Corrosive components in crude oil


Crude oil, as a mixture of hydrocarbons, is not inherently corrosive, however, there are often impurities and components present that could cause corrosion in pipelines and refinery equipment such as atmospheric columns, overhead lines, exchangers and condensers.

Sometimes the corrosiveness of crude oil is so high that extracting and refining oil cost-effectively becomes very complicated. The costs for repairs, replacement and maintenance of the equipment involved in the transport and processing of crude oil reach exorbitant figures and it is more necessary to stem the problem. The corrosive substances that can be found in crude oil are the following:

1. Brackish water (chlorides)

In most cases, brackish water containing chloride salts such as MgCl2, CaCl2 and NaCl is taken from crude oil wells along with hydrocarbons. The concentration of these salts in crude oil depends on the oil field from which the crude oil is extracted.

During preheating, if the crude oil reaches temperatures above 120°C, the chloride salts decompose into HCl, according to the following chemical reaction:

CaCl2 + H2O = CaO + 2 HCl

A similar reaction is also expected for MgCl2. NaCl, on the other hand, is more stable and is therefore less easily hydrolysed. By increasing the preheat temperature up to 380°C, most of the MgCl2 and CaCl2 salts will undergo hydrolysis.

Hydrochloric acid is an extremely corrosive substance for steel and one of the ways to mitigate its effects is the addition of ammonium (NH3) as a neutralization product, with the formation of ammonium chloride (NH4Cl). On the other hand, this substance is very corrosive to copper-based alloys, such as brass and bronze.

In another technique used to reduce this type of corrosion, the crude oil is washed with water and sent to a desalination vessel to remove the brackish water. Despite the desalination processes, a small concentration of chloride salts remains and is sufficient to cause corrosion and failure.

2. Carbon dioxide (CO2)

CO2 corrosion, also known as "soft corrosion", is a common problem in oil and gas production and transportation facilities and is a major corrosive agent in oil and gas production systems. When mixed with water, CO2 forms carbonic acid (H2CO3), making the fluid acidic. Generally, when the partial pressure of CO2 is above 0.5 bar, soft corrosion is expected (in some cases the partial pressure of CO2 in crude oil significantly exceeds 400 bar). CO2 corrosion is governed by temperature, increase in pH value, aqueous stream composition, presence of non-aqueous phases, stream conditions and metal characteristics.

Carbonic acid is a weak acid that attacks steel by creating iron carbonate or siderite (FeCO3), as a corrosion product. Detecting the formation of iron carbonate on the steel surface is one way to recognize soft corrosion. This corrosion product is generally considered a semi-protective layer that can prevent further corrosion. However, dissolved oxygen or high fluid velocity (more than 10 m/s) can remove this layer; furthermore, localized corrosion could also occur underneath the corrosion product.

To eliminate or mitigate soft corrosion, it is possible to intervene with the continuous addition of inhibitors, but the choice of directly replacing steel with long-lasting stainless steels is becoming more and more common.

3. Organic chlorides

Organic chlorides are impossible to remove during the salt separation process in desalination silos. They decompose into HCl during the preheating process and cause severe corrosion.

To avoid corrosion, the concentration of organic chlorides in crude oil should be less than 1 mg/L. Despite this, their concentration in most crudes tends to vary from 3 to 3.000 mg/L.

4. Organic acids

Naphthenic acids (R(CH2)nCOOH) are a kind of organic acids which can be present in crude oil and cause severe corrosion under certain circumstances. This type of corrosion, known as naphthenic acid corrosion (NAC), usually occurs at temperatures between 230°C and 400°C and in presence of sufficient naphthenic acids in the crude oil.

Such corrosion typically occurs in refinery distillation units such as furnace tubes, transfer lines, vacuum columns, and side shear piping. The phenomenon is rarer in fluid catalytic units because the catalysts and the temperature in these units (above 400°C) can decompose naphthenic acids.

Naphthenic acids react with sulfides in crude oil, creating compounds insoluble in water and oil that can form a protective layer on steel, thereby protecting it from further corrosion. Consequently, the presence of sulphides in the crude could decrease the corrosive rate, especially at low temperatures.

NAC is considered a localized corrosion and is observed in areas where fluid velocity is high and organic acid vapors are present. Many high-strength steels, including steels with a high chromium or molybdenum content, may also be subject to this type of corrosion.

One of the most common ways to reduce NAC in crude oil refining systems is by blending a highly acidic crude with a less acidic one, or by injecting corrosion inhibitors into the oil stream. In this case, economic issues and the effects of inhibitors on downstream processes should be considered. Phosphorus-containing inhibitors are very effective in mitigating NAC, however they may be interfering with end-of-process catalysts.

5. Sulfur

Crude oils usually contain sulphides which can cause corrosion at high temperatures, this phenomenon is called "sulphidation". The amount of total sulfur present in a crude oil depends on the type of oil reservoir and ranges from 0.05% to 14%. Naturally, sulfur values as low as 0.2% are sufficient to create sulfuric corrosion in simple and low alloy steels. These types of steels are often used in different parts of refinery units.

Most of the sulfides found in crude oil are in the form of organic molecules (such as mercaptan, alkyd sulfide, sulfoxide and thiophene) and traces of them are elemental sulfur and hydrogen sulfide (H2S). Not all types of sulfur compounds are corrosive; only a fraction can react with the metallic compounds to create sulfur corrosion. These are called "active sulfur" and include elemental sulfur, H2S, and low molecular weight mercaptan. However, in the presence of hydrogen (used in hydrocracking and hydrofinishing units in oil refineries), most organic sulfides, classified as inactive sulfides, decompose into H2S, an active sulfur which can lead to sulfurization.

Sulfurization occurs at temperatures above 230°C and its rate accelerates as the temperature rises to 480°C. At temperatures above 370°C, H2S decomposes into elemental sulfur, which is the most aggressive sulfur compound; the sulfuration rate reaches its maximum at about 400°C.

During sulfurization, a protective iron sulphide scale forms on the surface of the substrate which reduces the rate of corrosion. Certain factors can cause the FeS to malfunction. One such factor is the high velocity of fluids, which can keep this protective scale separate from the metal surface. The second factor is related to the presence of naphthenic acids in crude oil which can react with FeS to create soluble compounds. The third factor is related to hydrogen, which can penetrate the sulfide layer and create porous iron sulfide scales.

The most common technique for controlling high temperature sulfurisation is to select a suitable material, such as high chromium steels.

6. Bacteria

Microbiologically influenced corrosion (MIC) is an extremely common type of corrosion in oil and gas storage and transportation facilities. Among the different types of bacteria, sulfate-reducing bacteria (SRB) are the most important types of microbes that cause the majority of corrosion failures in oil production wells. These anaerobic bacteria use sulfate as an acceptor to create acid sulfide according to the following reaction:

SO4+ H2 = H2S + H2O

Fortunately, at temperatures above 40°C, microbial activity usually stops. The best method to reduce the MIC is the addition of biocides.