Heidersbach R. Metallurgy and Corrosion Control in Oil and Gas Production

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FORMS OF CORROSION 99

that cause this form of corrosion is the presence of

chlorides, although copper - based alloys stress corrode

in ammonia and other nitrogen - containing environ-

ments . Many environments that cause SCC are only

mildly corrosive insofar as other forms of corrosion are

concerned. It is not unusual to see SCC on surfaces that

otherwise seem to be uncorroded, or only mildly cor-

roded, at least to the unaided eye.

SCC initiation sites include pits, metallurgical defects,

surface discontinuities, intergranular corrosion, and

other stress raisers.

SCC is often unaccompanied by

visible corrosion products and may appear to be the

result of strictly mechanical causes. This is shown in

Figures 5.50 – 5.54 . Note the “ river branching pattern ” of

cracks in Figure 5.55 . This branched - crack appearance

is direct evidence of SCC, and no other metallurgical

failure mode produces this pattern of cracking. The

absence of this branching should not be taken as evi-

dence of a lack of SCC, because many metals, to include

high - strength steels, may reach a critical ﬂ aw size and

fail by SCC before the crack has extended long enough

to start branching. Cracks as short as a fraction of

an inch (several millimeters) have been known to

produce SCC failures in high - strength steel and other

materials.

The growth of stress corrosion cracks is discontinu-

ous and is thought to usually involve initiation and ﬁ rst -

stage propagation, secondary steady - state propagation,

and ﬁ nal rapid failure. HE has been proposed as the

mechanism whereby these stages occur, although this is

disputed by some researchers. The strongest evidence

for hydrogen - related mechanisms is in high - strength

ferritic steels.

In the presence of active corrosion,

usually pitting or crevice corrosion, the cracking is gen-

erally called SCC, but many authorities suggest that this

should more properly be called hydrogen - assisted stress

corrosion cracking (HSCC). This form of corrosion

will treat environmental cracking in accordance with

the guidance available in NACE/ISO RP010156, the

most widely used oilﬁ eld standards on the subject.

33,62,63

There are a wide variety of terms used to describe envi-

ronmental cracking, including SCC, season cracking,

corrosion fatigue, HE, caustic embrittlement, and liquid

metal embrittlement. Many oilﬁ eld personnel will use

the term SCC as a synonym for all of the above terms.

One clear consensus is that most environmental

cracking, with the exception of corrosion fatigue, occurs

due to a combination of tensile stresses and speciﬁ c

corrosive environments. Corrosion fatigue can occur in

any corrosive environment. A few oilﬁ eld environments

are listed in Table 5.5 . It is apparent from Table 5.5 that

S and chlorides are common to environmental crack-

ing in most oilﬁ eld environments. Despite all of the

research on environmental cracking, no screening tests

have been developed that identify new environments,

and all of the alloy – environment combinations have

been identiﬁ ed due to ﬁ eld failures.

At one time, environmental cracking was considered

to be a problem of certain alloys in certain environ-

ments. Unfortunately, every structural alloy system has

some environment where cracking is known to occur.

Note that in the following discussion, there are some

mechanisms where the stresses come from chemical

reactions either on the surface or within the metal.

This concept of environmental cracking is a major

departure from the idea of tensile stresses (applied or

residual) found in the general (as opposed to oilﬁ eld)

literature.

SCC

This term is used for most aqueous environmental

cracking that is not clearly associated with hydrogen or

S. The most common characteristic of environments

TABLE 5.5 Metals and Environmental Cracking Environments

Metal Environment Factors That Increase Risk of SCC

Carbon steels Hydrogen sulphide Increasing H

S, moderate temperatures, more acidic, higher strength/

hardness, higher stress levels

Carbon steels Carbonates Higher strength

Carbon steels Chlorides Higher strength, higher stress levels, more acidic

Copper alloys Ammonia Higher strength, higher stress levels

Martensitic stainless steels Hydrogen sulphide Increasing H

S, moderate temperatures, more acidic, higher strength/

hardness, higher stress levels

Austenitic stainless steels Chlorides Higher strength, higher chloride levels, higher stress levels, more acidic,

higher temperatures, presence of H

Duplex stainless steels Chlorides Higher strength, higher chloride levels, higher stress levels, more acidic,

higher temperatures, presence of H

Titanium Alcohol Higher stress levels, lower water content

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100 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

possibility of hydrogen involvement in the SCC

mechanism(s) is an indication that corrosion control

methods based on cathodic protection must be used

with caution. This is one reason why pipelines, where

corrosion control is normally by a combination of pro-

tective coatings and cathodic protection, are seldom

constructed out of high - strength (yield stresses greater

than 80 ksi [550 MPa]) steel. Most cathodic reduction

reactions on carbon steel pipelines are due to oxygen

reduction, but the possibility of hydrogen reduction,

especially beneath disbonded protective coatings, is a

potentially serious concern.

Unlike the controversy associated with mechanisms

of SCC in steels, there is no dispute that SCC in tita-

nium alloys can involve hydrogen, and hydrides of tita-

nium have been detected in titanium after SCC events.

Stress corrosion cracks often appear in groups or

colonies on otherwise uncorroded surfaces. This is

shown in Figure 5.52 , which shows intersecting cracks

on the outside of a buried pipeline during external exca-

cracking can occur in almost any acidic environment

where hydrogen reduction is the cathodic reaction.

Increasing the strength and hardness levels of carbon

steel, high - strength low - alloy steels, and martensitic

stainless steels often increases susceptibility to this form

of cracking.

Carbon steels and other ferritic steels are the most

commonly used metals in oilﬁ eld environments, and the

Figure 5.50 Stress corrosion cracking underneath insulation

on a stainless steel condensate line. Photo courtesy of NACE

Basic Corrosion Course, reproduced with permission.

Figure 5.51 Multiple branching cracks typical of many stress

corrosion cracking failures.

Figure 5.52 Clustered “ colonies ” of stress corrosion cracks

on the outside of a carbon steel pipeline.

Figure 5.53 Small cracks joining together and intersecting

circumferential cracks on the exterior of a pipeline.

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FORMS OF CORROSION 101

determine the causes of cracking, for example, in pipe-

line steels where the pH of the surface moisture may

inﬂ uence whether cracking is intergranular or trans-

granular.

Figure 5.55 shows the transgranular nature

of cracks in the pipeline steel shown in Figures 5.53 and

5.54 . While this analysis has proven useful in analyzing

the causes of SCC in buried pipelines, many cracks will

change mode during the crack progression.

SCC is controlled by avoiding metal - environment

combinations that cause this problem. Additional

methods of SCC control include various methods of

stress relief, for example, post - weld heat treatment, pro-

tective coatings, corrosion inhibitors, and cathodic pro-

tection. Much of this control, for example, in pipelines,

is devoted to avoiding the formation of stress risers,

small defects on metal surfaces that serve as initiation

sites for SCC which, once started, may be difﬁ cult to

control.

Caustic Embrittlement Caustic embrittlement is one

of the ﬁ rst forms of environmental cracking or SCC to

receive widespread industrial attention. Boiler water is

treated to a pH known to reduce corrosion rates (typi-

cally about pH = 8 – 9) by treatment with sodium hydrox-

ide. If water evaporation produces higher pH ﬂ uids, for

example, in crevices or at points where tubes meet

restraints such as headers or bafﬂ es, the pH can increase

to levels as high as 14, and this can cause intergranular

cracking of carbon steels. Caustic cracking is controlled

by the use of buffers, which prevent the buildup of high

pHs, and by the substitution of ammonium hydroxide

for sodium hydroxide. At high temperatures the

ammonia evaporates, which deprives the hydroxide

(OH

−

) ions of the necessary cation to balance electrical

charge and prevents the buildup of excessive pHs.

The

principals of boiler water treatment were developed in

the 1920s by the U.S. Bureau of Mines, and recent

advances have come from a variety of companies that

specialize in boiler water treatment chemicals. Most oil-

ﬁ eld operators rely on guidance from these specialized

water treatment suppliers.

HE and H

S - Related Cracking

The small size of hydrogen atoms means that hydrogen

can readily dissolve in most metals. The dissolution of

hydrogen into metals comes from two common sources:

the reduction of hydrogen ions at cathodes in electro-

chemical cells due to corrosion or electroplating and the

entry of hydrogen into metals from environments having

hydrogen - entry promoters such as H

S and cyanides.

These environments produce small amounts of mona-

tomic hydrogen which usually combine to form molecu-

lar (diatomic) hydrogen molecules, which are too large

Figure 5.54 Typical cross section of secondary cracks

showing mid - wall bifurcation.

Figure 5.55 Transgranular SCC in pipeline steel.

100 μm

Mag. Approx. ×150

vation and examination. Cracks, either internal or exter-

nal, will often grow together until they reach a critical

ﬂ aw size that may lead to ﬁ nal rupture. This is shown in

Figure 5.53 , where small cracks have joined together

and a circumferential crack has grown around a

pipeline.

Cracks often branch as they progress into the metal.

There are a number of reasons for this branching, which

is shown in Figure 5.54 for the same pipeline that is

shown in Figure 5.53 . Note how the crack splits at

approximately the mid - wall location in the pipeline and

how the outside surface is generally roughened, even

though only one crack seems to have started at the

surface shown in this picture.

SCC can progress in an intergranular (between the

crystals) or a transgranular (across the crystals) manner.

This is one means that failure analysts have used to

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102 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

some of which invariably dissolves into the steel. The

standard way of compensating for this inevitable intro-

duction of hydrogen into the metal substrate is to use

an elevated - temperature bake - out procedure of several

hours, depending on metal thickness, at temperatures

around 175 – 205 ° C (350 – 400 ° F).

Higher - strength steels are considered to be more sus-

ceptible than lower - strength alloys, and work hardening

seems to be preferable to heat treatment, for example,

in high - strength cables.

Concerns for HE are the

reasons that very high - strength wire, used in downhole

wireline applications, must be allowed to outgas for

days between downhole trips. Many authorities con-

sider the highly cold - worked metals used in these wires

to be less susceptible to hydrogen effects than thicker

metals, usually heat - treated for strength, at the same

strength (or hardness) levels. The presence of multiple

defects, primarily dislocations, is thought to serve to

minimize the accumulation of hydrogen in any one loca-

tion and to minimize formation of subsurface molecular

(diatomic) hydrogen considered to be associated with

HE.

Hydrogen charging, the introduction of monatomic

hydrogen into metals, can come from the breakdown of

water at elevated temperatures in welding processes.

This is the reason for protective, water - impermeable

coatings on most welding rod.

Charging can also occur on cathodes at defects expos-

ing steel underneath anodic protective coatings, for

example, zinc - plating. This is the reason that galvaniz-

ing (zinc coatings) is not allowed on high - strength

fasteners.

HE is considered to be a relatively low - temperature

phenomenon, and most failures seem to occur at tem-

peratures below 100 ° C (212 ° F). Prolonged exposure to

high temperatures can have counteracting effects. More

hydrogen may be generated on metal surfaces due to

accelerated corrosion or other chemical reactions, but

atomic diffusion and subsequent outgassing is also

enhanced.

Hydrogen Stress Cracking ( HSC ) This is a term used

in NACE RP0176/ISO 15156 to describe cracking in a

metal due to the presence of hydrogen in a metal along

with residual or applied tensile stresses.

It is used to describe cracking in metals that are not

sensitive to sulﬁ de stress cracking (SSC) but which are

embrittled when galvanically coupled as cathodes to

corroding anodes. The term galvanically induced HSC

is applied to this mechanism of cracking. The discussion

above on HE of galvanized bolts would be considered

to involve HSC by many oilﬁ eld authorities, although

this is not the terminology used outside the oilﬁ eld

industry.

to dissolve into metals. In the short time that mona-

tomic hydrogen atoms exist on surfaces, small amounts

of monatomic (nascent) hydrogen dissolve into the

metal substrate and follow diffusion paths from loca-

tions of high concentrations (the source surface) to

regions of lower concentration (the metal interior and

usually the opposite surface). This dissolution is usually

at interstitial sites (between the atomic locations of the

metal). Several forms of hydrogen degradation are asso-

ciated with the recombination of internal hydrogen

atoms to form hydrogen molecules, which are too large

for interstitial diffusion through the metal lattice. Other

forms of HE are due to mechanisms that are not pres-

ently understood and are the subject of research

controversies.

HE and other hydrogen - related problems can occur

in any H

S - containing environment and in electroplated

metals even in the absence of environmental hydrogen.

Another source of monatomic hydrogen is welding, and

improper welding procedures can introduce monatomic

hydrogen into metals.

There are a wide variety of hydrogen and H

S - related

cracking phenomena encountered in upstream environ-

ments. Many of the classiﬁ cations discussed below

follow terminology in NACE MR0175/ISO 15156,

which emphasizes the choice of materials for use in H

environments.

33,62,65

HE Small quantities of hydrogen inside certain metals

make them susceptible to subcritical crack growth under

stress. Metals can also have major decreases yield

strength and undergo brittle failures in hydrogen -

containing environments. Both processes are commonly

called HE. Oilﬁ eld metals with HE problems include

high - strength steels, aluminum, and titanium, although

most problems occur in high - strength steels. The exact

mechanisms of HE in steels have not been established,

and no iron hydrides have ever been reported, but

brittle intermetallic hydrides have been found in tita-

nium and other hydrogen - embrittled metals. Ferritic

steels, for example, carbon steels and low - alloy steels,

are considered to be more susceptible than austenitic

alloys.

The initial 1975 version of NACE RP0175 limited

S exposures to metals having a hardness of HRC22

or less which, depending on the size and shape of the

metal, correlates to yield strengths of approximately

80 ksi (550 MPa).

The sudden propagation of brittle fractures may be

time delayed and occur months, even years, after expo-

sure to hydrogen. This is a characteristic failure mode

in plated metal components. It is thermodynamically

impossible to electroplate metals such as zinc or chro-

mium onto steel without also generating hydrogen gas,

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FORMS OF CORROSION 103

they are used for determining environments where

HIC - resistant steels are necessary. Many operators

assume that virtually all oil ﬁ elds will eventually sour

and require H

S - resistant materials, but some gas ﬁ elds

are depleted so quickly that this may not be

necessary.

HIC susceptibility has been shown to be greatest in

high - sulfur steels and to be less likely in modern, low -

sulfur steels. However, in low - sulfur steels other consid-

erations, such as the presence of ferrite - pearlite banding,

also promote HIC. Condensate waters in gas systems

lack the mineral buffering available from formation

waters that accompany crude oil. For this reason, gas

Hydrogen - Induced Cracking ( HIC ) HIC, also known

as stepwise cracking, in carbon and low - alloy steels is

caused by atomic hydrogen diffusing into the steel and

forming hydrogen molecules internally at trap sites,

such as vacancies in the metal, grain boundaries, dislo-

cations, and second - phase particle boundaries, to

include inclusions.

70 – 73

HIC is a form of hydrogen -

related cracking that does not require tensile stresses,

either applied or residual, to produce cracking. This

lack of applied stresses is the main differentiation

between HIC and SCC. HIC is a major concern in the

S environments covered by NACE SP0176/ISO

15156 and in other environments, for example, strong

mineral acids (H

S is a weak mineral acid), known to

produce HE.

Figure 5.56 shows HIC in pipeline steel.

Note how

the cracks form parallel to the rolling direction of the

steel and how they tend to be planar — relatively long

and ﬂ at. Modern pipeline steels are treated with calcium

that reduces the total volume of inclusions and tends to

form hard, rounded inclusions which should present

fewer locations for HIC to form.

Figure 5.57 shows environmental conditions where

HIC is considered important for pipeline steels. The

combinations of carbon dioxide (CO

) and H

S in the

environment shown in this ﬁ gure are approximate, but

Figure 5.56 Hydrogen - induced cracking (HIC) in pipeline

steel.

Figure 5.57 Environmental conditions where HIC is important.

MODEST RISK OF HIC

Copper additions may be

effective

MODEST RISK

OF HIC

Increasing level of S

in the pipeline steel

SEVERE

RISK OF HIC

VERY SEVERE

RISK OF HIC

SEVERE RISK OF HIC

HIC

DOES

NOT

OCCUR

HIC

DOES

NOT

OCCUR

0.5

0.1 1 5

pH > 4.5 Oil Pipelines

pH < 4.5 Gas Pipelines

PP Carbon Dioxide (bar)PP Carbon Dioxide (bar)

Partial Pressure of Hydrogen Sulfide (bar)

110

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104 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

way as the smaller cracks. Hydrogen diffuses into the

steel and then gets trapped at locations where migration

is hindered, and the recombination of thermodynami-

cally unstable monatomic hydrogen to thermodynami-

cally stable diatomic hydrogen molecules is most likely

to happen. The most likely sites for this to happen are

near large ceramic inclusions (impurities) within the

steel. Figure 5.59 shows schematically how these inclu-

sions are likely to be arranged in steel plate and other

thick sections. As a result of the hot rolling process,

ceramic inclusions near plate surfaces are more likely

to be broken up and become smaller. Near the center

of plate steel there has been less plastic deformation,

and both the steel crystals and the inclusion particles

tend to be larger. As hydrogen migrates through the

steel, the chances for monatomic atoms to meet and

become trapped are greater near the larger inclusions

near the center of the plate. This is the reason why plate

steel, especially the relatively low - quality, inexpensive

plate steel used for storage tanks and similar structures,

is more likely to produce hydrogen blistering. Many of

these blisters form near the center of plate steel and can

systems are likely to have acidic environments and are

usually more corrosive than crude oil systems. If the gas

contains H

S, then the gas systems will require H

S -

resistant materials of construction.

SSC This common form of environmental cracking

(SSC) is considered to be a form of HIC. It requires a

residual or applied tensile stress and the combined pres-

ence of water and H

S, which indicates that some orga-

nizations would consider this to be a form of SCC,

although this is not the interpretation in NACE RP0175/

ISO 15156.

Susceptible alloys, especially steels, react with H

forming metallic sulﬁ des and monatomic nascent hydro-

gen. This monatomic hydrogen forms as a reduction

reaction product and diffuses into the metal matrix,

causing internal cracking. High nickel contents, which

limit surface corrosion and also cause the microstruc-

ture to have austenite, a more resistant phase than the

ferrite common in carbon and low - alloy steels, greatly

improve the resistance to SSC. SSC is worst around

80 ° C ± 20 ° C (176 ° F ± 36 ° F). Above this temperature,

hydrogen is more mobile and is likely to diffuse from

the metal before forming internal defects leading to

cracking. The term SSC is applied to cracking in liquid

water environments.

Stress - Oriented Hydrogen - Induced Cracking ( SOHIC )

Applying stresses to steel with HIC can result in inter-

connecting cracks between the hydrogen - induced

cracks. The result is relatively long cracks in the through -

thickness direction of a structure, for example, a pipe-

line.

This is shown in Figure 5.58 , where the small

hydrogen - induced cracks have been joined by connect-

ing cracks, resulting in considerably less resistance to

applied stresses. The linking of hydrogen - induced

cracks is referred to as SOHIC or as stepwise

cracking.

Susceptibility to SOHIC can be complicated, as low -

sulfur modern steels, thought to be resistant to this form

of damage, have been found to have additional prob-

lems associated with the metallurgical treatments of

newer steels used in repair and new construction. The

HIC shown in Figure 5.56 could lead to SOHIC in the

presence of applied stresses, for example, the hoop

stresses found in pressurized pipelines.

Hydrogen Blistering The small cracks discussed above

in sections on HIC, SSC, and SOHIC are sometimes

referred to as small blisters. Another use of the term

hydrogen blistering is for hydrogen gas blisters that

form inside structures that become so large that their

deformations can be seen macroscopically as surface

deformations. These larger blisters form in the same

Figure 5.58 Stress - oriented hydrogen - induced cracking

(SOHIC).

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FORMS OF CORROSION 105

steels are not immune to this problem, but it is much

less common in the highly processed and reﬁ ned low -

alloy steels used for most process pressure vessels.

Typical treatments for hydrogen blistering depend

on the application. For storage tank bottoms, which are

loaded in compression, it is fairly common to locate the

boundaries of the blisters with ultrasonic inspection.

Then, at a predetermined distance from the boundaries,

a plate is welded over the blister, and the blister is left

in place. Other organizations carefully pierce the blister

using non - sparking drills to relieve the pressure before

welding a patch over the surface. Similar procedures are

sometimes used on tank walls, and monitoring the

growth of blisters has been reported.

In pressure vessels, it is common to grind the blisters

out of the metal. This grinding to a predetermined dis-

tance beyond the detected limits of the blister is intended

to remove both the overlying “ blister ” steel, which

serves no structural purpose, and also to eliminate any

microcracking that has not been detected by the inspec-

tion process. The remaining wall thickness is then deter-

mined. While welding repairs are sometimes performed

to replace the missing metal, it is more common to

determine the maximum allowable operating pressure

of the equipment and to downgrade the service if neces-

sary. If reductions in operating pressure are inadvisable,

then external repairs (sleeves, clamps, etc.) are used to

increase the effective wall thickness in the area of

concern. The same downgrading or external reinforce-

ment procedures are used for pipelines, but it is seldom

feasible to grind out the blisters, especially if they are

internal.

The best way to avoid hydrogen blistering is by the

use of higher - quality, lower - inclusion steel, and this is

the reason that most hydrogen blisters are encountered

in above - ground storage tanks and other large struc-

tures where the economics of construction from higher -

grade steel are not justiﬁ ed and inspection and repair

of occasional blisters is an accepted alternative.

Hydrogen Attack

High - temperature hydrogen environments can cause

hydrogen to diffuse into the metal and react with the

carbon in the iron carbides (cementite) in steel. The

resulting formation of gaseous methane can cause blis-

tering similar to HIC or hydrogen blistering. This form

of attack, while a concern in reﬁ ning, is seldom a concern

in upstream operations.

Liquid Metal Embrittlement ( LME )

Liquid metals can attack solid metals and produce

fractures similar to those found in other forms of

become several inches (centimeters) in horizontal

dimension.

Common locations for hydrogen blisters include the

bottoms of above - ground storage tanks, where acidic

waters can concentrate, and the walls of tanks and

process equipment. Figure 5.60 shows blisters in the

wall of a CO

scrubber, and Figure 5.61 shows blisters

in a crude oil pipeline that collected sour crude for

many years.

The quality of steel determines the resistance to

hydrogen cracks and blisters of all types. Pressure vessel

Figure 5.59 Schematic representation of ceramic inclusions

(dark marks) and hydrogen blister formation in plate steel.

Figure 5.60 Hydrogen blister formed on wall plate of a CO

scrubbing tower.

Figure 5.61 Hydrogen blister on the inside of a crude oil

pipeline.

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106 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

5.62 assume that the cyclic stresses are the same on each

repetition. This is approximately true for many rotating

shafts, sucker rods, and so on, but it is far from true for

wave loading on offshore structures and for many other

oilﬁ eld applications.

Fatigue cracks, like many other forms of environ-

mental cracks, often start at stress raisers such as corro-

sion pits, machined notches, or surface scratches. Once

corrosion starts, localized corrosion fatigue cracks

develop occluded cell concentration differences com-

pared to the external environment, and the interaction

between chemistry and mechanical loading becomes

very complicated and virtually impossible to predict or

model. It thus becomes important to monitor likely

fatigue sites for crack initiation and propagation in

attempts to detect damage and correct the situation

before fracture occurs.

Figure 5.63 shows a typical corrosion fatigue fracture

surface. The origin of the fracture surface is at the upper

center of the picture and the crack grew radially from

this origin, leaving indications of the crack progression,

called beach marks or clamshell markings, which are

indications that the equipment tarnished to different

levels, possibly due to intermittent operation of the

equipment or changes in the cyclic loading level. Once

the crack reached a critical ﬂ aw size, the part broke,

leaving a shiny fracture surface at the bottom of the

picture. It is apparent that other surface defects started

additional cracks in the lower right of this picture. The

appearance of beach marks is a characteristic feature of

many corrosion fatigue failures. Note how the fatigue

fracture spread over most of the metal surface before

the ﬁ nal tensile overload indicated by the shiny surfaces

at the bottom of the picture.

Another corrosion fatigue fracture surface is shown

in Figure 5.64 . This oilﬁ eld sucker rod has a clearly

deﬁ ned origin, and beach marks indicate how the frac-

ture spread from this origin due to cyclic loading. After

environmental attack. Both intergranular and trans-

granular attack is known to occur. This form of attack

can happen during welding and other processes, but

careful removal of low - melting coatings, for example,

zinc coatings, prior to welding normally solves this

problem.

Most concerns with LME in upstream operations are

offshore and relate to safety in ﬁ res and to cracking of

brazed aluminum heat exchangers, which are used in

cooling natural gas to reduce the volume before inject-

ing it into a pipeline for transmission to shore.

Many operators have banned the use of aluminum

or galvanizing for offshore platform structures, for

example, hand rails and ladders, because of a concern

that these liquid metals could cause embrittlement of

carbon steels and stainless steel if the lower - melting zinc

or aluminum were to melt in a ﬁ re. The counter argu-

ment to this thinking is that by the time temperatures

have reached the melting point of these metals, it is too

late for the equipment concerned. No ﬁ rm guidelines

on this question exist, and many operators are now

using aluminum, for example, for decks, ladders, hand-

rails, and helidecks. The thin layers of zinc on galva-

nized structures are not considered adequate corrosion

protection for most offshore structural members.

Galvanizing is commonly used for corrosion resistance

in bolts and similar fasteners, often with an overlay of

an organic coating for ease of disconnect. In some loca-

tions, cadmium, which is banned for toxicity reasons by

some authorities, is the preferred anodic coating mate-

rial for fasteners, although it is seldom applied to larger

components.

Brazed aluminum heat exchangers are used for off-

shore cooling of natural gas, because of their weight

savings over other metals. To avoid cracking by liquid

mercury, which is eventually found in virtually all

natural gas formations, it is standard practice to place

mercury removal processes in the gas treatment stream

prior to the brazed aluminum heat exchangers used for

cryogenic cooling.

Corrosion Fatigue

Corrosive environments lower the fatigue life of many

oilﬁ eld components and structures. This is shown sche-

matically in Figure 5.62 , which shows the elimination of

the fatigue or endurance limit due to the presence of a

corrosive environment. It is possible to cyclically stress

a component so quickly that the effects of corrosion are

minimal, and it is also possible to introduce components

so corrosive that they corrode to failure before the

effects of cyclic stresses become signiﬁ cant. It is very

hard to predict the cumulative effects of corrosion and

fatigue. The simplistic ideas shown in Figures 4.16 and

Figure 5.62 The reduction in fatigue resistance due to a cor-

rosive environment.

Cycles to Failure

Endurance Limit

Noncorrosive Service

Corrosive Service

Breaking Stress →

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FORMS OF CORROSION 107

detect and monitor fatigue cracking is an important part

of corrosion fatigue control. Methods of preventing cor-

rosion, such as the use of more corrosion - resistant

alloys, corrosion inhibitors, and cathodic protection are

also helpful.

OTHER FORMS OF CORROSION IMPORTANT

TO OILFIELD OPERATIONS

There is no universally accepted terminology for corro-

sion, and the oil and gas industry has adopted a number

of terms for corrosion that frequently overlap with the

terms discussed in previous sections of this chapter. This

section discusses some forms of corrosion commonly

discussed in the oilﬁ eld literature and some other forms

of corrosion likely to be encountered in oil and gas

production.

Oxygen Attack

Oxygen attack normally refers to pitting corrosion due

to the presence of dissolved oxygen in production ﬂ uids.

This seldom occurs in downhole environments, and

when it does, it is usually due to inadequate treatment

of injection waters that were exposed to oxygen -

containing air in topside processing and storage. The

most common treatments for oxygen attack are mechan-

ical deaeration treatment of the water plus the use of

oxygen scavengers.

Sweet Corrosion

This term, which is becoming outdated, refers to corro-

sion in environments where the corrosion is due to the

presence of dissolved CO

. Most production ﬂ uid cor-

rosion, especially in natural gas production, is due to

. The most common treatments for sweet or

corrosion is the use of corrosion inhibitors. These

Figure 5.63 Beach marks on the surface of a corrosion -

fatigue surface from a marine propeller.

Beach Marks

Origin

Figure 5.64 Corrosion fatigue and shear lip formation on a

sucker rod fracture surface. Photo courtesy of NACE Basic

Corrosion Course, reproduced with permission.

Figure 5.65 Schematic showing the side view of a typical

corrosion fatigue rod failure.

Origin

Polished

Surface

Shear

Lip

the crack progressed across approximately one - half

of the rod, the surface became rough, due to the fact

that the crack remained open during compression

strokes and did not polish the surface as much as near

the origin. Once the crack reached a critical ﬂ aw size,

the rod broke, forming shear lips at approximately 45 °

to the fracture surface. The shadows formed by the

shear lips on the lower left and right of the picture

appear as dark triangles in Figure 5.64 . The bottom

center of the picture shows where the metal pulled apart

by shear, but the shear lip is down and away from the

viewer. Most overload failures, to include fatigue fail-

ures, will form shear lips on the ﬁ nal fracture surface.

A side view of this phenomenon is shown in Figure 5.65 .

Most fatigue failures progress for signiﬁ cant dis-

tances before ﬁ nal overload failures, and inspection to

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108 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

inhibitor can be maintained in the water phase at the

bottom of the line, it is difﬁ cult to apply this inhibitor

to the top of the line. Much effort concentrates on

developments in modeling of where TOL corrosion is

likely to occur and how delivery of corrosion inhibitors

can be maintained. Research efforts include modeling

the temperature proﬁ les of subsea pipelines. This is

shown in Figure 5.70 , which shows the water dropout

proﬁ le for a subsea pipeline.

Efforts to apply corrosion inhibitor to the inside top

of multiphase pipelines include periodic pigging with

Figure 5.66 Mesa corrosion of a 9 - chrome sucker rod.

Figure 5.67 Mesa corrosion on carbon steel plate.

Figure 5.68 Mesa corrosion at a threaded connection on

downhole tubing.

inhibitors become ineffective as the downhole tempera-

tures and pressures increase.

Sour Corrosion

The term sour corrosion refers to corrosion that occurs

in production ﬂ uids due to the presence of H

S. H

S is

a weak mineral acid, and most corrosion reactions are

relatively minor in these environments.

Figure 3.3 compares the effects of oxygen, CO

, and

S on corrosion. It is obvious that H

S is the least cor-

rosive of the three gases. Most problems with H

S are

associated with hydrogen - related cracking and, while

the environments associated with H

S cracking are con-

sidered to be “ sour, ” the cracking is seldom referred to

as sour corrosion.

Mesa Corrosion

Mesa corrosion refers to corrosion in CO

environments

that produce relatively ﬂ at surfaces where the metal is

protected by carbonate ﬁ lms, usually siderite (FeCO

This corrosion is characterized as fairly deep pits in the

form of sharp - edged holes that are considered to look

like the ﬂ at - topped “ mesa ” (table topped) mountains

found in the southwestern United States.

5,77

Mesa cor-

rosion is shown in Figures 5.66 – 5.68 . All three pictures

show relatively ﬂ at surfaces with localized pitting where

the partially protective carbonate ﬁ lms break down.

Most control of CO

(sweet) corrosion is by the use of

corrosion inhibitors.

Top - of - the - Line (TOL) Corrosion

The increased use of multiphase offshore pipelines and

gathering lines has led to interest in top - of - the - line cor-

rosion. This form of corrosion is shown schematically in

Figure 5.69 . Condensate, containing water high in CO

and possibly acetic acid or other organic acids, aggres-

sively attacks the top of horizontal pipelines where no

corrosion inhibitor is present.

This condensation happens as the pipeline cools with

distance from the compressor station. While corrosion

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