generator tube rupture).
NUREG/CR-6365
130
THERMAL-HYDRAULIC RESPONSE
Table 15. Double-ended failure of a steam generator tube: Sequence of events and key assumptions.
Steam Generator Tube Break Size (double-ended rupture)
= 0.006555 ft
272 sec
1,200 sec
2,400 sec
2,800 sec
3,000 sec
3,000 sec
Accumulators Isolated
3,600 sec
14,000 sec
14,000 sec
131
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
Time (h)
3
3000.0
20
PZR pressure (p-440010000)
15
CO
a.
Q.
- 10
3
0)
0)
CO
1000.0
0.0
0.0
5000.0
10000.0
Time (s)
15000.0
0
20000.0
Figure 54. Pressurizer pressure vs. time (steam line break with 1 SGTR).
Time (h)
2
5000.0
10000.0
15000.0
20000.0
Time (s)
C170-WHT-29S-5!
Figure 55. Pressurizer level vs. time (steam line break with 1 SGTR).
NUREG/CR-6365
132
THERMAL-HYDRAULIC RESPONSE
40.0
Time (h)
3
5
12.0
38.0
n
/ \
I
i
I
/
36.0
- 11.5
11.0
10.5
34.0
^
32.0
10.0
1/
9.5
5000.0
10000.0
Time (s)
15000.0
20000.0
Figure 56. Reactor vessel level vs. time (steam line break with 1 SGTR).
0
800.0
600.0
i-'
500.0
I\
CD
4
'
'
700.0
Time (h)
3
400.0
- 600
_500
1 300.0 1-
CD
Q.
""
^J^^y^y-
200.0
|2
400
100.0
- 300
'
o.o
5000.0
10000.0
Time (s)
15000.0
20000.0
Figure 57. Reactor coolant system hot leg temperature vs. time (steam line break with 1 SGTR).
133
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
NUREG/CR-6365
134
150.0
THERMAL-HYDRAULIC RESPONSE
Time (h)
3
300
K/
100.0
HPSI throttled
-200
D)
<D
E
.g
(0
<D
CO
rr
rr
50.0
- 100
0.0
0.0
5000.0
10000.0
5
o
0
20000.0
15000.0
Time (s)
Figure 58. Break and high pressure safety injection flow rates vs. time (steam line break with 1 SGTR).
1.5e+06
Time (h)
4 5
8
3.0e+06
1.3e+06
Extrapolated based on
throttled flow
Integrated flow
2.0e+06
05
10
CO
1.0e+06
0.0e+00
5000.0
10000.0
15000.0
20000.0
25000.0
30000.0
Time (s)
Figure 59. Integrated safety injection flow vs. time (steam line break with 1 SGTR).
135
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
Time (h)
800.0
700.0
600
600.0
(F 500.0
500
400.0
a>
Q.
300.0
CD
Q.
\i
.CD
400
-*\,<V200.0
100.0
o.o0.0
300
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 60. Residueal heat removal system inlet and outlet temperature vs. time (steam line break with 1
SGTR).
1000.0
(0
Q.
3
CO
CD
Q.
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 61. Failed steam generator secondary pressure vs. time (steam line break with 1 SGTR).
NUREG/CR-6365
136
THERMAL-HYDRAULIC RESPONSE
2
3000.0
Time (h)
3
1200
2000.0
-800
E
aT
1000.0
400
5
.o
-1000.0
400
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 62. Failed steam line break flow rate vs. time (steam line break with 1 SGTR).
Time (h)
3
200.0
4
80
150.0
60
100.0
40 .
JO
IT
I
I
5 0
2 0
^Y^IA/UI
5
o
o.o
LL
-50.0
40
-100.0
0.0
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 63. Pressurizer PORV flow rate vs. time (steam line break with 1 SGTR).
137
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
1500.0
0.0
50.0
100.0
150.0
200.0
250.0
300.0
350.0
400.0
Time (s)
Figure 64. Reactor coolant pump speed vs. time (steam line break with 1 SGTR).
1000.0
Time (h)
3
sure (psia
800.0
600.0
400.0
200.0
0.0
5000.0
10000 0
15000.0
20000.0
Time (s)
Figure 65. Intact steam generator pressure vs. time (steam line break with 1 SGTR).
NUREG/CR-6365
138
40.0
Time (h)
3
THERMAL-HYDRAULIC RESPONSE
4
30.0
I
1
I
20.0 -
I
I
10.0
5000.0
10000.0
15000.0
20000.0
Time (s)
Figure 66. Steam generator steam dump flow rate vs. time (steam line break witb 1 SGTR).
Table 16. Steam line break with one steam generator tube failed:
assumptions.
1.4 ft
0.006555 ft
200 sec
300 sec
1,800 sec
11,500 sec
1,800 sec
1,800 sec
1,800 sec
12,000 sec
13,000 sec
26,000 sec
139
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
NUREG/CR-6365
140
THERMAL-HYDRAULIC RESPONSE
3000.0
Time (h)
2
- 20
Pressurizer (p-440010000)
15
2000.0
CO
0_
to
Q.
10
to
to
=3
to
tn
S>
a.
0
1000.0
II
I
nn
o.o
-'r^v^
5000.0
10000.0
Time (s)
Figure 67. Pressurizer pressure vs. time (steam line break with 15 SGTRs).
o
15000.0
30.0
*;
20.0
CD
>
CD
>
(0
N
CD
N
CD
'i_
ZJ
CO
CO
CD
to
to
CD
10.0
5000.0
10000.0
15000.0
Time (s)
Figure 68. Pressurizer level vs. time (steam line break with 15 SGTRs).
141
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
Time (h)
2
40.0
35.0
10 m
>
30.0
25.0
5000.0
10000.0
15000.0
Time (s)
Figure 69. Reactor vessel level vs. time (steam line break with 15 SGTRs).
Time (h)
2
800.0
600
500
1
400.0
hY~jnr^n
RHR actuated
Q.
E
400
200.0
300
0.0
0.0
5000.0
10000.0
Time (s)
Figure 70. Hot leg temperature vs. time (steam line break with 15 SGTRs).
NUREG/CR-6365
142
15000.0
Time (h)
2
1000.0
THERMAL-HYDRAULIC RESPONSE
3
4
2000
500.0
1
I
1000
Wi
m
1
I
0.0
-500.0
0.0
-1000
5000.0
10000.0
15000.0
Time (s)
Figure 71. Break and emergency core cooling injection flow rates vs. time (steam line break with 15
SGTRs).
Time (h)
2
1.5e+06
RWST capacity
3.0e+06
Extrapolated based on
initial ECC flow
u>
03
0
5.06+05
1.0e+06
0.0e+00
10000.0
5000.0
Time (s)
10
15000.0
Figure 72. Integrated safety injection flow vs. time (steam line break with 15 SGTRs).
143
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
of at least one of the two RHR trains in operation. The RHR inlet and outlet temperatures are
displayed in Figure 73.
Table 17 presents the sequence of events and key
assumptions for this event.
5.6 Results of the RELAP5 Simulation of a
Steam Line Break with 15 Steam Generator
Tubes Failed and No Operator Actions
An analysis of 15 failed steam generator tubes
combined with a steam line break was performed
without operator action to show the effect of no
operator actions on the timing of core unco very.
Unlike the analyses described above, no
throttling of emergency core cooling injection is
assumed nor is actuation of the RHR system
credited in this evaluation.
5.7
Operator Actions During Combined
Steam Line Break-Tube Rupture Events
NUREG/CR-6365
144
THERMAL-HYDRAULIC RESPONSE
Time (h)
2
800.0
700.0
600
600.0
LL
o
0)
-J
to
500.0
500
400.0
-I
300.0
\\
m
o_
E
|2
i
;i
s RHR Initiation
400
w
\\ I
|
to
^_
CD
Q.
200.0
-
V^SINK,
100.0
" 300
0.0
0.0
5000.0
10000.0
15000.0
Time (s)
Figure 73. Residual heat removal system inlet and outlet temperatures vs. time (steam line break with 15
SGTRs).
Table 17. Steam line break with 15 steam generator tubes failed:
assumptions.
Steam Line Break Size
Steam Generator Tube Break Size
(double-ended ruptures)
Auxiliary Feedwater to Ruptured Steam Generator
Terminated at
Reactor Coolant Pump Trip Time
Secondary Cooldown Initiation Time
Using Atmospheric Dump Valves (Intact
Steam Generators)
Time High Pressure Safety Injection First Throttled
Time Low Pressure Safety Injection Terminated
Accumulator Actuation
1.4 ft
0.098325 ft
300 sec
200 sec
1800.0 sec
2400.0 sec
2400.0 sec
Not Isolated,
Accumulators Discharged
Time Conditions Achieved for RHR Entry
Time RHR Placed Inservice
Refueling Water Storage Tank Exhaust Time
1000 sec
3000 sec
6600 sec. (1.83 hours)
145
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
3000.0 2
2.
Time (h)
4
5
2000.0
CO
Q.
CO
Q_
3
CO
CO
CD
CO
CO
cc
1000.0
10000.0
20000.0
30000.0
Time (s)
Figure 74. Pressurizer pressure vs. time (steam line break with 15 SGTRs, no operator action).
800.0
700.0
Time (h)
4
5
( 600.0
CD
m
CD
a.
500.0
CD
fc
400.0
c
o
IS
3
300.0
|2
(TI
CO
500
I
CD
Q.
400
E
|2
200.0
100.0
0.0
0.0
-300
10000.0
20000.0
30000.0
Time (s)
Figure 75. Reactor coolant system hot leg temperature vs. time (steam line break with 15 SGTRs, no
operator action).
NUREG/CR-6365
146
THERMAL-HYDRAULIC RESPONSE
1500000.0 0
Time (h)
4
5
8
3.0e+06
CO
CO
500000.0
1.0e+06
L...
0.0
0.0
10000.0
20000.0
0
30000.0
Time (s)
Figure 76. Integrated emergency core cooling injection flow vs. time (steam line break with 15 SGTRs,
no operator action).
3
800.0
nperat
600
600.0
500.0
+*
500 g>
Q.
400.0
E
|2
Initiation of core
uncovery
Cladd "9
700.0
Time (h)
4
300.0
.c
\ r
wnfltr-^.
200.0
400
|
O
"V-J
100.0
0.0
0.0
300
10000.0
20000.0
30000.0
Time (s)
Figure 77. Fuel rod cladding surface temperature vs. time (steam line break with 15 SGTRs, no operator
action).
147
NUREG/CR-6365
THERMAL-HYDRAULIC RESPONSE
NUREG/CR-6365
148
Insights into the U.S. steam generator tube rupture risk profile can be gained from an examination of the USNRC and industry probablistic
risk assessment and IPE program results. The
risk associated with a steam generator tube rupture is dominated by a few significant failures.
Typically the dominate contributors are human
error (operator fails to depressurize) and failures
that cause loss of reactor water storage tank
inventory.
149
NUREG/CR-6365
RISK SIGNIFICANCE
1x10-6
4x10"
CDF Reported in U.S. IPEs
Figure 78. The U.S. nuclear power plants' core damage frequency distribution as reported to the U.S.
NRC by the IPE programs.
NUREG/CR-6365
150
RISK SIGNIFICANCE
Percent of
containment
bypass fraction
caused by
spontaneous steam
generator tube
rupture
0.4%
26 %
2%
10%
Not Reported
Not Available
6%
7%
11%
11 %
2%
11 %
0.04%
9%
8%
99 %
7%
20 %
5%
79 %
0.02%
2%
Arkansas 1
5 x 10-
Callaway
4 x lO"
Catawba
4 x lO"
Comanche Peak
4 x lO"
Cook
6 x 10-
Diablo Canyon
9 x lO"
Farley
1 x 10-
Kewaunee
7 x lO"
Indian Point 2
3 x 10-
Indian Point 3
4 x 10-
McGuire
4 x 10"
Seabrook
7 x 10-
1%
Not Available
Sequoyah
2 x 10"
4%
75%
Surry
2 x 10-
5%
Not Available
South Texas
4 x lO"
5%
22 %
Trojan
6 x 10
2%
Not Available
Vogtle
5 x lO"
4%
12 %
3%
6%
Watts Bar
3 x lO"
1.
2.
The steam generator tube rupture percentage of containment bypass values were estimated based
on information presented in the IPEs. In some cases it was difficult to determine these percentages
and they had to be estimated based on supporting information.
151
NUREG/CR-6365
RISK SIGNIFICANCE
TRANSIENTS WITH
SCRAM 16%
LOCAs18%
ATWS 4%
INTERNAL FLOODS 4%
LOSP 6%
r/
i,'i, ^c y-j7?y?y
,/"..,s ..y.,/
STEAM GENERATOR
TUBE RUPTURES 4%
-/-.
INTERFACING SYSTEMS
(V) LOCAs 0.01%
SUPPORT SYSTEM
FAULTS 48%
Figure 79. Typical steam generator tube rupture contribution to the total core damage frequency (note:
these results are from the Sequoyah nuclear power plant's IPE submittal).
NUREG/CR-6365
152
RISK SIGNIFICANCE
spontaneous
rupture, and
steam
generator
tube
153
NUREG/CR-6365
RISK SIGNIFICANCE
Other (25.2%)
SGTR (74.8%)
Figure 80. Steam generator tube rupture contribution to the total containment bypass fraction at the
Sequoyah nuclear power plant (ice condenser containment)
operational transients,
rare events, and
severe accidents.
NUREG/CR-6365
RISK SIGNIFICANCE
turbine trip,
loss of main feed,
temporary loss of off site power,
failed open turbine bypass valve, and
loss of a reactor coolant pump.
155
NUREG/CR-6365
RISK SIGNIFICANCE
Event Description
Initiator
Frequency"
(per year)
X = 7.4E-3
a = 2.5E-3
EF = 10.1
Event represents either a medium or large loss of coolant accident, with rupture
diameter greater than 2 inches. Initiator frequency obtained from Ericson et al.
(1990), medium and large loss of coolant accident.
X = 1.5E-3
a = 3.6E-3
EF = 9.7
X = 5.6E-2
a = 1.2
EF = 11.0
~ 12.8 MPa
(1,850 psi)
X = 2.0E-2
a = 0.18
EF = 31.6
~ 17.2 MPa
(2,500 psi)
X = 5.0E-4
a = 1.2E-3
EF = 9.7
X = 3.5E-2
a = 0.44
EF = 11.9
Trip of the turbine generator that decreases steam flow to the turbine. Initiator
frequency obtained from Gentillon et al. (1994).
X = 0.40
o = 1.6
EF = 5.3
Event represents a loss of alternating current power to the secondary heat removal
system. Initiator frequency obtained from Mackowiak et al. (1985), PWR
Category 37.
X = 0.11
a = 0.40
EF = 14.6
The loss or reduction of normal feedwater flow for one loop. Initiator frequency
obtained from Gentillon et al. (1994).
X = 0.43
c = 2.2
EF = 5.8
The rupture of the feedwater line. Initiator frequency obtained from Ericson et al.
(1990).
~ 17.2 MPa
(2,500 psi)
X = 5.0E-4
o = 1.2E-3
EF = 9.7
X = 4.2E-2
a = 0.63
EF = 9.1
- 17.2 MPa
(2,500 psi)
X = 1.4E-4
a = 1.0E-3
EF = 7.9
Transients
A transient with subsequent failure to SCRAM the reactor. Initiator frequency
obtained from Gentillon et al. (1994), all transients, and Ericson et al. (1990), Vol.
3, failure to scram the reactor."
NUREG/CR-6365
156
RISK SIGNIFICANCE
A is the initiating event frequency; a is the standard deviation of the initiating event frequency; EF is the associated error factor of the
log-normal distribution. The initiator was developed by adding the large loss-of-coolant (LOCA) and the medium LOCA initiators
together. The resulting initiator parameters were calculated by using Monte Carlo simulation with the equation: Large LOCA +
Medium LOCA, where Large LOCA was assumed to be a lognormal distribution with mean of 5.0E-4 and standard deviation of 1.2E-3
and Medium LOCA was assumed to be a lognormal distribution with mean of 1.0E-3 and standard deviation of 2.5E-3.
b.
The initiator was developed by multiplying die overall transient initiator by the probability of failing to scram the reactor. The resulting
initiator parameters were calculated by using Monte Carlo simulation with the equation: f(transients) * P(fail to scram | transient), where
f(transient) was assumed to be a lognormal distribution with mean of 2.4 and standard deviation of 2.2 and P(fail to scram | transient)
was assumed to be a lognormal distribution with mean of 6.0E-5 and standard deviation of 7.6E-5.
NUREG/CR-6365
RISK SIGNIFICANCE
It has been noted from combined thermalhydraulic and probabilistic risk assessment
sensitivity studies that the number of steam
generator tubes failing during a steam generator
tube rupture event impacts the risk profile when
the containment is bypassed. The impact on the
plant risk (defense in-depth) of a given number of
steam generator tube failures is listed in Table
20.
Number of Tubes
Failed
A few
Impact on Defense
In-Depth
Requires operator to depressurize the reactor coolant
system.
NUREG/CR-6365
158
RISK SIGNIFICANCE
mitigation strategies may become ineffective and
the containment bypass steam generator tube
rupture events may result in core damage and a
significant increase in the public risk. Steam
generator tube inspection procedures need to be
such that they protect against reaching the no
defense-in-depth break point number of severely
defected tubes. In other words, the inspection
and maintenance procedures must adequately
identify and correct the tube degradation to
prevent serious consequences.
159
NUREG/CR-6365
RISK SIGNIFICANCE
NUREG/CR-6365
160
RISK SIGNIFICANCE
= IA, *P(TR|IE)*P
E
where
A,
TR
P(TR | IE)
P;
lE
161
NUREG/CR-6365
RISK SIGNIFICANCE
( AP -AP
TRl
AP
-AP
AP
AP
Linear Interpolation.
A second potential
method for estimating the conditional probability
of a tube rupture is a linear fit of the tube rupture
probability between the normal operational
differential pressure and the maximum
differential pressure. Using the NUREG-0844
endpoint probabilities, the resulting equation for
the linear fit is given by:
pressure)
PJat high
APj
TR2
2.45X10" (AJP.)
- 3.44x10 -2
where:
TR2
V
APi
/
Conditional
tube
rupture
probability for at least one tube
during the i'th initiator
Peak tube differential pressure
during the i'th initiator.
where:
PTRI
TR
Conditional
tube
rupture
probability for at least one tube
during the i* initiator
Conditional
tube
rupture
probability for at least one tube
during a high pressure initiator
NUREG/CR-6365
162
RISK SIGNIFICANCE
0.030
0.020
.-/
-X
Q.
a.
A
Si
0.010
./
o.oos -
/'
J2
1600
1800
, I
2000
2200
2600
NUREG-0844
Figure 81. Comparison of two different conditional tube rupture probability screening methods.
has been discussed. The induced steam generator
tube failure frequencies provided in Table 21 are
developed when the information in Table 19 is
combined with the NUREG-0844 methodology.
Table 21 provides a summary of the frequency of
induced steam generator tube rupture. Note that
these values should be considered screening
values only, since they are not based on a
mechanistic quantification of the impact of tube
defects on the burst probability. However, the
values identify the initiating events where a
detailed evaluation of the impact of tube
degradation on the potential for induced steam
generator tube rupture is needed. A more
^IE*P(TR|IE)*P
163
NUREG/CR-6365
as
c
JO
o
o
Os
OJ
ON
1 TUBE
2 TO 10
TUBES
MORE THAN
10 TUBES
9.5E-4
9.5E-4
2.0E-5
1.9E-3
8.7E-4
8.7E-4
I.8E-5
I.813-3
9.3E-5
9.3E-5
2.1E-6
1.9E-4
2.4E-4
2.4E-4
5.0E-6
4.9E-4
4.4E-5
4.4E-5
9.0E-7
8.9E-5 -
6.6E-6
6.6E-6
1.4E-7
1.3E-5
6.6E-6
6.0E-6
1.4E-7
1.3E-5
2.8E-6
2.8E-6
5.6E-8
5.7E-6
1.8E-6
1.8E-6
3.6E-8
3.6E-6
1.7E-6
l.7E-fi
3.5E-8
3.4E-6
3.6E-7
3.6E-7
7.4E-9
7.3E-7
7.4E-8
7.4E-8
1.5E-9
1.5E-7
>
55
RISK SIGNIFICANCE
165
NUREG/CR-6365
RISK SIGNIFICANCE
where:
P
sg
p,
where
~l
failure pressure.
The function f may also be represented by a lognormal distribution. The Monte-Carlo method
samples points over the parameter's uncertainty
distribution to determine a mean failure
probability as a function of a tube overpressure
and defect size. A variance can also be
calculated with each failure probability.
,00 =
fair-
'
/ X T
sg^
. = l - ( ) p ( . ^ )
+
P"(1~P
\,
) ~"
sg'
/(^)
n\(N-n)\
The probability mat less than x tubes fail is given
by:
P ,rll=*nn)
Z.=(i-.)
fa
NUREG/CR-6365
Pf
166
= =
y/m-a))
RISK SIGNIFICANCE
elliptical wastage
where:
3S
P/Pr
a
t
R
L
=
=
PR _ m
t
m
ASME Section XI subsection IWB-3514.3 should
be used to calculate the burst pressure if the
tube's flaw length are greater than this critical
value.
Material Properties Effects. Variations in
material properties between tubes subjected to
different fabrication processes is an important
factor in determining burst pressures. Steam
generator tubes fail by an elastic-plastic fracture
process. The burst pressure of tubes with
different material properties can be obtained by
normalizing the results to the flow stress of the
material. The flow stress corresponds to a value
between the yield strength S and ultimate tensile
stress S of the material. For Alloy 600 tubes,
the flow stress given by:
y
Ap/^ ^
= (
L ) [
_a
SF _J_
a
S =[S +S ]
NUREG/CR-6365
RISK SIGNIFICANCE
NUREG/CR-6365
168
RISK SIGNIFICANCE
^ '
^S^
^
1E-01
ency
. '"
s '
,''
,.''
/*
3
tr
-- *" *~
, '
>*^
^
-
,'
/ '
o
i .
LL.
o> 1E-03 :
_2
'5
/S
^*
:
i.
X3
3
'
y
,
10MPa
15MPa
17
MPn
I 1 .. Ivlr o
"5
c
.
g 1E-05
o
Z
'
1FJ17
0.2
o.o
- i
0.4
0.6
o.s
1.0
Figure 82. Estimated steam generator tube failure probability as a function of pressure and crack depth.
1E-04
1 27
o
c
a>
3
CT
- -
z.04
5.08
. -"
ii-^
~1E-06
_3
'5
LL.
0J
XI
3
H
glE-os
E
o
Z
A?
/r
1E-10
0.0
>
0.2
0.4
1.
.1
0.6
0.8
1.0
Figure 83. Demonstration of induced steam generator tube rupture frequency for a single defective tube.
169
NUREG/CR-6365
RISK SIGNIFICANCE
Coolant
System
Natural
NUREG/CR-6365
170
RISK SIGNIFICANCE
6.8.2
Hot Leg Countercurrent Flow in
Recirculating Steam Generators
The natural circulation flow pattern during a
severe accident at a plant with U-tube steam
generators consists of hot leg counter-current
flows between the reactor pressure vessel and die
inlet plenums of the steam generators. Mixing of
the counter-current flow steams occurs in the
inlet plenums of the steam generators. However,
there are uncertainties in the amount and extent
of mixing when experimental data are scaled
from small scale experiments to the full scale of
the steam generator inlet plenum. Also, the case
of no-mixing in the inlet plenum is not expected
to occur but has been used in the past to asses
worst case severe accident steam generator tube
boundary conditions. Counter current flow mixing occurs when the cooler vapor flows back to
the reactor vessel along the bottom of the hot
legs. When the hotter vapor enters the steam
generator inlet plenum, it will mix and cool and
then rise toward the steam generator tubes. The
mixed vapor enters some of the tubes, displacing
the cooler steam that was in the tubes. The
displaced vapor enters the outlet plenum, then
reenters other steam generator tubes, forcing
vapor into the inlet plenum. A density gradient
is thus established between tubes. This density
gradient then pulls more mixed vapor into the
tubes, displacing additional cooler steam. The
process continues until a steady flow is establish-
h3
h2
h2
c2
171
c 3
NUREG/CR-6365
RISK SIGNIFICANCE
Steam generator /
Reactor vessel
Inlet
plenum
Outlet
plenum
Hot leg
NUREG/CR-6365
cl
172
RISK SIGNIFICANCE
c3
h3
c2
h 2
c3
NUREG/CR-6365
RISK SIGNIFICANCE
NUREG/CR-6365
174
RISKSIGNIFICANCE
175
NUREG/CR-6365
NUREG/CR-6365
176
REGULATORY PRACTICES
Table 22. Steam generator tubing inspection guidelines.
Baseline Inspection
Inspection Intervals
*United States
Czech Republic
Every 4 years
Every 4 years
France
Germany
Japan
Slovenia
Spain
Sweden
Each year
Switzerland
If susceptible tubing:
inspect the hot leg side up through the Ubend region to the top tube support plate
on the cold side
full inspection
If less susceptible tubing: random sample of
5.5% of all tubes
Every outage
Every 3 years
Eveiy 3 years
*If more than 10% of inspected tubes show indications, additional 3 % in that steam generator and 3 % in remaining steam generators. If more than 10% of second batch
show indications, inspect additional 6% in area of indications.
177
NUREG/CR-6365
REGULATORY PRACTICES
b.
NUREG/CR-6365
a.
Category
Inspection Results
C-l
C-2
C-3
178
Tabic 23. Steam generator tube inspection requirements in the United States.
2ND SAMPLE INSPECTION
Action Required
Result
C-1
None
C-2
Result
Action Required
N.A.
N.A.
N.A.
N.A.
C-1
None
N.A.
N.A.
C-2
C-1
None
C-2
C-3
N.A.
N.A.
C-3
C-3
Action Required
Result
All other
S.G.s are
C-1
None
N.A.
N.A.
Some S.G.s
C-2 but no
additional
S.G.s are
C-3
N.A.
N.A.
Additional
S.G. is C-3
N.A.
N.A.
S = 3N/n% where N is the number of steam generators in the unit, and n is the number of steam generators inspected during an inspection.
REGULATORY PRACTICES
b.
NUREG/CR-6365
180
REGULATORY PRACTICES
181
NUREG/CR-6365
REGULATORY PRACTICES
All sleeves and the tube areas behind the sleeves
are also inspected during each refueling outage.
Also, an ultrasonic baseline inspection was used
to confirm the quality of the sleeve-to-tube welds.
I-coil and Plus-Point eddy-current probes have
been implemented for subsequent examinations.
NUREG/CR-6365
182
REGULATORY PRACTICES
183
NUREG/CR-6365
REGULATORY PRACTICES
NUREG/CR-6365
184
REGULATORY PRACTICES
185
NUREG/CR-6365
a
w
Q
Parameter
Kenair Limit
Measure of defect severity
Typical allowable value
No leak, no Haw
Wall thickness
!>', V
(full denth rolled tubes)
Crack Lenglb
(axial PWSCCi
Vollaee criteria
fODSCC at TSI>)
N/A
detection
threshold
crack length
< 10mm (3/4")
< 13mm (7/8")
adequate to detect
degradation
bobbin
bobbin
MRPC, TJT
MRPC
Extent (inin.)
Frequency (max)
1<X)%
1 year
3%
3 years
100% (TS)
1 year
100% (topofTS)
1-2 years
12% (topofTS)
1 year
bobbin, confirmed by
MRPC
100% bobbin
I year
sampling, on-line
none
sampling
none
sampling
none
on-line
none
on-line
none
3.SI/min(l gpm)
<1.9l/min(0.5
gpm)
<0.41/min(0.1gpm)
on-line
yes, increases number of
plugged tubes
<1.9l/min(0.5gpm)
Iturst Strength
Structural model
as design
as design
Reinforcement by TS
No structural model!
design
dcsiim
design
>3
>1.4
design
>3
>J.4
burst, leak
3, 95% confidence
1.4, 95% confidence
burst, leak
Inspection
Method
00
Generic Criteria
UJ
ON
ON
'strongly depends on the inspection hardware and software, which differs in different countries (USA, France, Belgium...)
'hot-leg only
REGULATORY PRACTICES
187
NUREG/CR-6365
REGULATORY PRACTICES
How Implemented
Where Used
Japan
USA
Canada
Germany
Belgium
Slovenia
France
Spain
Sweden
Russia
Canada
USA
Belgium
Slovenia
Sweden
NUREG/CR-6365
188
REGULATORY PRACTICES
189
NUREG/CR-6365
REGULATORY PRACTICES
NDE
CG
NDE
SL
CG
NUREG/CR-6365
190
REGULATORY PRACTICES
The calibration standard was prepared per ASME
Code Section V, Article 8, Appendix II - 860.22.
A standard deviation of 7% was determined.
The largest 592 indications from a plant with
confirmed outside diameter IGSCC/IGA at the
tube support plates was evaluated by six analysts.
The standard deviation of the voltage readings
was found to be 10.3%. A combined root-mean
squares deviation for measurement error of
20.5% was then calculated.
To use the EPRI voltage criteria, the primary-tosecondary coolant system leakage during various
design basis accidents must also be estimated.
Therefore, EPRI correlated leak rate and
probability of leakage with bobbin coil voltage by
testing pulled tubes and model boiler tubes at
estimated main steam line break pressure
differences of 16.1 and 18.3 MPa (2335 and
2650 psi). (However, not all me tubes were
tested at both pressures, and analytical
adjustments were used.) Using the best fit curves
and standard deviations, along with the crack
growth rate and measurement uncertainty
distribution, a Monte Carlo analysis can be
performed to calculate an accident leak rate at the
end of the next operating cycle. (The leak rate
for a given crack size is the probability of
leakage multiplied by the leak rate.) The sum of
the upper 95/95 probability/confidence level
values is then used as the conservative upper
bound leak rate and compared to the site
boundary limits.
191
NUREG/CR-6365
REGULATORY PRACTICES
NUREG/CR-6365
192
REGULATORY PRACTICES
CG
-a
NDE
TS
TS
a = 4.5mm
a^ = 6.0 - a/3mm
a =0
TS
CG
NDE
193
NUREG/CR-6365
REGULATORY PRACTICES
Also, to minimize the probability of rupture,
EPRI recommends that the leak limit during
normal operation be reduced to 568 liters per day
(150 gpd) per steam generator.
1989). Also, analysis and testing were performed to determine if fatigue at the defect
locations could lead to tube rupture. Despite
these efforts, it was decided that a mid-cycle
inspection was necessary. The utility concluded
that the results of that inspection showed that the
models developed at the end of the previous
operating cycle overestimated the number and
size of the tubesheet expansion zone defects, but
underestimated the number and size of the defects
near the tube support plates. The mid-cycle and
future inspections of North Anna Unit 1 consisted
of 100% full length bobbin coil eddy-current
inspections, 100% 8x1 probe inspections of the
hot-legs, 100% rotating pancake coil inspections
near the top of the tubesheet, and follow-up of all
bobbin and 8x1 probe indications with a rotating
pancake coil eddy-current inspection.
NUREG/CR-6365
194
REGULATORY PRACTICES
195
NUREG/CR-6365
REGULATORY PRACTICES
2(a).
2(b)
NUREG/CR-6365
196
REGULATORY PRACTICES
(i)
(ii)
(iii)
197
NUREG/CR-6365
REGULATORY PRACTICES
NUREG/CR-6365
198
REGULATORY PRACTICES
The defect type and location specific fitness-forservice guidelines used in France are
summarized, as follows:
Axial PWSCC in the roll transition zone. The
axial crack length limit is based on an analysis of
crack growth and tube burst during a main steam
line break, which is considered to be the design
basis accident that imposes the highest loads.
Correlations of critical crack length versus burst
pressure have been developed from experiment.
The analysis uses these correlations and the
maximum tube diameter and minimum wall
thickness, adverse mechanical properties, upperbound temperatures and pressures, a conservative
allowance for crack growth during the next
operating cycle, and margin for NDE error.
Safety factors are not applied. In developing
these correlations, the French concluded that a
crack with an end within the tubesheet where the
tube is in contact with the tubesheet can
propagate in an unstable manner in only one
direction. The maximum allowable free crack
length is 13mm, for the 900 MWe plants. A
temporary criterion of 13mm has also been
adopted for the 1300 MWe plants. A definitive
plugging criterion will be established after
completion of certain probabilistic risk studies.
Circumferential PWSCC. Tubes with circumferential PWSCC must be plugged because (a)
the leak before risk of break approach does not
apply since the cracks are often not throughwall
until the tube is close to rupture (i.e., the cracks
tend to propagate around the tube first), and (b)
the rotating pancake coil eddy-current detection
limit is only about 50% of the wall thickness. In
other words, the French do not believe that there
is much margin between initial detection of
circumferential PWSCC and possible rupture
under extreme accident conditions.
199
NUREG/CR-6365
REGULATORY PRACTICES
NUREG/CR-6365
200
REGULATORY PRACTICES
Other.
Tubes with defects exceeding the
traditional 45 % loss of tube wall thickness are
repaired.
201
NUREG/CR-6365
REGULATORY PRACTICES
NUREG/CR-6365
202
REGULATORY PRACTICES
The Swedish approach forjudging axial PWSCC
in the tubesheet region is probabilistic or risk
based in nature (Hedner 1992). The objective is
to limit the probability of steam generator tube
burst during a main steam line break to less than
1 %, i.e., the sum of all tubes with an indicated
crack length, times the probability of burst for
that crack length, must be less than 0.01.
In equation form:
E P <0.01
M x
7.3.15
Fitness-For-Service Guidelines in
Switzerland
203
NUREG/CR-6365
NUREG/CR-6365
204
205
NUREG/CR-6365
6 = 1.98(p/fy )* mm,
rel
NUREG/CR-6365
206
6 = X/6
8.1.2 Basic Probes
where 8 is the phase lag angle in radians and X
is the depth within the material. At the depth of
X = 6 , the resulting phase lag is 57 degrees.
For thin-walled tubing, a frequency is often
selected to provide a sufficient eddy-current
density at both the inside and outside surface for
crack detection, but another frequency is selected
NUREG/CR-6365
Flexible guides
Active coi
Push tube
Toroidal reference coil
Figure 86. Eddy-current bobbin probe with flexible wafter guides, used for inspection of steam generator
tubesheet rolled joints (ASM 1989). Copyright ASM International, reprinted with permission.
NUREG/CR-6365
208
The eddy-current probes are operated at frequencies that offer the highest signal-to-noise ratio.
This ratio is determined by operating the eddycurrent instrument over a wide frequency range
and monitoring the probe signal responses from
samples containing known flaws and the noise
responses from extraneous sources such as
support plates, dents, and copper deposits. In
one case, the probes were operated over a 100 to
800 kHz frequency range. The results showed
that signal-to-noise ratio from large volume flaws
peaked at 300 kHz and the signal-to-noise ratio
from small-volume flaws peaked at 200 kHz.
The results also showed that at any frequency
between 100 to 800 kHz, a dent signal is greater
than a flaw signal, which was evident from the
flaw signal-to-noise (dent signal) ratio of less than
1.0(Krzywosz 1990).
Laboratory test results show that an optimal
signal response is obtained when the operating
frequency of the probe is near its resonance. For
conventional bobbin coils, the resonant frequency
is about 300 kHz, and the optimal operating
frequency is in the range of 200-300 kHz. Large
volume flaws, including volumetric defects
(wastage, wear, etc) and axial flaws, result in a
maximum signal-to-noise ratio at 300 kHz, and
circumferential and smaller volume flaws of less
than throughwall penetration result in a
maximum signal-to-noise ratio at 200 kHz
(Krzywosz 1990).
Figure 88 shows some typical common impedance plane eddy-current signals encountered
during inspection of a calibration tube with an
internal bobbin coil probe (Cecco and Van
Drunen 1985). The test frequency is 250 kHz.
Figure 88a shows the results from using an
absolute probe and Figure 88b shows the results
from using a differential probe. In this case, the
signal from the defect has a phase angle between
0 and 90 degrees, whereas signals from support
plates or outside surface deposits have a phase
angle greater than 90 degrees. The defects on
209
NUREG/CR-6365
COIL 2
COIL I
SIM]
(a)
^^P
COIL 1
COIL 2
CONNECTOR
PLASTIC
BOBBIN
FLEXIBLE
CENTERING
GUIDES
COIL 2
STAINLESS
STEEL CASE
(c)
!b)
Figure 87. Schematic showing (a) the location of the probe coils in an ac bridge circuit, (b) an absolute
probe configuration, and (c) a differential probe configuration (Cecco and Van Drunen 1985). Copyright
Academic Press; reprinted with permission.
NUREG/CR-6365
210
STEEL
SUPPORT
PLATE
OUTSIDE
GROOVE
INSIDE
GROOVE
THROUGH
HOLE
C
MAGNETITE
DENT
21
> :
PROBE
OUTSIDE
PROBE
WOBBLE
HOLE
OUTSIDE
DENT
DECREASING
FILL FACTOR
INSIDE
MAGNETITE
SUPPORT
PLATE
SUPPORT
PLATE
(b)
(a)
Figure 88. Eddy-current signals from a typical calibration tube using (a) an absolute probe and (b) a
differential probe (Cecco and Van Drunen 1985). The tube material is Alloy 600, 12.7mm outside
diameter by 1.1mm wall thickness, 250 kHz test frequency. Copyright Academic Press; reprinted with
permission.
the inside surface have a smaller phase angle,
whereas defects on the outside surface have a
phase angle near 90 degrees; the signals from
through-wall defects fall between these two
signals. As mentioned above, the phase angle for
a given defect is not a fixed value and it can be
increased or decreased by increasing or
decreasing me test frequency. The phase angle
of the signal provides an approximate indication
of the depth of a defect.
211
NUREG/CR-6365
CABLE
CONNECTOR
\ \
\ \
v. v. V v. v v. s . v. v. '. ^ \
&ZZZ2
V \ V'< \ \ \
S \ \ \ v, \ \ V \ \ \ \ A \ \ S \ V V K T
REFERENCE
COIL
V V
SPRING
Figure 89. A cross section of an eddy-current probe showing how the spring loaded pancake coil is
arranged in an absolute mode (Cecco and Van Drunen 1985). Copyright Academic Press; reprinted with
permission.
NUREG/CR-6365
212
Figure 90. Typical differential hybrid coil arrangement (Libby 1971). Copyright 1971 John Wiley and
Sons, Inc.; reprinted with permission.
213
NUREG/CR-6365
Multifrequency /multiparameter
eddy-current
(MFEC/MPEC) methods employing bobbin coils
are widely used for steam generator tube
inspections.
These methods provide more
reliable detection and additional characterization
information on the secondary side of the steam
generator tubes in the presence of extraneous test
variables such as the tubesheet or tube supports.
The tubesheet and the tube supports produce
large changes in an eddy-current signal
(impedance response) that mask or modulate the
changes produced by a defect. Denting of steam
generator tubes, first reported in mid 1970s, also
made reliable defect detection difficult and
provided an impetus for the use of these new
methods. The MFEC/MPEC methods isolate the
changes produced by a defect (a wanted
parameter) by suppressing the changes produced
by other unwanted parameters such as support
plates and denting.
NUREG/CR-6365
214
Figure 91. Example of support-plate suppression; (a) shows a normal single-frequency response from a
60% flaw, (b) shows the same response when the flaw is under a support plate, (c) shows the response
of a three-frequency multi-parameter mix (Davis 1980). Copyright Electric Power Research Institute, Inc.;
reprinted with permission.
215
NUREG/CR-6365
NUREG/CR-6365
216
Figure 92. Illustration of a motorized rotating pancake coil helical scan (Courtesy of M. Klatt, Zetec,
Inc.).
RECOMMENDED PROBE OIA
(NOMINAL TUBE ID. -,0<5)
ROTATIONAL
DIRECTION
1 COIL
q 3 COIL
M3 COL
B 2 COL
n 2 COIL
O1 COIL
Figure 93. Schematic of a shielded 3-coil motorized rotating pancake coil probe (Siegal and Klatt 1994).
217
NUREG/CR-6365
some resolution may be sacrificed for inside diameter cracking caused by PWSCC. This reduced
resolution is due to the larger coil size, lack of
shielding, and greater concentration of eddycurrents at the outside surface (Siegal and Klatt
1994).
A \
\ \ \ \
\ \ \ \ ' \ \
\ \ \ \ \ \ \ T
>
\ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \ \
Figure 94. A multiple coil probe for detecting circumferential cracks in steam generator tubing (Cecco
and Van Drunen 1985). The two rows of coils are staggered. Copyright Academic Press; reprinted with
permission.
NUREG/CR-6365
218
Obrutsky et al. (1994, 1996) state that the Cecco3 probe is more sensitive to circumferential
cracks on the tube outside surface, generates
219
NUREG/CR-6365
lower lift-off noise, and has a higher signal-tonoise ratio than the RPC probes. The Cecco-3
probe has no moving parts, making it
considerably more durable than the spring loaded
rotating pancake coil probes. And, the Cecco-3
probe permits single-pass inspections which are
as fast as the bobbin coil probe inspections.
NUREG/CR-6365
220
I
T
Upper Hydraulic
Expansion
Upper Hardrol!
Parent Tube
Sleeve
Tubesheet
Lower Hydraulic
Expansion
Lower Hardroll
Cladding
221
Copyright
NUREG/CR-6365
Tube
Sleeve
Upper Hydraulic /
Transition
Upper Hardroll /
Transition
'
Hardroll
Lower Hardroll \
Transition
^
Bottom of the
transition
Hydraulic
Expansion
Lower Hydraulic
Transition
NUREG/CR-6365
222
Initially, Zetec, Inc. developed the crosswound differential bobbin coils shown in Figure
97 for sleeve inspections (Siegal and Klatt 1994).
This probe was designed to minimize the effects
of the roll-transition region of the sleeve, but the
inspection results were difficult to interpret and
could not detect flaws in the parent tube during
mock-up sleeving trials. In addition, flaws were
found in the expansion area at several operating
plants that were not detectable with the crosswound bobbin coil. As a replacement for the
cross-wound bobbin probe, the I-Coil probe was
also developed by Zetec using surface riding
absolute, directional coils on the rotating pancake
coil inspection head (Figure 98) (Siegal and Klatt
1994). This probe, which was used successfully
at Kewaunee and Prairie Island for inspection of
Westinghouse and CE sleeves, provided better
penetration for detection of outside diameter
flaws and detected cracking in the expansion and
sleeve weld zones.
An improvement to the I-Coil probe, the PlusPoint probe, was recently developed by Zetec
which provides an improved signal-to-noise ratio
and better crack detection capability (Zetec
VI.
Figure 97. Schematic of a cross wound bobbin coil probe for sleeve inspections (Siegal and Klatt 1994).
223
NUREG/CR-6365
Circumferential Coil
^W
mm
Axial Coil
Figure 98. Schematic of the "I" type motorized rotating pancake coil probe for sleeve inspections (Siegal
and Klatt 1994).
Axial crack
Direction of
rotation (scan)
Circumferential crack
Direction of
rotation (scan)
Circumferential
crack response
M96 0145
Figure 99. Orientation of the coils in the Zetec Plus-Point probe and typical responses from a weld scan
with the probe configured in the standard differential mode (Zetec 1988).
NUREG/CR-6365
224
50 to 200-nmthick nickel
plate
, Length
/ ,
/
\
Roll
transition
area with
short axial
ID cracks
varied to
suit needs,
typically
. about
5-cm long
0-3072
Figure 100. Nickel plating of a roll-transition region with PWSCC cracks (EPRI 1985b). Copyright 1987
Electric Power Research Institute; reprinted with permission.
225
NUREG/CR-6365
NUREG/CR-6365
226
Tube
Plug shell
Expander
Approximate
location of
North Anna-2
plug failure
Tubesheet
Expander
Expanded plug
Unexpanded plug
N93 0048
Figure 101. Sketches of unexpanded and expanded mechanical plugs (Westinghouse 1989); reprinted with
permission.
ential cracks in pulled tubes has shown that the
rotating ultrasonic inspection system can detect
defects deeper than 30% throughwall (Roussel
1994). Framatome has also developed a rotating
ultrasonic testing system for the detection of
shallow ODSCC, particularly in the roll
transition zone at the tubesheet.
NUREG/CR-6365
Turbine Bearings
Probe
.Probe
Housing
45 Angled Mirror
-Tube
Figure 102. Schematic of rotating ultrasonic beam scanning device. Courtesy of Russell Technologies,
Incorporated, Edmonton, Alberta, Canada.
PWR feedwater piping susceptible to thermal
fatigue cracking.
a b
NUREG/CR-6365
228
229
NUREG/CR-6365
8.4
Limitations of Inservice Inspection
Methods for Steam Generator Tubes
The eddy-current and ultrasonic methods
discussed in this section have some limitations in
detecting degradation damage to steam generator
tubes. The sizing capabilities for these inspection
methods are particularly limited. In some cases,
the uncertainties in sizing of the defects are being
determined by comparing the eddy-current
measurements, and sometimes ultrasonic
measurements, with destructive examinations of
pulled tubes. The limitations of the inspection
methods for characterizing the damage caused by
each of the different steam generator tube
degradation mechanisms are discussed next in the
following order: primary water stress corrosion
cracking, intergranular attack, outside diameter
stress corrosion cracking, pitting, wastage,
denting, high-cycle fatigue, and wear.
8.4.1
Primary Water Stress Corrosion
Cracking
Primary water stress corrosion cracking has
generally been found at the expansion-transition
region near the tube sheet, any roll-expansion
region within the tube sheet, the U-bend region
of the first few rows, and near dents. The
expansion-transition regions include both rolltransition and explosive-transitions. The PWSCC
in a roll-transition region is mostly axial, though
230
231
NUREG/CR-6365
360 T
c
0)
270
O
LU
180
0)
Q
CD
C
<D
_1
90
4-
0
0
90
180
270
360
NUREG/CR-6365
232
233
NUREG/CR-6365
NUREG/CR-6365
234
235
NUREG/CR-6365
360 -r
c
o
270
O
T3
LU
180
CD
Q
C
CD
_J
o
<
90
0
90
180
270
360
Figure 104. Comparison of actual arc length of circumferential ODSCC cracks in pulled tubes with the
ones estimated using eddy-current inspection (Malinowski 1995).
pulled tube specimens.
The ultrasonic
measurements compared well with the actual
crack profile (Maurer 1995). According to
ultrasonic measurements, the macrocracks ranged
in circumference from 84 to 329 degrees and
ranged in depth up to 100% throughwall
(USNRC 1990).
NUREG/CR-6365
8.4.4 Pitting
Pitting appears as a group of small diameter wall
penetrations and is found between the top of the
tube sheet and the first support on the cold-leg
236
237
NUREG/CR-6365
Fretting and wear have occurred at the tube-tobaffle plate intersections on the cold leg side in
the Westinghouse Models D and E steam
generators with preheaters. Fretting and wear
have also occurred at the AVBs in the
recirculating steam generators of several different
designs. Loose parts have also caused wear of
peripheral tubes. Wear causes loss of material at
the tube outside diameter. The shape of fretting
induced wear is determined by the contact area
with the supporting structure and its length is
limited to the thickness of the supporting
structure. Fretting induced wear is also limited
to some critical tubes, which makes inspection
much easier. This damage is relatively easy to
detect and size with a bobbin coil probe.
NUREG/CR-6365
238
239
NUREG/CR-6365
8.5 Summary
Inspection of the steam generator tubes is critical
to the safe and economical operation of nuclear
power plants. Eddy-current inspections using
bobbin coil probes were fast and effective in
detecting and sizing me degradation that took
place in early steam generators. However,
newer forms of degradation have appeared in
NUREG/CR-6365
240
Table 26. Sites, typical characteristics, and inspection or steam generator tube damage.
Sites
Expansion transition
region, inside diameter
defects
Expansion transition
region, outside diameter
defects
Degradation
Mechanism
Characteristics of Damage
Axial cracks
Bobbin coil for detection; RPC for sizing, accuracy 1.5 mm; Cecco5 probe can also be used for detection.
Circumferential cracks
RPC detects > 50% throughwall cracks; Plus-Point probe detects >
26% throughwall cracks; Rotating ultrasonic probe detects > 50%
throughwall cracks; Array, Cecco-3 and Cecco-5 probes can also be
used for detection; RPC and ultrasonic probes underestimate arc
lengths.
IGA
Bobbin coil probe in an absolute mode and array probe for detection;
8 x 1 array probe to characterize deep localized IGA and estimate
circumferential event of IGA.
ODSCC
Circumferential cracks
RPC detects > 50% throughwall and 50-degrees arc length, or 100%
throughwall and 23-degree arc length; RPC and Cecco-5 sizing
accuracy 37 to 45 degrees, Cecco-3 detects > 40% throughwall
cracks with a depth sizing accuracy 15% of the wall thickness;
rotating ultrasonic probe detects >30% throughwall cracks, but
underestimates depth.
Pitting
Wastage
Wall thinning
Denting
Circumferential cracks
PWSCC
GO
PWSCC if
heavy denting is
present
ON
ON
O
H
oen
*n
w
o
H
a
a
H
m
n
H
c
o
o
o\
Table 26. Sites, typical characteristics, and inspection of steam generator tube damage (continued).
Sites
Degradation
Mechanism
IGA
Characteristics of Damage
Bobbin coil probe in an absolute mode and array probe for detection; 8
x 1 array probe to characterize deep localized IGA estimate
circumferential extent of IGA.
ODSCC
Axial cracks
ODSCC
associated with
significant
denting (carbon
steel support
plates)
Circumferential cracks
Cecco-3 probe detects > 40% throughwall cracks with a depth sizing
accuracy of 15% of the wall thickness; 8x1 array probe for detection
and sizing.
Wastage (first
two support
plates)
Wall thinning
ODSCC/IGA
PWSCC
Axial crack's
Flexible rotating pancake coil probe for both detection and sizing;
Bolibin coil probe for detection.
Fretting at
antivibration bar
supports
Wall thinning
High-cycle
fatigue of
improperly
supported tubes
Circumferential cracks
Difficult to detect because crack initiation time is quite long and the
crack growth is rapid.
Fretting caused"
by loose parts
Wall thinning
Bobbin coil probe for detection; sizing of affected area less accurate.
PWSCC in
parent lubes
Circumferential cracks
ODSCC in
parent tubes
PWSCC
CO
O
W
8
H
o
w
o
o
5S
is even more difficult to control than a spontaneous tube rupture transient, and radioactivity
released to the environment may exceed site
limits. The analysis of such transients in PWRs
indicate that effective operator intervention and
actions to throttle the emergency core cooling
injection and actuate the residual heat removal
system will result in a successful recovery from
a main steam line break with up to about 15
induced steam generator tube ruptures. More
than about 15 induced steam generator tube
ruptures produces a system response where the
reactor coolant system subcooling cannot be
recovered prior to exhaustion of the normally
available emergency core cooling water (which in
some plants can be replenished from outside
sources).
b
243
NUREG/CR-6365
equipment that is able to detect certain degradation is slow and expensive. More effective
equipment for detecting certain degradation is
being developed.
steam generator tubing inspection requirements and fitness-for-service criteria in various countries, and
NUREG/CR-6365
244
245
NUREG/CR-6365
stress
NUREG/CR-6365
246
Spontaneous and induced steam generator tube ruptures are small contributors
to the to the total core damage frequency
but are risk significant due to the potential for the radionuclides to bypass the
reactor's containment building.
247
NUREG/CR-6365
NUREG/CR-6365
248
249
NUREG/CR-6365
Inspection of IGA
Conventional bobbin coil and rotating
pancake coil probes are not sensitive to
the IGA-induced slow changes in the
electrical conductivity and magnetic
permeability. Therefore, these probes
cannot reliably detect and characterize
IGA damage.
Array probes with an 8 x 1 or 8 x 2
surface riding pancake coil arrangement
can detect intergranular attack and
estimate its circumferential extent and
depth.
Inspection of Pitting
Inspection of Dents
A rotating ultrasonic inspection probe or
an array probe with contactless pancake
coils has been successfully used for
estimating the profiles of dented tube
cross-sections.
NUREG/CR-6365
250
251
NUREG/CR-6365
10. REFERENCES
ASM (ASM Committee on Eddy Current Inspection) 1989. "Eddy Current Inspection" pp. 164-194 in
ASM Handbook, Vol. 17, Nondestructive Evaluation and Quality Control, ASM International,
Materials Park, Ohio.
ASME 1992, 1992 ASME Boiler and Pressure Vessel Code, Section XI, Article IWB-3640 and
Appendix C.
Airey, G. P., and F. W. Pement 1982. "A Comparison of Intergranular Attack in Alloy 600 Observed
in the Laboratory and in the Operating Steam Generators," Presentation to the National
Association of Corrosion Engineers, March 22-26, 1982, Houston, Texas.
Angwin, M. J. 1984. "High Temperature Pitting in PWR Steam Generator," Proceedings of the
International Congress on Metallic Corrosion, Volume 1, Toronto, Ontario, June 3-7, 1984,
National Research Council of Canada, Toronto, pp. 250-256.
Azodi, D., et al. 1987. "On the Integrity of Steam Generator Tubes and Plugging Assessment,"
Structural Mechanics in Reactor Technology, Transactions of the 9th International Conference,
Lausanne, August 17-21.
Balkrishnan, P. V., and R. S. Pathania 1988. "Correlation of Tube Support Structure Corrosion
Studies." Proceedings of the Third International Symposium on Environmental Degradation of
Materials in Nuclear Power systems-Water Reactors, Traverse City, Michigan, The
Metallurgical Society, Warrendale, Pennsylvania, pp. 489-499.
Bamford, W. H., G. V. Rao and J. L. Houtman 1992. "Investigation of Service-Induced Degradation
of Steam Generator Shell Materials," Proceedings of the Fifth International Symposium on
Environmental Degradation of Materials in Nuclear Power Systems Water Reactors, August
25-29, Monterey, California, pp. 588-595.
Bamford, W. H., et al. 1987. "Integrity Issues in PWR Steam Generator and Feedwater Systems,"
Performance and Evaluation of Light Water Reactor Pressure Vessels, PVP-Vol. 119,
American Society of Mechanical Engineers, New York, pp. 19-30.
Bandy, R., and D. van Rooyen 1984. "Initiation and Propagation of Stress Corrosion Cracking of
Alloy 600 in High Temperature Water," Proceedings of the Third International Symposium on
Environmental Degradation of Materials in Nuclear Power Systems-Water Reactors, Houston,
Texas, National Association of Corrosion Engineers, Houston, p. 763
Bandy, R., and D. van Rooyen 1984a. "Stress Corrosion Cracking of Inconel Alloy 600 in High
Temperature Water-An Update," Corrosion, 40, No. 8.
Baum, A. J., et al. 1987. Steam Generator Cold Leg Thinning in Operating Plants, EPRI NP-5140,
Electric Power Research Institute, Palo Alto.
253
NUREG/CR-6365
REFERENCES
Begley, J. 1988. "Application of the Gerber-Garud Strain Rate Damage Model to PWSCC,"
Proceedings: 1987 EPRI Workshop on Mechanisms of Primary Water Intergranular Stress
Corrosion Cracking, EPRI NP-5987SP, Electric Power Research Institute, September, pp. D6-1
toD6-ll.
Benson, J. 1988. "Application of an F* Probe at Connecticut Yankee," presented at the EPRI Steam
Generator Workshop, Myrtle Beach, South Carolina, June 7-9.
Berge, Ph., 1993. "After 33 Years, It is Time to Solve Pure Water Cracking," Keynote speech in
Proceedings: 1992 EPRI Workshop on PWSCC of Alloy 600 in PWRs, EPRI TR-103345,
December (proprietary report; not publicly available).
Berge, Ph., and J. R. Donati, 1981. "Materials Requirements for Pressurized Water Reactor Steam
Generator Tubing," Nuclear Technology, Vol. 55, October, pp. 88-104.
Blomgren, J. C. 1986. "Experience at Zion," presented at the EPRI Workshop on Fretting and Wear
Susceptibility in Nuclear Steam Generators, Washington, D.C., March 19-20, 1986.
Bodson, F. et al. 1991. "Specific Ultrasonic Inspection Methods for Steam Generator Tubes,"
NEA/CSNI-UNIPEDE Specialist Meeting on Operating Experience with Steam Generators,
Brussels, Belgium, 16-20 September.
Bollini, G., 1993. "Steam Generator Inspection Reliability and Safety," Second ASME/JSME
International Conference on Nuclear Engineering (ICONE), San Francisco, March.
Bowling, M. L. 1988. North Anna Unit 1 Steam Generator Tube Rupture, July 15, 1988, Revision 3,
Virginia Power Company.
Bradish, T. R. 1993. "Manual Reactor Trip Following a Steam Generator Tube Rupture," Licensee
Event Report No. 93-01, Rev. 2, Docket No. 5000529, August 14.
Bruemmer, S. M., L. A. Chariot, and C. H. Henager, Jr. 1988. "Microstructure and
Microdeformation Effects on IGSCC of Alloy 600 Steam Generator Tubing," Proceedings:
1987 EPRI Workshop on Mechanisms of Primary Water Intergranular Stress Corrosion
Cracking, EPRI NP-5987SP, Electric Power Research Institute, Palo Alto, September, pp. C3-1
toC3-31.
Canadian Standard Association 1994. "Periodic Inspection of CANDU Nuclear Power Plant
Components," CAN/CSA-N285.4.
Campbell, C. A. and S. Fyfitch 1994. "PWSCC Ranking Model for Alloy 600 Components," Sixth
International Symposium on Environmental Degradations of Materials in Nuclear Power
Systems-Water Reactors, San Diego, California, pp. 863-870.
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254
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in Research Techniques in Nondestructive Testing - Volume VIII, Academic Press, New York,
pp. 269-301.
Clark, R. A., and M. Lewis 1985. "Observations of Denting and Other Deterioration in the Surry
Steam Generator," Proceedings of the International Conference in Nuclear Power Plant Aging,
Availability Factor and Reliability Analysis, San Diego, California, July 8-12, 1985, V. S. Goel
(ed.), American Society for Metals, Metals Park, Ohio, pp. 193-195.
Clark, W. G., Jr. 1993. "Multiple-Element Eddy Current Probes for Enhanced Inspection," Materials
Evaluation, July, pp.794-802.
Cochet, B., 1989. Tube Plugging in the Tubesheet Area Leak Before Break Analysis - Tube Plugging
Criteria, Pecember.
Cofie N. G. et al. 1994. "Management of Steam Generator Feedwater Nozzle Cracking in PWRs,"
1994 Pressure Vessels and Piping Conference, Minneapolis, Minnesota, June 19-23, 1994,
ASME PVP Vol. 286, Changing Priorities of Codes and Standards: Failure, Fatigue, and
Creep.
Commonwealth Edison Co. 1987. Technical Specifications for Braidwood Station Units 1 and 2,
Appendix A to License No. NPF-72, Docket Nos. STN 50-456 and STN 50-457, also published
by the USNRC as NUREG-1276, July.
Connors, H. J., et al. 1988. Beaver Valley 1 Evaluation for Tube Vibration Induced Fatigue, WCAP11800, Westinghouse Electric Company, Pittsburgh.
Conway, W. F. 1993. Palo Verde Nuclear Generating Station Unit 2 Steam Generator Tube Rupture
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Coriou, H., et al. 1959. "Corrosion Fissurante Sous Contrainte De L'Inconel Dans L'Eau A Haute
Temperature," in Third Colloque de Metallurgie Corrosion, Center d'Etudes Nucleaires de
Saclay, France, North Holland Publishing Co., Amsterdam, p. 161.
Coulehan, V. R. 1988. "Manual Reactor Shutdown Due to 2 Gallon Per Minute Steam Generator
Primary to Secondary Leak in Number 31 Steam Generator Caused by Degraded Tube,"
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CSGORG (Counterflow Steam Generator Owners Review Group) 1983. "Appendix B, Independent
Evaluation of Proposed Modifications to Westinghouse D4, D5, and E Steam Generators,"
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Davis, T. J. 1981. "Advanced Multifrequency Eddy-Current System for Steam-Generator Inspection,"
Eddy Current Characterization of Materials and Structures, ASTM STP 722, American Society
for Testing and Materials, pp. 255-265.
255
NUREG/CR-6365
REFERENCES
Davis, T. J. 1980. Multifrequency Eddy-Current System for Inspection of Steam Generator Tubing,
EPRI NP-1621, November.
de Keroulas, F., and L. Lunven 1990. "Fissuration en Milieu Primaires des Tubes Generateurs de
Vapeur des Reacteurs 900 et 1,300 MWe: Resultats des Examens Metallurgiques sur Tubes
Extraits," International Symposium, Fontevraud II, Volume 1, Royal Abbey of Fontevraud,
September 10-14, 1990, Socfete Francaise d'Energie Nucleaire, pp. 206-214.
Dembek, S. 1995. "Summary of Electric Power Research Institute (EPRI) Led Presentation on Steam
Generator (SG) Tube Circumferential Cracking Sizing Techniques," Memorandum to J.
Strosnider, USNRC, March 13, 1995.
Dobbeni, D. 1991. "Ultrasonic Inspection Methodology," NEA/CSNI - UNIPEDE Specialist Meeting
on Operating Experience with Steam Generators, Brussels, Belgium, 16-20 September.
Dobbeni, D. and Degreve, D. 1990. "Adapting Ultrasonics to Examine PWSCC in Steam
Generators," Nuclear Engineering International, May.
Dobbeni, D., et al. 1985. "Belgian Approach to Non-Destructive Examination of Primary Side Stress
Corrosion Cracking," presented at the SGOG/EPRI Workshop at St. Petersburg Beach, Florida,
December 10-12, 1985.
Dodd, C. V., et al. 1988. "Eddy Current Inspection of Ferromagnetic Materials Using Pulsed
Magnetic Saturation," Material Evaluation 46, 12, pp. 1592-1597.
Dodd, C. V. and Deeds, W. E. 1981. "In-Service Inspection of Steam Generator Tubing Using
Multiple-Frequency Eddy Current Techniques," Eddy Current Characterization of Materials and
Structures, ASTM STP 722, American Society for Testing and Materials, pp. 229-239.
Engstrom, J. 1985. "Comparison of Eddy Current Test Results in Steam Generator Tubesheet Roll
with Results from Metallographic Examination of Pulled Tubes," presented at the SGOG/EPRI
Workshop at St. Petersburg Beach, Florida, December 10-12, 1985.
EPRI 1995. PWR Steam Generator'Tube Repair Limits - Technical Support Document for Outside
Diameter Stress Corrosion Cracking at Tube Support Plates, EPRI TR-100407, Rev. 2A,
January.
EPRI 1995a. Steam Generator Progress Report, Rev. 11, EPRI TR-106365.
EPRI 1995b. "NDE of Circumferential Cracks," presented at the NRC/NEIMeeting on
Circumferential Cracking NDE, Rockville, MD, September 8, 1995.
EPRI 1994. Steam Generator Progress Report, Rev. 10, Energy Management Services, Inc., Little
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NUREG/CR-6365
256
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EPRI 1993a. PWR Steam Generator Tube Repair Limits - Technical Support Document for Outside
Diameter Stress Corrosion Cracking of Tube Support Plates, EPRI TR-100407, Rev. 1, August.
EPRI 1993b. PWR Steam Generator Tube Repair Limits: Technical Support Document for Expansion
Zone PWSCC in Roll Transitions, EPRI NP-6864-L, Rev. 2, August.
EPRI 1993c. PWR Secondary Water Chemistry Guidelines, Rev. 3, EPRI TR-10234, Rev. 3, May.
EPRI 1990a. Alloy 690 for Steam Generator Tubing Application, EPRI NP-6997-SD, October.
EPRI 1990b. PWR Primary Water Chemistry Guidelines: Revision 2, EPRI NP-7077, Electric Power
Research Institute, Palo Alto, November.
EPRI NDE Center 1987. Advanced Eddy-Current Data Analysis for Steam Generator Tubing.
EPRI 1985a. Steam Generator Reference Book, Steam Generator Owners Group, Electric Power
Research Institute, Palo Alto, CA (proprietary report; not publicly available).
EPRI 1985b. Proceedings: 1985 Workshop on Primary-Side Stress Corrosion, St. Petersburg Beach,
Florida, December 10-12, EPRI NP-5158.
Ericson, D. M. et al, 1990. "Analysis of Core Damage Frequency: Internal Events Methodology,"
NUREG/CR-4550, Vol. 1, Rev. 1.
Erdogan, F., 1976. "Ductile Fracture Theories for Pressurized Pipes and Containers," International
Journal of Pressure Vessels and Piping, Vol. 4, pp. 253-283.
Flesch, B., and B. Cochet, 1990. "Leak-Before-Break in Steam Generator Tubes," International
Journal of Pressure Vessels and Piping, Vol. 43, pp. 165-179.
Fukui, S. et al. 1992. "Eddy Current Inspection System for Mechanical Plug of Steam Generator
Tube," Proceedings of the 11th International Conference on the NDE in the Nuclear and
Pressure Vessel Industries, Albuquerque, New Mexico, USA, 30 April-2 May.
Gentillon, C. D., J. B. Hudson, and J. A. Schroeder, 1994. Rates for Initiating Events in U.S.
Commercial Nuclear Power Plants, 1989-1993, INEL-94-0270.
Georgia Power Co. 1987. "Steam Generator Technical Specification 3/4.4.5" in Vogtle Electric
Generating Plant Unit 1 and 2 Technical Specifications, 1987 (Unit 1) and 1989 (Unit 2),
Appendix A to Operating Licenses NPF-68 and NPF-81, Docket Nos. 50-424 and 50-425.
Giacobbe, F. S., et al. 1988. "IGA/IGSCC of Sensitized Alloy 600 Tubing in TMI Unit 1 OTSGs,"
1987 EPRI Workshop on Secondary-Side Intergranular Corrosion Mechanisms: Proceedings,
EPRI NP-5971, Volume 2, Electric Power Research Institute, Palo Alto.
257
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REFERENCES
Gorbatykh, V. P., 1993. "The Corrosion Life of Metal," Thermal Engineering, Vol. 40, No. 7.
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267
NUREG/CR-6365
APPENDIX A
APPENDIX
This Appendix describes the heat transfer
modeling of the Residual Heat Removal (RHR)
Systems for the Surry Nuclear Steam Supply
System.
(T -T -(T -T )
a
(Ar) =
b)l
b 2
(2)
In
bI
(3)
bl
b2
a
C
Q
pb
where
=
=
=
=
=
=
=
a=(l +
W C
pa
(4)
and
=(I+I)U A
WC
WC
b pb
pa
T -T -(^-)(T -T )
a2
aI
b2
(5)
bl
pa
A-l
NUREG/CR-6365
APPENDIX
temperatures, T and T were used to recompute
the outlet temperatures, T^ and T , using Eqs. 3
through 5, thereby verifying the model. The
calculated values for T and T , are identified in
Figs. Al and A2 with the data symbol (square).
al
bl
b2
a2
300.0
0
450
425
*-*
400
8>
CO
&_
CD
Q.
CD
Q.
375
1-
200.0
350
325
100.0
0.0
20.0
10.0
NUREG/CR-6365
A-2
30.0
|
F
APPENDIX
140.0
LL
o
to 130.0
CL
E
^
120.0
110.0
100.0
0.0
10.0
20.0
Calculation No.
30.0
CI70-WHT-196-A2
A-3
NUREG/CR-6365
NRC f-ORM 3 3 5
12 89!
NBCM 1102,
M01.3202
1. R E P O R T NUMBER
(Assigned by NRC. Add Vol., Supp., Rev.,
and Addendum Numbers, If any.)
NUREG/CR-6365
INEL-95/0383
3.
April
YEAR
1996
E8238
5. AUTHOR(SI
6. TYPE OF REPORT
Ellison
Technical
7. PERIOD COVERED (Inclusive Dates)
8. PERFORMING ORGANIZATION NAME A N D A D D R E S S (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address: if contractor,
name and mailing address.)
provide
Idaho N a t i o n a l E n g i n e e r i n g Laboratory
Lockheed Idaho T e c h n o l o g i e s Company
Idaho F a l l s , ID 84315
9. SPONSORING ORGANIZATION - NAME AND A D D R E S S llfNRC,
and mailing address.)
type "Same as above''; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory
Commission,
S a f e t y Programs D i v i s i o n
O f f i c e f o r A n a l y s i s and E v a l u a t i o n of O p e r a t i o n a l Data
U . S . N u c l e a r R e g u l a t o r v Commission
Washington, DC 20555-0001
10. SUPPLEMENTARY NOTES
Steam g e n e r a t o r t u b e s , n u c l e a r p l a n t a g i n g , d e g r a d a t i o n mechanisms,
f a i l u r e mechanisms, i n s p e c t i o n and s u r v e i l l a n c e
Unlimited
14. SECURITY CLASSIFICATION
(This P.w.-I
Unclassified
(This Report)
Unclassified
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WC f O R .;_'!> 'P-89/