WRC 490 Ed. 2004 Damage Mechanisms Affecting Fixed Equipment in The Fossil Electric Power Industry
WRC 490 Ed. 2004 Damage Mechanisms Affecting Fixed Equipment in The Fossil Electric Power Industry
WRC 490 Ed. 2004 Damage Mechanisms Affecting Fixed Equipment in The Fossil Electric Power Industry
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Board
David N. French
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ISSN 0043-2326
Library of Congress Catalog Number: 85-647116
Jonathan D. Dobis
David N. French
Library of Congress
Catalog Card Number: 85-647116
Copyright © 2004 by
Welding Research Council, Inc.
All Rights Reserved
Printed in U.S.A.
ii
FOREWORD
Martin Prager
Executive Director of WRC
iv
CONTENTS
FOREWORD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
1.0 INTRODUCTION AND SCOPE
1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.3 Organization and Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1.4 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1.5 Definition of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1.6 Technical Inquiries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.0 REFERENCES
2.1 Standards. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.2 Other References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
3.0 DEFINITION OF TERMS AND ABBREVIATIONS
3.1 Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
3.2 Symbols and Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
4.0 GENERAL DAMAGE MECHANISMS — ALL INDUSTRIES
4.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
4.2 Mechanical and Metallurgical Failure Mechanisns . . . . . . . . . . . . . . . . . 5
4.2.1 Graphitization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
4.2.2 Softening (Spheroidization) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
4.2.3 Temper Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
4.2.4 Strain Aging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
4.2.5 885°F Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
4.2.6 Sigma Phase Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
4.2.7 Brittle Fracture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
4.2.8 Creep/Stress Rupture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
4.2.9 Thermal Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
4.2.10 Short Term Overheating — Stress Rupture . . . . . . . . . . . . . . . . . . . 22
4.2.11 Steam Blanketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4.2.12 Dissimilar Metal Weld (DMW) Cracking . . . . . . . . . . . . . . . . . . . . . . . 25
4.2.13 Thermal Shock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
4.2.14 Erosion/Erosion-Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4.2.15 Cavitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
4.2.16 Mechanical Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
4.2.17 Vibration-Induced Fatigue. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
4.2.18 Refractory Degradation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
4.2.19 Reheat Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
4.3 Uniform or Localized Loss of Thickness . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
4.3.1 Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
4.3.2 Atmospheric Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
4.3.3 Corrosion Under Insulation (CUI). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
4.3.4 Cooling Water Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
4.3.5 Boiler Water Condensate Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
4.3.6 CO2 Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
4.3.7 Flue Gas Dew Point Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
4.3.8 Microbiologically Induced Corrosion (MIC) . . . . . . . . . . . . . . . . . . . . 53
4.3.9 Soil Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
4.3.10 Caustic Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
4.3.11 Dealloying . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
v
4.3.12 Graphitic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62
4.4 High Temperature Corrosion [400°F (204°C)] . . . . . . . . . . . . . . . . . . . . . . 64
4.4.1 Oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
4.4.2 Sulfidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
4.4.3 Carburization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
4.4.4 Decarburization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
4.4.5 Metal Dusting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
4.4.6 Fuel Ash Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
4.4.7 Nitriding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
4.5 Environment—Assisted Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
4.5.1 Chloride Stress Corrosion Cracking (CIⴚSCC) . . . . . . . . . . . . . . . . . 80
4.5.2 Corrosion Fatigue. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
4.5.3 Caustic Stress Corrosion Cracking (Caustic
Embrittlement) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
4.5.4 Ammonia Stress Corrosion Cracking. . . . . . . . . . . . . . . . . . . . . . . . . . . 91
4.5.5 Liquid Metal Embrittlement (LME) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
4.5.6 Hydrogen Embrittlement (HE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
5.0 FOSSIL UTILITY INDUSTRY DAMAGE MECHANISMS
5.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
5.1.1 Uniform or Localized Loss in Thickness. . . . . . . . . . . . . . . . . . . . . . . . 97
5.1.1.1 Erosion (Cell) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
5.1.1.2 Flow Accelerated Corrosion (FAC) . . . . . . . . . . . . . . . . . . . . . . . . . 97
5.1.1.3 Ammonia Grooving. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
5.1.1.4 Down-Time Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99
5.1.1.5 Hydrogen Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
5.2 Boiler Tube Damage Matrix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
5.3 Process Unit FPD’s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106
5.3.1 Boiler Steam Condensate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106
vi
Damage Mechanisms Affecting Fixed Equipment
in the Fossil Electric Power Industry
like 1Cr-0.5Mo to large agglomerated carbides. b) The loss in strength is usually accompanied by
Spheroidization may cause a loss in strength and/or an increase in ductility which allows for defor-
creep resistance. mation at stress concentrations.
c) Spheroidization affects hot wall piping and
4.2.2.2 Affected Materials equipment in the FCC, catalytic reforming and
coker units. Fired heater tubes in boilers or
All commonly used grades of carbon steel and low
process units may be affected by a loss in creep
alloy steels including C-0.5Mo, 1Cr-0.5Mo,1.25Cr-
strength, but equipment, in general, is seldom
0.5Mo, 2.25Cr-1Mo, 3Cr -1Mo, 5Cr-0.5Mo, and 9Cr-
renewed or repaired because of spheroidization.
1Mo steels.
4.2.2.5 Appearance or Morphology of Damage
4.2.2.3 Critical Factors
a) Spheroidization is not visible or readily appar-
a) Metal chemistry, microstructure, exposure time,
ent and can only be observed through metallog-
and temperature are critical factors.
raphy. The pearlitic phase undergoes a time
b) The rate of spheroidization depends on the tem-
dependant transformation from partial to com-
perature and initial microstructure. Spher-
plete spheroidization (Figure 4–3 and Figure 4–4).
oidization can occur in a few hours at 1300°F
b) In the case of the 5% to 9% CrMo alloys,
(552°C), but may take several years at 850°F
spheroidization is the process of transforming
(454°C).
the carbides from their original finely dispersed
c) Annealed steels are more resistant to
morphology to large agglomerated carbides.
spheroidization than normalized steels. Coarse-
grained steels are more resistant than fine-
4.2.2.6 Prevention / Mitigation
grained. Fine grained silicon-killed steels are
more resistant than aluminum-killed. Spheroidization is difficult to prevent except by
minimizing long-term exposure to elevated tempera-
4.2.2.4 Affected Units or Equipment tures.
a) Spheroidization can occur in piping and equip-
4.2.2.7 Inspection and Monitoring
ment after exposure to temperatures above
850°F (454°C). The loss in strength may be as Spheroidization can only be found through field
high as about 30% but failure is not likely to metallography or removal of samples for metallo-
occur except under very high applied stresses, graphic observation. A reduction in tensile strength
in areas of stress concentration, or in combina- and/or hardness may indicate a spheroidized micro-
tion with other damage mechanisms. structure.
Notes:
1. Percent of impact is a comparison to original impact strength of non-embrittled materials.
2. The results for 304 SS in columns one and four are for different heats of material under different exposure conditions and are intended
to exemplify variability of embrittlement.
Fig. 4-7—Close-up photograph showing the gouges and the fracture origin (arrow) in one of the gouges.
b) Brittle fracture is an “event” driven damage sure at ambient temperatures during startup
mechanism. For existing materials, where the and shutdown, and periodic inspection at high
right combination of stress, material toughness stress locations (Figure 4-8).
and flaw size govern the probability of the event, d) Some reduction in the likelihood of a brittle
an engineering study can be performed in accor- fracture may be achieved by:
dance with API RP 579, Section 3, Level 1 or 2. i) Performing a post weld heat treatment
c) Preventative measures to minimize the poten- (PWHT) on the vessel if it was not originally
tial for brittle fracture in existing equipment done during manufacturing; or if the vessel
are limited to controlling the operating condi- has been weld repaired/modified while in
tions (pressure, temperature), minimizing pres- service without the subsequent PWHT.
RT, EC, dimensional measurements and repli- and followed by PT or WFMT on several-year
cation) should be employed. Destructive sam- intervals. Angle beam (shear wave) UT can also
pling and metallographic examination are used be employed, although the early stages of creep
to confirm damage. damage are very difficult to detect. Initial fabri-
b) For pressure vessels, inspection should focus on cation flaws should be mapped and documented
welds of CrMo alloys operating in the creep for future reference.
range. The 1 Cr-0.5Mo and 1.25Cr-0.5Mo mate- c) Fired heater tubes should be inspected for evi-
rials are particularly prone to low creep ductil- dence of overheating, corrosion, and erosion as
ity. Most inspections are performed visually follows:
Fig. 4-14 —In a carbon steel sample, metallographic section through thermal fatigue crack indicates
origin (here at the toe of an attachment weld) and shape. Mag. 50⫻, etched.
c) In steam generating equipment, cracks usually d) Water in soot blowers may lead to a crazing
follow the toe of the fillet weld, as the change in pattern. The predominant cracks will be circum-
section thickness creates a stress raiser (Figure ferential and the minor cracks will be axial.
4-15). Cracks often start at the end of an attach-
ment lug and if there is a bending moment as a 4.2.9.6 Prevention / Mitigation
result of the constraint, they will develop into a) Thermal fatigue is best prevented through de-
circumferential cracks into the tube. sign and operation to minimize thermal stresses
and thermal cycling. Several methods of preven- b) External SWUT inspection can be used for non-
tion apply depending on the application. intrusive inspection for internal cracking and
i) Designs that incorporate reduction of stress where reinforcing pads prevent nozzle examina-
concentrators, blend grinding of weld pro- tion.
files, and smooth transitions should be used. c) Heavy wall reactor internal attachment welds
ii) Controlled rates of heating and cooling dur- can be inspected using specialized ultrasonic
ing startup and shutdown of equipment can techniques.
lower stresses.
iii) Differential thermal expansion between ad- 4.2.9.8 Related Mechanisms
joining components of dissimilar materials
Corrosion fatigue (see 4.5.2) and dissimilar metal
should be considered.
weld cracking (see 4.2.12).
b) Designs should incorporate sufficient flexibility
to accommodate differential expansion.
4.2.9.9 References
i) In steam generating equipment, slip spac-
ers should slip and rigid attachments should 1. “Steam - Its Generation and Use,” 40th Edition, Babcock & Wilcox,
1992.
be avoided. 2. “Combustion Fossil Power Systems,” Third Edition, Combustion Engi-
neering, CT, 1981.
ii) Drain lines should be provided on soot- 3. H. Thielsch, “Defects And Failures In Pressure Vessels and Piping,”
blowers to prevent condensate in the first Krieger Publishing Co., NY, 1977.
4. R.D. Port and H.M. Herro, “The NALCO Guide To Boiler Failure
portion of the soot blowing cycle. Analysis,” McGraw Hill, NY, 1991.
5. D.N. French, “Metallurgical Failures In Fossil Fired Boilers,” John
iii) In some cases, a liner or sleeve may be Wiley & Sons, Publishers, Inc., NY, 1993.
6. B. Dooley and W. McNaughton, “Boiler Tube Failures: Theory and
installed to prevent a colder liquid from Practice – 3 Volumes,” EPRI, CA, 1995.
contacting the hotter pressure boundary
wall 4.2.10 Short Term Overheating – Stress
Rupture
4.2.9.7 Inspection and Monitoring
4.2.10.1 Description of Damage
a) Since cracking is usually surface connected,
visual examination, MT and PT are effective Permanent deformation occurring at relatively low
methods of inspection. stress levels as a result of localized overheating. This
a) Temperature, time and stress are critical fac- 4.2.10.6 Prevention / Mitigation
tors.
b) Usually due to flame impingement or local over- a) Minimize localized temperature excursions.
heating. b) Fired heaters require proper burner manage-
c) Time to failure will increase as internal pres- ment and fouling/deposit control to minimize
sures or loading decrease. However, bulging hot spots and localized overheating.
and distortion can be significant at low stresses, c) Utilize burners which produce a more diffuse
as temperatures increase. flame pattern.
d) Local overheating above the design tempera- d) In hydroprocessing equipment, install and
ture. maintain bed thermocouples in reactors and
e) Loss in thickness due to corrosion will reduce minimize the likelihood of hot spots through
time to failure by increasing the stress. proper design and operation.
e) Maintain refractory in serviceable condition in
4.2.10.4 Affected Units or Equipment refractory lined equipment.
a) All boiler and fired heater tubes are suscep- 4.2.10.7 Inspection and Monitoring
tible.
b) Furnaces with coking tendencies such as crude, a) In fired heaters, visual observation, IR monitor-
vacuum, heavy oil hydroprocessing and coker ing of tubes and tubeskin thermocouples are
units are often fired harder to maintain heater used to monitor temperatures.
outlet temperatures and are more susceptible b) Refractory lined equipment can be monitored
to localized overheating. with heat indicating paint and periodic IR scans.
c) Hydroprocessing reactors may be susceptible to Inspect for refractory damage during shut-
localized overheating of reactor beds due to downs.
inadequate hydrogen quench or flow maldistri- c) Maintain and monitor reactor bed thermo-
bution. couples as well as reactor skin thermocouples.
d) Refractory lined equipment in the FCC, sulfur
plant and other units may suffer localized over-
4.2.10.8 Related Mechanisms
heating due to refractory damage and/or exces-
sive firing. Creep/stress rupture (see 4.2.8).
Fig. 4-16 —1Cr-0.5Mo boiler superheater tube in 700 psig steam service that failed due to overheating.
4.2.11.7 Inspection and Monitoring Series SS differ by 30% or more. At high operat-
ing temperatures, the differences in expansion
Burners should be properly maintained to prevent
lead to high stress at the heat affected zone on
flame impingement.
the ferritic side.
4.2.11.8 Related Mechanisms c) As the temperature increases, differential ther-
mal expansion between the metals results in
a) Steam blanketing can cause caustic corrosion increasing stress at the weldment, particularly
(caustic gouging) as outlined in 4.3.10. if a 300 Series SS weld metal is used.
b) Very similar characteristics are observed in d) Stresses acting on the weldment are signifi-
short term overheating (see 4.2.10). cantly higher when an austenitic stainless steel
filler metal is used. A nickel base filler metal
4.2.11.9 References has a coefficient of thermal expansion that is
1. “Steam - Its Generation and Use,” 40th Edition, Babcock & Wilcox, closer to carbon steel, resulting in significantly
1992.
2. “Combustion Fossil Power Systems,” Third Edition, Combustion Engi- lower stress at elevated temperatures.
neering, CT, 1981. e) At elevated temperatures, the problem is aggra-
3. H. Thielsch, “Defects And Failures In Pressure Vessels and Piping,”
Krieger Publishing Co., NY, 1977. vated by the diffusion of carbon out of the heat
4. R.D. Port and H.M. Herro, “The NALCO Guide To Boiler Failure
Analysis,” McGraw Hill, NY, 1991. affected zone of the ferritic material and into
5. D.N. French, “Metallurgical Failures In Fossil Fired Boilers,” John
Wiley & Sons, Inc., NY, 1993. the weld metal. The loss of carbon reduces the
6. B. Dooley and W. McNaughton, “Boiler Tube Failures: Theory and creep strength of the ferritic material heat af-
Practice – 3 Volumes,” EPRI, CA, 1995.
fected zone, thereby increasing the cracking
4.2.12 Dissimilar Metal Weld (DMW) Cracking probability (Figure 4-19).
f) The temperature at which carbon diffusion be-
4.2.12.1 Description of Damage comes a concern is above 800°F to 950°F (427°C
Cracking of dissimilar metal welds occurs in the to 510°C) for carbon steels and low alloy steels.
ferritic (carbon steel or low alloy steel) side of a weld g) Ferritic/austenitic joints can generate signifi-
between an austenitic (300 Series SS) and a ferritic cant thermal expansion/thermal fatigue stresses
material operating at high temperature. at temperatures greater than 510°F (260°C).
h) Dissimilar metal welds with a 300 Series SS
4.2.12.2 Affected Materials weld metal on a ferritic steel may also result in
a narrow region of high hardness at the toe of
The most common are ferritic materials such as the weld, near the fusion line on the ferritic
carbon steel and low alloy steels that are welded to steel side. High hardness zones render the ma-
the austenitic stainless steels as well as any material terial susceptible to various forms of environ-
combinations that have widely differing thermal ex- mental cracking such as sulfide stress cracking
pansion coefficients. or hydrogen stress cracking.
i) Thermal cycling aggravates the problem.
4.2.12.3 Critical Factors
j) In environments that promote liquid ash corro-
a) Important factors include the type of filler metal sion, weld cracking problems may be acceler-
used to join the materials, heating and cooling ated by stress-assisted corrosion. The ferritic
rate, metal temperature, time at temperature, heat affected zone will preferentially corrode
weld geometry and thermal cycling. due to the large thermal strain. The results are
b) Cracking occurs because the coefficients of ther- long, narrow, oxide wedges that parallel the
mal expansion between ferritic steels and 300 fusion line of the weld (Figure 4-20).
Fig. 4-20 —When both liquid phase coal ash corrosion and a DMW exists, stress
assisted corrosion of the 2.25Cr-1Mo heat affected zone may occur. That this is
corrosion and not the normal DMW failure in progress is shown by the lack of creep
damage at the crack tip. Mag. 25⫻, etched.
k) Poor geometry of the weld, excessive undercut, b) Dissimilar metal welds have been used in pip-
and other stress intensification factors will ag- ing around FCC reactors and regenerator ves-
gravate crack formation. sels, in fired heater applications where the
heater tube material changes from 5Cr or 9Cr
4.2.12.4 Affected Units or Equipment to 300 Series SS, and in transitions in hydropro-
a) Dissimilar metal welds are utilized in special cessing reactor outlet piping from overlaid low
applications in refineries and other process alloy CrMo nozzles or piping to solid 300 Series
plants. SS piping.
Fig. 4-21—Dissimilar metal weld fracture follows the toe of the butt weld. Mag. 1.8⫻
Fig. 4-22—The metallographic cross-section shows the crack follows the weld
metal. Mag. 4⫻
tories in cyclones and slide valves have been e) Higher molybdenum containing alloys are used
very successful. for improved resistance to naphthenic acid cor-
c) Erosion-corrosion is best mitigated by using rosion.
more corrosion-resistant alloys and/or altering
the process environment to reduce corrosivity, 4.2.14.7 Inspection and Monitoring
for example, deaeration, condensate injection
or the addition of inhibitors. Resistance is gen- a) Visual examination of suspected or trouble-
erally not improved through increasing sub- some areas, as well as UT checks or RT can be
strate hardness alone. used to detect the extent of metal loss.
d) Heat exchangers utilize impingement plates b) Specialized corrosion coupons and on-line corro-
and occasionally tube ferrules to minimize ero- sion monitoring electrical resistance probes
sion problems. have been used in some applications.
Fig. 4-24 —Cast iron impeller in untreated cooling water after four years of
service.
c) IR scans are used to detect refractory loss on ogy includes cavitation, liquid impingement erosion,
stream. fretting and other similar terms.
tion, design or operating change is usually re- iii) Remove entrained air.
quired. iv) Increase the suction pressure of pumps.
b) Cavitation is best prevented by avoiding condi- v) Alter the fluid properties, perhaps by add-
tions that allow the absolute pressure to fall ing additives.
below the vapor pressure of the liquid or by vi) Use hard surfacing or hardfacing.
changing the material properties. Examples in- vii) Use of harder and/or more corrosion resis-
clude: tant alloys.
i) Streamline the flow path to reduce turbu- c) Attack is accelerated by the mechanical dis-
lence. ruption of protective films at the liquid-solid
ii) Decrease fluid velocities. interface (such as a protective corrosion scale
Fig. 4-28 —Cavitation pitting on the water side of a cast iron cylinder liner in a large engine.
Fig. 4-31—Fatigue crack in a 16-inch pipe-to-elbow weld in the fill line of crude oil storage tank after
50 years in service.
4.2.16.8 Related Mechanisms 3. ASTM MNL41, Corrosion in the Petrochemical Industry, ASM Interna-
tional, Mateirals Park, OH, 1995.
Vibration induced fatigue (see 4.2.17).
4.2.17 Vibration-Induced Fatigue
4.2.16.9 References 4.2.17.1 Description of Damage
1. “Fracture and Fatigue Control in Structures,”J.M. Barsom and S.T.
Rolfe, American Society for Testing and Materials, West Conshohocken, A form of mechanical fatigue in which cracks are
PA.
2. ASTM STP1428, Thermo-mechanical Fatigue Behavior of Materials,
produced as the result of dynamic loading due to
American Society for Testing and Materials, West Conshohocken, PA. vibration, water hammer, or unstable fluid flow.
Fig. 4-33—The surface of the fracture faces of the crack shown in Figure 4-31 and Figure 4-32.
Fig. 4-34 —Vibration induced fatigue of a 1-inch socket weld flange in a thermal relief system shortly after
startup.
g) Damage to insulation jacketing may indicate b) Refractory lined equipment should be designed
excessive vibration. This can result in wetting for erosion, thermal shock and thermal expan-
the insulation which will cause corrosion. sion.
c) Dry out schedules, cure times and application
4.2.17.8 Related Mechanisms procedures should be in accordance with the
Mechanical fatigue (see 4.2.16) and refractory deg- manufacturer’s specifications and the appropri-
radation (see 4.2.18). ate ASTM requirements.
d) Anchor materials must be compatible with ther-
4.2.17.9 References mal coefficients of expansion of the base metal.
e) Anchors must be resistant to oxidation in high
1. “Environmental Effects on Components: Commentary for ASME Sec-
tion III,” EPRI NP-5775, Project 1757-61, Final Report, EPRI, CA, 1998. temperature services.
2. API Publication 581, Risk-Based Inspection - Base Resource Docu- f) Anchors must be resistant to condensing sulfu-
ment, American Petroleum Institute, Washington, D.C.
rous acids in heaters and flue gas environ-
4.2.18 Refractory Degradation ments.
g) Refractory type and density must be selected to
4.2.18.1 Description of Damage resist abrasion and erosion based on service
requirements.
Both thermal insulating and erosion resistant re-
h) Needles and other fillers must be compatible
fractories are susceptible to various forms of mechani-
with the process environment composition and
cal damage (cracking, spalling and erosion) as well
temperature.
as corrosion due to oxidation, sulfidation and other
high temperature mechanisms.
4.2.18.4 Affected Units or Equipment
4.2.18.2 Affected Materials
a) Refractories are extensively used in FCC reac-
Refractory materials include insulating ceramic tor regenerator vessels, piping, cyclones, slide
fibers, castables, refractory brick and plastic refrac- valves and internals; in fluid cokers; in cold
tories. shell catalytic reforming reactors; and in waste
heat boilers and thermal reactors in sulfur
4.2.18.3 Critical Factors
plants.
a) Refractory selection, design and installation are b) Boiler fire boxes and stacks which also use
the keys to minimizing damage. refractory are affected.
4.2.19.9 References
1. R.Viswanathan, “Damage Mechanisms and Life Assessment of High
Temperature Components,” ASM International, Materials Park, OH.
2. D.N. French, “Metallurgical Failures in Fossil Fired Boilers,” Second
Edition, John Wiley and Sons, NY, 1993, pp. 455 – 458.
3. A. Dhooge, “Survey on Reheat Cracking in Austenitic Stainless Steels
and Ni Base Alloys,” IIW-Commission IX, Doc.IX-1876-97.
Fig. 4-36 —Preferential galvanic corrosion of the more active component of the two materials.
Fig. 4-37—Galvanic corrosion of a carbon steel nipple in a SS vessel in warm water service.
e) It is not usually possible to modify operating proach starting with prediction/analysis, then
conditions. However, consideration should be looking at the more invasive procedures. The
given to removing the insulation on equipment inspection plan should consider operating tem-
where heat conservation is not as important. perature; type and age/condition of coating; and
f) An inspection plan for corrosion under insula- type and age/condition of insulation material.
tion should be a structured and systematic ap- Additional prioritization can be added from a
e) Wavy or smooth corrosion at nozzle inlets/ tion, biocide residual, biological activity, cooling
outlets and tube inlets may be due to flow water outlet temperatures, hydrocarbon con-
induced corrosion, erosion or abrasion. tamination and process leaks.
f) Corrosion at ERW weld areas will appear as b) Periodic calculation of U-factors (heat exchanger
grooving along the weld fusion lines. performance measurement) will provide infor-
g) Metallurgical analysis of tube samples may be mation on scaling and fouling.
required to confirm the mode of failure. c) Ultrasonic flow meters can be used to check the
velocity of water in the tubes.
4.3.4.6 Prevention / Mitigation d) EC or IRIS inspection of tubes.
e) Splitting representative tubes.
a) Cooling water corrosion (and fouling) can be
prevented by proper design, operation and
chemical treatment of cooling water systems. 4.3.4.8 Related Mechanisms
b) Design for process side inlet temperatures be- Microbiologically induced corrosion (see 4.3.8), chlo-
low 135°F (57°C). ride stress corrosion cracking (see 4.5.1) and gal-
c) Minimum and maximum water velocities must vanic corrosion (see 4.3.1).
maintained, particularly in salt water systems.
d) The metallurgy of heat exchanger components 4.3.4.9 References
may need to be upgraded for improved resis-
1. T.J. Tvedt, Jr., “Cooling Water Systems,” NACE Course Book on
tance, especially in waters with high chloride Corrosion Control in the Refining Industry, NACE International, Houston,
content, low velocity, high process tempera- TX, 1999.
2. H.M. Herro and R.D. Port, “NALCO Guide to Cooling Water System
tures, and/or poorly maintained water chemis- Failure Analysis,” McGraw-Hill, Inc., NY, 1991, pp. 259-263.
try.
e) Periodic mechanical cleaning of tube ID’s and 4.3.5 Boiler Water Condensate Corrosion
OD’s should be performed in order to maintain
clean heat transfer surfaces. 4.3.5.1 Description of Damage
f) With very few exceptions, cooling water should
be on the tube side to minimize stagnant areas. General corrosion and pitting in the boiler system
and condensate return piping.
4.3.4.7 Inspection and Monitoring
4.3.5.2 Affected Materials
a) Cooling water should be monitored for vari-
ables that affect corrosion and fouling includ- Primarily carbon steel, some low alloy steel, some
ing, pH, oxygen content, cycles of concentra- 300 Series SS and copper based alloys.
Fig. 4-41—CO2 corrosion of a carbon steel oil and gas production flow line.
4.3.7.1 Description of Damage a) All fired process heaters and boilers that burn
fuels containing sulfur have the potential for
a) Sulfur and chlorine species in fuel will form sulfuric acid dewpoint corrosion in the econo-
sulfur dioxide, sulfur trioxide and hydrogen mizer sections and in the stacks.
chloride within the combustion products. b) Heat-Recovery Steam Generators (HRSG’s) that
b) At low enough temperatures, these gases and have 300 Series SS feedwater heaters may suf-
the water vapor in the flue gas will condense to fer chloride-induced stress corrosion cracking
form sulfurous acid, sulfuric acid and hydrochlo- from the gas side (OD) when the temperature of
ric acid which can lead to severe corrosion. the inlet water is below the dewpoint of hydro-
chloric acid.
4.3.7.2 Affected Materials c) 300 Series SS feedwater heaters in HRSG’s are
Carbon steel, low alloy steels and 300 Series SS. potentially at risk if the atmosphere of the
combustion turbine includes chlorine. Cooling
4.3.7.3 Critical Factors tower drift from cooling towers that use chlorine-
based biocides may blow into the combustion
a) The concentration of contaminants (sulfur and turbine and lead to potential damage in the
chlorides) in the fuel and the operating tempera- feedwater heaters.
ture of flue gas metal surfaces determine the
likelihood and severity of corrosion. 4.3.7.5 Appearance or Morphology of Damage
b) Since all fuels contain some amount of sulfur,
sulfuric and sulfurous acid dewpoint corrosion a) Sulfuric acid corrosion on economizers or other
can occur if the metal temperatures are below carbon steel or low alloy steel components will
the dewpoint. have general wastage often with broad, shallow
c) The dewpoint of sulfuric acid depends on the pits, depending on the way the sulfuric acid
concentration of sulfur trioxide in the flue gas, condenses.
but is typically about 280°F (138°C). b) For the 300 Series SS feedwater heaters in
d) Similarly, the dewpoint of hydrochloric acid HRSG’s, stress corrosion cracking will have
depends on the concentration of hydrogen chlo- surface breaking cracks and the general appear-
ride. It is typically about 130°F (54°C). ance will be somewhat crazed.
Fig. 4-46 —Same pipe as Figure 4-45. Note the halo effect.
g) Effective mitigation of established organisms b) Special probes have been designed to monitor
requires complete removal of deposits and or- for evidence of fouling which may precede or
ganisms using a combination of pigging, blast- coincide with MIC damage.
ing, chemical cleaning and biocide treatment. c) An increase in the loss of duty of a heat ex-
h) Add biocides to water phase in storage tanks. changer may be indicative of fouling and poten-
i) Maintain coatings on the interior of storage tanks. tial MIC damage.
d) Foul smelling water may be a sign of trouble.
4.3.8.7 Inspection and Monitoring
a) In cooling water systems, effectiveness of treat-
4.3.8.8 Related Mechanisms
ment is monitored by measuring biocide re-
sidual, microbe counts and visual appearance. Cooling water corrosion (see 4.3.4).
Fig. 4-48 —Same oil line as Figure 4-47. Hemispherical pitting typical of MIC can be seen after grit blasting to remove the
scale.
Fig. 4-50 —A cross section of the tube (Figure 4-49) revealing severe subsurface tunneling,
typical of MIC.
4.3.9.9 References
1. API Publication 581, Risk-Based Inspection - Base Resource Docu-
ment, Second Edition, American Petroleum Institute, Washington, D.C.
2. Peabody, A.W., “Control of Pipeline Corrosion,” NACE International,
Houston, TX, 1967.
3. Morgan, John, “Cathodic Protection,” NACE International, Houston,
TX, 1987.
Fig. 4-51—Corrosion of carbon steel pipe at the soil-air inter- 4. O’Day, D. Kelly, “External Corrosion in Distribution Systems,” AWWA
Journal, October, 1989.
face where the pipe emerges from underground. 5. Parker, Marshall E., “Pipe Line Corrosion and Cathodic Protection,”
Gulf Publishing Company, TX, 1954.
6. Romanoff, M., “Underground Corrosion,” NACE International, Hous-
ton, TX, 1997.
7. Jones, Denny A., “Principles and Prevention of Corrosion,” McMillan
Publishing Co., NY, 1992.
8. Herbert H. Uhlig, “Corrosion Handbook,” John Wilkey and Sons, Inc.,
1948.
9. EDM Services, Inc., “Hazardous Liquid Pipeline Risk Assessment,”
g) Other factors that affect soil corrosion include California State Fire Marshal, Pipeline Safety Division, CA, 1993.
10. NACE RP 0169, Standard Recommended Practice: Control of Exter-
galvanic corrosion, dissimilar soils, stray cur- nal Corrosion on Underground or Submerged Metallic Piping Systems,
NACE International, Houston, TX.
rents, differential aeration corrosion cells, and
microbiologically induced corrosion.
4.3.10 Caustic Corrosion
4.3.9.4 Affected Units or Equipment
4.3.10.1 Description of Damage
a) Underground piping and equipment as well as
Localized corrosion due to the concentration of
buried tanks and the bottoms of above ground
caustic or alkaline salts that usually occurs under
storage tanks (Figure 4-52).
evaporative or high heat transfer conditions. How-
b) Ground supported metal structures (Figure
ever, general corrosion can also occur depending on
4-53).
alkali or caustic solution strength.
4.3.9.5 Appearance or Morphology of Damage
4.3.10.2 Affected Materials
a) Soil corrosion appears as external thinning with Primarily carbon steel, low alloy steels and 300
localized losses due to pitting. The severity of Series SS.
corrosion depends on the local soil conditions
and changes in the immediate environment
4.3.10.3 Critical Factors
along the equipment metal surface.
b) Poor condition of a protective coating is a tell Major contributing factors are the presence of caus-
tale sign of potential corrosion damage. tic (NaOH or KOH). The following are sources of
caustic:
4.3.9.6 Prevention / Mitigation
a) Caustic is sometimes added to process streams
Soil corrosion of carbon steel can be minimized for neutralization or as a reactant.
through the use of special backfill, coatings and b) It is sometimes intentionally added to boiler
cathodic protection. The most effective protection is feedwater at low concentrations or may enter
a combination of a corrosion resistant coating and a inadvertently during regeneration of deminer-
cathodic protection system. alizers.
Fig. 4-53—Cross section through location (A) showing severe corrosion. The arrows point to a location
that was at the original thickness.
c) Alkaline salts may also enter process streams b) Similar concentrating effects of caustic may
through leaks in condensers or process equip- occur where caustic is added to a crude unit
ment. charge.
d) Some process units utilize caustic solutions for c) Accelerated localized corrosion can occur in pre-
neutralizing or removal of sulfur compounds. heat exchangers, furnace tubes and transfer
e) A concentrating mechanism must exist to build lines, unless the caustic is effectively mixed in
up the caustic strength. the oil stream.
f) Caustic may become concentrated by departure d) Units that use caustic for removing sulfur com-
from DNB, evaporation and deposition. pounds from product streams.
Fig. 4-54 —I.D. deposits on CS boiler tube with damage due to caustic corrosion.
Fig. 4-55—Cross-section of tube in Figure 4-53 showing localized attack due to caustic corrosion.
Fig. 4-56 —Cross section of a silicon-brass alloy C87500 pump impeller from stagnant fire-water service.
Layer-type dezincification depleted the zinc and left this porous red color of the copper. Mag. 50⫻
1. ASM Metals Handbook, “Corrosion,” Volume 13, ASM International, a) Graphitic corrosion occurs with several differ-
Materials Park, OH.
2. A. Cohen, “Copper and Copper-Base Alloys,” Process Industries Corro- ent cast iron alloys but is usually limited to
sion – The Theory and Practice, NACE International, Houston,TX, 1986.
3. R.D. Port and H.M. Herro, “The NALCO Guide to Boiler Failure very specific microstructure-environment com-
Analysis,” McGraw-Hill, Inc., NY, 1991, pp. 259-263. binations. Factors that influence graphitic cor-
4. ASM Metals Handbook, “Failure Analysis and Prevention,” Volume
11, ASM International, Materials Park, OH. rosion include the composition of the alloy and
Fig. 4-58 —Cross section of a gray cast iron drainpipe showing charcoal colored thru-wall graphitic
corrosion encroaching from both sides. Note the through wall crack at the bottom.
Fig. 4-60 —Higher magnification view of unaffected area “A” shown in Figure 4-59.
It should not be confused with graphitization, the 2. ASM Metals Handbook, “Failure Analysis and Prevention,” Volume
11, ASM International, Materials Park, OH.
decomposition of carbides at high temperatures (see 3. ASM Metals Handbook, “Corrosion,” Volume 13, ASM International,
Materials Park, OH.
4.2.1).
4.4 High Temperature Corrosion [400°F
4.3.12.9 References (204°C)]
1. R.D. Port and H.M. Herro, “The NALCO Guide to Boiler Failure
Analysis,” McGraw-Hill, Inc., NY, 1991, pp. 259-263. 4.4.1 Oxidation
Fig. 4-62—Oxidation of a carbon steel nut on a stainless steel stud at 1300°F (704°C).
Fig. 4-64 —Oxidation of the O.D. of a carbon steel furnace transfer line.
ties. They are often used in special alloys for b) Temperatures can be monitored through the
applications such as heater supports, burner use of tubeskin thermocouples and/or infrared
tips and components for combustion equip- thermography.
ment. c) Loss in thickness due to oxidation is usually
measured using external ultrasonic thickness
measurements.
4.4.1.7 Inspection and Monitoring
4.4.1.8 Related Mechanisms
a) Process conditions should be monitored for es-
tablishing trends of high temperature equip- Oxidation damage referred to in this section is due
ment where oxidation can occur. to surface scaling. Some damage mechanisms result
mix-ups in services where sulfidation is antici- 3. ASM Metals Handbook, “Corrosion in Petroleum Refining and Petro-
chemical Operations,” Volume 13, ASM International, Materials Park, OH.
pated. 4. E. B Backenstow et al, “ High Temperature Hydrogen Sulfide Corro-
sion”, CORROSION, Vol. 12, No. 1, 1956, pp 6t-16t.
5. NACE Task Group 176 Draft Report, “Overview of Sulfidic Corrosion
4.4.2.8 Related Mechanisms in Petroleum Refining”, NACE International, Houston, TX, 2003.
Fig. 4-72—In cross-section, the surface grooving is, in actuality, broad, V-shaped corrosion-
fatigue cracks. Mag. 100⫻, etched.
Fig. 4-74 —A nitrided 5Cr-0.5Mo thermowell from an ammonia synthesis plant with surface
cracking.
Fig. 4-76 —A higher magnification photomicrograph showing the diamond-shaped hardness indentations
in the hard nitrided layer (540 BHN) versus the softer base metal (210 BHN). Mag. 150⫻
4.4.7.7 Inspection and Monitoring c) Hardness testing of the affected surfaces (400
to 500 BHN or higher) can help indicate nitrid-
a) A change in surface color to a dull gray may
indicate nitriding. ing.
b) Materials exposed to nitriding conditions should d) Nitrided layers are magnetic. Therefore, 300
be inspected thoroughly because good appear- Series SS should be checked for magnetism as
ance may mask damage. an initial screening.
Fig. 4-81—Photomicrograph of a cross-section of sample in Figure 4-79 showing fine branching cracks.
(Unetched, Mag. 50⫻)
that may occur, increasing susceptibility to poly- b) PT or phase analysis EC techniques are the
thionic SCC, possible distortion problems and preferred methods.
potential reheat cracking. c) Eddy current inspection methods have also been
used on condenser tubes as well as piping and
4.5.1.7 Inspection and Monitoring pressure vessels.
a) Cracking is surface connected and may be de- d) Extremely fine cracks may be difficult to find
tected visually in some cases. with PT. Special surface preparation methods,
including polishing or high-pressure water sion under cyclic stress due to thermal stress,
blast, may be required in some cases, especially vibration or differential expansion.
in high pressure services. c) Contrary to a pure mechanical fatigue, there is
e) Crack depths can be measured with a suitable no fatigue limit load in corrosion-assisted fa-
UT technique. tigue. Corrosion promotes failure at a lower
f) Often, RT is not sufficiently sensitive to detect stress and number of cycles than the materials’
cracks except in advanced stages where a signifi- normal endurance limit in the absence of corro-
cant network of cracks has developed. sion and often results in propagation of mul-
tiple parallel cracks.
4.5.1.8 Related Mechanisms d) Crack initiation sites include concentrators such
as pits, notches, surface defects, changes in
Caustic SCC (see 4.5.3). section or fillet welds.
4.5.1.9 References
4.5.2.4 Affected Units or Equipment
1. C.P. Dillon, “Corrosion Control in The Chemical Process Industries,”
Materials Technology Institute, MO, 1994, pp. 88-90. Rotating equipment, deaerators and cycling boil-
2. “Corrosion Basics – An Introduction,” NACE International, Houston,
TX, 1984, pp. 111-123. ers, as well as any equipment subjected to cyclic
stresses in a corrosive environment. Some examples
4.5.2 Corrosion Fatigue
include:
4.5.2.1 Description of Damage a) Rotating Equipment
A form of fatigue cracking in which cracks develop Galvanic couples between the impeller and the
under the combined affects of cyclic loading and pump shaft or other corrosion mechanisms may
corrosion. Cracking often initiates at a stress concen- result in a pitting problem on the shaft. The
tration such as a pit in the surface. Cracking can pitting can act as a stress concentrator or stress
initiate at multiple sites. riser to promote cracking. Most cracking is
transgranular with little branching.
4.5.2.2 Affected Materials b) Deaerators
In the late 1980’s, deaerators in the pulp and
All metals and alloys. paper, refining and petrochemical and fossil
fueled utility industries had major deaerator
4.5.2.3 Critical Factors
cracking problems. Complete vessel failures in
a) The critical factors are the material, corrosive the pulp and paper industry resulted in a dili-
environment, cyclic stresses and stress raisers. gent inspection program that found major crack-
b) Cracking is more likely to occur in environ- ing problems across the various industries. It
ments that promote pitting or localized corro- was concluded that residual welding and fabri-
Fig. 4-83—Photograph of a carbon steel boiler tube cut in half lengthwise. Corrosion fatigue cracks
initiate at the I.D. of a tube, opposite a buckstay attachment on the O.D. (Mag. 1⫻)
d) Stresses that promote cracking can be residual H2S and mercaptan removal units, as well as
that result from welding or from cold working equipment that uses caustic for neutralization
(such as bending and forming) as well as ap- in sulfuric acid alkylation units and HF alkyla-
plied stresses (Figure 4-86 and Figure 4-87). tion units. Caustic is sometimes injected into
e) It is generally accepted that stresses approach- the feed to the crude tower for chloride control.
ing yield are required for SCC so that thermal b) Failures have occurred in improperly heat-
stress relief (PWHT) is effective in preventing traced piping or equipment as well as heating
caustic SCC. Although failures have occurred coils and other heat transfer equipment.
at stresses that are low relative to yield, they c) Caustic embrittlement may occur in equipment
are considered more rare (Figure 4-88 through as a result of steam cleaning after being in
Figure 4-91). caustic service.
f) Crack propagation rates increase dramatically d) Traces of caustic can become concentrated in
with temperature and can sometimes grow BFW and can result in caustic embrittlement of
through wall in a matter of hours or days dur- boiler tubes that alternate between wet and dry
ing temperature excursions, especially if condi- conditions due to overfiring.
tions promote caustic concentration. Concentra-
tion can occur as a result of alternating wet and 4.5.3.5 Appearance or Morphology of Damage
dry conditions, localized hot spots or high tem-
a) Caustic stress corrosion cracking typically
perature steamout.
propagates parallel to the weld in adjacent base
g) Special care must be taken with steam tracing
metal but can also occur in the weld deposit or
design and steamout of non-PWHT’d carbon
heat affected zones.
steel piping and equipment.
b) The pattern of cracking observed on the steel
surface is sometimes described as a spider web
4.5.3.4 Affected Units or Equipment
of small cracks which often initiate at or inter-
a) Caustic embrittlement is often found in piping connect with weld-related flaws that serve as
and equipment that handles caustic, including local stress raisers.
Fig. 4-92—Stainless steel expansion bellows from a steam-driven turbine previously subjected to a
caustic carryover upset condition.
Fig. 4-93—High magnification view of a cross-section of a brass exchanger tube showing transgranular cracking.
Fig. 4-95—External stress corrosion cracking of brass heat exchanger tubes in a crude tower
overhead system.
i) Copper-zinc alloys show improved resis- iv) 300 Series SS and nickel base alloys are
tance as zinc content decreases below 15%. immune.
ii) The 90-10CuNi and 70-30CuNi alloys are b) Carbon steel
nearly immune. i) SCC of steel can be prevented by PWHT or
iii) SCC in steam service can sometimes be through the addition of small quantities of
controlled by preventing the ingress of air. water to the ammonia (0.2%). Consider-
ates to form atomic hydrogen that can dif- g) Stresses include cooling during manufacture,
fuse into the steel. residual stresses from welding or applied loads.
iv) Wet H2S services or HF acid services in h) Thick wall components are more vulnerable
which atomic hydrogen diffuses into the due to increased thermal stress and high re-
steel. (Cyanides, arsenic and FeS can act as straint and take longer for hydrogen to diffuse
hydrogen recombination poisons that dimin- out.
ish the hydrogen gas reaction and allows i) In general, as strength increases, susceptibility
for greater charging rates.) to HE increases. Certain microstructures, such
v) Manufacturing – melting practices or manu- as untempered martensite and pearlite, are
facturing processes particularly where com- more susceptible at the same strength level
ponents are plated (hydrogen flaking). than tempered martensite. Carbon steel that is
vi) Cathodic protection. severely hydrogen charged will have lower
c) The effect is pronounced at temperatures from toughness than with no hydrogen.
ambient to about 300°F (149°C). Effects de-
crease with increasing temperature and HE is 4.5.6.4 Affected Units or Equipment
not likely to occur above 160°F to 180°F (71°C
to 82°C). a) Services where HE is a concern include cabon
d) HE affects static properties to a much greater steel piping and vessels in wet H2S services in
extent than impact properties. If the hydrogen FCC, hydroprocessing, amine, sour water ser-
is present and a sufficient stress is applied, vices and HF alkylation units. However, mild
failure can occur quickly. steel used for vessels and piping in most refin-
e) The amount of trapped hydrogen depends on ing, fossil utility and process applications have
the environment, surface reactions and the pres- low hardness and are usually not susceptible to
ence of hydrogen traps in the metal such as HE except at weldments, particularly the HAZ,
imperfections, inclusions and pre-existing flaws if suitable PWHT is not performed.
or cracks. b) Storage spheres are often made of slightly
f) The amount of hydrogen needed to have a mea- higher strength steels and are more susceptible
surable effect on the mechanical properties var- than most other refinery equipment.
ies with the strength level, microstructure and c) Bolts and springs made of high strength steel
heat treatment for the alloy. In some cases, are very prone to HE. (Alloys that have a ten-
thresholds of critical hydrogen concentrations sile strength above 150 ksi can absorb hydro-
have been established. gen during electroplating and crack.)
Carbon and low alloy steels. Hydrogen damage occurs in all steam-generating
units that operate above about 1000 psi, but is more
5.1.1.5.3 Critical Factors common in the higher-pressure units, those operat-
ing above 1800 psi.
In order for cracking to develop, two factors are
necessary:
5.1.1.5.5 Appearance or Morphology of Damage
a) A boiler-water pH that is strongly basic or,
more commonly, strongly acidic. a) Hydrogen damage failures are thick-lipped, lim-
b) Thick, usually localized, water-side deposits ited ductility fractures on the fire side of the
that promote under-deposit corrosion. The de- tube (Figure 5-1).
103
Fig. 5-1—Hydrogen damage failures are thick-lipped, limited ductility ruptures, often with a window
blown out. Rifled tubing promotes turbulence, but may failure by hydrogen damage, as in this case. 0.6⫻
b) Often, damage will first appear in the highest 5.1.1.5.6 Prevention / Mitigation
heat-release regions of the furnace, just down-
stream of circumferential butt welds. The ID of a) One of the problems of hydrogen damage is that
the weld disturbs the fluid flow and promotes it is often invisible until the first failure occurs,
rapid deposit build-up. and by then, it may be found universally
c) Microstructural analysis will show the inter- throughout the boiler.
granular cracks from the methane build-up and b) The thick deposits form rapidly when the pH is
decarburization that forms the methane (Figure out of the control range.
5-2 and 5-3). c) Boilers should be kept clean to prevent thick,
Fig. 5-2—The metallographic cross-section of the fracture edge will show extensive cracking along
the water side. Distinguish hydrogen damage from high-temperature creep failures in waterwall
tubes by extensive water-side cracking. Creep damage has fire-side cracking. 18 3⁄4 ⫻, etched.