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Chapter 7 Corrosion

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Chapter 7: Corrosion 
 
 
Chapter 7: Corrosion 
Oil Field Chemicals Training Manual 
7-2 
Property of Nalco Energy Services 
Confidential & Proprietary – DO NOT DUPLICATE 
7.1 Problem 
Corrosion is possibly the most important and costly cause of problems encountered in oil 
production systems. Corrosion requires special consideration during the design and fabrication of 
production equipment and the operation of the process. 
 
Corrosion detection, monitoring, and control are paramount considerations when seeking 
maximum equipment life, minimum cost, and maximum safety. 
 
Corrosion can occur anywhere in the production system — from well bottom to final transfer of 
produced gas or oil to the refinery. 
 
To control corrosion, you need to understand the nature and mechanisms by which it occurs. 
 
7.2 Theory 
Corrosion is the deterioration of a substance, usually a metal, due to a reaction with its 
environment, so “Why do metals corrode?” 
 
Metals do not normally exist in nature as pure substances. They occur combined with other 
elements as ores. Most ores are oxides where the metal element is combined with oxygen. For 
example, the most common form of iron ore is hematite, which is essentially a mixture of iron 
oxides of the type Fe2O3. Hematite looks like rust and is in fact one component of rust. 
 
Iron ore is converted to steel by the addition of energy. This same energy is expended when the 
steel reconverts back to rust as it corrodes. 
 
This principle applies to most corrosion processes. The refining and corrosion cycle is a process 
whereby energy is added during refining the ore to pure metal and expended as the metal 
corrodes back to its original ore. This energy is the driving force for corrosion. 
 
All of the corrosion problems that occur in oil and gas production systems are due to the 
presence of water, in either large amounts or just traces. This corrosion process is known as the 
“wet corrosion process” and is electrochemical in nature. 
 
7.2.1 Corrosion Mechanisms 
As stated above, wet corrosion is an electrochemical process. As corrosion occurs, an electrical 
current passes through the corroding metal. 
 
For current to flow, there has to be a voltage source and a completed electrical circuit. 
 
 
Chapter 7: Corrosion 
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7-3 
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7.2.1.1 Voltage Source 
 
The source of voltage is the energy stored during the original metal refining process. Different 
metals require different amounts of energy when being refined. This in turn gives them differing 
tendencies to corrode. This energy can be measured and is shown in the Galvanic or 
Electrochemical series, which is a progressive comparison of the electromotive force (EMF) of 
each metal when immersed in water. The electromotive force is the voltage required to lose or 
gain electrons (or to be oxidized/reduced). Potential values of EMF are a function of both the 
metal and the chemical and physical characteristics of the water. Absolute values also depend 
upon temperature, velocity, and other factors, but for most purposes, it is sufficient to compare 
voltages in water under similar conditions. 
 
This principle is shown in the following short table of metal potential comparisons. 
 
 Metal Volts* 
 
Magnesuim 
 
(Mg) 
 
-2.37 
Aluminum (Al) -1.66 
Zinc (Zn) -0.76 
Iron (Fe) -0.44 
Copper (Ca) +0.34 to +0.52 
Most Energy 
Required for 
Refining 
 
Silver (Ag) +0.80 
Most Eager to 
Corrode 
 
Least Energy 
Required for 
Refining 
Gold (Au) +1.50 to +1.68 Least Eager to 
Corrode 
 
* With respect to NHE (normal hydrogen electrode) 
 
7.2.1.2 The Electrical Circuit 
 
In addition to a voltage source, there also needs to be a completed electrical circuit consisting of 
an anode, a cathode, and an electrolyte. 
 
The Anode 
 
The anode is the part of the metal surface that corrodes — that is, the metal dissolves in the 
electrolyte. 
 
The reaction for iron would be: 
 
Fe 
Iron Atom 
Fe++ 
Iron Ion 
+ 2e- 
Electrons 
 
This loss of electrons is called oxidation. The iron ion goes into solution, and the two electrons 
are left behind in the metal. 
 
Chapter 7: Corrosion 
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The Cathode 
 
The cathode is that portion of the metal surface that does not dissolve. It is the site where 
chemical reactions that absorb the electrons generated at the anode. 
 
The electrons generated as the iron dissolves at the anode and travel through the metal to the 
cathodic surface area. There are two primary reactions possible at the cathode, the “hydrogen 
evolution reaction” and the “oxygen absorption reaction.” Other reactions are possible but are 
encountered less often. 
 
In the hydrogen evolution reaction, the electrons combine on the surface of the metals with 
hydrogen ions in the electrolyte to form hydrogen molecules, which escape as gas bubbles. This 
consumption of electrons is called a reduction reaction. It should be noted that some hydrogen 
atoms are left uncoupled and diffuse into the metal, which causes embrittlement or blistering. 
(See 11.2.4.2.) 
 
The reaction would typically be: 
 
2H+ 
Hydrogen 
Ions 
+ 2e- 
Electrons 
H2 
Hydrogen 
Gas 
 
Hydrogen ions exist to a small extent in water and are plentiful in acidic environments. Hence, 
this reaction is favored in acid solution and oxygen-free environments. 
 
The complete corrosion cell is represented by: 
 
Fe Fe2+ + 2e- Anodic Reaction 
 
2H+ + 2e- H2 
 
Cathodic Reaction 
 
This becomes overall: 
 
Fe 
Iron 
Ion 
+ 2H+ 
Hydrogen 
Ion 
 Fe2 
Iron 
+ H2 
Hydrogen 
Gas 
 
Iron metal goes into solution (corrodes), hydrogen gas is generated. 
 
In the oxygen absorption reaction, the electrons at the cathode combine with oxygen and water to 
form hydroxyl ions. 
 
 
Chapter 7: Corrosion 
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7-5 
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The reactions would typically be: 
 
O2 
Oxygen 
Atom 
+ 2H2O 
Water 
+ 4e- 
Electrons
 4OH- 
Hydroxyl 
Ions 
 
This reaction added to: 
 
2Fe 2Fe2+ + 4e- 
 
 
becomes overall: 
 
2Fe 
Iron 
Atom 
+ O2 
Oxygen 
+ 2H2O 
Water 
 2Fe2+ 
Iron 
Ion 
+ 4OH- 
Hydroxyl 
Ions 
 2Fe(OH)2 
Ferrous 
Hydroxide 
 
The iron ion and hydroxyl ions combine to form ferrous hydroxide, which is rapidly oxidized to 
ferric hydroxide. 
 
4Fe(OH)2 + O2 + 2H2O 4Fe(OH)3 
 
During rusting in the atmosphere, ferric hydroxide dehydrates to form red brown iron rust Fe2O3. 
 
4Fe(OH)3 2Fe2O3 + 6H2O 
 
 
The oxygen absorption reaction occurs in fresh water, seawater, salt solutions, and alkaline or 
basic media, which are fully oxygenated. 
 
Since oxygen is not naturally present in oil and gas production, the hydrogen evolution reaction 
is most commonly encountered. If oxygen is allowed to leak into the production system, then the 
oxygen absorption reaction will take place. 
 
For corrosion to occur, there must be a formation of ions and release of electrons at an anodic 
surface where oxidation or corrosion of the metal occurs. There also must be a simultaneous 
acceptance at the cathodic surface of the electrons that were generated at the anode. 
 
The anodic and cathodic reactions occur at equivalent rates. Electrons flow from the anode to the 
cathode through the metal. 
 
Convention says that the electrical current flows in the opposite direction to the electron flow. 
Thus, the electrical current flows from cathode to anode within the metal. 
 
The metal betweenanode and cathode is an electrical conductor. 
 
Chapter 7: Corrosion 
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The Electrolyte 
 
The above reactions will only occur if the metal surface is covered by an electrically conductive 
solution. This solution is called an electrolyte. 
 
Water is an electrolyte whose electrical conductivity increases as the amount of dissolved salts or 
ions increase. The electrolyte conducts current from the anode to the cathode. The current then 
flows to the anode through the metal, thus completing the circuit. 
 
The combination of anode, cathode, and electrolyte is called a corrosion cell. 
 
 
Fe+2 Fe+2
2e-2e
-
2H+ 2H+
H2 H2
Anode
Cathode
Electrolyte
Figure 1. 
 
Figure 1 illustrates a typical corrosion cell. Metal atoms do not necessarily dissolve at a single 
point on the metal surface and cathodic areas are not restricted to one area on the metal surface. 
 
These processes may be limited to localized areas resulting in localized corrosion known as 
“pitting.” If the reactions occur randomly over the surface of the metal the result is general 
corrosion. 
 
The reason why some areas act as anodes and some as cathodes is not fully understood. In most 
cases it is assumed that it is due to inhomogeneities on the metal surface, or in the electrolyte or a 
combination of both. 
 
 
Chapter 7: Corrosion 
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7-7 
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7.2.2 The Corrosion of Steel 
Most metals are not homogeneous; they contain inclusions, precipitates, and different phases. 
When such a metal is placed in an electrolyte, potential differences exist between these different 
areas, resulting in corrosion cells on the metal surfaces. 
 
For example, steel, the most widely used metal in the oil and gas production processes, is not a 
pure substance but is composed essentially of an alloy of iron and a number of trace elements 
such as carbon. Pure iron is a relatively weak, ductile metal. If it is alloyed with small amounts 
of carbon (0.2% to 1.0%), a much stronger metal is formed. The product of the iron and carbon is 
pure iron (Fe□) and iron carbide (Fe3C). 
 
Iron carbide is distributed within the steel as microscopic grains. These iron carbide grains, 
which appear as islands on the metal surface, have a lower tendency to corrode than the pure 
iron. The iron carbide and pure iron are in intimate contact, which allows electron flow between 
them. 
 
When the steel is placed in an electrolyte, the electrical circuit is completed, and current flows 
between the millions of micro cells on the metal surface. The iron acts as the anode and corrodes, 
while the iron carbide acts as the cathode. 
 
ANODE CATHODE
Fe3C
Fe
Fe2+
Fe2+
e-
H+ H+
H2 H2 H2 H2 H2
Figure 2. 
 
This is illustrated in Figure 2, where iron goes into solution at the pure iron anode and the 
electrons that are left behind migrate to the iron carbide cathode. As corrosion products 
accumulate, the potential distribution on the metal surface may change, shifting the anodic areas. 
 
 
Chapter 7: Corrosion 
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Other inhomogeneities in metals can be responsible for corrosion cells. Intergranular attack is 
caused and accelerated by potential differences between the grain and grain boundaries. Casting 
and welding can cause concentration differences in metal compositions from point to point, 
which gives a rise to potential differences between areas. 
 
-
+
-+
-
+-
+
-+
-
+
METAL
Figure 3. 
 
Metal inhomogeneities cause potential differences on metal surfaces. These differences are one 
of the primary causes of corrosion. Figure 3 illustrates this principle. 
 
Any metal surface is a composite of electrodes electrically short-circuited through the body of 
the metal itself. So long as the metal remains completely free of water, localized current does not 
flow and corrosion will not occur. 
 
 
Chapter 7: Corrosion 
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7.2.3 Polarization 
As noted earlier, hydroxyl ions (OH-), hydrogen gas (H2), or both are produced at the cathode as 
a result of the corrosion reactions. If these chemical reaction products remain at the cathode, they 
stifle the cathodic reaction. Consequently, the anodic reaction also slows down since it cannot 
proceed at a higher rate than electrons can be consumed at the cathodic surfaces. 
Cathodic polarization acts as a barrier to current flow, so the rate of corrosion attack is decreased 
or stopped completely. 
 
This is illustrated in Figure 4. 
 
Fe2+ Fe2+ Fe2+
Fe2+
Fe2+ Fe2+
Fe2+
Fe2+
e-e- e-
H+ H+ H+
H2 H2 H2
Gas Bubbles
H2O H2O
O2O2
OH- OH- OH-
e-e- e-
Fe
FeFe
Fe
Fe Fe
Fe
Fe
Fe
Fe
Fe
(a.)
(b.)
 
Figure 4: 
(a) Polarization of the cathodic area at lower pH values by hydrogen molecules. 
(b) Polarization of the cathodic area by an alkaline film highly concentrated in hydroxyl ions. 
 
 
Chapter 7: Corrosion 
Oil Field Chemicals Training Manual 
7-10 
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7.2.4 Factors Influencing Corrosion Mechanisms 
Corrosion principles have been generally discussed using steel as an example. Corrosion 
mechanisms can be greatly influenced by many factors such as: 
 
„ Electrolyte composition — conductivity, pH, salts 
„ Dissolved gases — oxygen, carbon dioxide, hydrogen sulfide 
„ Physical effects — temperature, pressure, velocity 
 
7.2.4.1 Electrolyte Composition 
 
Conductivity 
 
The electrolyte completes the electrical circuit. The more conductive the electrolyte, the easier 
the current can flow and thus the faster is the corrosion rate. 
 
The amount of metal that dissolves is directly proportional to the flow of current. For example, 
one ampere of current flowing for one year allows approximately 9 kg (19.8 lb.) of iron to 
dissolve. 
 
Distilled water is not very conductive, whereas by contrast seawater is quite conductive and can 
be very corrosive. Here, we are considering conductivity alone. The presence of dissolved gases 
and the pH may make even distilled water corrosive, whereas a saline water containing no 
dissolved gas and at alkaline pH may be almost noncorrosive. Most formation waters produced 
with oil and gas contain high levels of salts and are very conductive. 
 
If all other conditions remain constant, the more conductive the electrolyte the less corrosion 
current is at a given electromotive force. 
 
 
Chapter 7: Corrosion 
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pH 
 
pH is a means for measuring the alkalinity/acidity of water. The pH range is expressed as a scale 
from 0 to 14 and is the negative logarithm of the hydrogen ion concentration. 
 
pH = - Log [H+] 
 
A pH value of 7 is neutral, below pH 7 the water is acidic while above pH 7 the water 
is alkaline. 
 
 
 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 
 
 ACIDIC NEUTRAL ALKALINE 
 
Since pH is a logarithmic function there is a ten-fold difference in concentration between each 
pH level. For example, at pH 5 the concentration of hydrogen ions is ten times that at pH 6. At 
pH 3, the concentration of hydrogen ions is one thousand times that at pH 6. 
 
On exposure of the metalto water, the localized cells function and corrosion commences. 
 
The variations of corrosion rate with pH depend upon the metal and the composition of the 
electrolyte. 
pH
C
or
ro
si
on
 R
at
e
pH
C
or
ro
si
on
 R
at
e
14 14
(c.) (d .)
pH
C
or
ro
si
on
 R
at
e
pH
C
or
ro
si
on
 R
at
e
14 14
(a .) (b .)
0 0
0 0
 
Figure 5: 
(a) Nobel metals (i.e., gold, silver, platinum) 
(b) Metals with amphoteric oxides (i.e., zinc, aluminum and lead) 
(c) Acid soluble metals (i.e., magnesium) 
(d) Iron 
 
Figure 5 shows how the corrosion rate of various metals changes with increasing pH. 
 
Chapter 7: Corrosion 
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The noble metals (gold, silver, platinum, etc.) are relatively unaffected by the pH of water, while 
aluminum, zinc and lead exhibit what is known as “amphoteric characteristics.” In this case, the 
metal forms a protective hydroxide coating at neutral pH. When the pH is acidic or alkaline the 
protective hydroxide dissolves and the metal corrodes. 
 
Metals such as magnesium form protective hydroxide films which dissolve under acidic 
conditions. 
 
The corrosion rate of iron increases as the pH of the water decreases below pH 4. 
 
Between pH 4 and pH 12 a protective hydroxide film provides protection. This protective film 
dissolves below pH 4. At extremely high pHs iron is again attacked, by phenomena known as 
“caustic cracking.” 
 
7.2.4.2 Dissolved Gases 
 
Dissolved oxygen, carbon dioxide and hydrogen sulfide considerably increase the corrosivity of 
water. In fact, most corrosion in oilfield processes is due to dissolved gases. If it were possible to 
exclude these gases pH would be maintained at 7.0 or higher and corrosion in the oil and gas 
production systems would be greatly reduced. 
 
Oxygen 
 
Of the three gases mentioned above, oxygen has the greatest potential for corrosion. 
Dissolved oxygen at very low levels can cause corrosion. Combination with either or 
both the other two gases (H2S or CO2) drastically increases their corrosivity. 
 
Oxygen accelerates corrosion in two ways: 
 
„ As a depolarizer. This means oxygen combines with electrons preventing the 
formation of a hydrogen protective blanket. The energy taken to evolve hydrogen 
gas at the cathode is a major bottleneck in the corrosion reaction causing it to 
slow down or stop completely. When oxygen is present, the corrosion rate is 
limited primarily by the rate at which oxygen can diffuse to the cathode. 
„ As an oxidizer. The oxidation of ferrous ions (Fe++) to ferric ions (Fe+++) increases 
the corrosion rate at pH above 4. This is because ferric hydroxide is insoluble and 
precipitates from solution. The corrosion rate increases as more ferrous ions are 
supplied from the metal to maintain the equilibrium in the solution. If the ferrous 
ions are rapidly oxidized to ferric away from the metal surface then the corrosion 
reaction proceeds very rapidly. If on the other hand the oxidation occurs so 
rapidly that the ferrous ions cannot diffuse away from the metal surface, then 
ferric hydroxide can form on the anode and become protective. 
 
 
Chapter 7: Corrosion 
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Whether the precipitated ferric hydroxide is protective or not depends upon the nature 
of the deposit. If the deposit is adherent, continuous and nonporous then it will be 
protective. This type of deposition is rarely achieved. 
 
The normal corrosion reaction in oxygenated systems is: 
 
4Fe 4Fe++ + 8e- (1) 
4Fe++ 4Fe+++ + 4e- (2) 
4Fe 4Fe+++ + 12e- (3) Overall anode reaction 
3O2 + 6H2O + 12e- 12OH- (4) Overall cathode reaction 
 
Therefore, balancing the electron producing and electron consuming reactions by 
combining (3) and (4): 
 
4Fe + 3O2 + 6H2O 4Fe+++ + 12OH- (5) 
 
and finally: 
 
4Fe+++ + 12OH- 4Fe(OH)3 
 
 
Chloride ions can interfere with the formation of a protective layer and corrosion 
rates will then continue to increase with oxygen concentration. 
 
The amount of oxygen present in water is a function of the pressure in the system, 
temperature and chloride content. Oxygen is less soluble in saline water than in fresh 
water. 
 
Temperature Dissolved Oxygen Content (ppm) 
°C (°F) A B C 
0 (32) 14.6 13.0 11.3 
5 (41) 12.8 11.4 10.1 
10 (50) 11.3 10.1 9.0 
15 (59) 10.1 9.1 8.1 
20 (68) 9.1 8.3 7.4 
25 (77) 8.4 7.6 6.7 
30 (86) 7.6 6.9 6.1 
 
Where: 
 
A = Chloride content zero 
B = Chloride Content 10,000 ppm w/w 
C = Chloride content 20,000 ppm w/w 
 
Very small concentrations of oxygen (<1 ppm) can be very damaging. 
 
Chapter 7: Corrosion 
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Also, because of its depolarizing role oxygen will drastically increase the corrosivity 
resulting from other dissolved gases such as H2S and CO2. 
 
Concentration cells, or differential aeration cells can cause preferential attack or 
pitting. Whenever 
there is a difference in the oxygen content of water in two areas of a system, 
corrosion occurs preferentially in the areas exposed to the lowest oxygen 
concentration. Typical examples are crevices and water-air interface. 
 
In oil and gas production systems, only limited parts contain oxygenated fluids. 
 
Any oxygen present when the sedimentary rocks were laid down millions of years in 
the past will have reacted to form an oxide. This means that there is no free oxygen in 
the reservoir and as long as oxygen ingress is prevented the oil and gas production 
system will not suffer from oxygen attack. However, in sections of certain systems, 
notably the oily water effluent treatment plants, oxygen is not excluded and oxygen 
corrosion is experienced. 
 
Carbon Dioxide 
 
Corrosion caused by carbon dioxide is known as “sweet corrosion.” 
 
Carbon dioxide is about 36 times more soluble in water than oxygen at 25°C. It dissolves in 
water forming carbonic acid. This lowers the pH of the water and increases its corrosivity. The 
dissociation of carbon dioxide in water depends upon pH and can be described as follows: 
 
CO2 + 2H2O → 2H2CO3 
 
2H2CO3 → H3O+ + HCO3- 
 
HCO3- + H2O → H3O+ + CO32- 
 
2H3O+ → 2H+ + 2H2O
 
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The overall reaction for the dissociation of carbon dioxide in water is: 
 
a) CO2 + H2O → 2H+ + CO3 
 
The corrosion due to carbon dioxide proceeds as follows: 
 
b) Fe 
Iron Atom 
 Fe2+ 
Ferrous 
Ion 
+ 2e- 
Electrons 
Anodic 
Reaction 
 
c) 2H+ 
Hydrogen 
Ion 
+ 2e- 
Electrons 
 H2 
Molecular 
Hydrogen 
Cathodic 
Reaction 
 
 
d) Fe2+ 
Iron Ion 
+ CO3- 
Carbonate 
Ion 
 FeCO3 
Iron Carbonate Corrosion 
Product 
 
Combining a) and d), the overall reaction is therefore: 
 
Fe + H2O + CO2 FeCO3 + H2 
 
The important factors governing the solubility of carbon dioxide are pressure, temperature, pH, 
and water composition. Pressure is most often the controlling factor, especially in gas 
condensate systems where the dissolved mineral content is low. It is usual to use the partial 
pressure of carbon dioxide as a measure of the potential for corrosion. 
 
Partial pressure = total pressure x mol. fraction carbon dioxide 
 
For example, in a system where the pressure is 6,000 psi with a gas containing 1.17 mol % 
carbon dioxide. 
 
Partial pressure = 6,000 x 0.0117 = 70.2psi 
 
The following yardstick has been used to assess corrosivity of gas condensate wells 
producing small amounts of low salinity water: 
 
1. A partial pressure above 30 psi indicates that corrosion is almost certain. 
 
2. A partial pressure between 7 and 30 psi indicates that corrosion is possible. 
 
3. A partial pressure below 7 psi indicates noncorrosive conditions. 
 
 
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The above is based on the API guidelines that apply to most cases. However, recent 
field studies suggest that significant corrosion can occur even under 7 psi of CO2 
pressure. 
 
The presence of dissolved acid salts can buffer the water such that large increases in 
carbon dioxide may produce only a small change in pH. 
 
The solubility of carbon dioxide is inversely proportional to temperature changes. 
 
Figure 6 illustrates the relationships between pH, pressure, temperature and the 
solubility of carbon dioxide in water. 
 
pH
Pressure (psi)
Pr
es
su
re
 (1
00
0 
ps
i)
ppm CO2 in Brine
T1
T2
Te
m
pe
ra
tu
re
ppm CO2
P2
P1
(a.) (b.)
(c.)
T1 < T2
P1 < P2
 
Figure 6: 
(a) Effect of pressure of carbon dioxide on pH 
(b) Solubility of carbon dioxide with pressure 
(c) Solubility of carbon dioxide with temperature 
 
 
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Hydrogen Sulfide 
 
Corrosion caused by hydrogen sulfide is known as ‘Sour Corrosion’. Hydrogen 
sulfide is about 70 times more soluble in water than oxygen. Hydrogen sulfide 
represents a particularly serious corrosive problem because it can attack steel by three 
different mechanisms: acid attack, galvanic attack, or hydrogen attack. 
 
„ Acid attack — In the presence of water, hydrogen sulfide dissolves to form a 
weak acid, which then dissolves iron to form complex sulfides. In general terms 
the corrosive reaction can be described as: 
 
H2S 
Hydrogen 
Sulfide 
+ Fe 
Iron 
 FexSy 
Complex 
Iron 
Sulfides 
+ 2H 
Atomic 
Hydrogen 
 
„ Galvanic attack — Iron sulfide is one of the most insoluble compounds known 
and tends to deposit on, and adhere to, the metal surfaces. Iron sulfide is cathodic 
to steel and so stimulates the generation of an electric circuit, which results in 
further attack on the iron. If the entire iron surface is covered with iron sulfide 
deposits then this will disrupt the adsorption of electrodes at the cathodic sites and 
stop the reaction. However, iron sulfide films are not normally continuous or 
adherent. 
 
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„ Hydrogen attack — Hydrogen attack takes two forms, namely “hydrogen 
blistering” and “hydrogen embrittlement.” In both cases hydrogen atoms are 
generated by the standard corrosive reactions. Under normal circumstances these 
hydrogen atoms combine in pairs to form hydrogen gas molecules, which escape 
from the surface into the environment. 
 
However, hydrogen atoms are sufficiently small to diffuse into the steel where 
they cause damage. Some substances such as sulfide ions reduce the rate of 
formation of hydrogen molecules from atoms. Therefore, in the presence of 
sulfide ions, there is a greater concentration of hydrogen atoms on the surface and 
hydrogen damage is more severe. 
− Hydrogen blistering — Hydrogen atoms diffuse through the steel and at some 
point combine to form molecular hydrogen. Hydrogen molecules are too large 
to diffuse through the steel, so are trapped, and build up as additional atomic 
hydrogen diffuses in and recombines. An accumulation of gas, under rising 
pressure, finally becomes so great that the metal is ruptured. 
 
The blister type of failure is a result of conditions that lead to the formation of 
hydrogen gas at a specific depth below the metal surface. Accumulated gas, 
therefore, lies in a plane parallel to the surface. Pressure is ultimately relieved 
along this plane. The outward signs of this appear as a characteristic bulge or 
blister, which may range from microscopic size to several inches in diameter. 
− Hydrogen embrittlement — This occurs in high strength steels where the 
metal lattice is highly strained. When atomic hydrogen diffuses into this 
lattice, it is further strained rendering the steel brittle and less ductile. 
 
The failure of these high strength steels due to hydrogen embrittlement does 
not necessarily occur immediately on applying a load. Often, there is a long 
period where no damage is observed, followed by a sudden failure. The time 
to failure increases as the H2S concentration decreases. 
 
As little as 0.1 ppm H2S in water and partial pressure as low as 0.001 
atmosphere can cause this problem, although with very long time to failure. 
Hydrogen sulfide can be produced by microorganisms known as “sulfate 
reducing bacteria” (SRB). The presence of two or more of the gases (oxygen, 
carbon dioxide, or hydrogen sulfide) greatly increases the corrosive effect. 
 
 
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7.2.4.3 Physical Effects 
 
Corrosion rates are affected by the various physical conditions that exist in the system, such as, 
temperature, pressure and fluid velocity. 
 
„ Temperature — The effect of temperature can vary according to other conditions that prevail 
at the time. Temperature increases can produce the following effects: 
− The rate of the corrosion reaction will increase. As a rule of thumb, chemical reaction 
rates double for every 460F (80C) rise in temperature. 
− The solubility of dissolved gases will decrease. In open systems, dissolved gases can 
escape as a rise in temperature reduces their solubility. In a closed system, the gases 
cannot escape. Thus, the corrosivity of water will increase with temperature rise up to the 
point that dissolved gases escape and then decrease, but in a closed system will continue 
to increase. 
− The solubility of dissolved salts will be altered. Calcium or magnesium bicarbonate 
dissolved in water will decompose as the temperature rises. Released carbon dioxide may 
produce higher corrosion rates, but the resulting calcium and magnesium carbonates may 
deposit on the metal surface and provide a protective scale. 
„ Pressure — The major effect of pressure is the increase in dissolved gas as pressure 
increases, with a consequent increase in corrosivity of the system. 
„ Velocity — The effect of velocity is variable. 
− Increase in velocity tends to increase general type corrosion rather than pitting type 
corrosion. 
− Low velocities tend to increase pitting corrosion but decrease general corrosion. 
− High velocities combined with the presence of suspended solids or gas bubbles produces 
an effect known as “erosion corrosion” and also “impingement” or “cavitation.” 
− Low velocities favor the growth of SRB and thus the production of corrosive hydrogen 
sulfide. 
− Low velocities in mixed hydrocarbon and water systems favor the separation of the two 
phases and thus increase the corrosion rate, while high velocities favor emulsification and 
water entrainment with reduced corrosion. 
 
 
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7.3 Conducting a System Survey 
Guidelines for performing a system survey can be found in Attachment 1 in section 7.12, 
Appendix at the endof this chapter. 
 
7.4 Types of Corrosion 
Failure of metals due to corrosion can occur in many ways. The most common form of corrosion 
is uniform loss of metal, but in oil and gas production operations, metal loss is frequently 
localized in the form of discrete pits or larger localized areas. Metals can also crack due to 
corrosion without any perceptible loss of material. It is important to know the various forms that 
corrosion can take and how it can cause problems in oil and gas operations. 
 
For convenience corrosion can be classified into eight types, based upon the physical appearance 
of the corroded metal. They are: 
 
„ Uniform corrosion 
„ Galvanic or bimetallic corrosion 
„ Concentration cell corrosion 
„ Pitting corrosion 
„ Intergranular corrosion 
„ Stress corrosion 
„ Erosion/corrosion, impingement, cavitation 
 
To see the effects of the various types of corrosion, please see Basic Corrosion Identification. 
 
7.4.1 Uniform Corrosion 
This type of corrosion occurs when the anodic and cathodic areas keep shifting and corrosion 
takes place more or less uniformly over the entire exposed metallic surface. The metal becomes 
progressively thinner and eventually fails. 
 
This form of corrosion destroys the largest amount of metal, on a tonnage scale. However, 
technically, uniform attack causes the least concern since service life can be accurately estimated 
based on relatively simple laboratory tests. 
 
Localized corrosion often results in more unexpected failures. 
 
 
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7.4.2 Galvanic or Bimetallic Corrosion 
This type of corrosion occurs when two different metals are in contact with each other and 
exposed to a corrosive electrolyte. This coupling of dissimilar metals is referred to as a 
“bimetallic couple.” 
 
Corrosive attack on the more reactive metal is increased and corrosive attack on the less reactive 
metal is decreased. The more reactive metal becomes the anode and the less reactive becomes the 
cathode; a galvanic cell is produced. 
 
For example, when copper and steel are connected and placed in an electrolyte, such as water, 
steel becomes an anode. The steel is said to be anodic to the copper, which is cathodic. Since 
metal loss occurs at the anode the steel corrodes. 
 
The driving force for the current, and hence corrosion rate, is the potential difference between 
the two metals. This is the principle of the “dry battery.” 
 
This principle can also be utilized beneficially in cathodic protection, where for example, steel is 
connected to a more reactive metal such as magnesium. The steel then becomes cathodic relative 
to the magnesium, which becomes the anode and corrodes preferentially. Figure 1, in the 
Appendix, shows a simple galvanic series for metals exposed to water. The farther apart the two 
metals are in this series, the greater the potential difference when they are coupled. The metal 
higher in the series becomes anodic to the one below it and preferentially corrodes. 
 
A general rule indicating the likely severity of corrosive attack in galvanic corrosion is the “Area 
Principle” or “Area Effect.” This states that the total corrosion is proportional to the total area 
exposed to the corrosive electrolyte. 
 
Also, where conditions for galvanic corrosion exist the least resistant metal will suffer almost all 
of the corrosion. Thus steel rivets in monel (a copper/nickel alloy) or copper sheet will corrode 
rapidly whereas monel or copper rivets in steel plate do not corrode. The total corrosion in terms 
of metal loss at the anode is proportional to the total area exposed. 
 
As the ratio of the cathodic area to the anodic area increases the corrosion rate of the more 
anodic metal is rapidly accelerated. Rapid catastrophic failure can result if small areas such as 
rivets, welds or flanges are anodic to the bulk material. 
 
The area affect can also be seen in the pitting of fresh steel pipe. As it comes from the steel mill 
the pipe is covered in mill scale. Mill scale is an electrical conductor and cathodic to steel. 
Therefore, areas that are covered with mill scale are protected and corrosive attack is 
concentrated on those areas where there is no mill scale. Eventually the mill scale loosens and is 
removed in the fluid stream so this type of attack occurs only in the early life of the system. 
 
 
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Other examples of galvanic corrosion are: 
 
„ Weld-line corrosion 
 
The welding process sometimes creates a microstructure near the weld, which differs in 
potential from the parent steel. This is called HAZ (heat affected zone). The different 
areas have different tendencies to corrode. Care is thus taken during welding to avoid 
this, e.g., by post-weld heat treatment. 
„ Ringworm corrosion 
 
In pipe or tubing manufacture the heat required in “upsetting” the pipe end causes the 
heated end to have a different grain structure from the rest of the pipe. 
 
A transition zone is formed near the upset run out, which is susceptible to corrosive 
attack. The corrosion occurs in a tube a few inches from the upset either in a smooth 
fashion or as severe pitting. 
 
Ringworm corrosion can be avoided by fully heat treating the tubing after upsetting. 
 
7.4.3 Concentration Cell Corrosion 
Localized differences in electrolyte composition are referred to as concentration cells. A 
difference in potential is created when a single metal is exposed to water containing zones where 
the dissolved substances differ, or are present in different concentrations. 
 
The part of the metal in contact with the highest concentration of ion or substance becomes 
cathodic to that part of the metal in contact with the lowest concentrations of ion or substance. 
 
Examples of concentration cells are: 
 
„ Crevice corrosion 
 
Crevices on the metal surface promote the formation of concentration cells. For example, 
in oxygenated systems, oxygen in the crevice may be consumed more rapidly than fresh 
oxygen can diffuse into the crevice. This causes the pH in the crevice to decrease 
providing an acidic environment which accelerates corrosion. Another mechanism is 
described below (4. Deposits). Chances are that both occur. 
„ Oxygen tubercules 
 
This type of corrosion results from a similar mechanism to that of crevice corrosion but is 
caused by the formation of a porous layer of iron oxide or hydroxide which unevenly 
deposits on the steel surface. 
 
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„ Differential aeration cells 
 
An air/water interface in an atmospheric tank is one example of a differential aeration 
cell. The water near the surface contains more oxygen than the water below the surface. 
This difference in oxygen levels causes preferential attack at the water line. 
„ Deposits 
 
A deposit on the metal surface exposed to aerated water will corrode beneath the deposit 
as the oxygen level at that location becomes less than the oxygen concentration in the 
bulk liquid. As oxygen is hindered from migrating into the deposit, the area under the 
deposit becomes anodic relative to the surrounding area. Figure 7 illustrates this type of 
corrosion. 
 
The effect of dissolved solids on corrosivity is complex. Not only is the concentration 
effect important, but also the species of the ions involved. Some dissolved ions such as 
carbonate and bicarbonate may reduce corrosion by forming a tenacious layer. Others 
such as chloride and sulfate may increase corrosionby interfering with the formation of a 
protective layer and stabilizing pH. 
 
7.4.4 Pitting 
This form of corrosion is not only the most difficult to predict, but also is probably the most 
vicious type. 
 
In this type the anodic area remains fixed in one place and corrosion therefore proceeds inwardly 
on one spot. The entire driving force of the corrosion reaction is concentrated at these localized 
spots where the corrosion rate will be many times greater than the average corrosion rate over the 
entire surface. The pits that result may be wide and shallow or deep and narrow. Pitting is more 
dangerous than general corrosion because the pitted area can become penetrated in a relatively 
short time. 
 
The formation of local cells due to a partial destruction or breakdown of protective scale causes 
pitting of carbon steel. 
 
When a corroding metal becomes covered with a corrosion product that is dense and adherent, 
the product protects the metal from further corrosion. If the protective scale is removed from 
localized areas then these become anodic to the other areas beneath the scale, which remains 
protective. The anodic areas corrode preferentially and pitting occurs. 
 
Oxygen, hydrogen sulfide, and carbon dioxide are the commonly encountered corrosive species 
that cause pitting in oil field systems. 
 
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Cl- O2
Na+ Ca2+
O2 O2
O2
Cl-
Cl-
Cl-
Na+
(a) Debris settles on metal surface
Fe2+ Fe2+ Fe2+
Anodic
Area
2e 2e 2e
Cathodic reaction
O2 + 2H2O + 4e- 4OH-
Cl-Cl
-
Cl- O2
O2O2
Na+Na+
(b) Oxygen can reach metal surface only at open surface.
Cathodic reaction continues
O2 + 2H2O + 4e- 4OH-
Cl-
Anodes
Fe2+ Fe
2+
Fe2+ Fe
Cl- Cl-
Na+Na+
Na+ O2 O2
O2
Ca2+
Ca2+
(c) Oxygen continues to depolarize the cathodic area while chlorine
 diffuses into the porous deposit.
Na+ Na+
FeCl Cl-
Cl-
Cl-
FeCl2
Fe2+
Fe(OH)3
deposits
O2 + 2H2O + 4e- 4OH-
(d) The iron within the deposit remains soluble as Fe2+ in the absence
 of O2; and corrosion increases as ionic strength in the deposit
 increases.
Figure 7. 
 
 
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Stainless steels are extremely susceptible to pitting because of the properties that make them 
stainless. Stainless steels are resistant to normal corrosion because protection is provided by the 
formation of a thin oxide layer. When this layer is destroyed in localized areas these become 
anodic and pit. High chloride levels in oilfield waters exacerbate pitting by creating a very 
aggressive environment within the pit as it forms. 
 
7.4.5 Intergranular Corrosion 
In this form of corrosion, localized surface attack occurs along the metal grain boundaries. This 
results from a metallurgical structure that causes the grain boundaries to be more susceptible to 
attack than the grains themselves. 
 
Intergranular corrosion is experienced in many alloys including austenitic stainless steel, copper, 
aluminum and nickel alloys. 
 
There are numerous ways in which the alloys can be made resistant to intergranular attack, but 
most rely upon proper treatment during manufacture, such as annealing and careful control of the 
chemical composition of the alloy. 
 
7.4.6 Stress Corrosion 
This is the acceleration of corrosion caused by stress. This is caused by an interaction between 
chemical and physical forces, either of which alone might not have caused the corrosion. In the 
absence of stress the metal would not corrode as readily, and in the absence of the corrodent, the 
metal could easily withstand the stress. 
 
The result of the combined effect is a brittle failure of a normally ductile metal. 
 
Stress corrosion results from the exposure of an alloy, under stress, to a particular corrosive 
environment. No one corrosive species causes stress corrosion in all alloys and most alloys are 
subject to attack in only a few specific corrosive environments. 
 
Mild steels are susceptible to sodium hydroxide (caustic) and nitrate attack. High strength steels 
are susceptible to hydrogen attack. Austenitic stainless steels are susceptible to chloride attack. 
Copper-based alloys are susceptible to ammonia and oxygen. Aluminum, nickel and titanium 
alloys are the most resistant to stress corrosion cracking, but even these alloys can be attacked 
under specific conditions. 
 
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7.4.7 Erosion Corrosion, Cavitation, and Impingement 
Most metals owe their corrosion resistance to the formation of a protective film on the metal 
surface, usually formed from the metal oxide. 
 
„ Erosion corrosion is a type of attack where the protective film is removed at localized areas. 
This type of attack takes the form of a very rapid pitting or grooving attack at the areas where 
the protective film has been removed, usually by the physical attack of gas bubbles, liquid 
droplets (in gas systems) or suspended solids. Carbon steel and other low alloy steels are 
particularly susceptible to this attack. 
„ Cavitation is a localized form of corrosion, combined with much mechanical damage that 
occurs in turbulent areas of liquid flow. The formation and collapse of bubbles in the fluid 
cause it. 
 
Cavitation occurs wherever the absolute pressure at a point in the liquid stream is reduced to 
the vapor pressure of the liquid, such as around pump impellers. Damage is caused by 
repeated impact blows produced by the collapse of the voids within the fluid. 
„ Impingement is similar to cavitation attack, but is localized. It often results from turbulence 
associated with small particles adhering to a metal surface. The resulting attack consists of 
pits, which are elongated and undercut on the downstream end. 
 
This type of corrosion occurs in pumps, valves, orifices, on heat exchanger tubes, and at 
elbows and tees in pipelines. 
 
7.5 The Prevention of Corrosion 
The four main ways in which corrosion can be avoided are through the use of: 
 
1. Appropriate corrosion resistant materials for construction. 
 
2. Coatings, linings, etc. 
 
3. Cathodic protection. 
 
4. Chemical corrosion inhibitors. 
 
 
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7.5.1 Materials of Construction 
Mild steel is the material most often used in oil/gas production systems, especially for equipment 
such as wells, pipelines, vessels and tanks. For situations where more resistant material is 
required alternatives may be used, such as: 
 
„ Ferrous alloys 
− Stainless steels (e.g., 316 SS) 
− Martensitic steels (e.g., 13 Cr, 15 Cr) 
− Duplex steels (e.g., 22 Cr, 25 Cr) 
„ Non-ferrous alloys 
− Nickel-based alloys 
⎯ Hastelloy (Ni - Cr - Mo) 
⎯ Inconel (Ni - Cr - Fe) 
⎯ Monel (Ni - Cu) 
− Copper based alloys 
⎯ Admiralty metals 
− Aluminum-based alloys 
− Titanium 
 
The high cost of alloys and special metals is only justified when compared to the cost of 
maintenance or replacement, such as in an offshore environment. Other alternatives are often 
more attractive. 
 
The choice of material is usually made at the design stages. This decision involves metallurgists, 
production engineers and service companies who supply chemical inhibitors. Once the decision 
is made it is usually more expedient to then apply chemicalinhibition if unforeseen corrosion 
occurs. 
 
It is not proposed to discuss here in detail the different types and relative merits of the various 
metals and alloys used in oil/gas production systems. 
 
 
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7.5.2 Coatings, Linings and Nonmetallic Piping 
For the purpose of this manual, we will discuss only internal coatings applied for protection 
against corrosion. A coating may be defined as a thin material applied as a liquid or powder, 
which, on solidification, is firmly and continuously attached to the material which it is designed 
to protect. For internal use, this may be called a lining. 
 
It is necessary that coatings have the following properties: 
 
„ Be flexible 
„ Be resistant to impact 
„ Be resistant to chemical attack from the fluids to be contacted 
„ Are nonporous to water 
„ Have good adhesion and cohesion 
„ Be stable at the temperature to which they are exposed 
 
Coatings may be classified into two main types: inorganic coatings and organic coatings 
 
7.5.2.1 Inorganic Coatings 
 
Inorganic coatings include both sacrificial coatings, which furnish cathodic protection at small 
breaks in the coating, and nonsacrificial coatings, which protect only the area actually covered. 
 
Sacrificial coatings include galvanizing, or coating with other metals anodic to the metal to be 
protected, and massive suspensions of zinc particles in silicate or organic coatings. The zinc 
particle coating in organic medium, being nonconductive is less effective than that in silicate 
carrier. 
 
Sacrificial coatings are sensitive to extremes of pH, highly basic or acidic environment may 
quickly remove the anodic coating. 
 
Nonsacrificial coatings include metal plating cathodic to the metal to be protected, such as 
nickel, and nonmetallic coatings such as ceramics. It is essential that cathodic metal plating is 
nonporous to water. Nickel is such a cathodic coating, applied electrolytically or by a chemical 
process or by metalized spray. 
 
Ceramic coatings are effective against corrosion but are costly to apply and tend to be very 
fragile. For this reason, they are limited to relatively small pieces of equipment. 
 
Limited use has been made of cement coatings, mainly in tanks, filters and water disposal pipes 
and tubing. Cement linings are damaged by pH levels below 5 and by high sulfate levels. One 
disadvantage of cement lining is its porosity. 
 
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7.5.2.2 Organic Coatings 
 
Organic coatings for internal application consist mainly of epoxy resins, phenolic resins, 
polyurethane and polyesters (PVC is not suitable in the presence of hydrocarbon). 
 
The phenolics, epoxies and polyurethanes are limited to a low nominal thickness because of their 
brittle nature. These coatings are acceptable if fiberglass or asbestos fibers are used as 
reinforcement. 
 
One of the main problems with organic coatings is that of mechanical damage to the surface 
which then completely nullifies the beneficial effect of the coating. 
 
7.5.2.3 Nonmetallic Piping 
 
Nonmetallic piping should be briefly considered since its use is possible in some applications. 
Nonmetallic piping does not corrode in the strict sense, but it may deteriorate or be weakened by 
attack from its environment. 
 
There are various non-metallic materials used in piping such as: 
 
„ Extruded Thermoplastic Pipe —This material can be repeatedly reheated, softened and 
reshaped without destruction. Examples are: 
− Polyvinyl chloride (PVC) 
− Chlorinated polyvinyl chloride (CPVC) 
− Polyethylene (PE) 
− Polypropylene (PP) 
− Polyacetal (PA) 
− Acrylonitrile-butadiene-styrene (ABS) 
− Cellulose acetate butyrate (CAB) 
„ Glass Reinforced Thermoset Pipe — This material is chemically set and cannot be softened 
or reshaped. Examples are: 
− Fiberglass reinforced epoxy (FRE) 
− Fiberglass reinforced polyester (FRP) 
„ Cement Asbestos Pipe — This consists of a homogenous material made from cement, 
asbestos fiber and silica. It can be epoxy lined. 
 
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„ Plastic Lined Pipe — Nonmetallic pipes are attractive from many angles provided they meet 
the technical requirements. It is essential that the advantages and disadvantages be carefully 
studied. 
 
Advantages include: 
− Immune to corrosion by water 
− Light weight 
− Easily jointed and installed 
− Smooth interior allowing for reduced friction losses 
Disadvantages include: 
− Limited temperature and pressure working range 
− Require careful handling during installation 
− May be adversely affected by exposure to sunlight 
− Low resistance to vibration and pressure surges 
− More susceptible to erosion 
− Low mechanical strength 
 
 
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7.5.3 Cathodic Protection 
Cathodic protection involves the application of a direct current from an external source to a 
metal surface immersed in an electrolyte to oppose the discharge of corrosion current from 
anodic areas. When such a protection system is installed, all exposed portions of the protected 
metal surface become a single cathodic area. 
 
Two methods are used: sacrifical anodes and impressed current: 
 
„ Sacrificial Anodes 
 
The choice of material used as sacrificial anodes is limited to those that are less noble in the 
galvanic series than those to be protected. For example, for the protection of steel the 
materials used as sacrificial anodes are usually aluminum, magnesium and zinc because of 
the great potential difference between them and steel. 
 
Zinc is used in low resistivity soils and water. Aluminum is excellent in saline water and also 
has a high energy capacity per anode weight. This relates to the rate at which the anode is 
consumed in use. 
 
For example, typically magnesium is consumed at an approximate rate of 17 pounds per 
ampere per year, zinc at a rate of approximately 26 pounds per ampere per year and 
aluminum alloy at approximately 7 pounds per ampere per year, for a similar system. 
„ Impressed Current 
 
For many systems, the amount of protective current required is too large for a practical size 
of sacrificial anode. In these situations it is more practical to use a silicon/iron alloy as an 
anode by connecting it to the positive side of a DC generator, at the same time connecting the 
negative side to the metal to be protected. In this way, generated currents can be used to 
make the protected metal cathodic. 
 
It is always important to ensure that anodes are properly installed so that minimum electrical 
resistance exists between anode and the surrounding electrolyte. For example, anodes used to 
protect structures should be placed in areas of low soil resistance with low resistance material 
packed around the anode to serve as a backfill. It is also important to minimize stray currents. 
 
In general, sacrificial anodes are used where the required amounts of protective current are small 
and well distributed, such as along a pipeline. They are also limited to soils and waters of low 
resistivity. 
 
On the other hand impressed currents are used to generate much larger currents and require an 
external power source. Impressed currents are most often used to protect storage tanks. 
 
 
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Figure 8 demonstrates the theory of cathodic protection. 
 
Cathodic protection is used effectively to provide external protection to oil and gas lines and 
vessels, but is not effective in the protection of inner surfaces. 
+External DCPower Source
Inert
Anode
Sacrificial
Anode
Current Flow From Anode
Reduces Corrosion
Current to Zero
IMPRESSED CURRENT
SYSTEM
SACRIFICIAL
SYSTEM
 
Figure 8. 
 
7.5.4 Chemical Corrosion Inhibitors 
An inhibitor is a substance, which when added to a system, slows down or even stops a chemical 
reaction. A corrosion inhibitor, therefore, is a substance, which when added to a corrosive 
environment, effectively decreases the corrosion rate of metals within it. 
One commonly used classification relates to whether the inhibitors are inorganic or organic. 
 
 
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7.5.4.1 Inorganic Corrosion Inhibitors 
 
There are four categories of inorganic corrosion inhibitors, but the two main types are anodic and 
cathodic. The following chart describes each and provides examples. 
 
Type of 
Inorganic 
Corrosion 
Inhibitor 
Description Examples 
Anodic These inhibitors reduce corrosion by 
disrupting the electrochemical 
reactions at the anodic sites of the 
metal surface. 
The mechanisms involved vary 
depending upon the inhibitor used and 
are not easily explained. Essentially the 
most important mechanism is that of 
passivation. 
The passivating effect is detected as a 
shift in the corroding metal electrode 
potential to a more noble value, which 
makes it less reactive. 
„ Chromate — Chromates form 
films or complex precipitates that 
thinly blanket the metal surface. 
The film is initiated at the anode 
but may eventually cover the 
entire metal surface. 
„ Nitrites 
„ Silicates 
„ Molybdates 
 
These types of inhibitors are not 
suitable for oil/gas production 
systems. 
Cathodic These inhibitors are generally less 
effective than anodic inhibitors. They 
function by forming a film, often 
visible, on the cathodic surface. This 
polarizes the metal by restricting the 
access of dissolved oxygen to the metal 
surface. The film also acts to block 
hydrogen evolution and prevent 
subsequent depolarization. 
„ Polyphosphates 
„ Zinc 
„ Phosphonates 
 
These types of inhibitors are not 
suitable for oil/gas production 
systems. 
Combined 
Anodic/Cathodic 
Experience has shown that a 
combination of anodic and cathodic 
inhibitors can give an enhanced effect. 
This synergistic effect can be quite 
considerable. For example, chromate 
by itself requires 200 to 300 mg/l CrO4-
- to prevent corrosion in a particular 
aqueous environment; but chromate 
combined with zinc and various 
organic and inorganic phosphates 
provides equal or better results at only 
20 to 30 mg/l chromate. 
„ Zinc/chromate 
„ Chromate/polyphosphate 
„ Zinc/polyphosphate 
„ Polyphosphate/silicate 
 
These combinations are incompatible 
with oil/gas systems and, therefore, 
are not used. 
 
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Type of 
Inorganic 
Corrosion 
Inhibitor 
Description Examples 
Neutralizing This type of inhibitor chemically 
combines with a corrosive 
component of the metal 
environment, thus minimizing 
corrosive attack. 
Most neutralizers are organic chemicals, 
but examples of the inorganic type are: 
„ Oxygen scavengers, such as sodium 
sulfite or ammonium bisulfite, which 
reduce the oxygen content of 
injection waters, thus rendering them 
less corrosive. 
„ Ammonia gas is added to overhead 
distillation streams in refineries to 
neutralize acidic gases produced 
during the distillation process. 
„ Caustic soda is also used in refinery 
distillation units. Added to the crude 
oil feed it reacts with magnesium 
chloride, preventing its subsequent 
hydrolysis to hydrochloric acid. 
Neutralizer dosage is high, since it 
reacts stoichimetrically with the 
corroding species. 
It is convenient at this point to mention 
organic neutralizers, which work 
similarly to neutralize corroding species. 
These include morpholine which reacts 
with hydrochloric acid in refinery 
overhead streams, triethanolamine and 
diethanolamine which react with carbon 
dioxide and hydrogen sulfide in gas 
dehydration systems frequently located 
in oil/gas systems and sweetening units, 
and finally cyclohexylamine used to 
react with carbon dioxide in steam 
generator condensate return systems. 
 
 
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7.5.4.2 Organic Inhibitors 
 
Organic corrosion inhibitors are carbon-based chemicals with nitrogen, sulfur, or phosphorous 
containing groups. These organic inhibitors cannot be specifically designated as cathodic or 
anodic since, as a rule, they affect the entire surface of a corroding metal. These inhibitors reduce 
corrosion by generating a protective barrier film on the metal surface. They are often called 
adsorption inhibitors. 
 
The first molecular layer formed may be strongly bonded perhaps by an electrical charge 
exchange analogous to a chemical reaction or by a physical bonding. The physical bonding 
process probably takes place for the deposition of subsequent layers of film. 
 
Most organic adsorptive inhibitors are long-chain molecules composed of two sections that 
exhibit different properties. At one end of the chain is a group with polar characteristics: the 
chain itself is nonpolar and hydrocarbon soluble. 
 
A simplified inhibition method has been postulated, which states that the polar head of the 
molecule attaches and bonds to the metal surface. The attachment mechanism is probably a 
combination of chemisorption and physical adsorption by Van der Waals forces. The strength of 
this bond has a significant effect upon the persistence of the inhibitor. 
 
The hydrocarbon soluble, nonpolar section of the molecule is then orientated outward from the 
surface of this metal to generate an oleophilic or oil wettable surface. By definition, this surface 
then is hydrophobic, or water repellent, and so the metal is isolated and protected from the 
corrosive aqueous phase. An idealized diagram of this concept is shown in Figure 9. 
 
METAL SURFACE
NON-POLAR TAIL
(OIL SOLUBLE)
POLAR HEAD
 
Figure 9. 
 
 
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In a hydrocarbon water system, the inhibitor exists in equilibrium between the two phases. A 
certain number of inhibitor molecules may be dissolved in each phase. Any additional inhibitor 
will exist as colloidal micelles. The micelles are not surface active and function mainly as 
reservoirs to maintain the concentration of soluble film forming molecules in each phase. As 
soluble inhibitor films onto the metal surface, more inhibitor is released from the micelles to 
maintain the soluble concentration. 
 
The attraction of the polar group to the metal surface is much stronger than to the 
hydrocarbon/water interface. This attraction is not easily reversible. This means that the inhibitor 
will persist for some time, even where there are no reserves in the environment, such as when 
addition of inhibitor is interrupted. This persistency characteristic depends greatly upon the 
particular inhibitor molecule and the environment in the system. 
 
Some inhibitors have a pronouncedability to entrain hydrocarbon into the “tail” of the molecule 
as it is attached and presented to the environment stream. The extra entrained hydrocarbon 
reinforces the hydrophobic nature of the film. 
 
Various factors are important in determining the effectiveness of adsorption inhibitors. These 
include the type of polar group, the number of bonding atoms, the carbon chain length, and the 
degree of aromaticity and/or conjugate bonding. 
 
 
7.5.4.3 Types of Adsorption Inhibitors 
 
There are numerous types of inhibitors and combinations thereof. These can be exemplified by 
their chemical description. The following groups are typical. 
 
Primary Mono Amines 
 
Unmodified general formula: 
 
R - NH2 
 
 
Modified: 
 
a) Salts from acids such as acetic acid: 
 
[R-NH3] + [CH3COO]- 
 
 
 
 
 
 
 
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b) Ethoxylates: 
 
 
 
R-N 
(CH2.CH2O) x H 
 
 
 
(CH2.CH2O) y H 
 
 Where x and y very from 2 to 50. 
 
c) Amides (See Amides.) 
 
Polysubstituted Mono Amines 
 
a) Secondary amines R 
 
 
 
R 
 
 
NH 
 
 
b) Tertiary amines R 
 
 
 
R 
 
 
NR 
 
Diamines 
 
Unmodified: 
 
R-NH-CH2-CH2-CH2-NH2 
 
Modified: 
 
a) Salts with acids (as per mono amines) 
 
b) Ethoxylates (as per mono amines) 
 
c) Amides (See below.) 
 
 
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Amides 
 
Produced by reaction of amine with fatty acid. 
 
Unmodified O 
║ 
R - C - NH2 
 
Modified 
Ethoxylates 
O 
║ 
R - C - N 
(CH2.CH2O) x H 
 
 
 
(CH2.CH2O) y H 
 
Polyamines 
 
Unmodified: 
 
R-(NH-CH2-CH2)n-NH2 
 
Modified as per mono amines. 
 
Imidazolines 
 
A type of tertiary amine. 
 
Unmodified: 
 
N CH2 
 
 
RC 
N CH2 
 
R’ 
 
R’ is usually: 
 
(CH2-CH2-NH)nH or (CH2-CH2-O)nH 
 
Modified as per A if R’ is CH2-CH2-NH2 
 
 
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Quaternary Ammonium Compounds 
 
Unmodified: 
 
[RN(CH3)3] + X - 
 
Where X is usually chloride. 
 
Modified — by ethoxylation. 
 
In all the above groups, R is the oleophillic, hydrocarbon section of the molecule. 
 
Commercially the R components are derived from condensation reactions with “tall oils” that 
contain long chain fatty acids and rosin acids. 
 
Tall oils contain 60% to 70% fatty acids and 30% to 40% rosin acids. About 35% of all rosin 
acid is abietic acid. 
 
7.5.4.4 Physical Characteristics of Corrosion Inhibitors 
 
Liquid chemical corrosion inhibitors are invariably a blend of 25 to 45% active inhibitor (and 
there may be up to three different inhibitors) blended with 55 to 75% of a complex solvent 
system comprising a basic solvent together with additional surfactants with specialized 
characteristics (co-solvent, antifoam, surface cleaners, emulsion breaker, etc.). 
 
Solubility 
 
This physical characteristic is of prime importance and allows liquid chemical corrosion 
inhibitors to be classified according to their solubility and dispersibility in water and 
hydrocarbon. Not only does solubility affect the filming properties, but it also controls the 
ability of the inhibitor molecules to be transported to the areas of corrosive attack. 
 
An inhibitor is generally considered soluble in a solvent if the inhibitor-solvent mixture 
remains clear. An inhibitor is considered dispersible in a solvent if it can be evenly dispersed 
in the solvent by moderate agitation. For these test purposes, the quantity of solvent is equal 
to or greater than the quantity of inhibitor. If the dispersion breaks rapidly in say less than 
one minute, it is known as a “temporary dispersion.” An inhibitor that remains uniformly 
dispersed in the solvent is a “dispersible inhibitor.” 
 
Depending upon the proportions of hydrocarbon/water and the inhibitor, some inhibitors may 
be partly soluble and partly dispersible in a solvent system. 
 
 
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The usual classification given to inhibitors based on their solubility is: 
 
„ Water soluble 
„ Oil soluble 
„ Oil soluble/water dispersible 
„ Limited solubility 
 
Oil soluble inhibitors are generally more persistent than water soluble inhibitors. Persistent in 
this context means strength of film adhesion. The more persistent the inhibitor, the less 
chance it will be washed away. Limited solubility inhibitors are the most persistent but their 
limited solubility decreases the feasibility of transporting them to the area of corrosion. 
 
Emulsion and Foam Forming Characteristics 
 
Filming corrosion inhibitors are surfactant and thus have a tendency to promote emulsions 
and foams in oil/water systems. Fluids from the system should always be tested to give 
assurance that emulsion and foaming characteristics for the recommended inhibitor are 
acceptable. A simple set of tests can be set up to do this. 
 
Compatibility with Other Chemicals 
 
It is recommended that the compatibility of the inhibitors be checked with regard to other 
chemicals in the system. Although there may be no apparent incompatibility when two or 
more chemicals are added at the low use concentrations, it is possible that they may nullify 
each other’s effect. On the other hand, if the chemical user wishes to mix two or more 
chemicals together before addition to the system, then greater care has to be taken since 
many oilfield chemicals have different solvent systems to those used in corrosion inhibitors. 
For the same reason, many oilfield corrosion inhibitors are not compatible with each other. 
An investigation should be made before any chemicals are mixed together. 
 
Thermal Degradation/Stability 
 
Corrosion inhibitors have temperature limits above which they lose their effectiveness and 
can also change their chemical compositions resulting in polymerization or “gumming.” This 
effect is also related to the time of exposure to the temperature. 
 
It is important that the inhibitor will withstand the temperature of its environment for the 
duration of its contact time, not only to ensure its continued effectiveness but also to avoid 
problems it may cause on decomposition. 
 
 
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7.6 Value/ROI Calculations 
Obtain the current value/ROI calculations from the appropriate resource. 
 
7.7 Failure Analysis 
Corrosion and/or mechanical conditions can cause failures. Correct identification of the cause of 
the failure allows you to get to the root cause of the problem and take the correct action to 
prevent future failures. If a failure is caused by corrosion, many times the type of 
corrosion can be identified visually by the “signature,” or pattern, that it leaves on the metal. 
Corrosion failures can be reduced or eliminated by the use of corrosion inhibitors. If, however, 
the failure is caused by mechanical conditions, corrosion inhibitors will not eliminate the 
mechanical stresses and, therefore, may not reduce failures. If necessary, a detailed analysis can 
be requested from the Sugar Land Metallurgical Laboratory. Be aware that although this analysis 
can provide valuable information to you and your customer, it can be costly and time consuming. 
Call your Research Group Leader for instructions on how to obtain this analysis.Described below are some corrosion signatures to look for when viewing a piece of metal: 
 
„ General Corrosion — Characterized by a uniform thinning of the metal without 
appreciable localized attack 
„ Under Deposit Corrosion — A type of localized corrosion that is characterized by any 
metal loss under a deposit 
„ Erosion Corrosion — Degradation of metal caused by a rapidly moving corrosive fluid; 
characterized by localized metal loss adjacent to the disrupted fluid flow, often resulting 
in the formation of horseshoe shaped pits with the “U” oriented in the direction of fluid 
flow 
„ Galvanic Corrosion — May show either generalized or local attack but will always 
involve two dissimilar metals; keep in mind that galvanic corrosion can occur even if one 
of the metals is present initially as an ion in the liquid phase. 
„ CO2 Corrosion — Characterized by pits with sharp edges and gently sloping walls; pits 
are distinctly round in shape, with round bottoms, and are often connected; frequently 
referred to as “ringworm” corrosion 
„ Oxygen Corrosion — Can vary in appearance depending on conditions; may cause 
general corrosion producing red or orange iron oxide (rust) deposits; more typically 
oxygen will cause distinct separated pits that tend to have very steep walls with sharp 
edges 
„ H2S Corrosion — Characterized by cone shaped pits with gently sloping edges; the metal 
around the pits will typically be covered with a dark iron sulfide coating; it may also be 
characterized by sulfide stress cracking. 
 
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„ Microbiologically Induced Corrosion (MIC) 
− Sulfate Reducing Bacteria (SRB) Corrosion — A type of MIC; SRB corrosion 
typically appears as clusters of distinct hemispherical pits that look like overlapping 
“grape clusters” or “rings within rings” 
− Acid Producing Bacteria (APB) Corrosion — A type of MIC; the bacteria produce 
lactic acid and acetic acid; APB corrosion typically appears as deep, narrow pits 
characterized as “worm holes” with smooth unattacked metal in between 
„ Weak-Acid Corrosion — Characterized by smooth walled pits with plateaus of 
unattacked metal in between 
„ Strong Acid Corrosion — Characterized by sponge-like appearance; pits are under-cut 
(they get wider as they get deeper); there are no plateaus of unattacked metal in between 
pits; attack will occur preferentially along welds and other stress lines. 
 
To better identify the various types of corrosion, please see the Basic Corrosion Identification 
handbook. 
 
7.8 Corrosion Inhibitor Selection Process 
7.8.1 Overview 
The test schedule for a typical corrosion inhibitor selection study is conducted in the following 
order: 
 
„ Field characterization 
„ Solubility/dispersibility screening 
„ Bubble test screening 
„ Rotating cylinder screening (if there are still a large number of candidates) 
„ Flow loop screening 
„ Jet impingement 
 
The study usually starts with a large list of candidates (ca 20), which would be progressively 
reduced at each stage. (The rotating cylinder screening is used only if dynamic tests are needed 
for a large number of candidates.) Usually, four products would be tested in the flow loop stage. 
 
All of the tests should be conducted under replicated field conditions at the correct operating 
temperature. Test solutions should be fully de-aerated with CO2 or the appropriate gas mixture, 
normally at 1 bar (absolute). The solutions should also contain any other oilfield chemicals such 
as scale inhibitor and demulsifier because in some cases these can severely affect corrosion 
inhibitor performance. This step is frequently not possible in new fields, so a final compatibility 
test must be completed as soon as the other chemicals have been chosen. 
 
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Important performance factors that need to be considered in the development of an inhibitor 
selection strategy are: 
 
„ Partitioning behavior. 
„ Film stability/persistency. 
„ Compatibility with other additives. 
„ Environmental impact. 
 
These will decide the appropriateness of an inhibitor for field trial/deployment and give a 
practical indication of the expected injection rate. 
 
7.8.2 Test Schedule 
7.8.2.1 Field Characterization and Testing 
 
Before any selection procedure begins, the most important step is to characterize fully the 
system. This will involve flow modeling to characterize the flow regimes and range of wall shear 
stresses experienced in the pipeline, and to identify critical areas where inhibition may be 
difficult because of local flow disturbances. This way the right conditions can be selected for the 
test methods. Full water analysis and operational conditions are also mandated so that the water 
chemistry used in the tests can be accurately replicated. Uninhibited field samples of crude oil 
should always be used wherever possible. 
 
7.8.2.2 Replicating Field Conditions in the Laboratory 
 
Internal corrosion of oil and gas pipelines by transported fluids is complicated and is frequently 
tricky to replicate in the laboratory. Complete recreation of field conditions at a single laboratory 
test facility is not possible. Laboratory tests are basically conducted in a closed facility that is 
only charged once with the test environment; but in the field there is typically a once-through 
situation. For reproduction and standardization, polished steel specimens are regularly used in 
laboratory tests. These specimens consequent surface condition may be far different from that of 
the steel being used in the field where corrosion is of consequence. Obviously, it is important to 
recognize the confines of laboratory tests. They are a compromise in terms of copying actual 
field conditions. Even so, they are still valuable even if they eventually supply only a qualitative 
ranking of conditions or inhibitors, instead of a quantitative measure of absolute corrosion rates 
in the field. 
 
 
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An accurate simulation of field corrosivity begins with recreating system chemistry and 
temperature. The brine composition, crude oil type and water/crude oil ratio are especially 
important. The tests should be conducted at atmospheric pressure with the fluids being saturated 
with a gas mixture containing CO2 (and/or H2S) at the correct fugacity. An inert gas such as 
nitrogen or argon makes up the remainder of the mixture. Certainly, this is only possible for acid 
gas fugacities less than 1 bar. Pressurized equipment is available for higher values. Another 
approach often used in inhibitor selection for oilfield CO2 corrosion is to use testing as a ranking 
exercise, with 1 bar (absolute) of CO2 used throughout. This frequently surpasses the severity of 
the field conditions. 
 
In addition to these variables, it is important to recreate the hydrodynamics of the field situation 
when conducting the laboratory test. Liquid shear stress is considered an important 
hydrodynamic variable throughout the industry. This surface parameter best identifies the 
influence of a flowing fluid on the formation and stability/persistency of an adsorbed inhibitor 
film. Nevertheless, it is important to remember that this still shows only one, although 
significant, aspect of the influence of flow. In cutting back to meet laboratory testing restrictions, 
matching the surface shear stress will often rule out the ability to recreate the actual flow regime 
that is causing shear stress in service

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