ABSTRACT
The aim of this paper is to test, in the laboratory, the ability of relatively new “green” inhibitors
vs traditional organic inhibitors to decrease the corrosion of carbon steels, generally used in oil and gas
production wells, in a sour (H2S) environment. Green inhibitors can be said to be organic catonic with
active groups such as aliphatic and aromatic or polar (hydrophilic) chains. It is the fact that the
components of these inhibitors are biodegradable and do not accumulate that makes them green. As
background to this study, I present short discussions on: oil and gas formation, enhanced oil and gas
recovery methods, corrosion risks, forms of corrosion, corrosion environments, factors that accelerate
corrosion, types of inhibitors, and corrosion testing methods.
The laboratory work was performed in MOL’s corrosion laboratory in Bekasmegyer, Hungary.
One traditional, proven to work, organic inhibitor was tested along with 3 newer green inhibitors. For
confidentiality reasons the specific names of the inhibitors are not given but only referred to as
traditional inhibitor “A” and green inhibitors “B”, “C” and “D”. Solubility, compatibility and emulsion
tests were performed first. These tests were followed by static and persistence tests in autoclaves ( 5o
and 150 ppm inhibitor), dynamic tests (100 ppm inhibitor), and hydrodynamic tests (300 ppm inhibitor)
that measure corrosion rates through weight loss by continuous linear polarization resistance readings.
In the last mentioned tests, water with a high salt concentration (10,000 ppm) was used in order to
duplicate enhanced oil recovery methods that inject water.
Inhibitor “B” showed promising results in solubility tests; but showed extremely low corrosion
protection efficiency, even at high concentrations, compared to traditional inhibitor “A”. Inhibitor “C”, at
a concentration of 150 ppm, had a protection efficiency of 88% compared to 91% for traditional
inhibitor “A”. Inhibitor “D” showed a 90% protection efficiency in linear polarization tests. These results
suggest that green inhibitors can be as effective as traditional inhibitors. Drawbacks to green inhibitors
are that they require high concentrations to be effective.
INTRODUCTION
The primary purpose of this paper is to discuss the results of my laboratory work performed in
order to test the effectiveness of green inhibitors vs. traditional organic inhibitors in decreasing the rate
of metal corrosion in oil production wells. The use of corrosion-reducing materials involves balancing the
cost of whether to spend millions of dollars on corrosion-resistant well materials or to install cheaper
materials that can be expected to be replaced in 10 years time.1 I focus on the corrosion of carbon steel
(CS1018) because it is readily available and meets the mechanical, structural, fabricational and cost
requirements for metals used in oil field production wells. It should be noted that C1018 is quite
susceptible to CO2 corrosion.
I begin my discussion by reviewing how oil and gas are formed. This gives the reader some
insight into the byproducts of oil and gas formation that can affect corrosion. This is followed by a short
1
review of enhanced oil recovery (EOR) methods along with the associated injected chemicals which can
raise the risk of increased corrosion. Next I briefly review corrosion types and divide the subject into 3
categories: mechanisms, appearance, and chemistry.
Somewhat longer reviews on sweet, sour, and microbial corrosion follow. Sweet corrosion refers
to corrosion caused by CO2 regardless of whether the gas exists in the drilled rock formations or is
injected into an oil or gas reservoir during EOR. As previously mentioned metals commonly used in oil
producing wells are highly susceptible to CO2 induced corrosion. Sour corrosion refers to corrosion
caused by H2S; microbial corrosion, as the term signifies, is associated with bacteria that exist within the
drilled rock formations and are mainly in the form of sulfate-reducing bacteria (SRB).
A more focused discussion is given pertaining to corrosion inhibitors. I discuss how inhibitors
function and put them into 4 categories: inorganic, organic, anodic, and cathodic. Relatively older type
inhibitors, mostly toxic and non-degradable, include inorganic-cathodic, inorganic-anodic and organicanodic inhibitors. My primary focus is on green inhibitors. These are environmentally friendly,
biodegradable, readily available, cheap, sometimes made from plant extracts, and often classified as
organic cathodic. This review is followed by descriptions of direct and indirect methods of measuring
corrosion rates along with descriptions of some commonly employed tests used when dealing with
oilfield production.
The second half of this paper is devoted to the results of my laboratory tests on the
effectiveness of new green inhibitors vs. traditional organic inhibitors on the corrosion rate of carbon
steel (CS1018). This work was performed in the Hungarian Oil Company (MOL) corrosion laboratories in
Budapest, Hungary.
OIL AND GAS FORMATION
Insight into factors that affect corrosion in oil and gas production wells can be gained from a
review of how hydrocarbon is formed through geologic time. Oil and natural gas are products of the
transformation of organic matter during long periods of time in sedimentary basins. In general the
sedimentary rocks containing the organic matter from which oil and gas are generated, and referred to
as source rocks, pass through 4 stages of evolution: diagenesis, catagenesis, metagenesis, and
metamorphism. 2
Sediments deposited in subaquatic environments contain water (60% by weight), minerals, dead
organic material, and living microorganisms. In the diagenesis stage these sediments are buried at
shallow depths, usually less than 1000 m and rarely 2000 m, 2 and the temperature and pressure to
which the sediments are subjected gradually increases as the depth of burial increases. During
diagenesis the increases in temperature and pressure are small. Aerobic microorganisms consume free
oxygen, and anaerobic organisms reduce sulfates to release oxygen. The constituents of the organic
matter are arranged into new polymer structures resulting in the formation of kerogen, the precursor to
2
petroleum, along with CO2, ammonia and water. The pH of interstitual water is slightly increased.
During diagenesis some methane (CH4) is formed by biochemical processes. The end of diagenesis
occurs at a temperature of about 50 C when most carboxyl groups are removed.3
As the sediments are more deeply buried temperatures gradually reach more than 50 C, and
catagenesis begins.4, 5 During catagenesis temperatures range from 50 to 150 C and geostatic pressure
due to the overlying rock column can range from 300 to 1500 bars. Rock compaction occurs, water is
expelled, porosity and permeability decrease, and the salinity of water contained in pore spaces
increases approaching the salt saturation point. Kerogen, the precursor of petroleum that was formed
during diagenesis, produces first liquid petroleum then later wet gas and condensate accompanied by
large amounts of methane (CH4). The end of catagenesis occurs when no more liquid petroleum is
generated and only limited amounts of methane.2 Tissot and Welte2 refer to the next stages as
metagenesis and finally metamorphism.
Metagenesis is characterized by the generation of dry gas, the loss of water in clay minerals, and
the change of iron oxides containing water (geothite) to oxides with no water (hematite). Much of the
original rock structure is destroyed due to recrystallization. As temperatures increase as a result of
deeper burial, the contained organic matter is composed only of methane and carbon residue; coal is
transformed into anthracite.2 In the last stage, metamorphism, any residual kerogen is converted to
graphic carbon.
3
Figure 1
Shown are the first 3 stages of hydrocarbon generation as a function of depth of burial of the source rock. Depths correspond
to an average for Mesozoic and Paleozoic source rocks. Figure modified from Tissot and Welte, 1978. 2
Figure 1 shows the general scheme of hydrocarbon generation. The indicated depths of burial
will vary with the value of the local geothermal gradient (increase of temperature with depth), the
geologic history and the age of the source rock.
During metagenesis (temperatures generally greater than 150 C), significant amounts of
hydrocarbons, except for methane, cease to be generated. The methane in this stage is generated
mainly from the cracking of other hydrocarbons. Methane can be destroyed chemically by the presence
of sulfur which reacts with methane to produce H2S. Free sulfur can occur in sedimentary rocks,
especially in carbonate rock sequences. H2S generation usually occurs at depths of 3-4 km and in the
temperature range of methane formation. Methane can exist at temperatures of 550 C.2, 6 This suggests
that the economic drilling depths for methane may not be controlled by thermal temperature; but,
instead, by the decrease in rock porosity as a function of depth6. However, the highest temperatures
recorded in wells drilled for oil and gas in the Gulf Coast region of the U.S. are mostly less than 300 C. In
4
Hungary the highest recorded temperatures in wells, at depths of 3500 m, are less than 180°C
(personnel communication, Csabai, Tibor, MOL).
Temperature as a function of depth is determined by the local geothermal gradient. These
gradients are highly variable and can change over geologic time. The world’s average geothermal
gradient is about 25-50 C /km 7 and the variation between sedimentary basins is high (15-50 C /km)
according to Tissot and Welte.2 The average geothermal gradient in Hungary is 40-45°C/km (personal
communication, Csabai, Tibor, MOL)
Pressure as well as temperature can affect the formation of oil and gas and, in addition, the rate
of corrosion in well materials. In the rock column pressure rises with increasing overburden load of the
overlying sedimentary rocks. However, if the pore spaces of the rock are effectively interconnected, the
interstitial fluids are under hydrostatic pressure. It is only when compaction expels pore fluid and the
fluid is carried away that geostatic pressure is obtained. Under geostatic pressure the pore fluid bears
the entire load of the overlying sediment-water column. Interstitial fluid pressures in sedimentary rocks,
therefore, usually vary between normal hydrostatic and higher geostatic pressure. At depths between
1000 and 6000 m petroleum and gas must move through pores saturated with water at fluid pressures
between 98 and 1373 bars. It is these high temperatures and pressures in reservoirs that cause some
types of corrosion during production.
Another factor that affects corrosion is the salt content of pore water in reservoirs. There is a
general increase in pore-water salinity with increasing depth. Gradients for salinity have been reported
to vary between 70 mg/L/m and 250 mg/L/m.2 Pore-water salinities range from fresh water to total salt
saturation and can reach values close to 300 g/L.
In summary, at depths between 1000 and 6000 m petroleum and gas must move through pore
spaces in the rock column at fluid pressures between 98 and 1373 bars and temperatures between 50
and 300 C. Pore-water salinities may reach values close to 300 g/L; a high salinity usually corresponds
to a high corrosion rate. In fine-grained carbonate rocks sulfur-rich petroleum can form during
catagenesis which then leads to sour corrosion problems during recovery.
OIL PRODUCTION AND METHODS OF EOR AND EGR
There are three general phases of producing oil reserves: primary, secondary and tertiary
recovery. The primary method allows for the retrieval of about 10-20% of the reservoir, depending on
the rock porosity. The natural pressure in the reservoir, or gravity, pushes the crude into the well-bore
and, with the help of pumping equipment, drives the oil to the surface of the well.8 Secondary methods
give more promising results, allowing 20-40% of the oil in a reservoir to be extracted and usually
requires the injection of water or gas to displace the oil driving it to the surface.8 But, with the world’s
oil resources being depleted, producing only 20-40% of a reservoir is not acceptable. This is where
tertiary techniques, Enhanced Oil Recovery (EOR) or Enhanced Gas Recovery (EGR), come into play. EOR
5
is a generic term for techniques that increase the amount of crude oil extracted
from an oil field. “Using EOR, 30-75%, or more, of a reservoir’s in place oil can be
extracted.” 8, 9 This is extremely important if we look at the rate of increase of oil
consumption for the world. The United States Department of Energy (DOE)
estimates that using EOR with CO2 injection, the US will be able to generate
around 200 billion additional barrels of recoverable oil.10 EGR is not as popular as
EOR becaude natural gas recovery from a reservoir usually approaches 75 – 90%
without employing EGR; however, the amount of methane, ethane or other
popular natural gases can be increased by the injection of cheaper gases, CO2,
nitrogen, etc. as in EOR.
Improved oil recovery techniques stem from the secondary method of
injecting substances into wells. Injection methods include: gas injection, chemical
injection, thermal recovery and microbial injection.8, 11 An example of a tertiary
injection well is shown in Figure 2. In one well CO2 is injected into a reservoir
causing oil to be driven to the surface in a nearby well. A brine disposal well (deep
re-injection) is a requirement as EOR tends to allow large quantities of brine,
which may contain radioactive material or toxic metals, to rise to the surface.
Gas injection using CO2 tends to be the most widely used EOR method
although natural gas or nitrogen can also be injected.8, 10 CO2 is commonly injected
because it is considered a “green” material; it is non-toxic, relatively inert, its
critical temperature is only 304 deg K and it is non-flammable. Injecting air is out
of the question because at the reservoir temperatures it would cause the oil to
catch fire. Natural gas injection is also favored because, not only is the added
pressure beneficial, but mixing with natural gas tends to lover the viscosity of the
oil, and a large amount of the injected gas (from 1/2 to 2/3) returns to the surface
with the crude oil and can be re-injected lowering field operating costs.13 This
injection benefits clean coal producers and the like because they produce massive
amounts of CO2 which they cannot simply release into the environment, but now,
they can sell the stored CO2 to oil companies looking to employ in EOR.
Figure 2 from ref. 12
Another alternative is the injection of dilute chemical solutions to aid in Shown above is a CO2
injection well along with its
oil recovery. Chemical injection uses long-chained polymers to increase the brine re-injection on the left.
viscosity of the injected water.10 Alkalis, caustic solutions and surfactants can be
added to emulsify the oil, thereby lowering its surface tension, allowing the oil droplets to move through
the reservoir.14 Chemical injection is generally more expensive than gas injection because of the cost of
the chemicals and because a large amount of the added chemicals get lost in the field’s rock structure;
it is also more toxic to the environment.8,10,14
Thermal recovery processes introduce heat into the reservoirs of heavy crude oil to decrease its
viscosity and/or vaporize part of the oil to improve its ability to flow through the reservoir. Methods
6
used to heat the oil include: cyclic or continuous steam injection, steam flooding, fire flooding and in
situ combustion. 8, 15 Cyclic steam injection is usually a starting point and involves injecting steam into a
reservoir then closing off the flow for a couple days. During this down time the steam condenses to hot
water in the cooler reservoir rock, and this hot water improves the flow of the oil. The oil-water mixture
is then pumped more easily to the surface and the process repeated.15 The other mentioned processes
are similar; heat is introduced into the reservoir with the help of water. In situ combustion is a tricky
process as it involves setting fire to part of the oil in a reservoir and is used only as a last resort because
the fire is usually aided by the injection of corrosive oxygen and part of the oil is lost.
Microbial injection, one of the most expensive of the EOR methods, is the newest and most
rarely used. “Strains of microbes have been both discovered and developed (using gene mutation)
which function by partially digesting long hydrocarbon molecules, by generating bio-surfactants or by
emitting carbon dioxide” (CO2 then functions as described in Gas injection above). 16 These methods
involve the injection of bacterial cultures along with a food source (i.e., molasses) into a reservoir (or
just the food source itself if the microbes are present). With the provided food source the microbes
become oleophilic; they increase their natural surfactant production, metabolizing the oil. Once the
food source has been depleted the microbes dislodge and their exteriors become hydrophilic and small
oil droplets are formed at the oil-water interface.11, 17 In cases when the paraffin components of the
crude pose production problems, injected bacteria break down the paraffin to smaller chains keeping it
from solidifying as the temperature drops during extraction from the reservoir. 11, 16
RISK OF CORROSION IN OIL PRODUCTION
Although the employment of secondary and tertiary methods greatly enhances the amount of
recoverable oil, their use can raise the risk of corrosion. Water injection is often used to maintain
reservoir pressure during recovery. More often than not there is a simultaneous flow of water and oil
until the final stage of separation. As the oil is extracted over time, pressure in the well will continuously
drop and water from the surrounding rock will seep in. As the oil saturation drops and the water-cut
increases the reservoir becomes more and more difficult to properly mine because with high water-cuts
comes added corrosion. However, with the large demand for oil, many wells operate at water-cuts up
to 80%.18 When talking about off-shore drilling it is generally accepted that: 19




<2 wt% H2O cut  low risk corrosion
2-10 wt% H2O cut  medium risk corrosion
>10-40 wt% H2O cut  high risk corrosion
>>40 wt% H2O cut  very high risk corrosion
It should be noted that all of these risk estimates are highly affected by flow patterns and materials
encountered while in service. “Oil wetting is generally inhibitive to corrosion whereas H2O wetting is a
root cause of corrosion.” 19 The well-bore, pipes and pumping equipment are all exposed to the drastic
conditions of the reservoir. In the presence of water and the reservoir’s natural occurring CO2 and H2S,
7
the corrosion damage inflicted on well equipment is extremely expensive to repair and/or replace, and
valuable time and product is lost, not to mention the polluting effects on the environment. Well
materials are made from various types of refined metals, and during the refining process these metals
“store” energy that becomes the driving force of corrosion. 20 Refined metals are generally unstable and
tend to revert to a lower energy state by reacting with their environment, i.e. they corrode. 21, 22
It is important to note that when considering oil production (not otherwise), corrosion cannot
take place in an anhydrous environment; 23 there might be material decay and morphing but if water is
not present then it is NOT corrosion. Corrosion occurs in a corrosion cell at a liquid-solid interface. The
corrosion cell consists of:




A metal conductor
An anode
A cathode
An electrolyte
The metal conductor allows for electron flow. In oilfield work low-carbon steel tends to be the most
commonly used metal. The anode has a positive charge and is formed where the iron is oxidized; it is
where the metal goes into solution. The negative charged cathode’s job is to maintain the balance; this
is where the electrons are present. The electrolyte covers the iron surface and is usually salt water.
Fe  Fe2++ 2e-
(anode)
2H+ + 2e-  H2
(cathode)
O2 + 2H2O + 4e-  4OHCorrosion cells can be found in multiple places all of which are where water and metal meet. These
locations are the following: 23







Where dissimilar metals meet
Points of internal stress
Where there’s a difference in corroded ion concentration
On the sides of a bending axis of bent metal
At stress sites caused by manufacturing processes
Places of imperfections (i.e.- scratches, stress, etc.) on a uniform material
Where there’s a difference in oxygen concentration (In oil production oxygen is present
only when it enters the environment due to open equipment technology or when reinjecting brine)
8
All corrosion processes are made up of chemical reactions. In oilfield corrosion pipe metals corrode
spontaneously as a decrease in their “stored” system’s energy occurs during reaction with the
environment. The metallic structure of the well equipment also influences its corrosion since metals are
inhomogeneous and made-up of a grain-like structure of microscopic metal crystals. Between these
grains arise potential differences which trigger corrosion.23 See Figure 3.
Figure 3 from ref. 23
In the above picture the inhomogenity of the metal can be seen
along with the electron flow from the potential differences.
FORMS OF CORROSION
Although many types of corrosion exist they all fundamentally lead to the same end: lost
revenue. Though types of corrosion are somewhat different, similarities do exist and 3 methods of
grouping are shown in Table I. These are not set in stone, other groupings such as high and low
temperature corrosion, corrosion that can be seen with the naked eye and those that require an aid to
see them, etc. exist, and multiple corrosion types can co-exist.
BY MECHANISM24
Corrosion of Exterior Surfaces
In the presence of oxygen
Galvanic
Due to dissolved gases
Velocity corrosion
Wear
Stress and fatigue
Microbial Induced (MIC)
BY APPEARANCE20
Uniform
Pitting (localized and scattered)
Crevice
Galvanic
Intergranular
Cavitation
Erosion
Microbial Induced (MIC)
Environmental Cracking
BY CHEMISTRY22
Wet Corrosion
Dry Corrosion
Table 1 showing the groups of corrosion
9
A brief overview of each of the corrosion types (as shown in Table 1) follows as it is impossible
to understand the work of an inhibitor if the corrosion process itself is not understood.
GROUPED BY MECHANISM:
Corrosion of exterior surfaces, although only accounting for roughly 1/5 of corrosion problems
in contrast with the slightly greater than 1/2 due to interior, or process side corrosion, is still a
problem.23 Exterior surface corrosion is generally controlled by applying a protective coating on the
exterior of the equipment to prevent contact with the corrosive environment. Cathodic protection is an
acceptable protection method for exposed
metal surfaces.24
Corrosion in the presence of
oxygen tends to be the most detrimental
type of gas corrosion, though, in oil
production oxygen is present only when it
enters the environment due to open
equipment technology or when reinjecting brine. Corrosion takes place when
there’s a difference in the oxygen
concentration of the water between two
areas; the area with the lower oxygen
concentration will begin to corrode.
Oxygen corrosion is harmful because it
only requires 40-50 ppb of oxygen to be
highly corrosive and oxygen accelerates
the corrosion rates of CO2 and H2S alike.
(See Fig. 4)21, 24 Oxygen corrodes severely
with a pitting effect starting with small
needle-like holes and expands to large
shallow pitting often ending in metal
fatigue.
Galvanic corrosion occurs at the
union of two dissimilar metal surfaces.
The corrosion of the less resistant metal
will increase while the other metal is
protected. This causes severe corrosion for
one metal and increases in severity when the
anode is small and the cathode is large. It
Figure 4 from ref. 21
The above diagram shows the comparative corrosiveness of three
common gases in water solutions (25⁰ C, 5-7 day exposure, 2-5 g/L NaCl,
HCO3 alkalinity <50 mg/L)
10
can be combated by insulating the metals.24
The most often encountered type of corrosion in the oil industry is corrosion due to dissolved
gases. Mainly CO2 and H2S gases are considered since corrosion from other gases tends to be minimal.
CO2 causes what is called “sweet” corrosion, the most common form of corrosion, while corrosion in the
presence of H2S is referred to as “sour”. Both gases tend to dissolve in water lowering the pH and
therefore increasing the corrosion rates but in different ways. Sweet and sour corrosion are discussed in
later sections of this paper. In most cases in the absence of water both gases would be non-corrosive.24
Both gases can lead rapidly to equipment failure and tend to be dealt with using a variety of inhibitors.
Velocity corrosion arises from liquid flowing through a metal pipe. Both high and low velocity
liquids can cause corrosion in their own ways. High velocity liquids can strip inhibitors, remove or inhibit
scales and the like from pipe surfaces and expose the metals to a corrosive environment; this is easily
identifiable due to markings that follow the flow direction. On the other hand low velocity liquids can
result in water holding or incubation sites for bacteria such as sulfate-reducing bacteria (see Section
entitled MIC).24, 25
Wear corrosion, as the name suggests, ioccurs when materials repeatedly rub together resulting
in the removal of their protective agents or by weakening the material. It is often called erosion and
involves the sideways displacement of material.
Stress and fatigue corrosion encompass all the stress and strain placed upon the metal during
handling, installation and use. It can occur from welding, hammering or simply the repeated use of the
part. Metal fatigue usually begins with an initial crack followed by other cracks which ultimately lead to
the destruction of the remaining material.
Microbial Corrosion (MIC) arises when micro-organisms complicate matters in the environment.
There are: bacteria (single celled organisms), algae (simple plants able to photosynthesize) and fungi
(simple plants unable to photosynthesize). These micro-organisms complicate matters in a number of
ways. They can form a biofilm on a surface under which corrosion is initiated due to oxygen depletion
or H2S or FeS production which then causes corrosion in the manner previously discussed. Other biofilms
can result in plugging and fouling due to the slimes that are formed form. The most common MIC is a
form of sulfate-reducing bacteria (SRB) which reacts with iron to form FeS.26, 27 MIC will be discussed in
more detail in a later section of this report.
GROUPED BY APPEARANCE:
Uniform corrosion is easily recognizable, is the most common form of corrosion encountered in
oil field operations and causes the greatest loss on a tonnage basis. Rates are reported in units of width
per time, usually millimeters per year (mm/y). Estimates are easily made, using mathematical equations,
11
about future damage and materials undergoing uniform corrosion tend to be categorized by their rates
as: 25



<0.15 mm/y – metals with good corrosion resistance
0.15- 1.5 mm/y – metals are satisfactory
>1.5 mm/y – in most cases these are non-satisfactory metals
Pitting corrosion is more viscous and destructive than uniform and is said to account for the
largest number of unexpected losses.20 It is unfortunately most often localized causing severe damage
in a short time period. It is estimated that a typical flowline can function without major problems for
about 15-20 years, but in cases of localized pitting that flowline can fail in as little as 30 days.23
Materials that are generally susceptible to localized pitting are those relying on passive protective films
such as aluminum and stainless steels. Pits tend to be somewhat circular in shape and deep with sharp
slopes or shallow with rounded bottoms depending on the corrosive agents.
Crevice corrosion can exist in multiple areas: in cracks, crevices, under deposits or scales, where
the free access of the surrounding environment is restricted. It can also occur under loose fitting parts
that allow some liquid to seep in under them. Crevice corrosion can be prevented by coating all the
cracks with some water-resilient compound.20
Galvanic corrosion as a mechanism was discussed above but what makes it easily identifiable by
appearance is the fact that where the two dissimilar metals meet there is an intense corrosion of one
while the other metal is protected.
Intergranular corrosion is localized along grain boundaries with a decreased corrosion of grains.
Transgranular corrosion also exists where the corrosion appears as cracks across the grain structure of
the metal, apparently randomly, not affected by the grain boundaries.20
Cavitation is a form of a velocity-related attack. It is localized and occurs where there are high
velocity and turbulent liquids accompanied by rapid pressure changes. There is a repeated formation
and collapse of bubbles at one site and as the bubbles collapse near to where a liquid meets a metal
surface a significant amount of kinetic energy is released.20 If the amount of released energy is high
enough the protective layer on the metal can be broken and corrosion initiated.
Erosion corrosion is another type of high-velocity-related attack. Turbulent and unpredictable
liquid motions break down the protective film of scaling on a metal or alloy and further oxidize the
unprotected surface.20 This type of corrosion most often results in pitted areas on the metal surface.
Dissolved solids or bubbles can dramatically accelerate the deterioration.
MIC is identifiable from the observable black slim-covered holes. Under this slime oxygen
depletion occurs, which then results in pitting corrosion. The holes appear as shallow concentric pits
within pits (stair-like) or “worm-holes”.
12
Environmental cracking is another distinctive mark of corrosion. Although, there are different
types of cracking, they all occur with the brittle failure of a previously ductile material due to stress and
corrosion. Stress Corrosion Cracking (SCC) is a combination of tensile stress and a corrosive
environment.20, 21 Hydrogen Induced Cracking (HIC) occurs when hydrogen atoms, because of their small
size, are able to penetrate into the molecular structure of the metal. Inside the metal the hydrogen
atoms then form larger hydrogen molecules resulting in blisters and cracking.20 Sulfide Stress Cracking
(SSC) refers to cracking that occurs when sulfide poisons the reaction and allows even more atomic
hydrogen to enter the metal than in HIC.21 Corrosion fatigue, another type of environmental cracking,
occurs when a metal’s useable life runs out and it fails; the useable life of a metal is much shorter when
exposed to a corrosive environment.22
GROUPED BY CHEMISTRY:
Dry corrosion is sometimes also known as chemical corrosion. Dry corrosion occurs when liquid
is either absent or the temperature of the environment is above the dew point of the liquid.22 It results
mainly through the direct chemical action of the corrodents, in this cases gases or vapors, with metal
surfaces. This type of corrosion is not encountered, or very rarely, in oilfield production.
Wet corrosion, or electrochemical corrosion, accounts for the largest percentage of corrosion
problems in oilfield production and occurs when a liquid is present.22 Electrolytes and aqueous solutions
are involved and a conducting liquid is in contact with a metal resulting in the formation of anodic and
cathodic areas.
SWEET (CO2) CORROSION
Sweet Corrosion Mechanism:
Kermani and Morshed28 give an overview of CO2-based corrosion, its types and mechanisms, and
control methods. Carbon dioxide corrosion, also called “sweet” corrosion, is the most often
encountered type of corrosion in oil and gas production wells and is the main cause of material failures.
There are three main reasons for this observed prevalence of CO2 corrosion. (1) The actual CO2
corrosion mechanism itself is still not fully understood. (2) The existing long-term prediction models are
unreliable. (3) The carbon and low-alloy steels, widely used in oil and gas production wells, have poor
resistance against CO2 corrosion.
CO2 corrosion has been studied extensively;28, 29, 30, 31 however, current mechanisms used to
explain CO2 corrosion are limited in scope or have limited acceptance in the scientific community.28
Sweet corrosion is gaining additional attention due to the increased use of CO2 injection method for
enhanced oil recovery (EOR). Dry CO2 gas is not corrosive at the temperatures occurring in oil and gas
production wells and requires an aqueous phase. The main cause of the corrosion is that CO2 dissolves
in water, yielding a weak acid, H2CO3 which can be more corrosive than a stronger acid, such as HCl, at
the same pH.28 The equilibrium
13
CO2 + H2O  CO2 – H2O ≈ H2CO3  H+ + HCO3makes it difficult to identify the rate-determining step (RDS) in the reaction between the dissolved CO2
and the steel surface. The proposed interpretations range from viewing H2CO3 simply as the source for
H+ for a cathodic hydrogen evolution reaction33 to viewing the HCO3- ion being reduced directly at the
cathode.34 In either spectrum, the concentration of the dissolved CO2 and the mass transport of the
dissolved CO2 to the surface of the steel have a major impact on the rate of corrosion.
Although CO2 corrosion itself generally doesn’t cause catastrophic failures, such as the cracking
associated with H2S corrosion, its high corrosion rate can, in the end, be even more damaging. CO2
corrosions often occur as general corrosion or localized corrosion, such as pitting, mesa-attack, and
flow-induced localized corrosion.
Several factors influence the amount and rate of carbon dioxide corrosion. Among these, are
hydrodynamics, type of steel, presence of acid gases, operating conditions, fluid chemistry, hydrocarbon
type, and presence of inhibitors. These parameters provide the foundation that influences the rate of
corrosion and the ability to predict the rate of corrosion. Current predictive capabilities are short term.
Their accuracy for predicting long term effects have not been established.28 The lack of industry
standards for long term prediction further complicates the process of establishing an approach to be
adopted by the community. A “rule of thumb” approach is often used to establish guidelines for
material selection and to perform qualitative assessment. Models from experimental results may also
contribute to the predictive capability of CO2 corrosion.
Sweet Corrosion Control:
Due to the complex nature of CO2 corrosion and the difficulty of understanding the actual
corrosion mechanism, it is difficult to provide adequate control. The possibility of corrosion, however,
impacts the cost of oil and gas production as well as the safety of the facilities and the environment.
Some of the parameters that have been recommended to be adjusted for corrosion control are:
operational parameters and system design, e.g., flow, temperature, sharp bends, crevices, etc.,
operational environment, interfacial condition of the metal, use of corrosion resistant materials, and use
of corrosion inhibitors.
Most of the literature on CO2 corrosion control deals with the use of corrosion resistant alloy
steels; although all alloys of interest to the oil and gas industry will undergo some CO2 corrosion and
there is no industry standard for them, the literature does provides some references and recommends
various steel alloys to be used in different CO2 environments depending on temperature, CO2 partial
pressure, flow, etc.
Other than choice of alloy steels, control methods primarily deal with the preservation,
thickening, or hardening of the protective film (or scale) of iron carbonate (FeCO3) formed on the metal
surface that is in contact with the fluid. This film or scale formation provides a diffusion barrier and/or a
low porosity protective layer against corrosion. The pH of the aqueous solution plays an important role
in the corrosion of carbon steels by influencing the electrochemical reactions that cause dissolution as
well as the precipitation of protective FeCO3 scales. For pH values >5 the probability of FeCO3 scale
formation is greatly increased. Under certain conditions, however, constituents in the aqueous solution
with CO2 present can buffer the pH and lead to the formation of a film layer that in itself is corrosive
thereby increasing the amount and rate of corrosion. This effect can be considerable when production
fluids contain organic acids such as acetic acid (HAc).
14
Recently CO2 corrosion inhibitors have been discussed in the literature. Li35 tested two generic
CO2 corrosion inhibitors: quaternary ammonium salts and fatty amino acids. This author’s tests show
that a direct exposure to oil phase enhances the performance of a fatty amino. Both tested inhibitors
apparently produce, not only a reduction in oil-water interface tension, promotes easy water
entrainment by the oil, but also changes the wetting ability of the steel surface from hydrophilic to
hydrophobic which may reduce the possibility of CO2 corrosion.
Farelas and Ramirez36 found that 1-(2-aminoethyl)-2(heptadec-8-enyl-bis imidazoline acted as a
CO2 corrosion inhibitor by helping to form a more compact inhibitor layer on the surface of the metal in
contact with the fluid. The molecular structure of this inhibitor allows the use of low concentrations (10
ppm) without loss of efficiency.
Foss et al.37 studied the performance of two CO2 corrosion inhibitors, oleic imidazoline
compound (Ol) and a phosphate ester compound (PE), on the wetting ability of carbon steel in the
presence of an iron carbonate (FeCO3) film. The CO2 corrosion tests were performed at 60 °C, 1 bar CO2,
3 wt% NaCl, and 20 vol% oil, where samples were alternately exposed to oil and aqueous phases. Both
inhibitors achieved a transition from a water-wet state to a preferentially oil-wet state. These authors
found that the addition of Ol caused the FeCO3 surface to retain an oil film after immersion in oil; this
apparent oil film caused a significant reduction in the rate of corrosion of the steel in aerated solutions.
SOUR (H2S) CORROSION
Sour Corrosion Mechanism:
Brief explanations of H2S induced corrosion (often referred to as sour corrosion) are given by
Schroder et al.38 and Felipe and Mize.39 One of the clearest explanations is given by Bellarby.40 According
to this author H2S reacts with steel to form a semi-protective film of iron sulfide (FeS). Because the FeS
film is normally not uniform and can be removed by liquid flow, fresh metal is exposed to H2S. The
exposed area is anodic and small in area compared to the surrounding iron sulfide film. Hence, the
exposed metal preferentially corrodes causing pitting (see Fig. 5). In most oil reservoirs, H2S levels in
produced fluids are low; therefore, H2S pitting is less often encountered than that by CO2. When H2S
concentrations are low, however, sulfide stress cracking (SSC), a form of hydrogen stress cracking (HSC),
can occur.
The role of H2S in SSC formation is to provide hydrogen at the metal surface by corrosion and to
prevent hydrogen escaping into the surrounding fluid (see Fig. 6). In the absence of H2S, hydrogen
normally formed at a cathode in a production well would simply bubble off. However, sulfide in
surrounding fluids prevents the escape of hydrogen (H2S poison effect). The hydrogen thus finds an
alternative path through the metal due to the small size of the hydrogen atom. At high temperatures the
migration of the hydrogen atoms is rather easy; but, at low temperature migration is restricted and,
therefore, the concentration of hydrogen atoms inside the metal (where temperature is lower than in
the surrounding fluid) builds up.40 Once inside the metal and away from sulfide, the small hydrogen
atoms combine to form larger hydrogen molecules and pressure builds. At first blisters appear; later,
however, under more pressure the metal catastrophically cracks (hydrogen induced cracking) followed
15
by propagation of the cracking. The risk, therefore to SSC lies at the top of most wells where pressure is
still high, but temperature has decreased. SSC can occur at relatively low H2S concentrations.40
Figure 5 from ref. 40 - Hydrogen pitting on steel surface.
Figure 6 from ref. 40
Sulfide stress cracking (SSC).
According to Wei Sun et al.41, corrosion by H2S has not received as much attention as corrosion
associated with CO2 and, even though H2S corrosion mechanisms have been proposed, they have not
been completely validated. This author goes on to say that the proposed H2S corrosion mechanisms in
16
the literature explain the behavior of experimental data but not thermodynamic and kinematic
mechanisms.
Sour Corrosion Control:
H2S occurs in natural gas and crude oil due to the decomposition of organic matter; it also
occurs in rock fissures, volcanic gases and arises from bacterial action in brackish waters.42 According to
Bellarby40 the primary mechanism for oil field souring is the reduction of sulfate to H2S by sulfatereducing bacteria (SRB). The bacteria are present in seawater and probably in most oil and gas
reservoirs. If it were possible to remove all SRB, reservoir souring would probably not occur; however, a
microbe free environment is almost impossible to achieve, despite the common use of biocides in well
fluids and ultraviolet lamps.40
On a reservoir scale, two methods can be employed to control souring:40 (1) The introduction of
sulfate-removal plants.40, 43, 44 Sulfate levels of approximately 10 ppm are required to lower SRB activity
to acceptable levels; however, sulfate-removal plants typically achieve a few tens ppm. (2) Injection of
nitrates with seawater.40, 45, 46 This method encourages the growth of nitrate-reducing bacteria (NRB)
that produce nitrogen rather than H2S. The NRB consume the fatty acids that are an essential food
source for SRB; thereby reducing the growth of SRB. However, questions exist pertaining to the side
effects of this technology (possible corrosion to production equipment when fluids are recycled).
The proper choice of steels in well equipment can significantly reduce sour corrosion. The most
referenced standard for defining sour corrosion is the National Association of Corrosion Engineers
(NACE), now known as NACE International.47 NACE International sets standards that are legally
enforceable in the USA and recommends various metal combinations to be used in H2S and CO2 mixed
environments depending on the ratio of H2S to CO2. Low-alloy steels work well under sour conditions;
but, many of these are unsuitable for sweet environments.
Care is required in the treatment of welded areas of well equipment that is exposed to a sour
environment. In well completion equipment welding should be used infrequently.40 Most well
completion equipment use seamless tubing to avoid welds and threaded rather than welded
connections.
MICROBIOLOGICALLY INFLUENCED CORROSION
Microbiologically influenced corrosion (MIC) is also known as biocorrosion or microbial
corrosion. It occurs when micro-organisms complicate matters in the environment. The type of metal
used in construction, the microstructures, the metal surfaces, metal alloys, all play a part in affecting
MIC. An understanding of MIC requires an understanding not only of corrosion but of microbiology and
this lack of communication between the two sciences explains why an understanding of MIC is only a
17
recent development. As was already said when describing the types of corrosion, bacteria, algae and
fungi all play a role; and the average dimensions of these microbes is typically in the range of
micrometers. Their small size makes their dispersion in the environment and into crevices and many
hard to access areas possible. One source27 gives the definition of MIC as “The electrochemical process,
here the participation of microorganisms, is able to facilitate, or accelerate the corrosion reactions
without changing its electrochemical nature”. This source27 goes on to say that corrosion rates can be
1,000-100,000 times greater in the presence of microorganisms than in their absence.
Bacteria can be quite detrimental and to further complicate the problem they are able to
withstand extreme conditions; often from below freezing to quite high temperatures.22 Another
problematic characteristic they possess is their ability to enter a “spore” form once they are dehydrated
together with their ability to remain in a spore stage until an acceptable environment allows them to
germinate later.26, 27 All natural waters contain bacteria and often MIC is observed in stagnant process
waters. Bacteria can work to instigate MIC in a number of ways: 26




They can destroy protective films on the metals.
They can produce localized acid environments.
They can form corrosive environments.
They can alter anodic/ cathodic reactions.
When discussing MIC, focus will lay on chemotropic microorganisms. These are: sulfatereducing bacteria (SRB), iron and manganese bacteria and sulfur-oxidizing bacteria.26, 27 In oilfield
production the main cause of MIC are SRBs. These reduce sulfate to sulfide and use the sulfate ion to
produce H2S.21, 22, 26, 27
4Fe + SO42- + 4H2O  3Fe (OH) 2 + FeS + 2OHThey occur in anaerobic environments and create an alkaline environment which is detrimental to irons
and steels. Theories on how SRBs influence MIC are the following: 26




By generating H2S
Creating oxygen concentration cells
Forming insoluble sulfides when metal ions combine with sulfur
Cathodically depolarizing
One of the main corrosion mechanisms of microorganisms is their ability to form biofilms. As
soon as a metal is immersed into water biofilm formation begins. A biofilm is defined as an
accumulation of microorganisms, a microbial mass, on the surface of a metal. The microbes acquire
nutrients from the surrounding environment and retain water while accumulating inorganic matter.
When these biofilms are damaged, or create an anaerobic environment underneath them, then
corrosion is initiated. MIC is easily identifiable and tends to be in the form of pits at stagnant liquid
points in the systems. Concentric rings, dark colored, slime-covered mounds, or small pinholes with
large cavities underneath them are all characteristics of MIC.
18
MIC can be controlled by changing materials or environments and by adding barriers; any way in
which the microorganisms will cease contact with the metal surface. A common technique is the use of
biocides which are chemicals which reduce or eliminate the presence of the organisms.26, 27
FACTORS THAT ACCELERATE CORROSION AND CONTROLLING CORROSION
Now that a basic understanding of the different methods of corrosion attack has been reviewed,
factors that accelerate corrosion need to be discussed before moving on to control techniques.
Accelerating factors include but are not limited to:20, 21, 22, 23, 25 pH of the water, dissolved acid gases,
temperature, pressure, dissolved solids, velocity of the fluids through the flowlines, metallurgy,
dissolved oxygen and suspended solids. The effects of dissolved CO2 and H2S have already been
discussed as being more corrosive in greater concentrations. Temperature usually has a positive
correlation with corrosion but not always. Certainly higher temperature means lower solubility of
possible corrosive gas, but protective scales against corrosion may form on the surface of a metal at
higher temperatures. High pressure increases corrosion as does an increase in dissolved solids. Both
low and high liquid velocities can induce corrosion depending on the environment. The effect of
dissolved salts can increase or decrease the amount and/or rate of corrosion, again depending on the
environment. There is a positive correlation between dissolved salts and corrosion as the conductivity
of the electrolyte increases causing the current flow in the electrochemical cell to increase. The
corrosion rate can also decrease as the salt concentration increases if the dissolved gas solubility and
diffusion rate decrease or protective scales precipitate on the surface of the metal.
Following the above discussions pertaining to the various forms of corrosion and factors that
accelerate corrosion, I want to summarize the main ways of controlling corrosion. This is generally
possible by implementing changes that make for a non-corrosive environment. Generally the easiest
methods to reach the goal are: 23





Changing the metal to a corrosion resistant alloy (CRA) or chrome interior
Physically treating the metal with a barrier (ex: glass, ceramic, etc. coating)
Giving electrochemical cathodic protection to the system (ex: with a “sacrificial anode”)
Removing gases from the water or dehydrating the system
Using chemical inhibitors
The remainder of this paper will focus on inhibitors: their functions, laboratory testing
procedures and the chemicals used. As previously stated the primary aim of this study is to evaluate, in
the laboratory, the effectiveness of newer green inhibitors vs. traditional organic inhibitors for their
ability to decrease the corrosion rate of carbon steels.
19
INHIBITORS
Inhibitors are often considered to be the first line of defense against corrosion. NACE
International states that an inhibitor is “a substance which retards corrosion when added to an
environment in small concentrations”.21 A generalization made by Jones21 is that all inhibitors directly or
indirectly coat or film the metal surface. In a broader view many different substances can be called
“inhibitors”:






Organic film formers (ex: Imidazolines/ amides, nitrogen heterocycles, fatty acid salts)
Scavengers (ex: sulphites for oxygen or aldehydes for hydrogen sulfide)
Neutralizers (ex: simple amines)
Inorganic film formers (ex: phosphates or zinc/ calcium salts)
Passivators (ex: chromates or nitrites)
Bactericides (ex: aldehydes or quats)
An inhibitor can be said to function by either adsorbing onto the surface of a metal, thereby
producing a thick corrosion product, or by changing the corrosive environment.48 For the sake of
understanding the processes involved, inhibitors are grouped as follows: 49, 50
1.
2.
3.
4.
Forming protective filming or scales
Slowing the corrosion rate by increasing/ decreasing the anodic/ cathodic reactions
Decreasing the diffusion rate of ions to the metal surface
Increasing the electrical resistance of the metal surface49
Inhibitors focused on in this paper function by adsorbing on the surface of a metal; and, in order
to do this, they must offer efficient solubility and be in contact with the pipe wall. Phase-inversions
must also be considered to guarantee that throughout the whole process this is true. Other factors
affecting the efficiency of the inhibitor range from the size of the organic molecule to the carbon chain
length to the pipe material and the flow conditions.18, 48 Desirable properties of inhibitors are: (1) that
low concentrations are efficient at minimum surface saturation, (2) the transport of the active corroding
inhibiting ingredient to the metal is high, and (3) there are no adverse side effects such as emulsions and
foaming.10, 35 Since inhibitors generally work through oil-wetting, emulsions and foaming are frequently
encountered but can be combated by blending demulsifiers (for temporary water dispersion) and
defoamers (such as glycol or Si) to the inhibitor.21, 24
In selecting inhibitors a number of factors should be considered such as the solubility,
dispersability and the compatibility. Is the inhibitor compatible with the system’s waters and
components (seals, gaskets, etc.)? Should the inhibitor be:



Oil soluble
Oil soluble/ water dispersible
Water dispersible
20
Most often oil soluble, high molecular weight amine inhibitors are used in production wells. Other tests
for inhibitor selection can be performed in the laboratory. These include solubility tests with varying
concentrations of inhibitors, emulsion tests, static tests in autoclaves, dynamic tests in a bomb
environment or hydrodynamic tests.
Jones21 states that oilfield inhibitors are created most often by starting with a 20-40% by weight
amine base which is then diluted with an aromatic solvent. Alcohol is added and the final product is oilsoluble. Jones also claims that dual-phase inhibitors can be obtained by blending an oil-soluble amine
base with emulsifiers and low molecular weight amines.
In order to formulate a difference between inhibitors used in the past and new “green”
inhibitors appearing on the market today, inhibitors are divided into the following groups:




Inorganic
Organic
Anodic
Cathodic
INORGANIC:
Inorganic anodic inhibitors tend to be made from mineral sources, the most common type being
crystalline salts: 21 phosphates, chromates, sodium molybdate, silicates, borates and nitrites; and are
most often used in cooling waters. They decrease corrosion because of the negative anions they carry
and are therefore considered anodic. When Zinc is involved they can be cathodic.21 Lots of inorganic
inhibitors are toxic either as irritants, carcinogens, poisons or narcotics.50
ORGANIC:
Organic inhibitors tend to be made from plant or animal sources and can be generalized as filmforming that prevent metal dissolution by forming a hydrophobic layer on its surface. Organic anodic
inhibitors such as: 21 sulfonates, mercaptobenzothiazole (MBT), triazoles, thioureas, acetylenic alcohols
and phosphates are used quite often.21, 50 These fall in the category of traditional inhibitors while organic
cathodic inhibitors: 21 amine/acid salts, high molecular weight diamines, imidazoles, amides and
quaternary ammonium salts tend to be newer and greener; but, these will be discussed further in the
following sections.
ANODIC:
Anodic inhibitors reduce the anode reaction and cause the polarization curve to shift so that the
current flow decreases.50 They can be oxidizing or non-oxidizing. Oxygen Passivators fall into this
category (phosphates) and with continuous application they work to transport oxygen through a system
in such a way that it doesn’t contact the metal surface.23 Oxygen inhibitors are anionic and, therefore,
not acceptable as H2S or CO2 corrosion inhibitors.21
21
CATHODIC:
Cathodic inhibitors reduce the cathode reaction and decrease the hydrogen evolution in acidic
systems.50 They can poison the cathode, precipitate layers (ex: calcium or magnesium scales) or they can
be oxygen scavengers (such as bisulfate) which remove oxygen from the system.23, 50 Cathodic inhibitors
often rely on quaternary ammonium or alkyl pyridinium compounds.
TRADITIONAL (OLDER) INHIBITORS
Traditional inhibitors used in oilfield production wells up until modern times are considered
inorganic anodic, inorganic cathodic and organic anodic. They can be roughly grouped into: 49, 50






Amines (Imidazolines) and salts of amines
Chromates
Nitrites
Amino acids
Benzoates
Phosphates
All of these have some drawbacks; many require high dosages and are not biodegradable.
Nitrites are susceptible to localized attack and others are only acceptable for certain materials (such as
benzoate which works best for mild steels). Others, such as the chromates and nitrites, are toxic and
their use has therefore been limited or even ceased due to environmental damages and safety
regulations. In many cases it is a decision between efficiency and toxicity. Chromium has been shown
to be an effective inhibitor with as little as 0.5-0.3 wt% for low-alloy steels, and in sweet environments it
forms a protective chromium-oxide film, but its use is also limited due to its toxicity.51
Amines with the utilization of organic acids, phosphor and sulfur, are very commonly used since
they form effective micelle in oil and water phases.23, 24 The positive amine end attaches to the metal
surface and the negative hydrophobic ends form a tough, oily protective layer on the surface and
prevent liquids from reaching the metal. It was found21 that initially the amines adsorb in a 1 molecule
thick layer; this is about 1x10-7 mm. Depending on conditions the amines will desorb overtime from the
surface and go back into the bulk solution; this can be anywhere from a few hours to a few weeks to a
number of months depending on the concentrations and temperatures. Imidazolines are the most
effective film forming amines and have been shown to be quite stable, even at temperatures exceeding
125⁰ C.21, 24
GREEN (NEWER) INHIBITORS
Green inhibitors are becoming more and more popular due to the fact that they are
biodegradable, and they don’t contain any heavy metals or other toxic compounds. Plant extracts used
as inhibitors are gaining leverage because they are readily available at low cost and are renewable (to an
extent); though sadly their inhibitive properties are only applicable at surface conditions and are almost
22
never used in oil production.21, 40, 49, 50, 52 A study by Khamis53 shows that certain herbs can act as
inhibitors for steels in an acidic environment; these are thyme, coriander, hibiscus, anis, black cumin and
garden cress. Studies on the effects of natural honey and rosemary were also made, although these
results were not consistent and only showed resistance in certain metals under certain conditions.50
Green inhibitors can be said to be organic cationic with active groups such as aliphatic and
aromatic or polar (hydrophilic) amine groups and oily hydrocarbon (hydrophobic) chains as was
discussed for older inhibitors and can act as surfactants and stabilize oil and water emulsions.21, 50 They
can range from rare earth metals to organic compounds.50 Popular green inhibitors tend to rely on
phosphonates. Mostly their surface adsorption is accomplished through the polar atoms: O, N, P and
S.21, 48, 53 And even though some of their components are not those that one would normally consider
“green” it is the fact that these components are biodegradable and do not accumulate that makes them
green. Nor do they contain mutagens or carcinogens and they do not have long term damaging effects
on the environment. One source21 even described the types of adsorption they represent as occurring
through:



-bond orbital adsorption
Electrostatic adsorption
Chemisorption
Often the plant extracts are mixed with existing inhibitors to obtain the desired effects.
Drawbacks of biodegradable inhibitors are that their storage and long-term use are limited, they require
very high concentrations and often they are not satisfactory at lowering the corrosion rates.
Plant extracts have been tested in a number of studies but with great inconsistency. Most often
they only show promising results under very narrow conditions and for very few metals. Tannins,
alkaloids, organic plant dyes and organic amino acids are the areas of interest for the near future.50 In
recent years inhibitors doped with sol-gels along with APGs have been quite promising.49, 52 One study54
also lists cerium-salicylate as a green inhibitor for steel.
INHIBITOR AND CORROSION TESTING METHODS
Corrosion testing may be one of the most important aspects of corrosion engineering. Having
reliable testing methods is desirable for companies and lowers their costs by decreasing the need for
repairs and replacements. Having the best performing material in operation also decreases wasted time
and effort.26 Even though this is the case, tests are often poorly performed or results poorly reported.
This leads to misinterpretation of information. In designing acceptable testing methods the two most
important criteria are reproducibility and reliability; 22 the best way to reach these goals is through
careful planning and execution. Testing methods, even in oil production, can still encompass a wide
range of goals: 26 determining the best materials, predicting life expectancy of the equipment, evaluating
corrosion resistance, etc. They can be grouped according to where they are performed: 21, 22, 26, 55
23



Laboratory tests
Pilot-plant tests
Plant or Field tests
NACE International provides full lists of international standards: “Recommended Practices”, “Test
Methods”, “Materials Requirements” and “Standards”.56 These practices span a large amount of data
and range from the handling and proper usage of inhibited oilfield acids (RP0273) to preparation and
installation of corrosion coupons and interpretation of test data in oilfield operations (RP0775). These
practices can be used as they are, though they tend to be adapted somewhat to meet specific
requirements. Examples of some testing methods presented by NACE International and applicable in
oilfield production are the following: 56
-
-
TM0171 - Autoclave Corrosion Testing of Metals in High-Temperature Water
TM0172 - Determining Corrosive Properties of Cargoes in Petroleum Product Pipelines
TM0274 - Dynamic Corrosion Testing of Metals in High-Temperature Water
TM0374 - Laboratory Screening Tests to Determine the Ability of Scale Inhibitors to Prevent the
Precipitation of Calcium Sulfate and Calcium Carbonate from Solution (for Oil and Gas Production
Systems)
TM0177 - Laboratory Testing of Metals for Resistance to Specific Forms of Environmental Cracking in H 2S
Environments
TM0284 - Evaluation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking
TM0194 - Field Monitoring of Bacterial Growth in Oilfield Systems
TM0296 - Evaluating Elastomeric Materials in Sour Liquid Environments
TM0198 - Slow Strain Rate Test Method for Screening Corrosion-Resistant Alloys (CRAs) for Stress
Corrosion Cracking in Sour Oilfield Service
In this paper the topic will be narrowed and will focus on laboratory testing methods of the
effectiveness of chemical inhibitors. It is important that models of a metal to be tested resemble the
actual metal, particularly the surface, as closely as possible, from the grain size to the surface condition;
often this includes the cleaning of the metal before testing.22 Next, inhibitor transport tests allow for the
proper inhibitor selection. These include solubility and compatibility tests usually in oils and brines since
these are the conditions often encountered in the oil and gas production. Once a number of inhibitors
have been selected, parallel tests should be performed to compare their effectiveness. The corrosion
rate can also be thought of as the penetration rate and the easiest way to compare inhibitors is by
calculating protection efficiency (in percent) from the corrosion rate.
Testing methods can be labeled as direct or indirect.48
DIRECT METHODS:
Direct methods are most often used and tend to yield the most precise results, though they
usually take longer than indirect methods. They utilize weight loss of a metal over time, usually in the
form of a metal coupon.48 Although coupons are the most popular, rods, strips, etc. can be used and all
24
are exposed to the replicated corrosive environment (salts, acid gases CO2 or H2S, etc.). This is done in a
controlled manner so that all the variables can be tested. Autoclave testing is very popular since the
high temperatures and pressures found in reserves can be safely reached. The dynamic (wheel tests)
and hydrodynamic methods (flowing gas phases), described in a later “Laboratory Work” section of this
paper, also employ weight loss calculations. The measured weight loss of the test coupons, along with
the exposure time are used to calculate corrosion rates (in mm/y).
INDIRECT METHODS:
Indirect methods tend to give quicker results (in as little as a few minutes); they rely on the
electrochemical processes present such as cathodic reactions and polarization curves and are usually
used when uniform corrosion is encountered. For example hydrogen atoms entering a metal can be
measured and give a decent potential for hydrogen blistering, which can be quite damaging. (This
method is used for sour systems) Linear polarization resistance (LPR) is quite popular as it can give
instantaneous readings. LPR uses the slope of the potential-current density curve at the free corrosion
potential (which is the polarization resistance of the material) which can be related to the corrosion
current. Potentiodynamic and potentiostatic polarization methods exist where working electrode’s
potentials are changed and the resulting currents are monitored.48 The corrosion potential and the
polarization resistance both have effects on the corrosion rate because they indicate changes in the
anodic or cathodic reactions.26 Electrochemical impedance spectroscopy (EIS), also known as AC
impedance, is somewhat different from the other techniques and has been reported to be successful.26
It works by applying small amplitudes of signal to the test electrode over a range of frequencies. The
results are more difficult to interpret as they have to be fitted to the resulting EIS curve.
Electrochemical noise (EN) tests are the most sensitive and are popular since they are non-intrusive.
Instruments have been developed to measure fluctuations of the potential or the current of the
corroding metallic material as functions of time.26 The well known oscillations of electrochemical
processes are easily convertible to electrochemical noise. No matter what type of tests are considered,
their reproducibility is of utmost importance.
LABORATORY WORK
The following work was completed in MOL’s corrosion laboratory in Bekasmegyer, Hungary.
One traditional, proven to work, organic inhibitor was tested along with a few newer green inhibitors.
Due to confidentiality reasons the names of the specific inhibitors cannot be given and will therefore be
referred to as:




Traditional inhibitor  “A”
Green inhibitor #1  “B”
Green inhibitor #2  “C”
Green inhibitor #3  “D”
25
As was discussed in an earlier section of this paper entitled “Corrosion Testing Methods”, NACE
International outlines many testing methods of inhibitors used in oilfield production. In the following
work a number of those tests were closely followed but with some degree of variation because MOL has
its own corrosion testing priorities and methods.
Throughout the tests two salt-concentration models for water were used. The first model
attempts to replicate natural gas reservoirs in which the salt concentration is low (120 ppm, 50 mg/L
NaCl and 70 mg/L NaHCO3). The condensed waters that accompany natural gas extraction can have salt
concentrations comparable to distilled water. The second model attempts to duplicate oil wells around
which water is injected to help excavate the oil. In this case the produced water usually has a high salt
concentration (as high as 10,000 ppm, the salt concentration of sea water). The high concentration of
salt is due to fact that oil, unlike in gas, is able to dissolve salt. Salt concentrations higher than 10,000
ppm can be found in places such as near the North Sea. Salinities recorded in wells depend on well
location and the mode of formation. A saturated salt solution of NaCl would contain about 35,000 ppm
NaCl, and as other salts are included this value decreases. The gas composition used in the experiments
to replicate sour corrosion was: 87% CO2, 3% H2S, 10% methane. (In Hungary 3% is the highest recorded
value for H2S concentration in production wells.) Precise inhibitor concentrations are measured
throughout the tests by diluting the inhibitors and measuring with Hamilton syringes.
Brief descriptions of the inhibitors used are the following:
INHIBITOR “A”: produced by NALCO EXXON:




Benefits:
o Proven to be a very effective corrosion inhibitor against sweet and sour corrosion, and
for trace amounts of O2
o Forms stable dispersion in oilfield brines
o Soluble in hydrocarbons
o Contains demulsifiers
Description and uses:
o Inhibitor “A” is an oil-soluble/ water dispersible corrosion inhibitor making it effective in
oilfield, high water-cut systems when there is low laminar flow.
o It can be applied in batch (200-2,000 ppm) or continuous (5-10 ppm) treatment on
liquids.
Compatibility:
o Can be used with carbon and stainless steels, and teflons
o Should not be used with polypropylene, polyethylene or other rubbers.
Safety considerations:
o Composition and hazardous materials:
 Diesel Fuel No. 2: 60.0-100.0 (w/w) % - solvent
26
o
 Light Aromatic Naphtha: 1.0-5.0 (w/w) % - active ing.
 Diethylenetriamine: 1.0-5.0 (w/w) % - active ing.
 1, 2, 4- Trimethylbenzene: 0.1-1.0 (w/w) % - active ing.
 Fatty acid-amine condensate: 30.0-60.0 (w/w) % - active ing.
 Mesitylene: 0.1-1.0 (w/w) % - demulsifier
Causes burns. Limited evidence of a carcinogenic effect. May cause sensitization by
skin contact. Toxic to aquatic organisms, may cause long-term adverse effects in the
aquatic environment. Harmful: may cause lung damage if swallowed.
INHIBITOR “B”: produced by BAYER:




Benefits:
o Is 74% readily degradable in 5% solution
o Contains no mutagens or carcinogens
o Does not accumulate in the environment
o Soluble in oilfield brine waters
o Not toxic to aquatic life
Description and uses:
o Can be used as a scale inhibitor or a dispersing agent
o Can be applied in batch or continuous modes
o Forms stable dispersions in alcohols
o Molecular formula of [C4H4NO3Na]x
o Composition:
 Assay of polyaspartic acid sodium salt (min. 38%) – active ing.
 Water (40-60%) - solvent
o In a 10% solution it has a pH of 9.5-10.5
Compatibility:
o Compatible with most carbon steels and stainless steels, not with rubbers.
Safety Considerations:
o Irritating when inhaled
o Causes burns
o No hazardous decomposition products, or thermal decomposition if used and handled
correctly
INHIBITOR “C”: produced by BAKER PETROLITE:


Benefits:
o Is 99.99% biodegradable in 20 days
o Is completely soluble in most brine systems
o Will inhibit sweet and sour corrosion by adsorption at the active corrosion sites
Description and uses:
o Is a liquid formulation of amine salts of organic phosphates in an aqueous solvent
system
o Can be used in crude oil or natural gas production systems
o Can be applied in water injection systems and where high water solubility is required.
o Components:
27



Ethanediol (ethylene glycol): 10-30% - anti-freezing ing.
Ethoxylated Imidazolines (oxylation of imidazolines benefits their environmental
profile): 5-10% - active ingredient
 Propan-2-ol: 1-5% - solvent
 Quaternary ammonium compounds: Benzyl Chlorides (Can be multiple
combinations; the point is that they are ammonium salts in which organic
radicals are substituted for the hydrogen. The central nitrogen should be joined
to 4 organic radicals and one acid radical): 1-5% - active ing., emulsifier
 Thioalcohol (aka sulfur alcohols) (can be methyl, ethyl, etc.): 1-5% - active ing.
 Trideceth-6-phosphate: 5-10% - active ing. (corrosion/scale inh.)
 Water: 35-80% - solvent
o Even though some of the components (Ethanediol, propan-2-ol and the sulfur
containing thioalcohols) are not safe in themselves; the bacteria in the water will
degrade them to a point where they no longer pose a threat to the environment.
Considerations:
o Ethanediol and Propan-2-ol exposures are limited in the work-place
o Highly flammable, harmful if swallowed. Toxic by inhalation and burns skin. Irritating to
eyes and toxic to aquatic life IF not disposed of properly. Vapors can cause drowsiness
and dizziness.
o Can corrode to form carbon dioxide, carbon monoxide and oxides of nitrogen
INHIBITOR “D”: produced by BAKER PETROLITE:




Benefits:
o Is 90% readily degradable
o Is completely soluble in most brine systems.
o Will inhibit sweet and sour corrosion by adsorption at the active corrosion sites.
o Good environmental profile when handled correctly
o Excellent cold weather handling properties until 60°C
o Very cost effective
Description and uses:
o Composition:
 Acid phosphate esters: 5-10% - active ing.
 Propan-2-ol: 60-100% - solvent
 Quaternary Ammonium compounds: benzyl chlorides: 5-10% - active ing.
o Can be used in crude oil or natural gas production systems
o Can be applied in water injection systems and where high water solubility is required.
Compatibility:
o Compatible with stainless steels, polyethylene and polypropylenes
o Not compatible with mild steels, aluminums or nylons
Safety Considerations:
o Irritating to skin
o Causes severe damage if swallowed
o Toxic if inhaled
28
INHIBITOR SELECTION METHODS:
Solubility Testing
The solubility of the inhibitors was tested in water, hydrocarbon condensate (gasoline), methanol
and glycol. About 1 mL of the clean inhibitor was added to 10 mL of solvent in test tubes which
were shaken, left for 24 hours and the solubility observed. Solubility is important because a large
amount of dissolved inhibitor increases the chance that the inhibitor will adequately coat all
possible surfaces of the equipment. The results were as follows:

INHIBITOR “A”:
Inhibitor color
Solubility in:

Yes (dispersible)
Yes
No
Yes
Water
Gasoline
Methanol
Glycol
Light Brown
Yes
No
Yes (dispersible)
Yes
INHIBITOR “C”:
Inhibitor color
Solubility in:

Water
Gasoline
Methanol
Glycol
INHIBITOR “B”:
Inhibitor color
Solubility in:

Brown
Amber
Water
Gasoline
Methanol
Glycol
Yes (dispersible)
Yes
Yes
No
INHIBITOR “D”:
Inhibitor color
Solubility in:
Amber
Water
Gasoline
Methanol
Glycol
Yes
No
Yes
Yes
29
Sometimes the inhibitors were easily soluble in the
solvent as was the case for inhibitor “B” in water.
Other times the inhibitors were only slightly
soluble and the test tubes required agitation to
dissolve low amounts of inhibitor as was the case
for “B” in glycol. Figure 7 shows the solubility
results for inhibitor “B”. Here it is seen that “B”
dissolves completely in water, is relatively
insoluble in gasoline, only dispersible in methanol,
and slightly solububle in glycol.
Compatibility Testing
Figure 7
From left to right is seen inhibitor “B” in: water,
The compatibility of the inhibitors was tested in 10,
gasoline, methanol and glycol
15, 20 and 30% water/ methanol mixtures. Low
salt-content water was used. The inhibitors were diluted to 10% in their respective solvents
(depending on the results of solubility tests). Inhibitor “A” was diluted with gasoline, “B” with
water and “C” with methanol. Then 1 mL of the diluted inhibitor was added to 9 mL of the
respective methanol mixture. Methanol compatibility is important because waters containing
carbon dioxide often freeze and methanol is added as an antifreeze agent. Methanol is the most
often used hydrate (frozen natural gas) inhibitor in oil producing fields. Corrosion inhibitors are
almost always injected in a dilute methanol solution. The test tubes were shaken and left to sit for
24 hours after which time they were observed for stability. The following results were obtained:

INHIBITOR “A”:
Compatibility in water content
methanol
10%
15%
20%
30%

Not Stable
Not Stable
Not Stable
Not Stable
INHIBITOR “B”:
Compatibility in water content
methanol
10%
15%
20%
30%
Stable
Stable
Stable
Stable
30

INHIBITOR “C”:
Compatibility in water content
methanol
10%
15%
20%
30%

Stable
Stable
Stable
Stable
INHIBITOR “D”:
Compatibility in water content
methanol
10%
15%
20%
30%
Stable
Stable
Stable
Stable
Compatibility results can sometimes be seen immediately; whereas in
other cases they are difficult to discern and the materials in the test tubes
must be given sufficient time to settle. Figure 8 shows the tests of
inhibitors “A” and “B” in 30% methanol solutions. Here it is quite obvious
that “A” is not compatible with methanol while “B” is. Such results are
not always so obvious.
Emulsion Testing (5000 ppm inhibitor)
Figure 8
The tendency of the inhibitors to create emulsions was tested using 5000 On left “A” on right “B”
ppm inhibitors in ratios of 1:1, 1:4 and 4:1 of Dunasol/water. The first
mentioned Dunasol-water mixture has a boiling point of 180⁰ C and the final 220⁰ C. It is a light
solvent with a low aromatic and sulfur content and resembles gasoline. Once again water with a
low salt content was used and 1 mL of the clean inhibitor was added to the mixtures and mixed for
2 minutes. The mixture was quickly poured into a 200 mL graduated cylinder and the time
required for the phases to separate measured. This test was performed at room temperature. The
desired outcome is a low separation time so that the inhibitor can be applied in the field.

INHIBITOR “A”:
Emulsion forming Tendency
Dunasol and water
Separation Time (Min.)
3:30
3:00
1:00
Ratio
1:4 Dunasol/ water
1:1 Dunasol/ water
4:1 Dunasol/ water
31

INHIBITOR “B”:
Emulsion forming Tendency
Dunasol and water

Ratio
1:4 Dunasol/ water
1:1 Dunasol/ water
4:1 Dunasol/ water
Separation Time (Min.)
2:30
0:30
0:20
Ratio
1:4 Dunasol/ water
1:1 Dunasol/ water
4:1 Dunasol/ water
Separation Time (Min.)
1:00
2:00
4:00
Ratio
1:4 Dunasol/ water
1:1 Dunasol/ water
4:1 Dunasol/ water
INHIBITOR “C”:
Emulsion forming Tendency
Dunasol and water

Separation Time (Min.)
Instant
Instant
Instant
INHIBITOR “D”:
Emulsion forming Tendency
Dunasol and water
Emulsion values can be estimated from the solubility tests. The emulsion time will be less when
the soluble phase is present in a greater amount. Take inhibitor “A” for example. It is soluble in
gasoline but not in water. Therefore, it can be estimated that the emulsion time will be low when
the ratio of Dunasol to water is high and vice versa. The fact that inhibitor “B” has an
instantaneous separation time is a promising characteristic. All of the recorded emulsion times
are considered excellent. Separations occurring within minutes are acceptable; it is when they
take longer that they pose problems. From this it can be said that all the tested inhibitors can be
used in both squeeze and batch treatments since they to not interfere in the recovery of gas.
Static and Persistence Test in Autoclaves (50 and 150 ppm inhibitor)
Static testing of the inhibitors using metal test coupons placed in autoclaves was performed. Five
hundred mL of the prepared low-salt-content water was placed in glass beakers that were into the
autoclaves. Test coupons of carbon steel (CS1018) were measured using a digital scale with care
taken to wear gloves so that oil from one’s skin would not contaminate the test coupon. Once
placed in their plastic holders the coupons were inserted into the water filled beakers. Parallel
tests were done using a blank sample and inhibitor concentrations of 50 and 150 ppm. The 12 test
beakers were then placed into 4 autoclaves, the apparatus were properly sealed and the required
gas composition injected; 20 bars H2S, followed by 50 bars CO2, and finally filled to 80 bars with
N2. After a final temperature of 80⁰C was reached the pressure was raised to 150 bars.
32

SAFETY NOTE: When working with H2S extreme care needs to be taken as the gas is highly
toxic. Proper ventilation and gas catching equipment is required. Work with H2S should
never be performed alone, there should always be a lab buddy present in case an accident
occurs.
The apparatus was then left for 4 days after which time the gases were safely disposed of and the
autoclaves opened. The test coupons were removed from the liquid, placed in an inhibitor
solution of hydrochloric acid (1 part water, 1 part concentrated HCl and .002 part inhibitor to keep
the metal from being eaten away) to remove corrosion products, and onto an ultrasonic mixing
tray. After mixing for 2 minutes the coupons were removed and scrubbed with scouring powder
(Derma) to remove any remaining materials. After washing they were quickly towel dried to
prevent surface oxidation and quickly weighed on a digital balance. Corrosion rates were
calculated by computer using the formula:
((m2-m1)* 10*365)/ (A*d*ৎ)
Where m2 and m1, respectively, equal the mass of the coupon before and after exposure to the
corrosive environment , A is the the surface area of the coupon, d is the number of days that the
coupon is left in the autoclave, and ৎ is the density of the coupon material. The results were as
follows:

INHIBITOR “A”:
Inhibitor
Conc.
(ppm)
0
50
150
Coupon
Initial
Mass (g)
Final
Mass (g)
Mass
Loss (g)
416
415
417
101
102
103
46.2555
45.9428
46.2950
46.1531
46.1569
46.3099
45.9721
45.6212
46.1799
46.0582
46.1186
46.9721
0.2834
0.3216
0.1151
0.0949
0.0383
0.0254
Corrosion
Rate
(mm/y)
1.0919
Protection,
Efficiency
(%)
-
0.3790
65.29
0.1150
89.47
33

INHIBITOR “B”:
Inhibitor
Conc.
(ppm)
0
Coupon
Initial
Mass (g)
Final
Mass (g)
Mass
Loss (g)
090
091
092
093
096
097
47.6338
47.5109
45.9921
46.1173
46.9709
47.2723
47.3010
47.2306
45.7300
4.8801
46.8096
47.1166
0.3328
0.2803
0.2621
0.2372
0.1613
0.1557
Coupon
Initial
Mass (g)
Final
Mass (g)
Mass
Loss (g)
104
105
106
107
117
118
47.2045
47.8432
45.8690
46.5667
46.3464
47.2395
46.9073
47.4847
45.6922
46.4089
46.3019
47.2064
0.2972
0.3585
0.1768
0.1578
0.0445
0.0331
Coupon
Initial
Mass (g)
Final
Mass (g)
Mass
Loss (g)
210
211
212
213
216
217
46.8245
47.2341
45.9835
46.6622
46.6554
46.1193
46.6001
47.0355
45.8720
46.5356
46.6048
46.0703
0.2244
0.1986
0.1115
0.1266
0.0506
0.0490
50
150

Protection,
Efficiency
(%)
-
0.9011
18.55
0.5721
48.30
Corrosion
Rate
(mm/y)
1.1834
Protection,
Efficiency
(%)
-
0.6039
49.00
0.1401
88.15
Corrosion
Rate
(mm/y)
0.7634
Protection
Efficiency
(%)
-
0.4297
43.7
0.1798
76.45
INHIBITOR “C”:
Inhibitor
Conc.
(ppm)
0
50
150

Corrosion
Rate
(mm/y)
1.1065
INHIBITOR “D”:
Inhibitor
Conc.
(ppm)
0
50
150
From the calculated protection efficiencies it can be seen that “A”, the traditional inhibitor, gave
the best protection; however, “C” and “D” also gave comparable results at
concentrations of 150 ppm. Other than “A” the performances of the other
inhibitors are considered unacceptable at concentrations of 50 ppm. The
performance of “B” was not acceptable at any of the tested concentrations and
seems to offer only very minimal protection. In a visual inspection of the test
34
Figure 9
On left: Inh. “C” at 50 ppm. On right:
blank sample. Both BEFORE washing.
coupons it could be observed that in the blank tests not only was
the water deeply colored but the coupons had a thick corrosion
product layer on them. For “A”, “C” and “D” at concentrations of
50 ppm localized corrosion took place. I believe this is because the
inhibitors worked by forming a protective film over the metal
surface, but this was not enough to cover the entire metal surface,
resulting in severe corrosion at discontinuities in the film. At the
higher concentrations slight uniform corrosion was noted. In
Figure 9 the difference between the blank samples and somewhat
protected coupons can be observed. In addition, Figure 10 shows the difference between
localized and uniform corrosion of the samples.
Figure 10
Dynamic Testing (100 ppm inhibitor)
On top: uniform. On
bottom: localized. Both
after washing
Dynamic testing of the inhibitors was performed at atmospheric pressure in
hot oil. Low-salt-concentration water was used and the measured test coupons
(C1018) were placed in holders in containers containing 450 mL process water
and 100 ppm of inhibitor. I decided that 50 ppm inhibitor tests were not worth performing as the
“green” inhibitors have very low protection efficiencies at such low concentrations. CO2 as a
corrosive agent was bubbled through the test mixtures for 4 minutes to remove any air from the
water, after which time the container was quickly shut tight in the same manner as an autoclave.
The containers were “rolled” to thoroughly mix them and placed into a hot (80⁰ C) oil bath. Inside
the oil bath was a chain which rolled the containers at a speed of 20 rpm allowing the coupon to
contact both the gaseous and the liquid phases present. The continuous rolling motion is the
reason for the test name “dynamic”. After 24 hours the coupons were removed, cleaned in the
same manner as in the Static Testing and values recorded.
100 ppm of
Inhibitor
Coupon
Initial Mass
(g)
Final Mass
(g)
Mass Loss
(g)
Blind
1457
1458
1463
1464
1465
1466
1461
1462
1459
1460
14.7578
14.7894
14.7678
14.5583
14.7794
14.8033
14.7800
14.8036
14.7512
14.7737
14.5902
14.6208
14.7519
14.5387
14.6899
14.7062
14.7457
14.7661
14.7193
14.7432
0.1676
0.1686
0.0159
0.0196
0.0895
0.0971
0.0343
0.0375
0.0319
0.0305
“A”
“B”
“C”
“D”
Corrosion
Rate
(mm/y)
0.6068
Protection
Efficiency
(%)
-
0.0641
89.4
0.3368
44.5
0.1296
78.6
0.1126
81.4
The dynamic test, like the static autoclave test showed that the
traditional inhibitor “A” has slightly better protection ability than the
green inhibitors (excluding “B”). In dynamic tests“D” proved to have
a somewhat better protection ability than “C”, in contrast to the
35
results of static tests. I believe the difference between the static and dynamic test results were
due to fact that different inhibitor concentrations were used in the two tests. In the dynamic tests
the difference between using an inhibitor and not using an inhibitor could be observed instantly
upon opening the cells, as is seen in Figure 11; the darker the color the more corrosion product
can be expected and vice versa. In this figure localized corrosion can also be observed where
protection films are disrupted. Figure 12 shows the readily apparent difference between severe
uniform and localized corrosion along with the protected specimen.
Figure 11
On top: clean water; on
bottom: corrosion polluted
36
Hydrodynamic Test (300 ppm inhibitor)
A hydrodynamic test was the last inhibitor test performed. The apparatus used was only
capable of testing 3 inhibitors at a time plus a blind. Inhibitor “B”, therefore, was left out due to its
poor performance in the previous tests. The hydrodynamic test measures corrosion rates through
weight loss and by continuous linear polarization resistance readings. High-salt-concentration
water (10,000 ppm) was used, as discussed previously, to simulate EOR methods that rely on
water injection. Inhibitor concentrations of 300 ppm were injected. This high concentration of
inhibitor was used because the hydrodynamic test is an 8 hour test that can NOT be left to run on
its own and a person must be present for the entire 8 hours. If low concentrations are used then
the amounts of corrosion would not be ample enough to draw any conclusions. The apparatus’s
heating water was turned on the night before to ensure the desired 80⁰ C was reached by the
following morning when 500 mL process water was poured into each of the 8 inner cells present in
the apparatus. Aterwards 300 ppm inhibitor was injected in the proper places and the test
coupons slowly lowered into the test cells by means of attached rubber bands. The electrodes
that measure linear polarization are introduced into the system through the plugs, and once the
system is closed the following corrosive gases are turned on:



200 L/h CO2
20 L/h methane + H2S
20 L/h air
Note: The electrodes should first be soaked in an inhibited concentrated HCl solution (the same
used for cleaning the coupons) and scrubbed with scrubbing powder to remove previous corrosion
products then dried with gas and covered until used to prevent oxidation of the electrode
surfaces.
It can be observed in Figure 13 that the electrodes are
inserted into the cells at the top (through a plug). At the
bottom of the cells the test coupon can be seen with its
attached rubber band used to lower and remove the coupon.
The gases going to each chamber of the apparatus should be
individually checked to make sure that the flow to all
chambers is equal (~25 L/h); these flows can be individually
adjusted. Then using a “CorrOceanII” device the linear
polarization resistance in each chamber is read every 15
minutes. The device automatically calculates the corrosion
rate in mm/y from the resistances.
Figure 13
The gas flows should be frequently checked as the rates of
flow can change quite drastically in a number of minutes; care
On left is blank cell (notice dark color);
should be taken to make sure that they stay within the on right is cell with “A” (notice light color
desired range. The test is run for 8 hours after which time the and positioning of electrode and coupon
gases are safely disposed of and the coupons examined in the
same way as described in the previous tests. The following results were obtained:
37

LINEAR POLARIZATION RESISTANCE READINGS:
- Shown are the average LPR readings of the parallel tests.
Time
(min.)
Blind
cells 1-2
(mm/y)
Inh. "A"
cells 3-4
(mm/y)
Inh. "D"
cells 5-6
(mm/y)
Inh. "C"
cells 7-8
(mm/y)
0:15
0:30
0:45
1:00
1:15
1:30
1:45
2:00
2:15
2:30
2:45
3:00
3:15
3:30
3:45
4:00
4:15
4:30
4:45
5:00
5:15
5:30
5:45
6:00
6:15
6:30
6:45
7:00
7:15
7:30
7:45
8:00
8:15
1.2013
1.1427
0.9276
0.9307
0.9215
0.9321
0.6733
0.6428
0.5930
0.5812
0.5413
0.5397
0.5349
0.5124
0.5288
0.5075
0.4725
0.4812
0.4855
0.4902
0.4946
0.5004
0.4759
0.4925
0.4476
0.4357
0.4512
0.4324
0.4426
0.4324
0.4255
0.4286
0.4211
0.3311
0.1236
0.1059
0.0909
0.0802
0.0768
0.0711
0.0632
0.0579
0.0546
0.0531
0.0531
0.0525
0.0504
0.0511
0.0500
0.0498
0.0447
0.0479
0.0452
0.0435
0.0411
0.0407
0.0396
0.0386
0.0398
0.0381
0.0370
0.0374
0.0372
0.0369
0.0421
0.0423
0.2866
0.1435
0.0982
0.0809
0.0734
0.0698
0.0627
0.0601
0.0557
0.0561
0.0555
0.0552
0.0549
0.0518
0.0522
0.0507
0.0494
0.0504
0.0507
0.0499
0.0492
0.0498
0.0500
0.0489
0.0499
0.0475
0.0463
0.0464
0.0453
0.0455
0.0449
0.0450
0.0453
0.3675
0.3204
0.1999
0.1287
0.0910
0.0890
0.0754
0.0726
0.0698
0.0758
0.0882
0.0870
0.0913
0.0917
0.0897
0.0888
0.0867
0.0752
0.0692
0.0644
0.0591
0.0621
0.0614
0.0607
0.0608
0.0578
0.0594
0.0612
0.0714
0.0694
0.0675
0.0689
0.0678
300 ppm
38

EFFICIENCY BASED ON AVERAGED LPR RESULTS:
Inh. “A”
Inh. “D”
Inh. “C”
Time
Eff-LPR
"A" Inh.
(%)
Eff-LPR
"D" Inh.
(%)
Eff-LPR
"C" Inh.
(%)
0:15
0:30
0:45
1:00
1:15
1:30
1:45
2:00
2:15
2:30
2:45
3:00
3:15
3:30
3:45
4:00
4:15
4:30
4:45
5:00
5:15
5:30
5:45
6:00
6:15
6:30
6:45
7:00
7:15
7:30
7:45
8:00
8:15
72.4
89.2
88.6
90.2
91.3
91.8
89.4
90.2
90.2
90.6
90.2
90.2
90.2
90.2
90.3
90.1
89.5
90.7
90.1
90.8
91.2
91.8
91.4
92.0
91.4
90.9
91.6
91.4
91.5
91.4
91.3
90.2
90.0
76.1
87.4
89.4
91.3
92.0
92.5
90.7
90.7
90.6
90.3
89.7
89.8
89.7
89.9
90.1
90.0
89.5
89.5
89.6
89.8
90.1
90.0
89.5
90.1
88.9
89.1
89.7
89.3
89.8
89.5
89.4
89.5
89.2
69.4
72.0
78.4
86.2
90.1
90.5
88.8
88.7
88.2
87.0
83.7
83.9
82.9
82.1
83.0
82.5
81.7
84.4
85.7
86.9
88.1
87.6
87.1
87.7
86.4
86.7
86.8
85.8
83.9
84.0
84.1
83.9
83.9
39

EFFICIENCY BASES ON WEIGHT LOSS:
-Average weight losses were the following:
300 ppm of
inhibitor
Coupon
Initial
Mass (g)
Final
Mass (g)
Mass Loss
(g)
Blind
1470
1471
1472
1473
1474
1475
1476
1477
14.8080
14.6990
14.8033
14.7586
14.8169
14.8737
14.7599
14.8142
14.7965
14.6880
14.8024
14.7576
14.8150
14.8716
14.7582
14.8123
0.0115
0.0110
0.0009
0.0010
0.0019
0.0021
0.0017
0.0019
“A”
“C”
“D”
Corrosion
Rate
(mm/y)
0.4873
Protection
Efficiency
(%)
-
0.0411
91.5
0.0866
82.2
0.0780
84.0
Graph 1
The results of the LPR and weight loss measurements for the hydrodynamic tests are shown by
Graph 1. It should be noted that the weight loss of the coupons throughout the measurement is NOT
constant. The reason for including the overall weight loss efficiency of the coupons over the 8 hour testtime interval is to give a comparison of the weight loss results against the LPR results. The LPR
measurement is performed every 15 minutes during testing; whereas, the weights are measured once
before corrosion takes place and once after. It can also be observed from the graphed results that the
LPR-derived efficiency values for the “C” inhibitor oscillates in a range of about 10% whereas that of
inhibitors “A” and “D” stay in a range of about 1%. I believe this high oscillation of calculated “C” values
can be explained by one or another of two possible phenenon (or possibly both):
1. During the measurement it was observed that in cell 7 the bubbling of the water seemed to be
constantly fluctuating. This suggests that there might have been a glitch in the apparatus
causing the amount of corrosive gas entering the cell to vary with time. Perhaps higher than
average values on the graph represent instances when relatively large amounts of acid gas were
injected into the system; the reverse being true for values lower than average. Possibly a
difference in the porosity of the cells caused injected gas flow fluctuations.
2. Another explanation for the observed oscillations could be a result of the formation and
detruction of protective layers on the surface of the coupons. The observed increases in
efficiency could mark times when protective layers were forming, and the observed decreases
would mark times when a protective layer was absent after being washed away.
In either case the test was performed over a span of 8 hours, enough time for the supposed fluctuations
about an average value to have taken place. If the tests were repeated and the order of the cells
switched it might be possible to obtain more insight into the problem.
40
CONCLUSIONS
From the results of my laboratory testing of inhibitors “C” and “D” I can conclude that in some
cases new “green” inhibitors can be as effective as traditional, organic inhibitors. This is not always the
case, as was seen from the results obtained with inhibitor “B”; however, traditional inhibitors aren’t
always as efficient as expected either. In reality success in obtaining inhibitors for a given task is always a
trial and error process. Inhibitor “A”, proven before hand to be an effective traditional inhibitor, as
expected displayed excellent protection efficiency in all tests; protection efficiency values as high 91%
were recored. Even at a low concentration of 50 ppm, “A” still recorded the highest efficiency value,
over 15% better than any of the other tested inhibitors. One possible drawback to the use of “A” is that
it is toxic and complications can arise from its low solubility in alcohols. Inhibitor “B”, on the other hand,
showed promising results in the inhibitor selection tests: it faired well in solubility tests, was stable in all
methanol solutions and displayed instantaneous emulsion separation times. But, it showed extremely
low protection efficiencies even at high concentrations, and at low concentrations it offers practically no
protection (18% efficiency). Inhibitor “C”, at a concentration of 150 ppm, recorded a protection
efficiency of 88% in autoclave tests, only one percent less than that of “A”. This high protection
efficiency value for “C” held true through all the tests; its recorded efficiency value, however, did drop
somewhat, as might be expected, when the concentration was lowered to 100 ppm. In the
hydrodynamic test it was not obvious why the protection efficiency of “C” decreased when the
concentration of inhibitor was increased; certainly it was thought that the protection value would
correspondingly increase, and no reasonable explanation was found to explain this decrease. Inhibitor
“D” closely followed expectations; at a concentration of 50 ppm it offered some protection and at
concentrations of 100 and 150 ppm it displayed ample protection. In all tests “D” displayed high
protection efficiencies values; the values closely compared to those recorded for “A”. The LPR results of
the hydrodynamic testing of “D” at concentrations of 300 ppm recorded a protection value of about
90%. This vaue of 90% for “D” differs significantly from the efficiency value (84%) for “D” derived from
weight loss calculations recorded during hydrodynamic tests; the 6% difference might have been the
result of corrosion products remaining on the electrodes after cleaning. The results of these tests
indicate that green inhibitors can be as effective as traditional inhibitors, and due to their
biodegradability and environmentally friendly profiles, might, in some cases, be considered superior to
some traditional inhibitors. The major drawback to green inhibitors is that they require high
concentrations in order to obtain satisfactory results.
These tests were performed in sour environments and can not be expected to be reproducible
for other environments. For example, inhibitor “B”, although scoring very low in these tests, might rank
high if tested for prevention of encrustation in a water treatment plant, while the others would fail at
the task. I believe more comprehensive results could have been obtained if a greater range of inhibitor
concentrations were tested (perhaps at concentration intervals between 20 ppm and 500 ppm) and if
corrosion in sweet environments was also tested.
41
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