Crude oil, as a mixture of all sorts of hydrocarbons, is not corrosive. However, there are some other impurities and components often found in crude oil that could cause corrosion in pipelines, vessels and refinery equipment, such as atmospheric columns, overhead lines, exchangers and condensers. In fact, sometimes the corrosivity of a crude oil is so high that extraction and refining that oil in a cost-effective manner becomes impossible. Here we'll take a look at some of the corrosive substances that may be found in crude, and what can be done to mitigate their effects.

Brackish Water (Chlorides)

In most of cases, water containing chloride salts such as MgCl2, CaCl2 and NaCl is drawn from crude oil wells along with hydrocarbons. The concentration of these salts in the crude oil depends on the oil field from which the crude is extracted, but it is usually present within the range of 3 to 300 pounds per barrel. In heavy crude oils, this value tends to be higher.

During preheating, if the crude oil reaches temperatures of more than 248°F (120°C), these chloride salts break down to HCl. The chemical reaction for CaCl2 degradation can be seen here:

CaCl2 + H2O = CaO + 2 HCl

There is a similar reaction for MgCl2. However, NaCl is more stable and is therefore less easily hydrolyzed. By increasing the preheating temperature up to 716°F (380°C), most of the MgCl2 and CaCl2 salts will undergo hydrolysis.

HCl in gas state isn't dangerous in terms of corrosion. However, when it cools down to temperatures lower than the dew point of water, it reacts with moisture (condensing water) to produce hydrochloric acid, which is an extremely corrosive substance. So, the presence of this so-called "sour acid" (H2S) in the system make corrosion more likely. Once HCl reacts with steel, it will react with iron chloride to reproduce HCl. This causes the ongoing corrosion of steel.

CaCl2 + H2O = CaO + 2 HCl

HCl + Fe = FeCl2 + H2

FeCl2 + H2S = FeS + 2 HCl

One of the ways to mitigate the effects of hydrochloric acid is by adding ammonium (NH3) as a basic material to neutralize HCl. Ammonium can react with HCl to form ammonium chloride (NH4Cl). This substance is highly hygroscopic and can even react with water vapor (steam). The water containing NH4Cl is very corrosive for copper-based alloys, such as brass and bronze.

In the other technique used to reduce this type of corrosion, the crude oil is rinsed with water and sent to a desalting vessel to remove brackish water. Despite all of this, a small concentration of remaining chloride salts in crude oil is enough to cause a failure in the upstream units.

Carbon Dioxide (CO2)

Carbon dioxide stems from three different sources:

  • It is often trapped in oil reservoirs naturally.
  • It is the by-product of reactions in well acidizing work by HCl to stimulate of carbonate, limestone or dolomite reservoirs.
  • Because it is an inexpensive gas, it is most commonly injected into crude oil wells for enhanced oil recovery (EOR).

Carbon dioxide causes a severe kind of corrosion that is called "sweet corrosion". This gas can react with water to produce carbonic acid (H2CO3). The rate of this reaction depends on the temperature and partial pressure of CO2. Generally, when the partial pressure of CO2 is more than 0.5 bars (7 psi), sweet corrosion is expected. It should be mentioned that in some cases, the partial pressure of CO2 in crude oil is considerably more than 400 bars.

Carbonic acid, which is a weak acid that keeps its pH nearly constant in an acidic region, attacks steel and creates iron carbonate, or siderite (FeCO3), as a corrosion product. Detecting the formation of iron carbonate on the surface of steel is one of the ways to recognize sweet corrosion. This corrosion product is usually considered to be a semi-protective layer that can prevent more corrosion. However, dissolved oxygen or high fluid velocity (more than 10 m/s) can remove this layer. In addition, localized corrosion could also occur beneath the corrosion product.

There are two key ways to eliminate or mitigate the sweet corrosion. The first is by adding inhibitors to crude oil. Replacing steel with stainless steels is another way that is becoming more common because adding inhibitors is typically more expensive.

Phantom Chlorides (Organic Chlorides)

Organic chlorides are sometimes called "undesaltable chlorides" because it is impossible to remove them during the salt separation process in desalting vessels. They decompose into HCl in the preheating process and cause severe corrosion in either overhead or downstream units.

To avoid corrosion, the concentration of organic chlorides in crude oil should be less than 1 mg/L. Despite that, their concentration in most of the crude oils tends to range from 3 to 3,000 mg/L.

Organic Acids

Naphthenic acids are a sort of organic acids that can be present in crude oil and cause severe corrosion in certain circumstances. This kind of corrosion, known as naphthenic acid corrosion (NAC), usually occurs at temperatures between 446°F and 752°F (230°C and 400°C) and in the presence of a sufficient quantity of naphthenic acids in the crude oil.

Naphthenic acid corrosion generally happens in refinery distillation units such as furnace tubes, transfer lines, vacuum columns and side cut piping. NAC rarely happens in fluid catalytic units because the temperature at these units is more than 752°F (400°C), which can decompose naphthenic acids. Moreover, in hydrodesulfurizer units, the catalysts can decompose naphthenic acids and eliminate NAC.

The proposed chemical formula of naphthenic acid is R(CH2)nCOOH, where R is one or more cyclopentane rings and n is more than 12. Their atomic mass unit is between 120 and 700. The following reaction shows the interaction between naphthenic acids and steel. The product of this reaction is hydrogen and a complex of iron-organic acid, which is soluble in crude oil.

Fe + 2 RCOOH = Fe (RCOO)2 + H2

In the presence of sulfides in crude oil, Fe (RCOO)2 reacts with H2S to create FeS according to following reaction:

Fe (RCOO)2+ H2S = FeS + 2 RCOOH

FeS is insoluble in water and oil and can form a protective layer on steel at low shear stress of fluid, therefore protecting it from further corrosion. As a result, the presence of sulfides in crude oil might decrease the rate of NAC, especially at low temperatures. On the other hand, the reproduced naphthenic acid keeps the corrosion happening.

NAC is considered to be a localized corrosion and is seen in areas where fluid velocity is high and organic acid vapors are present. The lack of corrosion product in the corroded area is another feature of NAC. Many high-resistance steels that are resistant to sulfur corrosion, including high chromium and even high molybdenum steels, could be susceptible to this kind of corrosion.

The concentration of naphthenic acids in crude oil is shown by the Total Acid Number (TAN). TAN is defined as the amount of potassium hydroxide (in milligrams) needed to neutralize one gram of oil. A normal TAN value in crude oils varies in the range of 0.1 to 3.5 mg/gr. Despite that, higher values of TAN, such as 10 mg/g, have been reported in rare cases. TAN is not a constant characteristic in an oilfield, and can change over a period of time during the extraction of crude oil. It is believed that NAC occurs when TAN is more than 0.5 mg/g. However, in some cases, NAC has been reported for TAN values between 0.3–0.5 mg/g.

According to investigations, just 5% of the naphthenic acids present in crude oil are corrosive. In other words, two crude oils with equal TAN values do not necessarily have to show similar naphthenic acid corrosion behavior.

One of the most common ways to reduce NAC in crude oil refining systems is by blending a high TAN crude oil with a crude oil having low TAN. In this condition, the overall TAN value will be reduced to the immune range (less than 0.3 mg/g). The blending process for a new source of crude oil should be done with caution because, as mentioned in the above, adequate concentration of a certain kind of naphthenic acid in a crude oil with low TAN value can cause a high rate of NAC.

Injecting corrosion inhibitors into the crude oil stream is another method to decrease the naphthenic acid corrosion rate. In this case, the economic issues and effects of inhibitors on downstream processes should be considered. Since NAC occurs at high temperatures and iron sulfide deposits are not formed on the surface, traditional filming amine inhibitors are not suitable. Phosphorous and non-phosphorous containing inhibitors are very effective inhibitors to mitigate NAC. Although the phosphorous containing inhibitors have more inhibition efficiency, their effects on the poisoning of catalysts downstream have to be considered.


Crude oils usually contain sulfides that can cause corrosion at high temperatures. This is called "sulfidation". It is a well-known corrosion in different units in oil refineries. The amount of total sulfur in a crude oil depends on the type of oil field and it varies from 0.05% to 14%. Of course, sulfur values as low as 0.2% are enough to create sulfidation corrosion in plain steels and low alloy steels. These kinds of steels are usually proposed to be used in several parts of refinery units.

Most of the sulfurs in crude oil are in the form of organic molecules (such as mercaptan, alkyd sulfide, sulfoxide and thiophene), and trace amounts of them are elemental sulfur and hydrogen sulfide (H2S). But not all kinds of sulfur compounds are corrosive; only a fraction can react with metallic compounds to create sulfidation corrosion. These are called "active sulfur" and they include elemental sulfur, H2S and low-molecular mercaptan. Despite that, in the presence of H2 gas, most of the organic sulfides—which are categorized into inactive sulfides—decompose to H2S, an active sulfur that can lead to sulfidation. Therefore, sulfidation becomes more severe in the presence of hydrogen gas. H2 is used in hydrocracking and hydrofining units in oil refineries.

Sulfidation happens at temperatures higher than 446°F (230°C) and its rate accelerates when the temperature is raised to 896°F (480°C). At temperatures higher than 698°F (370°C), H2S decomposes into elemental sulfur, which is the most aggressive sulfur compound. In fact, the sulfidation rate reaches its maximum at around 752°F (400°C).

During sulfidation, a protective iron sulfide scale is formed on the surface of a substrate and reduces the corrosion rate. This scale is known as a diffusion barrier layer and its growth follows parabolic kinetics (d=kt½).

However, some factors can cause FeS malfunction. One of those factors is a high velocity of fluids, which can keep this protective scale separate from the metallic surface. The second factor is related to the presence of naphthenic acids in crude oil. As mentioned above, these acids can react with FeS to create soluble compounds. The third factor is related to hydrogen, which can penetrate into sulfide scale and create a porous iron sulfide scale.

The most common technique to control high temperature sulfidation is to select suitable material that is resistant to sulfidation. One of the useful tools for selecting proper steel is using "McConomy" curves. These curves present a variation of sulfidation corrosion rate as a function of temperature and total sulfur content. McConomy curves show that the steels containing more chromium exhibit higher corrosion resistance against sulfidation. Moreover, the corrosion rate increases by increasing the sulfur content and temperature.

In the McConomy curves, the corrosion rate depends on the total sulfur content. However, only active sulfides (such as H2S) can cause sulfidation. In other words, McConomy curves overestimate high corrosion rates. Therefore, the corrosion rates in McConomy curves are decreased by a 2.5 factor, resulting in "Modified McConomy" curves.

The other drawback of McConomy curves is that the effects of fluid velocity and the presence of H2 gas have not been considered in McConomy curves. Therefore, the NACE T-8 committee on Refining Industry Corrosion has introduced the "Couper-Gorman" curves based on a series of experimental surveys. According to Couper-Gorman curves, iron sulfide is not thermodynamically stable and no sulfidation occurs at very low levels of H2S and temperatures above 519°F (315°C).

It should be noted that estimates achieved from either the McConomy or the Couper-Gorman curves are uniform corrosion rates or thickness loss, while the localized corrosion that usually happens and might occur at a higher rate is not considered when estimating the first leak or corrosion allowance.


Microbiologically influenced corrosion (MIC) is an extremely widespread kind of corrosion in oil and gas storage and transportation facilities. Among different types of bacteria, sulfate reduction bacteria (SRB) are the most important kinds of microbes that have caused more than 75% of corrosion failures in oil-producing wells in the U.S. These anaerobic bacteria use sulfate as an acceptor to create sulfide according to the following reaction:

SO42- + H2 = H2S + H2O

Due to the metabolism process, SRB consume hydrogen that is produced by cathodic reaction. Also, H2S is a by-product of SRB metabolism that can increase the corrosion rate by influencing on anodic reaction. In fact, SRB depolarizes both cathodic and anodic reactions to raise the corrosion rate. It should be mentioned that at temperatures higher than 104°F (40°C), the activity of SRB usually stops. The best method to reduce MIC is by adding biocides.