Corrosion in petroleum industry causes a loss of billions of dollars every year. Many cases of extensive corrosion have occurred in production tubing, valves, and in flow lines from the wellhead to the processing equipment. The reason for this is that oil and gas from the well contain varying amounts of water, which can be precipitated as a separate phase in contact with the material surface, and that this water contains gases such as CO2 and possibly H2S, as well as salts. In most cases of severe corrosion, CO2 plays a major role. Uniform corrosion taking place causes 30% failures and other 70% is caused by localized corrosion. Various methods of controlling corrosion are discussed here.
Key words: Corrosion, Petroleum industry.
EVERY industry, even every plant, has its own distribution of corrosion phenomena that occur with different frequency. About 75% of all corrosion failure takes place because of insufficient information and knowledge, as well as inadequate interaction among different groups responsible for the acceptance and approval of anti-corrosion decisions. The human factor is one of the main reasons of corrosion failures. Corrosion problems occur in petroleum industry in three main areas: (1) production, (2) transportation and storage, and (3) refinery operations. Many refineries contain over fifteen different process units, each having its own combination of numerous corrosive process streams and temperature and pressure conditions. The deterioration normally occurs very slowly, unless incorrect or defective materials were initially installed. Refinery corrosion can be also categorized as: (1) Low-temperature corrosion which occurs at temperatures below 260°C and in the presence of water. (2) High-temperature corrosion: occurs at temperatures above 260°C, with no water present.
The petroleum industry includes the global processes of exploration, extraction, refining, transporting (often by oil tankers and pipelines), and marketing petroleum products. The largest volume products of the industry are fuel oil and gasoline (petrol). Petroleum (oil) is also the raw material for many chemical products, including pharmaceuticals, solvents, fertilizers, pesticides, synthetic fragrances, and plastics. The industry is usually divided into three major components: upstream, midstream and downstream. Midstream operations are usually included in the downstream category.
Petroleum is vital to many industries, and is of importance to the maintenance of industrial civilization in its current configuration, and thus is a critical concern for many nations. Oil accounts for a large percentage of the world's energy consumption, ranging from a low of 32% for Europe and Asia, to a high of 53% for the Middle East, with developed nations being the largest consumers. The production, distribution, refining, and retailing of petroleum taken as a whole, represents the world's largest industry in terms of dollar value.
Corrosion in Petroleum Industry
Corrosion in production
Oil and gas fields consume a high amount of iron and steel pipe, tubing, pumps, valves, and sucker rods. Leaks cause loss of oil and gas and also permit infiltration of water and silt, thus increasing corrosion damage. Saline water and sulphides are often present in oil and gas wells. Corrosion in wells occurs inside and outside the casing. Surface equipment is subject to atmospheric corrosion. In secondary recovery operations, water is pumped into the well to force up the oil.
Condensate wells handle fluids (gas containing dissolved hydrocarbons) at pressures up to 1,751,300 nm. Depths run up to 4572 m. Carbon dioxide is the chief corrosive agent, with organic acids contributing to the attack. Approximately 90% of the corrosive condensate wells encounter conditions as follows: (1) depth greater than 1524 m, (2) bottom hole temperature above 71ºC and pressure above 262,695 Nm (3) a carbon dioxide partial pressure above 2,626.95 Nm, an (4) a wellhead pH of less than 5.4.
Sweet Oil Wells
It appears that corrosion in high-pressure flowing wells that produce pipeline oil has become almost common place in many areas. Three methods are used to combat this corrosion – coated tubing, inhibitors, and alloys. Coated tubing has found most favor, and until recently, backed-on phenolics have been used for almost all coating installations. Air-dried and baked epoxy resins are now being used in increasing amounts.
Sour Oil Wells
These wells handle oil with higher sulfur contents than sweet wells and represent a more corrosive environment. In high H2S wells there may be severe attack on the casing in the upper part of the well where the space is filled with gas. Water vapor condenses in this area and picks up H2S and CO2.
Corrosion in transportation and storage
Petroleum products are transported by tankers, pipelines, railway tank cars, and tank trucks. The most severe internal corrosion problem occurs in tankage. Gasoline-carrying tankers present a more severe internal corrosion problem than oil tanks because the gasoline keeps the metal too clean. Oil leaves a film that affords some protection. Tank cars and tank trucks are coated on the outside for atmospheric corrosion. The main reason for internal corrosion of storage tanks is the presence of water which settles and remains on the bottom.
Rust formation on the internal walls of the pipelines caused by water precipitated from products may reduce the line throughout and may give rise to contamination of the product. Formation of the rust may be prevented by lining the pipe or rust formation may be inhibited by the injection of inhibitors (a few parts per million) such as amines and nitrites into the product stream. Corrosion of the external walls of the pipelines varies enormously according the nature of the soil or water, the temperature, access of oxygen and other factors. To prevent soil corrosion both coatings and cathodic protection are used. Three basic types of coating and wrapping now finding use in oil industry are (a) hot-applied coal-tar enamel and asphalt coatings, (b) plastic tapes, and (c) coal-tar/epoxy coating. Two principal tapes at present offered for buried pipe-line protection are those of polyvinyl chloride, and polyethylene. In the past few years the application of cathodic protection to products transmission lines have become normal practice. It is now generally recognized that the combinations of good coating and cathodic protection is the best method of ensuring a long leak-free life to buried pipes.
Corrosion in refinery units
Crude oil always contains impurities which frequently lead to severe corrosion problems in processing. Condensed products from the distillation processes are frequently contaminated with such substances as sulphuric acid, naphthenic acid, hydrogen sulphide and hydrogen chloride. Considerable corrosion is, therefore liable to occur on the product side of the condenser and cooler tubes. Corrosion generally takes the form of uneven general wastage and insoluble corrosion products such as copper sulphide are frequently formed. Pitting may proceed rapidly beneath these non-protective deposits. The most widely used tube materials are brasses with a high zinc content. When sea water or brackish water is used for cooling, there is a possibility of corrosion on the water-side in the heat exchange equipment. On the product side of heat exchange tube, corrosion can be minimized by injection of alkali or ammonia to keep the pH at a controlled figure in conjunction with the addition of one or other film forming amine inhibitors. On the cooling water-side, benefits may be obtained by the application of proper systems of cathodic protection in condenser and cooler channels and heaters. Zn or Mg can be used as sacrificial anodes.
Sea water cooling with circulating pumps in refineries provides a major problem in corrosion control. When cooling water is through steel pipe, a combination of thick coatings based on coal tar pitch plus cathodic protection is effective. Cooling water circulating pumps are made of bronze and cast iron, which are fitted with cathodic protection from an external source of impressed current.
For tubing in stills and gas-cracking tubes austenitic stainless steels are used. In some cases, a single tower is lined with two or three different materials to take care of the changing corrosiveness from the top to the bottom of the tower. Corrosion by sour crudes increases with temperature and with increasing sulphur content. Chromium is the most beneficial alloying element in steel for resistance to sulphur compounds. Thus, the Cr content of steel is increased with increasing sulphur and temperature starting as low as 1 per cent Cr.
Non-metallic materials are resistant to chemical corrosion and are free from contamination of the product. These render them very attractive to refinery and petro-chemical industries. Natural rubber has been used as a structural material and as a lining for vessels to prevent contamination and corrosion. Flexible pipes are widely used as temporary connections in the storage and transport of materials. Graphite has a very good thermal conductivity, and this property combined with its resistance to steam and highly corrosive fluids opens up the field of heat-exchange applications, in addition to its use in vessels, valves, pumps and piping.
Corrosion under insulation
This type of corrosion is difficult to detect because the insulation must be removed for the inspection of the surface and hence it is considered one of the largest and most expensive and most dangerous problems for the various industries. It occurs in the contact area between the metal and the insulation. It is generally observed in pipes, tanks and equipments and is due to the type of insulation used. Corrosion under insulation is occurred in presence of oxygen and water. When water and oxygen are present in the metal surface, corrosion occurs due to the metal dissolution (anodic effect).
This chemical process is balanced by reduction of oxygen. The rate of corrosion under insulation depends on type of insulation, the availability of oxygen, the impurities of water, temperature and heat, transfer properties of metal surface and the condition of metal surface of being dry or wet. In absence of oxygen, corrosion is negligible, although carbon and low alloy steels typically have the lowest corrosion rates in alkaline environment, but chloride ions under the cover causes a local hole localized pitting. If the sulfur and nitrogen oxides, which are acidic, penetrate through the impurities inside the water or air inside the insulation, or if the water is acidic corrosion occurs. Sometimes impurities of water or air, especially nitrate ions cause external stress corrosion crack SCC under the cover in carbon or low alloy steels.
The problem comes from this fact that due to the conditions of the insulation, pipes, tanks and the other equipments suffers from corrosion under insulation. Regardless of how tightly the insulation wrapped around pipes or imposed on it, in the space between the two, there's high temperature difference, because in this part high temperature suddenly placed in contact with the lower one. Thus condensation is achieved. Warm air holds more moisture than the cold one. When the warm air quickly cools in contact with the insulation, the heat transfer rate is reduced and moisture is released or in other words, condensation occurs, and thus by emergence of moisture and oxygen in the air, rust and corrosion occurs. Insulation on the metal surface prevents moisture evaporation and in this case insulation acts as a carrier and more the moisture accumulated in one area to other areas and causes the corrosion formed in a region to be moved elsewhere. Surface covered with traditional insulation such as fiberglass and rock wool traps moisture and prevents the evaporation.
Traditional insulation contain coloride , and if this exposed to the moisture, the coloride with the moisture can be appeared on the surface of metals such as oil and gas pipeline and due to corrosion, it can create holes or cracks on the surface.
CO2 and H2S Corrosion in oil pipelines
Corrosion of steel by CO2 and CO2 /H2S is one of the major problems in the oil industry. The presence of carbon dioxide, hydrogen sulphide and free water can cause severe corrosion problems in oil and gas pipelines. Internal corrosion in wells and pipelines is influenced by temperature, CO2 and H2S content, water chemistry, flow velocity, oil or water wetting and composition and surface condition of the steel. A small change in one of these parameters can change the corrosion rate considerably. In the presence of CO2, the corrosion rate can be reduced substantially under conditions when corrosion product, iron carbonate (FeCO3) can precipitate on the steel surface and form a dense and protective corrosion product film. This occurs more easily at high temperature or high pH in the water phase. When corrosion products are not deposited on the steel surface, very high corrosion rates of several millimetres per year can occur. When H2S is present in addition to CO2, iron sulphide (FeS) films are formed rather than FeCO3. This protective film can be formed at lower temperature, since Fes precipitates much easier than FeCO3. Localised corrosion with very high corrosion rates can occur when the corrosion product film does not give sufficient protection, and this is the most feared type of corrosion attack in oil and gas pipelines.
Carbon dioxide corrosion is one the most studied form of corrosion in oil and gas industry. This is generally due to the fact that the crude oil and natural gas from the oil reservoir/gas well usually contains some level of CO2. The major concern with CO2 corrosion in oil and gas industry is that CO2 corrosion can cause failure on the equipment especially the main downhole tubing and transmission pipelines and thus can disrupt the oil/gas production. The basic CO2 corrosion reaction mechanisms have been well understood and accepted by many researchers through the workdone over the past few decades. The major chemical reactions are:
CO2(g) CO2(aq) (1)
CO2 + H2O H2CO3 (2)
The carbonic acid then dissociates into bicarbonate and carbonate in two steps as in equations (3) and (4).
H2CO3 H+ + HCO3- (3)
HCO3- H+ + CO32- (4)
CO2 corrosion is an Electrochemical reaction with the overall reaction given in equation (5).
Fe + CO2 + H2OFeCO3 + H2
(5) Thus, CO2 corrosion leads to the formation of a corrosion product, FeCO3, which when precipitated could form a protective or a non‐protective scale depending on the environmental conditions. The electrochemical reactions at the steel surface include the anodic dissolution of iron as given in equation (6).
Fe Fe2+ + 2e-
(6)The cathodic reactions are proton reduction reaction and the direct reduction of carbonic acid as in equations (7) and (8).
2H+ + 2e- H2 (7)
2H2CO3 + 2e- H2 + 2HCO3-
(8)The net cathodic current was assumed to be the sum of the currents of the two cathodic reactions. It has been suggested that the direct reduction of bicarbonate ion becomes important at higher pH.
The effect of pH
The pH is the indication of the H+ concentration in the solutions, which is one of the main species involved in the cathodic reaction of CO2 process. It has been illustrated both experimentally and computationally that corrosion rate changes significantly with respect to pH. Higher pH leads to a decreased solubility of iron carbonate and thus results in an increased precipitation rate, faster formation of protective films and hence reduction of the corrosion rate. The protective nature and composition of the corrosion product depend greatly on the pH of the solution. At lower values of pH (<2), iron is dissolved and iron sulfide is not precipitated on the surface of the metal due to a very high solubility of iron sulfide phases at pH values less than 2. In this case, H2S exhibits only the accelerating effect on the dissolution of iron. At pH values from 3 to 5, inhibitive effect of H2S is seen due to the formation of ferrous sulfide (FeS) protective film on the electrode surface.
The effect of Temperature
Temperature accelerates all processes involved in CO2 corrosion including transport of species, chemical reactions in the bulk of the solutions and electrochemical reactions at the metal surface. The growth of iron carbonate film is a very slow and a temperature dependent process. Increasing the temperature increases the precipitation rate of iron carbonate significantly. Depending on the solubility of protective films, temperature can either increase or decrease the corrosion rate. In the case of corrosion where protective films do not form (typically at low pH), corrosion rate increases with increase in temperature. However, at a higher pH increased temperature would accelerate the kinetics of precipitation and facilitate protective film formation, thus decreasing the corrosion rate.
In the presence of H2S, metallic materials suffer corrosion which leads to hydrogen generation and subsequently a variety of hydrogen induced embrittlement and cracking problems that can potentially cause catastrophic failure.
Pitting corrosion of low alloy steels can also occur under certain conditions of temperature, flow rate, and ratio of CO2 to H2S. The resistance of carbon and low alloy steels to sulphide stress corrosion cracking (SSC) has been shown to be dependent not only on the partial pressure of H2S, but also on the pH of the environment.
The internal corrosion of carbon steel in the presence of H2S represents a significant problem for both oil refineries and natural gas treatment facilities. Surface scale formation is one of the important factors governing the corrosion rate. The scale growth depends primarily on the kinetics of scale formation. In contrast to relatively straight forward iron carbonate precipitation in pure CO2 corrosion, in an H2S environment many types of iron sulfide may form such as amorphous ferrous sulfide, mackinawite, cubic ferrous sulfide, smythite, greigte, pyrrhotite, troilite and pyrite, among which mackinawite is considered to form first on the steel surface by a direct surface reaction. A probable mechanism for Iron dissolution in aqueous solutions containing H2S based on the formation of mackinawite film is shown in figure 1.
The effect of H2S Concentration
H2S concentration has an immense influence on the protective ability of the sulfide film formed. As the concentration of H2S increases, the film formed is rather loose even at pH 3‐5 and does not contribute to the corrosion inhibiting effect.
The temperature dependence of H2S corrosion is very weak for short term exposure and does not seems to have an effect at longer exposure times. This suggests that the corrosion rate is predominantly controlled by the presence of iron sulfide scale.
The internal corrosion of mild steel in the presence of both CO2 and H2S represents a significant problem for oil and gas industries. Although the interaction of H2S with low carbon steels have been published by various authors, the understanding of the effect of H2S on CO2 corrosion is still limited because the nature of the interaction with carbon steel is complicated.
Cost of Corrosion
The cost of corrosion includes two components: corrosion loss and investments in corrosion control (use of preventive anti-corrosion measures plus corrosion monitoring methods. Crude oil production industry is not immune to the global financial meltdown being experienced world over which have been resulted in a continual fall of oil price. This has necessitated the need to reduce cost of production. One of the major cost of production is corrosion cost, hence, its evaluation.
The secret of effective engineering lies in controlling rather than preventing corrosion, because it is impracticable to eliminate corrosion. Production costs of oil are not tied directly to commodity price. The commodity price of oil and the cost of production will continue to dictate whether or not, production will continue at a profitable rate. Reducing operating Costs: Direct method of reducing cost in which money is spent includes replacement, installation, maintenance and clean up of spillages. The indirect methods in which no money is spent includes unplanned shutdowns and loss of products. It's nearly cost about 67% for repairs, 33% in lost production.
Types of corrosion occurring in Petroleum industry and their solutions Corrosion inhibitors
Corrosion inhibitor is a chemical agent whose task is to hinder the process of damage to the material. It creates a tight protective film on the surface of the material (metal) or facilitates the metal's passivation. The inhibitors hinder corrosion but do not remove the changes formed earlier i.e. rust, slime etc. In general, organic and inorganic compounds are used as corrosion inhibitors. Considering the mechanism of action, inhibitors can be divided into: anodic, cathodic and mixed cathodic-anodic.
The effectiveness of these inhibitors largely depends on the pH of the environment. Some of them demonstrate good protective properties exclusively in neutral solutions, whereas in acid electrolyte they do not affect the range of corrosion and sometimes even promote it. There are also compounds which are active only in acid environment. Most inhibitors affect specifically one metal or a group of metals, but they do not provide protection to a greater number of metals or alloys. The exceptions are chromates which passivate most of the metals. Taking into account the mechanism of action, the following can be singled out.
Inhibitors which create protective layers
This group comprises of organic compounds which are adsorbed on the surface of the corroding metal, creating in this way a tight protective film. The extent of adsorption of the compound determines the corrosion rate, reducing it considerably when the metal is completely isolated from the corrosive environment.
Another method of creating a protective layer is passivation, which is based on chemical interaction of the surface of the corroding metal with a potential inhibitor. In this way, the metal surface is covered with an insoluble protective layer whose main components are oxides. This group of compounds comprises e.g. organic phosphates and chromates.
Another method to inhibit or totally eliminate corrosion is the application of substances which will remove the corrosion initiators from the environment. Hydrazine and sodium sulfate (IV) demonstrate this type of action, as they bond the molecules of oxygen and eliminate it from the environment. At present, they are the most commonly used inhibitors of the scavenger type.
Na2SO3 + 1/2O2 Na2SO4
Apart from using inhibitors, another method of protection from corrosion or biocorrosion is the application of metal coating (insulating and shielding films), inorganic (enamel, oxide, phosphate and chromate films) or organic (paints, lubricants, oils, polymers), as well as electro-chemical (anodic or cathodic) protection.
These are usually anions which create insoluble compounds in the anodic areas with the ions of dissolved metal. This group includes redox substances, the so-called passivators (e.g. chromates, dichromates, nitrites) and compounds which form insoluble films (e.g. phosphates, benzoates acting only in the presence of oxygen). Inhibitors acting as oxidizers, reduce themselves so their concentration in the solution diminishes. Too low concentration of the inhibitor accelerates the corrosion, therefore only a few anodic areas are protected. Thus in practice, higher inhibitor concentration is used than the one theoretically indispensable.
Cathodic inhibitors inhibit the cathodic process by reduction of oxygen concentration in the solution and by increase in the overpotential of hydrogen liberation.
The first group comprises of cations Mg2+, Ca2+, Zn2+ which bind the oxygen and precipitate as hydroxides, sulphates or carbonates, creating a protective film in cathodic areas. Hydrazine and sodium sulphate (IV) also known as cathodic inhibitors.
The second class of cathodic inhibitors are represented by bismuth (Bi3+) and arsenic (As3+) ions which increase the overpotential of hydrogen liberation. In comparison with anodic inhibitors, any concentration of applied cathodic inhibitor leads to a noticeable decrease in corrosion rate.
Anodic-cathodic (mixed) inhibitors
Anodic-cathodic inhibitors are substances which moderate both the anodic and cathodic processes simultaneously. Organic compounds containing N or S (e.g.: amines, thiols, organic sulphides) are considered to possess such activity. This class of agents adsorb in an active centre on the metal surface, such interaction is associated with the van der Waals bonds and electrostatic forces (physical adsorption). However, chemisorption is regarded as a key factor in the case of the most effective inhibitors.
In general, the success of organic inhibitors depends on the extent of the covering on the metal surface. Maximal protection is usually achieved by monomolecular film. Higher the inhibitor concentration, greater is the protection of the metal surface, until the maximum value is achieved. Once the value is achieved, the protection decreases.
Corrosion inhibitor, potentially applied in the oil industry, should possess sufficient solubility in hydrocarbons. Based on the chemical nature, corrosion inhibitors may be placed into one of the following groups:
amines and ammonium salts,
quaternary ammonium salts,
heterocyclic compounds which possess a nitrogen atom.
In common applications, the oil and gas industry prefers to use hydrophobic corrosion inhibitors. Taking into account their physical and chemical properties they are more effective as they ensure that an additional permanent protective layer is created on the surface of the metal.
The rational solution which can reduce the occurrence of corrosion is the application of agents which act as potential corrosion inhibitors. Over the last few decades, the chemical industry has been working on new substances which may inhibit corrosion, while the composition of commonly used inhibitors is modified and improved.
Examples of Corrosion
Crude oil flows inside of the tubes, outside – vacuum bottom. The temperature varies from 280-32°C. Sulfur content in crude oil varies from 4.3 to 5.6% and carbon steel is not resistant to high sulfur (above 1% weight) crude oil and vacuum bottom at temperatures above 290 C.
Water from the desalter at 90 °C flows inside this pipeline made of carbon steel. The coating system resistant to industrial atmosphere at ambient temperature of about 25°C was chosen. This coating failed after several months of use. Temperature is the critical parameter for use of coating systems. Another example is the coating system for the air cooler ventilator. The temperature sometimes rose to 100 °C in this area. This coating failed after 2 years of use.
The typical pattern on the inner surface of carbon steel bottom could be determined as a result of microbial attack. Usually very dense sludge of the height of 1 to 2 meters is formed at the bottom, and it is impossible to take a sample from the bottom - bottom for the microbial analysis. The only solution is to coat the bottom surface inside the tank and periodical cleaning from the sludge. Sometimes MIC can result in corrosion damage of equipment in contact with water deteriorated by microorganisms even in several weeks.
The petroleum industry is very much prone to corrosive attacks. It is open to a wide variety of corrosive environment. Oilfields are situated in tropical areas where high humidity, salt bearing winds and air borne sand cause damage to the structures and equipments. Pipelines transport the crude oil, which is corrosive towards the steel and iron, to the refineries and coastal installations. In the refineries, very large quantities of cooling water is required for their operation, sea water is also used, so that intakes lines, condensers and coolers all require special protection against corrosive attack.
https: //en.wikipedia.org/wiki/Petroleu m_industry
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