1.

Graphitization
Affected Units or Equipment:
Several serious cases of graphitization have occurred in the reactors and piping of fluid catalytic
cracking units, as well as with carbon steel furnace tubes in a thermal cracking unit and the failure of
seal welds at the bottom tube sheet of a vertical waste heat boiler in a fluid catalytic cracker. A
graphitization failure was reported in the long seam weld of a C-0.5Mo catalytic reformer
reactor/inter-heater line.

2. Temper Embrittlement
Description of Damage
Temper embrittlement is the reduction in toughness due to a metallurgical change that can occur in some
low alloy steels as a result of long term exposure in the temperature range of about 650°F to 1070°F
(343°C to 577°C). This change causes an upward shift in the ductile-to-brittle transition temperature as
measured by Charpy impact testing. Although the loss of toughness is not evident at operating
temperature, equipment that is temper embrittled may be susceptible to brittle fracture during start-up
and shutdown.
Critical Factors
Temper embrittlement of 2.25Cr-1Mo steels develops more quickly at 900°F (482°C) than in the
800°F to 850°F (427°C to 440°C) range, but the damage is more severe after long-term exposure at
850°F (440°C).

3. 885°F (475oC) Embrittlement

Description of Damage
885°F (475°C) embrittlement is a loss in toughness due to a metallurgical change that can occur in
alloys containing a ferrite phase, as a result of exposure in the temperature range 600°F to1000°F
(316°C to540°C).

4. Brittle Fracture
Prevention / Mitigation
Some reduction in the likelihood of a brittle fracture may be achieved by:
1) Performing a post weld heat treatment (PWHT) on the vessel if it was not originally done during
manufacturing; or if the vessel has been weld repaired/modified while in service without the
subsequent PWHT.
2) Perform a “warm” pre-stress hydrotest followed by a lower temperature hydrotest to extend the
Minimum Safe Operating Temperature (MSOT) envelope.

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5. Creep and Stress Rupture
Critical Factors
The rate of creep deformation is a function of the material, load, and temperature. The rate of
damage (strain rate) is sensitive to both load and temperature. Generally, an increase of about 25°F
(12°C) or an increase of 15% on stress can cut the remaining life in half or more, depending on the
alloy.

Threshold Temperatures for Creep

Material Temperature Limit
Carbon Steel (UTS ≤ 60 ksi) 650°F
Carbon Steel (UTS > 60 ksi), Carbon Steel – Graphitized 700°F
C-1/2Mo 750°F
1-1/4Cr-1/2Mo - 9Cr-1Mo 800°F
2-1/4Cr-1Mo-V - 3Cr-1Mo-V 825°F
9Cr-1Mo – V 850°F
12 Cr 900°F
AISI Type 304 & 304H 1000°F
AISI Type 316 & 316H, 321 & 321H, 347 & 347H 1000°F
Alloy 800, 800H, 800HT 1050°F
HK-40 1200°F

6. Thermal Fatigue
Affected Units or Equipment
Steam actuated soot blowers may cause thermal fatigue damage if the first steam exiting the soot
blower nozzle contains condensate. Rapid cooling of the tube by the liquid water will promote this
form of damage. Similarly, water lancing or water cannon use on water wall tubes may have the
same effect.
Appearance or Morphology of Damage
Water in soot blowers may lead to a crazing pattern. The predominant cracks will be circumferential
and the minor cracks will be axial.

7. Short Term Overheating – Stress Rupture

Description of Damage
Permanent deformation occurring at relatively low stress levels as a result of localized overheating. This
usually results in bulging and eventually failure by stress rupture.

8. Dissimilar Metal Weld (DMW) Cracking

Description of Damage
Cracking of dissimilar metal welds occurs in the ferritic (carbon steel or low alloy steel) side of a weld
between an austenitic (300 Series SS or Nickel base alloy) and a ferritic material operating at high
temperature. Cracking can result from creep damage, from fatigue cracking, from sulfide stress cracking
or hydrogen dis-bonding.

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9. Erosion/Erosion – Corrosion
Critical Factors
In most cases, corrosion plays some role so that pure erosion (sometimes referred to as abrasive
wear) is rare. It is critical to consider the role that corrosion contributes.

10.Cavitation
Affected Units or Equipment
Cavitation is most often observed in pump casings, pump impellers (low pressure side) and in piping
downstream of orifices or control valves.
Inspection and Monitoring
Cavitating pumps may sound like pebbles are being thrashed around inside.
Techniques include limited monitoring of fluid properties as well as acoustic monitoring of turbulent
areas to detect characteristic sound frequencies.
Visual examination of suspected areas, as well as external UT and RT can be used to monitor for
loss in thickness.

Cavitation will not be inspected by eddy current.

11.Mechanical Fatigue
Appearance or Morphology of Damage
The signature mark of a fatigue failure is a “clam shell” type fingerprint that has concentric rings
called “beach marks” emanating from the crack initiation site . This signature pattern results from the
“waves” of crack propagation that occur during cycles above the threshold loading. These concentric
cracks continue to propagate until the cross-sectional area is reduced to the point where failure due to
overload occurs.
Critical Factors
Metallurgical Issues and Microstructure
For some materials such as titanium, carbon steel and low alloy steel, the number of cycles to
fatigue fracture decreases with stress amplitude until an endurance limit reached. Below this
stress endurance limit, fatigue cracking will not occur, regardless of the number of cycles.

12.Galvanic Corrosion
Inspection and Monitoring
Visual inspection and UT thickness gauging are very effective methods for detecting galvanic corrosion.
The damage may sometimes be hidden underneath a bolt or rivet head.

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13.Corrosion Under Insulation (CUI)
Critical Factors
Corrosion rates increase with increasing metal temperature up to the point where the water
evaporates quickly. For insulated components, corrosion becomes more severe at metal
temperatures between the boiling point 212°F (100°C) and 350°F (121°C), where water is less likely
to vaporize and insulation stays wet longer.
Prevention / Mitigation
Since the majority of construction materials used in plants are susceptible to CUI degradation,
mitigation is best achieved by using appropriate paints/coatings and maintaining the
insulation/sealing/vapor barriers to prevent moisture ingress.

14.Cooling Water Corrosion

Prevention / Mitigation
Design for process side inlet temperatures below 140°F (60°C).
Minimum and maximum water velocities must maintained, particularly in salt water systems.

15.Boiler Water Condensate Corrosion

Critical Factors
Corrosion protection in the boiler is accomplished by laying down and continuously maintaining a
layer of protective Fe3O4 (magnetite).
Appearance or Morphology of Damage
Corrosion in the condensate return system tends to be due to carbon dioxide although some oxygen
pitting problems can occur if the oxygen scavenging treatment is not working correctly. Carbon
dioxide corrosion tends to be a smooth grooving of the pipe wall.

16.CO2 Corrosion
Appearance or Morphology of Damage
Carbon steel may suffer deep pitting and grooving in areas of turbulence.
Prevention / Mitigation
The 300 Series SS are highly resistant to corrosion in most applications. Selective upgrading to
stainless steels is usually required in operating units designed to produce and/or remove CO2 (such
as hydrogen plants and CO2 removal units).
400 Series SS and duplex SS are also resistant.
Inspection and Monitoring
VT, UT and RT inspection techniques should focus on general and local loss in thickness where
water wetting is anticipated.

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17.Flue-Gas Dew-Point Corrosion
Critical Factors
The dewpoint of sulfuric acid depends on the concentration of sulfur trioxide in the flue gas, but is
typically about 280°F (138°C).
Similarly, the dewpoint of hydrochloric acid depends on the concentration of hydrogen chloride. It is
typically about 130°F (54°C).

18.Microbiologically Induced Corrosion (MIC)

Affected Units or Equipment
MIC is most often found in heat exchangers, bottom water of storage tanks, piping with stagnant or
low flow, and piping in contact with some soils.

19.Soil Corrosion
Critical Factors
Soil resistivity is frequently used to estimate soil corrosivity, mainly because it is easy to measure.
Soil resistivity is related to soil moisture content and dissolved electrolytes in the soil water.

20.Dealloying
Prevention / Mitigation
Resistance to dealloying can sometimes be improved by the addition of certain alloying elements so
that a similar alloy with a different composition may be resistant. For example, tin tends to inhibit
dealloying of copper alloys; admiralty brass is inhibited by the addition of a very small amount of
phosphorous, antimony or arsenic

21.Graphitic Corrosion
Description of Damage
Attack results in a porous structure with a loss of strength, ductility and density. It usually occurs
under low pH and stagnant conditions, especially in contact with soils or waters high in sulfates.
Affected Units or Equipment
Graphitic corrosion can occur in soft water, salt water, mine waters, dilute acids and in underground
piping as well as in boiler feedwater equipment. Typical examples include feedwater piping, pumps
(including pump impellers), valves, and underground cast iron pipe. Fire water systems are particularly
Vulnerable.

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22.Oxidation
Critical Factors
In general, the resistance of carbon steel and other alloys is determined by the chromium content of
the material. Increasing chromium levels produce a more protective oxide scale. The 300 Series SS
are resistant to scaling up to about 1500°F (816°C).
Prevention / Mitigation
Chromium is the primary alloying element that affects resistance to oxidation. Other alloying
elements, including silicon and aluminum, are effective but their concentrations are limited due to
adverse effects on mechanical properties. They are often used in special alloys for applications such
as heater supports, burner tips and components for combustion equipment.

23.Sulfidation
Critical Factors
Sulfidation of iron-based alloys usually begins at metal temperatures above 500°F (260°C).

24.Carburization
Affected Units or Equipment
Fired heater tubes are the most common type of equipment susceptible to carburization in the
environments mentioned earlier.
Coke deposits are a source of carbon that may promote carburization, particularly during decoke
cycles where temperatures exceed the normal operating temperatures, accelerating the
carburization.
Carburization is sometimes found in heater tubes in catalytic reformers and coker units or other
heaters where steam/air decoking is performed.
Carburization is also encountered in ethylene pyrolysis and steam reformer furnaces. Significant
carburization occurs during decoking cycles.

25.Metal Dusting
Appearance or Morphology of Damage
In low alloy steels, the wastage can be uniform but usually is in the form of small pits filled with a
crumbly residue of metal oxides and carbides.

26.Fuel Ash Corrosion

Affected Units or Equipment
Heater tubes are sometimes not affected because their skin temperatures are cooler than the
threshold melting point of the slags in most heaters. Tube hangers and supports, however, operate
hotter and can suffer severe fuel ash corrosion.

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27.Nitriding
Critical Factors
Nitriding begins above 600°F (316°C) and becomes severe above 900°F (482°C).
Appearance or Morphology of Damage
In a more advanced stage, the material will exhibit very high surface hardness. In most cases, a
slightly harder surface layer of a vessel or component will not affect the mechanical integrity of the
equipment. However, the concern is for the potential development of cracks in the nitrided layer that
could propagate into the base metal.
Above 770°F (410°C), preferential grain boundary nitriding may lead to microcracking and
embrittlement.

28.Chloride Stress Corrosion Cracking (Cl-SCC)

Critical Factors
Cracking usually occurs at metal temperatures above about 140oF (60oC), although exceptions can
be found at lower temperatures.
Nickel content of the alloy has a major effect on resistance. The greatest susceptibility is at a nickel
content of 8% to 12%. Alloys with nickel contents above 35% are highly resistant and alloys above
45% are nearly immune.

29.Corrosion Fatigue
Prevention / Mitigation
Deaerators
Proper feedwater and condensate chemical control.
Minimize residual welding and fabrication stresses through PWHT.
Minimize weld reinforcement by grinding weld contours smooth.

30.Caustic Stress Corrosion Cracking (Caustic Embrittlement)

Affected Materials
Carbon steel, low alloy steels and 300 Series SS are susceptible. Nickel base alloys are more resistant.
Critical Factors
Cracking can occur at low caustic levels if a concentrating mechanism is present. In such cases,
caustic concentrations of 50 to 100 ppm are sufficient to cause cracking.
Appearance or Morphology of Damage
Caustic stress corrosion cracking typically propagates parallel to the weld in adjacent base metal but
can also occur in the weld deposit or heat-affected zones.
Prevention / Mitigation
Nickel base alloys are more resistant to cracking and may be required at higher temperatures and/or
caustic concentrations.
Steamout of non-PWHT’d carbon steel piping and equipment should be avoided. Equipment should
be water washed before steamout. Where steamout is required, only low-pressure steam should be
used for short periods of time to minimize exposure.

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31.Ammonia Stress Corrosion Cracking
Description of Damage
Aqueous streams containing ammonia may cause Stress Corrosion Cracking (SCC) in some copper
alloys.

32.Liquid Metal Embrittlement (LME)

Critical Factors
LME occurs in very specific combinations of metals in contact with low melting point metals such as
zinc, mercury, cadmium, lead, copper and tin.

33.Hydrogen Embrittlement (HE)

Inspection and Monitoring
RT often is not sufficiently sensitive to detect HE cracks.

34.Amine Corrosion
Description of Damage
Amine corrosion refers to the general and/or localized corrosion that occurs principally on carbon
steel in amine treating processes. Corrosion is not caused by the amine itself, but results from
dissolved acid gases (CO2 and H2S), amine degradation products, Heat Stable Amine Salts (HSAS)
and other contaminants.

35.Sulfate Stress Corrosion Cracking

Affected Materials
Some copper alloys are highly susceptible, especially admiralty brass.

36.Ammonium Bisulfide Corrosion (Alkaline Sour Water)

Appearance or Morphology of Damage
Low velocities may result in extremely localized under-deposit corrosion if insufficient water is
available to dissolve the NH4HS salts that precipitated.
Affected Units or Equipment
FCC Units
NH4HS concentrations are usually less than 2 wt % but high velocities and/or the presence of
cyanides can remove protective iron sulfide scales.
Prevention / Mitigation
Maintain velocities within industry guidelines of 10 to 20 fps for carbon steel. Carbon steel may be
susceptible to high corrosion rates above about 8 wt % NH4HS concentration.
Appearance or Morphology of Damage
NH4HS rapidly corrodes admiralty brass tubes and other copper alloys.

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37.Ammonium Chloride Corrosion
Critical Factors
Ammonium chloride salts may precipitate from high temperature streams as they are cooled,
depending upon the concentration of NH3 and HCl, and may corrode piping and equipment at
temperatures well above the water dewpoint [> 300°F (149°C)]

38.Hydrochloric Acid (HCl) Corrosion

Prevention/Mitigation
Crude Units
Upgrading carbon steel to nickel base alloys or titanium can reduce HCl acid corrosion
problems. Titanium tubes will solve most overhead condenser tube corrosion problems.
39.High Temp H2/H2S Corrosion
Critical Factors
 The major factors affecting high temperature sulfidation are the temperature, the presence of
hydrogen, the concentration of H2S and the alloy composition.
 Depending on the quantity of hydrogen that is present, corrosion rates may be significantly
different than those associated with high temperature sulfidation in the absence of hydrogen.
 Sulfidation rates increase with increasing H2S content and especially increasing temperature
 Higher corrosion rates are found more in gas oil desulfurizers and hydrocrackers than naphtha
desulfurizers by a factor of almost ‘2’.
 Susceptibility to sulfidation is determined by the chemical composition of the alloy.
 Increasing chromium content of the alloy improves resistance. However, there is little
improvement with increasing chromium content until about 7-9Cr as shown by the relative rate
reduction factors in Table 5-1.
 Chromium-containing nickel base alloys are similar to stainless steel. Similar levels of chromium
provide similar corrosion resistance.

40.Hydrofluoric (HF) Acid Corrosion

Critical Factors
Typical HF alkylation units operate with 1% to 3% water in the acid, equivalent to an HF-in-water
concentration of 97% to 99% and the temperatures are generally below 150oF (66oC). Under these
conditions carbon steel is widely used for all equipment except where close tolerances are required
for operation (i.e., pumps, valves, instruments).
Industry guidelines regarding RE content have been developed and implemented into some industry
consensus standards as indicated below. A more detailed discussion of these guidelines is outlined
in References 1 and 2.
1) • For Base Metal: %C > 0.18 wt.% and %Cu + %Ni < 0.15 wt.%
2) • For Weld Metal: %Cu + %Ni + %Cr < 0.15 wt.%

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41.Naphthenic Acid Corrosion (NAC)
Description of Damage
A form of high temperature corrosion that occurs primarily in crude and vacuum units, and downstream
units that process certain fractions or cuts that contain naphthenic acids.
Critical Factors
Neutralization number or Total Acid Number (TAN) is a measure of the acidity (organic acid content)
as determined by various test methods such as ASTM D-664. However, NAC corrosion is
associated with hot dry hydrocarbon streams that do not contain a free water phase.
Naphthenic acids remove protective iron sulfide scales on the surface of metals.
Prevention / Mitigation
For severe conditions, Type 317L stainless steel or other alloys with higher molybdenum content
may be required.

42.Phenol (Carbolic Acid) Corrosion

Critical Factors
High velocities may promote localized corrosion.

43.Phosphoric Acid Corrosion

Description of Damage
Phosphoric acid is most often used as a catalyst in polymerization units. It can cause both pitting
corrosion and localized corrosion of carbon steels depending on water content.

44.Sour Water Corrosion (Acidic)

Description of Damage
Corrosion of steel due to acidic sour water containing H2S at a pH between 4.5 and 7.0. Carbon
dioxide (CO2) may also be present.
Inspection and Monitoring
Evidence of locally thinned areas can be found using scanning ultrasonic thickness methods or
profile radiography.

45.Sulfuric Acid Corrosion

Critical Factors
Carbon steel corrosion rates increase significantly if the flow velocity exceeds about 2 to 3 fps (0.6 to
0.9 m/s) or at acid concentrations below 65%.
Appearance or Morphology of Damage
Hydrogen grooving may occur in low flow or stagnant areas such as in storage tanks or rail cars.

10
46.Polythionic Acid Stress Corrosion Cracking (PASCC)
Description of Damage
A form of stress corrosion cracking normally occurring during shutdowns, startups or during
operation when air and moisture are present. Cracking is due to sulfur acids forming from sulfide
scale, air and moisture acting on sensitized austenitic stainless steels.

47.Wet H2S Damage (Blistering/HIC/SOHIC/SSC)

Critical Factors
pH
Hydrogen permeation or diffusion rates have been found to be minimal at pH 7 and increase at both
higher and lower PH. The presence of hydrogen cyanide (HCN) in the water phase significantly
increases permeation in alkaline (high pH) sour water.

48.Carbonate Stress Corrosion Cracking (ACSCC)

Description of Damage
Carbonate stress corrosion cracking (often referred to as carbonate cracking) is the term applied to
surface breaking cracks that occur adjacent to carbon steel welds under the combined action of tensile
stress in systems containing a free water phase with carbonate, where some amount of H2S is also
present. It is a form of Alkaline Stress Corrosion Cracking (ACSCC).

49.High Temperature Hydrogen Attack (HTHA)

Description of Damage
High temperature hydrogen attack results from exposure to hydrogen at elevated temperatures and
pressures. The hydrogen reacts with carbides in steel to form methane (CH4) which cannot diffuse
through the steel. The loss of carbide causes an overall loss in strength.
Prevention/Mitigation
As a result of the problems with the 0.5 Mo alloy steels, its curve has been removed from the main
set of curves and the material is not recommended for new construction in hot hydrogen services.
For existing equipment, this concern has prompted an economic review of inspection cost versus
replacement with a more suitable alloy. Inspection is very difficult because problems have occurred
in weld heat affected zones as well as base metal away from welds.
Inspection and Monitoring
Ultrasonic techniques using a combination of velocity ratio and AUBT have been the most successful
in finding fissuring and/or serious cracking. HTHA damage can only be found using these
techniques if damage has progressed to the point where microvoids would be visible at a
magnification of 1500X or lower, if a sample of the metal was removed for examination.
Prevention/Mitigation
Use alloy steels with chromium and molybdenum to increase carbide stability thereby minimizing
methane formation. Other carbide stabilizing elements include tungsten and vanadium.

11
50.Titanium Hydriding
Description of Damage
Hydriding of titanium is a metallurgical phenomenon in which hydrogen diffuses into the titanium and
reacts to form an embrittling hydride phase. This can result in a complete loss of ductility with no
noticeable sign of corrosion or loss in thickness.
Appearance or Morphology of Damage
Another possible damage mode that has occurred is ignition and fire of titanium tubes.
Metallographic examination of titanium tubes from a bundle that burned showed significant amounts
of hydride, especially in the vicinity of the metal that had been melted.

12