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Note: The source of the technical material in this volume is the ProfessionalEngineering Development Program (PEDP) of Engineering Services.
Warning: The material contained in this document was developed for SaudiAramco and is intended for the exclusive use of Saudi Aramcos
employees. Any material contained in this document which is notalready in the public domain may not be copied, reproduced, sold, given,
or disclosed to third parties, or otherwise used in whole, or in part,
without the written permission of the Vice President, Engineering
Services, Saudi Aramco.
Chapter : Materials & Corrosion Control For additional information on this subject, contact
File Reference: COE10505 S.B. Jones on 874-1969 or S.P. Cox on 874-2488
Engineering EncyclopediaSaudi Aramco DeskTop Standards
Corrosion-Resistant Characteristics
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CONTENTS PAGES
CORROSION RESISTANCE CHARACTERISTICS, DESIGN
PRACTICES, AND ANALYSIS METHODS ............................................................ 1
Uniform or General Corrosion ........................................................................ 1
Uniform Corrosion Allowance ........................................................................ 7
Estimated Remaining Life ............................................................................... 8
Nonuniform Corrosion .................................................................................. 10
Pitting Corrosion................................................................................ 11
Under-deposit Corrosion.................................................................... 12
Crevice Corrosion .............................................................................. 13
Galvanic Attack ................................................................................. 14
Intergranular Attack ........................................................................... 16
Dealloying.......................................................................................... 18
Stress-Related Corrosion.................................................................... 19
Stress Corrosion Cracking of Stainless Steels.................................... 21
Stress Cracking of Carbon and Low-Alloy Steels ............................. 26
Effect of Velocity on Corrosion......................................................... 28
EVALUATING TYPICAL DESIGN RELATED PROBLEMS............................... 31
CORROSION RESISTANCE STRATEGIES USED IN SAUDI
ARAMCO ................................................................................................................. 33
General Corrosion-Resistant Characteristics of Carbon Steel ....................... 33
Localized Corrosion-Resistant Characteristics of Carbon Steel .................... 34
General Corrosion-Resistant Characteristics of Stainless Steel ..................... 34
Localized Corrosion-Resistant Characteristics of Stainless Steel............. ..... 35
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General and Localized Corrosion-Resistant Characteristics of
Other Commonly Used Materials.................................................................. 36
Nickel-Base Alloys ............................................................................ 36
Copper-Base Alloys ........................................................................... 36
Titanium............................................................................................. 37
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Corrosion Resistance Characteristics, Design Practices, and Analysis
Methods
Corrosion is defined as a deterioration of a material (usually a metal) or its properties due toexposure to an environment. The type of corrosion damage and deterioration that occurs in a
particular material will depend upon its environment. The corrosion resistance of a metal or
alloy is extremely important and must be considered when selecting materials of construction
to prevent or minimize corrosion in service.
It is necessary to recognize and understand the various types of corrosion that can occur. The
important features, susceptible materials, and typical environments for uniform and
nonuniform corrosion are summarized below.
Uniform or General Corrosion
When the entire surface of a metal or alloy corrodes at about the same rate in a particular
environment, the corrosion is termed general or uniform corrosion. Examination of a crosssection of the corroded material would reveal relatively uniform thinning, shown in Figure 1.
Figure 1. Cross Section of a Material Subject to Uniform
Corrosion
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Carbon and low-alloy steels can suffer general corrosion during service due to their inherent
lack of corrosion resistance. Certain environments found in refineries, petrochemical plants,
and/or production facilities promote corrosion of carbon and low-alloy steels. Some of the
common environments are: Hydrocarbons containing wet hydrogen sulfide (sour service)
Hydrocarbon gas streams containing wet hydrogen sulfide + carbon dioxide
Sour water (process water containing hydrogen sulfide)
Steam condensate containing dissolved carbon dioxide
Hot sulfur-bearing hydrocarbons
Amine-hydrogen sulfide-carbon dioxide solutions
Brines
Industrial atmosphere
High temperature oxidation (furnace tubes).
While this list is not all-inclusive, it does include the environments that are responsible for
much of the corrosion of carbon and low-alloy steel equipment in a refinery, petrochemical
plant, or production facility.
Industrial atmospheres promote external corrosion of carbon and low-alloy steels. Corrosion
rates are usually low, 0.025-0.050 mm/yr (1-2 mils/yr), but some atmospheres, especiallythose containing acid vapors, can be very corrosive. Figure 2 illustrates weight loss data
versus time for corrosion test samples exposed at three locations. Two locations, the Martinez
Refinery and the Geysers in California, represent industrial locations, while the University of
California at Davis is a nonindustrial, residential location. The data in Figure 2 illustrate that
the weight loss (which can be converted to corrosion rate) experienced by the samples due to
atmospheric corrosion in a residential location is much less than that in an industrial location.
In addition, after about three years, the weight loss experienced by the samples exposed to the
Geysers surpasses that of the samples located in the refinery. This is because the atmosphere
around the Geyers contains sulfur dioxide and sulfur trioxide which form sulfurous and
sulfuric acids when exposed to the water vapor in the atmosphere.
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Note the Corrosion at the Refinery, about 1.1 mpy for Carbon Steel.
Figure 2. Atmospheric Corrosion Test Data.
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Figure 3 illustrates isocorrosion lines (lines of constant corrosion rate) for carbon-steel
material exposed to aqueous solutions containing various concentrations of H2S, NH3, and
HCl up to 500 ppm each.
Figure 3. Acid Corrosion: Isocorrosion Lines for Carbon Steelin a Solution of HCL-H2 S-NH3 Each Totaling 500
ppm.
Several important concepts apparent from this diagram are:
The corrosion rate of carbon steel decreases as the NH3 concentration is
increased, and the HCl and H2S concentrations are decreased.
The corrosion rate of carbon steel increases as the concentration of either H2S
or HCl is increased.
These observations are expected, since carbon and low-alloy steels corrode at much higher
rates in acids, such as HCl or H2S, than in bases, such as NH3. In some process units, such asthe overhead system of crude units, compounds based on NH3 are added to process streams to
inhibit corrosion in carbon and low-alloy steels.
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Carbon and low-alloy steels are very susceptible to oxidation at high temperatures and
consequently are seldom used for components such as furnace tubes or tube supports. Figure
4 may be used to select an alloy for high temperature applications. For the temperature range
covered by Figure 4, Type 310 Stainless Steel, Incoloy or Inconel alloys are required toprovide satisfactory oxidation resistance.
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
1516
1718
19
20
25
300.02
0.03
0.05
0.1
0.2
0.5
0.7
1.0
1.5
2.0
4.0
10.0
20.0
12
Rfere
nce
Lin
e
%C
hromiumi
nthealloy
TemperatureF
Excessive
Moderate
Satisfactory
Corros
ionrate,
in./year
% Nickel in the alloy
1600
1700
1800
1900
2000
0
510
1520
25
30
35
40
45
50
6070
Figure 4. High-Temperature Oxidation of FE-Cr-Ni Alloys.
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The vast majority of equipment and piping in a refinery is fabricated from carbon steel and
low-alloy steels such as 5 Cr- Mo and 9 Cr-1 Mo. However, these materials are susceptible to
sulfidation corrosion when exposed to hot sulfur-bearing hydrocarbons. The sulfidation rate
depends upon the sulfur content of the hydrocarbon and the temperature. In general, thesulfidation rate increases as the temperature or sulfur content is increased. Figure 5 illustrates
the sulfidation rates of carbon steel, 5 Cr- Mo, 9 Cr-1 Mo, and stainless steel as a function of
temperature in an oil containing 0.60 wt-% sulfur.
Figure 5. Sulfidation Rates of Carbon Steel, 5Cr1/2Mo Steel,
9Cr 1Mo Steel
and 18Cr 8Ni Stainless Steel.
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As can be seen from the curves, the sulfidation rate of carbon steel becomes rather high above
about 288 C (550 F) and reaches a maximum rate at about 371 C (700 F) before dropping.
A similar peak is exhibited by the other materials. Sulfidation rates exhibit a drastic decrease
at high temperatures above about 427 C (800 F), because the hydrocarbon decomposes andforms a protective layer of coke on equipment surfaces. In practice, carbon steel is seldom
used in sulfur-bearing environments at temperatures above 288 C (550 F). Under these
conditions, 5Cr and 9Cr materials are normally used.
When a material corrodes by general, uniform corrosion, the corrosion rate may be
determined by ultrasonic thickness measurements, or by using corrosion coupons. Corrosion
coupons are made to standard dimensions (to ensure a known surface area) and are weighed
before and after exposure to the corrosive environment. The coupon should be exposed for
30-60 days to obtain meaningful data and cleaned after exposure to remove corrosion
products and scale. It is important to realize that corrosion coupons may not accurately
represent the conditions along a vessel or heat exchanger wall. Consequently, the corrosion
rate obtained from the coupon may be somewhat different than the actual corrosion rate.However, if the coupons are located properly, they are certainly capable of indicating
significant changes in corrosion rate. Increases or decreases in corrosion rate are usually due
to changes in the process or operating conditions or to frequent upsets within the system, such
as temperature excursions.
The corrosion rate in mils per year (MPY) is determined as follows:
Cor. Rate (MPY) =
Original Weight Final Weight ( milligrams )
Area (SQ DM ) Days is Service
1.437
Density
To relate inches per year (IPY) to MPY, multiply IPY by 1000.
It is also useful to visually examine the corrosion coupon before and after cleaning, to observe
the appearance of the corrosion product or scale and the appearance of the corroded corrosioncoupon.
Uniform Corrosion Allowance
A common petroleum industry practice is to design new equipment able to safely undergo
uniform corrosion by providing a greater thickness than that required for pressure,
temperature, head of liquid, wind load, etc. The greater thickness or corrosion allowance is
based upon the expected corrosion rate (mpy) in the particular service and the design life of
the equipment or unit. For example, the predicted corrosion rate for a new carbon-steel
product cooler is 6 mpy, and the unit design life is 15 years. The required corrosion
allowance is 6 mpy x 15 years = 90 mils (0.090 in). The usual approach is to provide a 3.2
mm (1/8 in) minimum corrosion allowance. If the corrosion rate is somewhat higher (say 8mpy), the fifteen year life can still be attained. If the uniform corrosion rate remains at around
6 mpy, the actual service life may be safely and economically extended.
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It is important to note that corrosion allowance must be based on the predicted or measured
corrosion rate for the particular service and expected operating temperature. In some cases,
changes in operating temperature (higher or lower), liquid/vapor phase changes, and increases
in velocity may significantly increase corrosion rate and reduce service life. Depending onthe required service life of the equipment or unit, replacement in kind, replacement with an
increase in corrosion allowance, or replacement with a more corrosion-resistant material or
alloy may be required.
Estimated Remaining Life
As corrosion occurs on the equipment, the wall thickness and corrosion allowance are
reduced. It is necessary to periodically measure the wall thickness to determine the remaining
corrosion allowance and to estimate the remaining service life.
The estimated remaining life can be determined as follows:
Estimated remaining life (years) =
Remaining Corrosion Allowance (mpy )
Current Corrosion Rate (mpy / yr)
A practical example of this approach would be a fire, causing an unscheduled shutdown of an
atmospheric crude tower. Figure 6 shows the range of thickness readings, 3.6 mm (0.14 in)
and greater, obtained from an ultrasonic survey on a 760 mm (30 in) diameter carbon steel
overhead line. The minimum required thickness (T min.) is 2.5 mm (0.100 in). Based on the
last two inspections, the current corrosion rate is approximately 45 mils/yr. The next
scheduled shutdown for the crude unit will be in 2 years. To decide on necessary repairs, the
estimated remaining life approach can be used:
Estimated remaining life=
Remaining Corrosion Allowance
Current Corrosion Rate
2 years = Remaining Corrosion Allowance
45 mpy
90 mils (.090 in) = Remaining Corrosion Allowance T (min.)
+ Corrosion Allowance (CA) = Required Thickness
Where: T (min.) = 0.10 in (2.5 mm), CA = 0.090 in (2.3 mm); the Required Remaining
Thickness = 0.10 in + 0.090 in = 0.19 in (4.8 mm)
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On this basis, it was decided to install external bands or reinforcing plates on all areas 5.2 mm
(0.20 in) or less in thickness. After the completion of the repairs, the unit was restarted.
Figure 6. Ultrasonic Thickness Survey
on Atmospheric tower Overhead Line
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Nonuniform Corrosion
Nonuniform or localized corrosion occurs at what appear to be small, randomly selected sites
on the surface of the material. Only a small percentage of the total surface, for example less
than 3%, may be actively corroding. Local corrosion manifests itself as pitting, crevice
corrosion, under-deposit corrosion, or stress corrosion cracking. In some situations, only
pitting corrosion may occur, as illustrated schematically in Figure 7a. In other environments,
general corrosion as well as local pitting corrosion might occur. This is illustrated
schematically in Figure 7b.
Figure 7a. Pitting Corrosion Can Leave Some
of the Original Surface Unattacked.
Figure 7b. Other Forms of Pitting Are Combined
with Generalized Corrosion
Pitting, under-deposit corrosion, and cracks due to stress corrosion cracking are often found
by visual examination of the material surface. However, some cracks caused by stress
corrosion are extremely fine and might be missed during visual examination. To remedy this
situation, the surfaces of non-magnetic materials are liquid penetrant (PT) inspected, and the
surfaces of magnetic materials (carbon and low-alloy steels) are inspected using magnetic
particle (MT) or wet fluorescent magnetic particle (WFMT). Other inspection techniques,
such as radiography and ultrasonic testing, are also used to detect cracks.
Depending upon the specific environment, nonuniform or localized corrosion such as pitting,
crevice corrosion, and under-deposit corrosion has been experienced at Saudi-Aramco
facilities when using high-alloy materials like the 300 series austentitic stainless steels.However, nickel-base alloys like Incoloy and Inconel can also exhibit pitting and under-
deposit corrosion in higher-temperature, low pH chloride-bearing aqueous environments. A
good example of localized corrosion is the pitting of austenitic stainless steels in seawater.
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Pitting Corrosion
In pitting corrosion, the small diameter holes or depressions that form on the materials
surface during service are called pits. Pits usually form because of the presence of small
surface discontinuities that might include microscopic inclusions, machining marks, small
scratches, or dents. Although a pit may be extremely small when it first forms, it can grow
until a through-wall failure occurs if the environment is sufficiently aggressive.
An example of pitting-induced failure can been seen in the use of the 300 series austenitic
stainless steels in salt or brackish water. These materials will perform satisfactorily if the
component is crevice free and if the water is maintained at a velocity of about 5 ft/sec.
Sufficient fluid flow is required to maintain the passivity (adherent corrosion film) of the
stainless steel surface. However, if the equipment is shut down and not drained, or contains
crevices or stagnant dead-legged areas, chloride-induced pitting is likely. It is important to
understand that once pitting begins in a stagnant, low-flow area, it is very difficult, if not
impossible, to stop. The pits grow rapidly, and the material fails via through-wall perforationin a relatively short period of time. Under severe pitting conditions, failures in stainless steel
equipment in sea or brackish water service have been known to occur in six months or less.
Because of the problems associated with pitting corrosion in chloride-bearing media, such as
sea and brackish waters, the 300 series stainless steels are seldom specified for these services.
To avoid pitting problems under these conditions a duplex alloy, such as Zeron 100, or
austenitic alloys such as 904L, Avesta 254SMO, Inconel 625, or Hastelloy C276 must be
used. These alloys contain more molybdenum than the 300 series stainless steels and are more
resistant to pitting. Nonferrous materials such as Titanium are also suitable for sea and
brackish water service.
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Under-deposit Corrosion
Dirt, solids, loose (non-adherent) corrosion products, or salts present in process streams can
cause severe corrosion of exchanger tubes (internal or external) and piping. Figure 8 shows
external under-deposit attack on a condenser tube.
Figure 8. Under-Deposit Attack on Outside of a Condenser
Tube.
Note the Perforation in the Tube Wall.
The damage to the tube occurred as a result of oxygen concentration cell attack. During
service the oxygen present in the cooling water continually repaired and maintained the
protective film on the surface of the clean tube, giving the tube its corrosion resistance.
However, when deposits formed on the tube, the oxygen in the water could no longer reachthe tube surface to repair and maintain the protective film. Consequently, areas beneath the
deposits were highly susceptible to corrosive attack, while the deposit-free surfaces were
protected. This created a galvanic cell in which the material beneath the deposits corroded in
preference to the deposit-free surfaces. The corrosion rate associated with under-deposit
attack can be very high and the resulting damage severe, as illustrated in this figure.
Another example of under-deposit corrosion is corrosion that occurs in carbon-steel tubing in
condensers or air coolers in Hydrotreating or Hydrocracking Units. The corrosion is caused
by H2S and NH3 which are formed during the hydrotreating process from the sulfur and
nitrogen in the crude oil. Liquid hydrocarbons, solid NH4HS, and NH4Cl salts are formed
when the effluent from the reactor is condensed. The solid ammonium salts are deposited on
the tube ID surfaces. At temperatures below the dew point in the presence of moisture severeacidic corrosion of the tube material occurred beneath the deposits. The corrosion was due to
the formation of HCl. This problem was solved by replacing the carbon-steel tubes with high-
alloy tubes manufactured from Incoloy 800 or Incoloy 825. Another mitigation method would
have been to utilize water washing to dissolve the deposits.
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Crevice Corrosion
It is important to eliminate crevices whenever possible when designing and fabricating
equipment. When this is not possible, the crevice areas may be sealed with a continuous fillet
weld or filled with a protective coating or sealer. Crevices that are not sealed are susceptible
to accelerated corrosion. The mechanism is essentially identical to that described above for
under-deposit corrosion. In stainless steel equipment exposed to chloride-bearing media, this
problem is especially severe because the stagnant crevice conditions result in a corrosion
mechanism that is similar to pitting. Recall that pitting corrosion occurs at very high rates, and
through-wall failures can occur within months. Figure 9 illustrates the type of damage
associated with crevice corrosion.
Figure 9. Corrosion at a Crevice Formed between a Metal
Coupon
and an Insulating Washer in a Test Spool
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Galvanic Attack
Galvanic attack occurs when dissimilar metals are brought into intimate contact with one
another in an electrolyte. The more active metal called the anode corrodes, while the noble
metal (i.e., platinum, iridium, osmium, palladium, rhodium, ruthenium, silver, gold) called
the cathode does not. For certain environments, it is important to understand that the corrosion
rate of a particular metal increases dramatically when it is brought into contact with a more
noble metal. In other words, the more noble metal causes an increase in the corrosion rate of
the more active metal.
Figure 10 shows a schematic example of galvanic attack.
Figure 10. Galvanic Attack
The table in Figure 11 lists the galvanic series of various metals and alloys in seawater.
MagnesiumZinc
CadmiumAluminumAntimonyTungstenLeadTinNickelCopper
0.00.4
0.49.8
153.1176.0183.2171.1181.1183.1
3104.3688.0
307.9105.9
13.85.23.62.50.20.0
Corrosion (iron)mg
Corrosion(second metal)
mg
Second Metal
Figure 11. Table Gives Corrosion Results for
Plates of Iron and a Second Metal,Coupled Galvanically and Totally Immersed in a 1%
Sodium Chloride Solution.
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In a galvanic series, the materials are listed in descending order of activity, with the most
active metal listed first and the least active metal listed last. Materials are also grouped in
families. For example, the copper alloys (brasses, bronzes and copper-nickels) and 300 series
stainless steels form two distinct families. Pairings of metals from the same general family, forexample Red Brass and Admiralty Brass or Type 304 stainless steel and Alloy 20Cb3, will not
result in excessive attack of either metal due to galvanic corrosion. However, pairings of
metals from outside their respective families can result in excessive corrosion of the more
active metal. For example, a very severe galvanic cell is created when aluminum, which is
very inert, is coupled with carbon steel, which is relatively active. The aluminum corrodes at a
rate that is unacceptably high for engineering purposes.
Galvanic considerations are particularly important in cooling water and other services
involving aqueous phases. It is very important in heat exchangers that the tube material be
more noble than the tubesheet to prevent premature failure of the tubes. For example, it is
appropriate to use noble stainless steel tubes in a carbon steel tubesheet. The thick tubesheet,
being the active member of the couple, can tolerate a relatively high corrosion rate for a longperiod of time. However, if the tubes were steel and the tubesheet stainless steel, the thin
carbon steel tubes would perforate quickly, resulting in a reduced service life for the
exchanger tubing.
Another important factor to consider in assessing galvanic attack is the ratio of anode-to-
cathode area, sometimes referred to as the area effect. The galvanic effects on the anodic
material will be minimal if the surface area of the anodic material is larger than the surface
area of the cathodic material. However, if the cathodic area is larger than the anodic area, the
galvanic corrosion will be extremely severe.
A good example of the area effect occurred when a carbon steel plug was inadvertently
installed in a Monel channel in brackish cooling water service. The plug rapidly corroded and
the exchanger leaked.
Galvanic corrosion can be minimized by using similar materials or materials from the same
family, i.e., avoiding dissimilar metal couples, electrically isolating connections involving
dissimilar metals, and providing sacrificial anodes to protect the anodic material. An example
of the use of sacrificial anodes is the installation of magnesium anodes in cooling water
exchangers to protect the carbon-steel channels. Depending on water quality, it is often
necessary to use copper-nickel or brass materials for tubes and tubesheets to obtain
satisfactory tube bundle life. Carbon-steel channels are specified to minimize costs.
Magnesium anodes are installed on the channel ID to minimize galvanic corrosion of the
carbon-steel channel in the area immediately adjacent to the copper-nickel or brass tubesheet.
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Intergranular Attack
Heat treatment or welding of alloys can result in changes in the microstructure of the material.
A good example of this phenomenon is the sensitization of the 300 series stainless steels
during welding.
Sensitization is caused by the heat of welding and results in the formation of chromium
carbide in the grain boundaries of the heat-affected material adjacent to the weld nugget.
Carbide formation depletes the metal immediately adjacent to the grain boundaries of
chromium on a microscopic scale. This loss of chromium results in a very narrow band of
material on both sides of the grain boundary which no longer has the corrosion resistance of
the bulk stainless steel. In certain aqueous, corrosive media, a galvanic cell develops between
the chromium depleted zone and the chromium-rich, bulk material. In this cell the chromium
depleted area is the anode, and corrodes preferentially to the cathodic bulk material. The
corrosion proceeds along the grain boundaries and is sometimes referred to as weld decay.
Environments that promote weld decay (intergranular corrosion) in the 300 series austeniticstainless steels include wet sour crude oil, sodium hypochlorite, sulfuric acid, nitric acid, and
sulfurous acid (SO2 + H2O). This is by no means a complete list.
Figure 12A. Schematic Depiction of Intergranular Attack
in the Heat Affected Zone.
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Figure 12B. Macrophotograph of Weld
Showing This Form of Attack.
Welding is not the only process that promotes sensitization of austenitic stainless steel.
Postweld heat treatment (PWHT) can also result in sensitization. It is important to note that
after PWHT the entire component, not just the weld areas, may be susceptible to intergranular
corrosion. Stainless steels are almost never given conventional PWHT for this reason.
In certain environments, particularly if the stainless steel material is under a high degree of
stress, cracks can initiate at the root of the intergranular corrosion. This type of cracking is
known as intergranular stress corrosion cracking. In the absence of cracking, the intergranular
stress corrosion process proceeds until through-wall penetration occurs.
Intergranular corrosion of weld heat-affected material in the 300 series austenitic stainless
steels can be controlled by using L grade (low carbon content) material and limiting the
heat input during welding. It is recommended that Saudi Aramco Specifications andMaterials/Welding Engineers be consulted.
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Dealloying
Dealloying the environment selectively removes one of the alloy components from a material.
Copper-base alloys may be attacked by:
Dezincification-removal of zinc from brass
Dealuminification-removal of aluminum from aluminum brasses and
bronzes
Denickelification-removal of nickel from cupronickels and Monel.
Figure 13 shows a schematic illustration of layer and plug-type dezincification and a
photomicrograph of plug-type dezincification of brass.
Figure 13. Photomicrograph of Plug Type Dezincification of
Brass.
This type of attack is not very common in todays facilities, since brasses are no longer widely
used.
Graphitization of cast iron occurs when the iron is selectively removed and only carbon
(graphite) is left. This can occur in cooling water piping. Since this type of attack occurs over
a long period of time, the usual solution is to replace the cast iron pipe in kind.
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Stress-Related Corrosion
Stress corrosion cracking, also termed environmental cracking, is defined as a cracking
process caused by the combined effects of tensile stress and environment on a specific
material. There are several types of stress corrosion cracking. It is important to understand the
fundamentals of each type, and the materials that are least/most susceptible.
In general, for stress or environmental cracking to occur, the material must be susceptible to
corrosion in the particular environment, must be under tensile stress, and must be exposed to
this environment for a sufficient period of time. Cracking usually occurs at right angles to the
principal direction of the stress, and can be transgranular or intergranular, depending on the
mechanism of the stress corrosion. For example, chloride stress corrosion cracking (SCC) of
austenitic stainless steels is usually transgranular, while polythionic acid stress cracking is
intergranular. The cracking is usually highly branched, but may consist of only one major
crack. The stresses required to induce stress corrosion cracking need only be static (tensile).
Figure 14A schematically illustrates stress corrosion cracking.
Figure 14a. Stress Corrosion Cracking
Corrosion fatigue requires cyclical stresses, i.e., dynamic loading to induce cracking. It is
important to understand that under cyclical stress conditions the corrosive environmentreduces the fatigue resistance of the material. A very aggressive environment can affect crack
initiation, crack propagation, or both. The cracks often initiate at pits or intergranular
corrosion sites. They can be either intergranular or transgranular. Corrosion products often
cause a wedge-opening action, and straight singular cracks with little branching are observed.
Corrosion fatigue is most pronounced under low cyclic, high stress conditions. High cycle
fatigue is relatively unaffected by corrosion, unless the material is severely pitted. In severely
pitted material, cracks can initiate at pits.
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A schematic illustrating corrosion fatigue is shown in Figure 14B.
Figure 14b. Corrosion Fatigue
Corrosion fatigue can be mitigated by minimizing the corrosivity of the environment. Refer to
Figure 15.
Figure 15. Effect of Alternating Stresses with and without
Corrosion.
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Stress Corrosion Cracking of Stainless Steels
The most common form of stress corrosion cracking (SCC) is undoubtedly chloride SCC of
300 series austenitic stainless steels, such as Type 304 SS, Type 316 SS, etc.
Several conditions are required for cracking to occur. These are:
The environment must contain aqueous chlorides.
Temperature must be above 60 C (140 F).
The material must be under stress.
The material must be exposed for a sufficient period of time.
For materials exposed to acidic chloride bearing solutions, chloride SCC can occur at lower
temperatures. It is also important to realize that tensile stress must be present for cracking to
occur.Figure 16 shows a photomicrograph of chloride SCC of austenitic stainless steel.
Figure 16. Stress Corrosion Cracking in Austenitic Stainless
Steel
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The presence of dissolved oxygen and acidic components in the environment usually
accelerates the time to failure. This form of cracking occurs in aqueous chloride-bearing
environments such as brackish water or seawater. However, it can occur in any chloride-
bearing environment such as wet crude oil, produced water from a production facility orGOSP, fresh water used for cooling, boiler feedwater, process water, steam condensate, etc.
Cracks are usually transgranular and highly branched.
It is important to determine if chlorides are present whenever specifying or considering the
use of the 300 series austenitic stainless steels in aqueous environments. If chlorides are
present, and the temperature is above 60 C (140 F), it is probably advisable to use a duplex
stainless steel or an austenitic stainless steel that has a high nickel content, such as Alloy
20Cb3, Incoloy 825, or Alloy 904L. Consult Saudi Aramco Specifications and the Materials
Engineering & Corrosion Control Department.
As shown in Figure 17, nickel content is an important factor in the prevention of SCC in
austenitic stainless steels.
Figure 17. The Effect of Nickel Content on SCC of Austenitic
Materials.
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Figure 18 shows the results of a survey on chloride SCC (136 cases in 109 locations). It is
important to note that some failures occurred at or below 1 ppm chlorides.
Figure 18. Chloride SCC of Austenitic Stainless SteelsMTI
Survey Data
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As shown in Figure 19, chlorides and oxygen can have a synergistic effect on SCC of 304
stainless steel.
304SCC - All Heat Treatments SCC No SCC
SCC
Sensitized
Only
Tentative
SCC - Safe Area
1000
1001010.1
0.01
0.0010.01
0.1
100
1,000 10,000
Sensitized
Annealed
10
1
250 - 300 C
DissolvedO,
g/m
(ppm)
2
CI Concentration, g/m (ppm)3
Figure 19. Synergistic Effect of Chlorides and Oxygen
on the SCC of Type 304 Stainless Steel.
Environments such as polythionic acid promote intergranular stress corrosion cracking of
sensitized austenitic stainless steels, such as Type 304 and Type 316. Cracking can occur in
the weld area or in the base metal, and is caused by sensitization due to long-term elevated
temperature service. This type of stress cracking is an important consideration in
hydrocracking and hydrotreating units. It should be noted that equipment items in these units
are fabricated from Cr-Mo steel internally clad with stainless steel. Cracking does not occur
during operation, but occurs when the units are shutdown and opened to the atmosphere for
inspection or maintenance. The polythionic acid forms when the sulfide scale on the internal
stainless steel surfaces is exposed to oxygen and moisture from the air. Intergranular cracking
occurs in a relatively short period of time if the cladding material or the welds in the cladding
material is sensitized and contains sufficient residual stress.
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Polythionic acid stress corrosion cracking is mitigated by using the stabilized grades of
stainless steel for cladding (Type 321 or Type 347). The low carbon L grades, such as Type
304 L stainless steel are not recommended, since these materials suffer sensitization after
long-term elevated temperature service. However, it should be pointed out that even Types321 or 347 will eventually sensitize. To minimize the risk of cracking, equipment items in
Hydrotreating or Hydrocracking Units are rinsed with a basic solution prior to opening the
equipment to the environment. The basic residue will neutralize the polythionic acids as they
form.
Figure 20 illustrates the microstructure of unsensitized and sensitized austenitic stainless steel.
The left photo shows the desired microstructure with the carbides dispersed throughout the
grains. The right photo shows a sensitized structure. Note that carbides have formed in the
grain boundaries. The adjacent areas have substantially lower chromium content. This can
lead to intergranular attack of the sensitized stainless steel as shown in Figure 21, or to
intergranular stress corrosion cracking.
Figure 20 . Unsensitized and Sensitized Austenitic Stainless
Figure 21. Intergranular Attack of Sensitized Stainless
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Stress Cracking of Carbon and Low-Alloy Steels
Carbon and low-alloy steels in wet H2S service are susceptible to sulfide stress corrosion
cracking. Cracking usually occurs in the weld heat-affected zone of welds which have not
been stress relieved, especially if the material exhibits excessive hardness. The cracking is
usually transgranular, but can be intergranular. In general, carbon steels that exhibit hardness
values in excess of 22 Rockwell C are very susceptible to sulfide stress corrosion cracking at
ambient temperature. To minimize the risk of sulfide stress cracking in sour service, materials
of construction should comply with the requirements contained in NACE MR-01-75.
The figure on page 5 of the Appendix shows transverse cracking in the weld metal of a
pressure vessel main seam weld. (Source: Reference No. 1, NACE Corrosion paper)
Note the range in Brinell hardness. This sulfide stress crack originated in the hard outside pass
and terminated in the soft previous passes.
The risk of sulfide stress corrosion cracking can be minimized by exercising several
precautions. It is recommended that the requirements contained in NACE Standard MR-01-75 be followed when considering materials of construction for equipment in wet H2S service
in refining and production facilities. It is also recommended that the equipment be given
PWHT to reduce residual stresses and lower weld hardness.
Carbon and low-alloy steels are also susceptible to cracking due to caustic embrittlement. This
form of cracking has occurred in boilers and in equipment handling high temperature caustic.
Cracking usually occurs in the weld heat affected zone of welds which have not been stress
relieved, or in adjacent base metal that is under a high degree of residual stress. It is
recommended that equipment be given PWHT to reduce residual stresses and reduce weld
hardness to minimize the risk of cracking.
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As shown in Figure 21, caustic-embrittlement cracking of carbon steel is highly branched.
The examples that have been reviewed above represent only a few of the important
environment/material combinations that are known to cause stress corrosion cracking in
refining and production facilities. The table in Figure 22 lists the most common types of stresscorrosion cracking and the corresponding susceptible materials. It should be noted that this is
not a complete list.
CLASSIFICATIONS OF STRESS CORROSION FORMS
TYPES OF STRESSCORROSION CRACKING ALLOY FAMILY
Chloride
Polythionic Acid
Caustic
Wet H S
Amines
Hydrogen
Ammonia
Austenitic stainless steel
Austenitic stainless steel (sensitized)
Carbon Steel
Carbon Steel
Carbon Steel
Carbon and low alloy steels
Copper base alloys
2
Figure 22. Classifications of Stress Corrosion Forms
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Effect of Velocity on Corrosion
In piping and heat exchanger tubes the appearance of the corroded surface may be related to
the fluid flow. For example, when preferential wall thinning occurs at an elbow or a return
bend, it indicates that the components are suffering local erosion or erosion/corrosion due to
changes in the fluid flow direction. The corrosion mechanism is also likely to be
erosion/corrosion when pits become elongated in the direction of the flow and have a groove-
like appearance. In erosion/corrosion, the corrosion product, which in some situations is
protective, is continually removed from the material surface as a result of excessive velocity
or the action of abrasive particles in the fluid. This results in very high metal loss, as a
protective layer of corrosion product is never formed.
Figure 23 illustrates erosion/corrosion on a tube ID surface.
Figure 23. Tube Showing Cross Section of Impingement Pits.
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It is important to recognize the effects of velocity on corrosion rate when designing piping
systems or heat exchangers. Figure 24 indicates the effect of velocity on the corrosion rate of
various materials in seawater.
Figure 24. Metal Loss and Pitting Behavior as a Function of
Velocity
for Several Materials in Stagnant and Flowing
Seawater.
It is also important that the velocity limits indicated for piping and condenser design be
followed. If the recommended velocities are exceeded, the service life of the equipment or
piping is likely to be reduced. It is important to recognize that for some alloys, such as brassor copper/nickel, relatively small increases is fluid velocity can drastically increase the metal
loss. These materials are relatively soft and have inherently poor erosion resistance. (Erosion
is not a corrosion mechanism.)
Impellers in pumps can suffer from cavitation damage, a form of erosion, due to a lack of net
positive suction head during operation. Under these conditions bubbles form and collapse on
the material. This hammering effect results in spongy cavities.
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Figure 25 shows a schematic representation of cavitation erosion.
Figure 25. Schematic representation of cavitation.
Erosion problems are most often solved by modifying equipment and plant design. A larger
pipe size can be installed to reduce velocity. Filtration equipment can be installed to remove
abrasive particles. If none of these options are possible, components can be overlaid withhardfacing alloys or a more erosion-resistant material can be used.
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EVALUATing Typical Design Related Problems
NACE International has published the Corrosion Data Survey, Metals Section, Sixth Edition
(available in hard copy or survey computer software). The Survey contains extensive
information on uniform corrosion rates, pitting, stress corrosion cracking, intergranular attack,
and crevice attack. It is extensively used as a guide for materials selection. The information
was originally developed by Shell Development Company Engineers. NACE periodically
updates and publishes the Survey.
Refer to the Corrosion Data Survey, Metals Section, Sixth Edition, and the Errata dated
October 1985. The Matrix Key and Key to Data Points can be found on page 6 of the
Appendix (Source: Reference No. 2 NACE Corrosion Data Survey, matrix section). As the
Matrix Key explains, the vertical grid relates to temperature in F and C, the horizontal grid
relates to percent concentration in water. The Key to Data points explains that the symbols
used to indicate average penetration rate per year are: o < 2 mpy, o < 20 mpy, [] 20-50 mpy,
and x > 50 mpy.Note: As shown in the Erratum the last column should be m not mm. Throughout the book
corrosion rate data points are arranged on the grid for various services (in NACE alphabetical
order) and for various materials (steel, cast iron, stainless steel, copper base, nickel base, and
other metals and alloys). In addition to the data points reporting average penetration rate,
footnotes cover pitting, stress corrosion cracking, intergranular attack, and crevice attack. In
the absence of previous service information, the Corrosion Data Survey may be used to screen
the suitability of various materials for a field trial or corrosion testing.
Several examples that illustrate the use of the NACE Corrosion Data Survey for metals are
presented below.
Pages 7 and 8 of the Appendix show the information on pages 10 and 11 of the Survey.
Using the information on ammonium chloride, 6, the following can be noted: High corrosion rates: > 50 mpy on steel, 12Cr, 17Cr, and 304 SS at certain
concentrations and temperatures.
Both 304 and 316 SS are subject to pitting and stress corrosion cracking
(footnotes 1, 2).
Low Corrosion rates: < 2 mpy on several nickel-base alloys, tantalum, titanium,
and zirconium.
Pages 9 and 10 of the Appendix show the information on pages 118 and 119 of the Survey.
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Using the information on sodium hydroxide 2, the following information can be obtained:
Carbon steel can be used at lower temperatures and concentrations with
corrosion rates < 20 mpy.
The corrosion resistance of Type 316 SS is significantly better than Type 304
SS below 93 C (200 F).
The nickel-base alloys show low corrosion rates for a wide range of
concentrations and temperatures.
Page 11 of the Appendix shows the Caustic Soda Service Graph on page 176 of the Survey.
This graph is widely used as a reference to determine when stress relief of carbon steel welds
and bends is necessary, or when nickel alloys are required:
Area A: no stress relief required
Area B: stress relief of carbon steel welds and bends required
Area C: nickel alloys should be considered.
It is important to remember that equipment temperatures may be higher than normal operating
temperatures due to:
External steam tracing
Steam out or wash out with hot water during shutdowns
Upsets in temperature or pressure during operation.
There have been extensive industry reports of caustic cracking of pressure vessels and piping
attributed to these higher temperatures.
Pages 12 and 13 of the Appendix show the Sulfuric Acid Service Graph and Code For
Sulfuric Acid Graph, which are found on pages 184 and 185 of the Survey. This is a useful
reference to quickly determine the suitability of various materials (reported corrosion rate
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