Crude Pipeline Corrosion - Math Problem Example

Name: Professor: Course: Date of submission: CRUDE PIPELINE CORROSION Generally, crude oil is not corrosive, however, a number of impurities that are usually found inside it are. The crude oil, being a mixture of various forms of hydrocarbons, isn’t corrosive. On the other hand, there are some different impurities and apparatus usually found in the crude oil that might result to deterioration within any pipeline, vessel and refinery equipment, for example, an atmospheric column, overhead line, exchanger and condenser. In actual fact, from time to time the degree of deterioration of the crude oil is too high that to extract and refine this oil in a cost-effective way turns out to not viable. Here we will discuss on various deterioration compounds that might exist in the crude oil, and what could be done as a mitigation of their impacts. Brackish Water (Chlorides) In most instances, water that contains chloride salts, for example, CaCl2, NaCl and MgCl2, gets drawn from a crude oil well as well as with various hydrocarbons. The degree of concentration of these salts in this crude oil is dependent on the oil fields from where the extraction of crude oil is done, but it often has presence that is ranging from 3 - 300 pounds per every barrel. However, for a heavy crude oil this figure has the probability of becoming higher. In the course of preheating, whenever the crude oil has reached a temperature that exceeds 248°F (120°C), the chloride salts decompose to HCl. The chemical reaction for the CaCl2 decomposition is seen as follows: CaCl2 + H2O = CaO + 2 HCl We have an alike reaction with MgCl2. However, NaCl has more stability and is thus comparatively not easily hydrolyzed. Follolwing an increment of the preheating temperatures to almost 716°F (380°C), majority of the MgCl2 and CaCl2 compounds undergoes hydrolysis. When HCl is in gaseous state, it isn't a threat in regard to being corrosive. However, whenever HCl has cooled down to any temperature that is slightly lower compared to dew point of water, it undergoes a reaction with moisture (that is the condensing water) and produces HCL acid, which is an exceedingly corrosive product. Therefore, the availability of this "sour acid" (H2S) in the crude oil system, increases the likelihood of corrosion within the system. Whenever HCl has reacted with steel, it reacts with iron chloride and produces HCl. This, therefore, amounts to the progressing degradation of steel. CaCl2 + H2O = CaO + 2 HCl HCl + Fe = FeCl2 + H2 FeCl2 + H2S = FeS + 2 HCl Desalters remain one of the main aspects found in majority of oil refineries. The desalters are generally the first processing units found within the chain, as they remove the salt that is available in the crude prior to its beginning the distillation processes. Instead of really being suspended within the crude oil itself, different salts are generally forming part of a remedy of the brackish water. The water is often found in the crude oil being in an emulsified form; therefore the desalter might first require having demulsification and dehydration of the oil. A dissimilar form of technique referred to as the desalinization plant might similarly be termed to as the desalter. Crude oil is usually wet whenever it is under extraction, since it usually comprises of the emulsions of brackish water. The water might be having various salts evident, comprising of calcium chloride, magnesium chloride, and sodium chlorides. In case these chlorides aren’t removed before the fractional distillation of crude oil, numerous machineries, for example, a heat exchanger and catalyst could have some damages. An additional worry can be that any downstream processing unit usually operates at a very high temperature, which could result to an induction of water hydrolysis and allows the hazardous hydrochloric acid forming. Another method amongst the various methods of mitigating the impacts of HCl acid is through the addition of ammonium (NH3) as a fundamental component of neutralizing the HCl acid. Ammonium reacts with HCl and forms ammonium chloride (NH4Cl). NH4Cl compound is significantly hygroscopic and has the likelihood of even reacting with the water vapor (steam). The water that contains NH4Cl has high degree of corrosion with any copper-based alloy, for example, brass and bronze. Another approach used in reducing this form of corrosion is whereby one rinses the crude oil with water and sending it to some desalting vessels with a motive of removing the brackish water. In spite of all this, a smaller concentration of the residual chloride compounds in the crude oil is significant in causing failures within the upstream components. Carbon Dioxide (CO2) Carbon dioxide originates from three dissimilar sources: It is usually trapped within the various oil reservoirs trivially, it is one of the by-products of the chemical reactions within the well acidizing activities resulting from the HCl in stimulating the carbonates, limestones, or dolomite reservoirs and since it is a cheaper gas, it is usually injected into the crude oil wells with the motive of enhanced oil recovery (EOR). Carbon dioxide gas results to a critical form of degradation that is referred to as the "sweet corrosion". The carbon dioxide gas is capable of reacting with water and consequently produces carbonic acid (H2CO3). The rates of these reactions depend on the temperatures and the partial pressure of carbon dioxide gas. Usually, whenever the partial pressure of carbon dioxide is exceeding 0.5 bars (7 psi), there is a high possibility of the occurrence of sweet corrosion. It is worth mentioning that in various instances, the partial pressures of carbon dioxide gas in the crude oil is to some extent exceeding 400 bars. The Carbonic acid, which is an example of the weaker acids, maintains its pH almost constant within acidic regions, reacts with steel and forms iron carbonate, that is, the siderite (FeCO3), as the major corrosion product. Detection of the production of iron carbonate on the outer surface of the steel has turned out to be one of the various methods of recognizing the phenomenon of sweet corrosion. This degradation product is generally perceived as the semi-protective layers that have the potential of preventing additional degradation. On the other hand, the dissolved oxygen or higher fluid velocities (exceeding a velocity of 10 m/s) might help in removing this layer. Additionally, the localized degradation could similarly happen under the corrosion product. Iron is naturally (thermodynamically) adequately active for the reaction suddenly with water (degradation), and generates soluble iron ions as well as the hydrogen gas. The helpfulness of an iron alloy is dependent on the minimization of the corrosion magnitude. Deterioration of steel is usually an “electrochemical process,” that involves the transmission of electrons from an iron atom within the metal to the hydrogen ions otherwise oxygen in water. The deterioration reactions of iron reacting with acid is elucidated by the following equation ....................(1) Thie above reaction is entailing two distinct processes, as follows ....................(2) [the production of the soluble iron and the electrons (this becomes the “anodic” progression—the oxidation of the metals)] in addition to ....................(3) [the using up of the electrons by the acid to produce the hydrogen gas (this remains one of the “cathodic” processes—the reduction of proton)]. This division of the whole corrosion processes into two processes in’t an electrochemical tinge; the two reactions usually happen at separated places on the same part of the metal. The above separation needs the availability of a medium for the completion of electrical circuit between the anodes (place for the dissolution of iron) and cathodes (place for the reduction of corrodant). The electrons move within the metal phase, while those ions that are involved in the deterioration process can’t. Ions need the availability of water; thus, deterioration needs the availability of water. This whole process is portrayed comprehensively in the figure below. The space that is evident between the anodes and cathodes might be smaller or larger based on various aspects. Illustration of the separation of the position of the anodic and cathodic deterioration sites. Acid isn’t the sole corrodant that is probable. An additional usual process at the cathode is the reduction of the oxygen molecules, as shown below ....................(4) The above reaction could similarly occur at a place that is not the same as that of the dissolution of the iron. Another chemical components that are present in the anodic sites dictate the final chemical results of the Fe++ ions, for example, the precipitation of the iron-containing solid on or within the sites of the corroding surfaces. The aggregate rates of deterioration is affected by how fast the corrodants arrive at the iron-atoms/water edge, how much corrodants are available, the electrical potentials (energy) of the corrodants (oxygen possesses a more potential compared to the protons), and the inherent rates of any cathodic reaction—electrons transfer processes that involve protons and oxygen aren’t instant and are dependent on the type of the surfaces of the solids on which they happen. The speed at which the corrodants arrive is dependent on two factors: Mass transportation within the corroding fluid and the Permeating surface barriers within the iron metal as well as the water phase. The Surface barrier is a placed barrier, that comprise of: Paints’ or plastics’ coating, passivation of the oxide films innate to the metals and the Low-permeability deterioration products (for example, the siderites, as generated in the presence of particular types of oil and/or inhibitor) We have two major mechanisms of eliminating or mitigating the sweet corrosion. The first is through the addition of a particular inhibitor to the crude oil. Replacement of steel with stainless steel is the other mechanism that is turning out to be more often since the addition of inhibitors is usually exceedingly expensive. Organic Acids Naphthenic acids, for example, are a type of organic acids which are often found in the crude oil and have been associated with the causing of substantial deterioration in particular situations. This type of deterioration, which is referred to as the naphthenic acid corrosion (NAC), typically happens at the temperatures within the range of 446°F to 752°F (230°C to 400°C) and in the existence of a adequate amount of naphthenic acid within the crude oil. Naphthenic acid deterioration usually occurs within the refinery distillation units for example a furnace tube, transfer line, vacuum column and side cut piping. Naphthenic acid corrosion infrequently occurs within a fluid catalytic unit since the temperatures at such a unit is way beyond 752°F (400°C), and this might breakdown the naphthenic acids. Additionally, inside any hydrodesulfurizer unit, the catalysts might also breakdown the naphthenic acids and get rid of the Naphthenic acid corrosion. The projected chemical formula for the naphthenic acid is accepted to be R(CH2)nCOOH, whereby R is representing one or additional cyclopentane rings while n is usually a number which is at least 12. The atomic mass unit of these compounds is ranging from 120 and 700. The reaction that follows is showing the reaction between the naphthenic acids and the steel metal. The products of the following reaction are hydrogen gas and a complex of the iron-organic acid. This complex has high solubility in crude oil. Fe + 2 RCOOH = Fe (RCOO)2 + H2 with the sulfides being present in the crude oil, Fe (RCOO)2 undergoes a reaction with H2S to form FeS in accordance to the reaction that follows: Fe (RCOO)2+ H2S = FeS + 2 RCOOH FeS compound is not soluble in both water and oil and has the tendency of forming protective layers on the steel metal at lower shear stress of the crude oil, thus shielding it from an additional deterioration. Consequently, the availability of sulfides inside the crude oil can lower the rates of Naphthenic acid corrosion, particularly at lower temperatures. In contrast, the regenerated naphthenic acid sustains the deterioration reactions. Naphthenic acid corrosion is well thought-out to be a localized deterioration and is experienced in sites where the fluid velocity is higher and organic acid vapor is evident. The absence of deterioration products in the putrefied areas is a further attribute of Naphthenic acid corrosion. Numerous high-resistant steels, which are resistant to sulfur deterioration as well as high chromium and the higher molybdenum steels might be vulnerable to this sort of deterioration. The concentration of naphthenic acid in the crude oil is exhibited using the Total Acid Number (TAN). Total Acid Number is termed to as the quantity of potassium hydroxide (in mgs) that is required in the neutralization of one gram of the crude oil. An ordinary Total Acid Number in crude oil varies by ranging between 0.1 to 3.5 mg/gr. Nevertheless, high values of Total Acid Number for example, 10 mg/g are being experienced rarely in the refining industries. Total Acid Number isn’t a constant attribute within the oilfields, and might varies over a duration of time in the course the extraction of the oil. It is assumed that Total Acid Number arises whenever Total Acid Number exceeds 0.5 mg/g. Conversely, in some instances Total Acid Number has been experienced for Total Acid Number figures that range from 0.3 to 0.5 mg/g. Depending on studies, as little as 5% of the naphthenic acids evident in the crude oil are substantially corrosive. Alternatively, any two crude oils that have an equal Total Acid Number figures don’t obviously have to exhibit related naphthenic acid corrosion behaviors. A usual approach of reducing Total Acid Number within a crude oil refining system is through the blending at a high Total Acid Number crude oil with some crude oil that have a significantly lower Total Acid Number. In this scenario, the general TAN figures would be decreased to an immune range (below 0.3 mg/g). The blending processes for newer sources of crude oil have to be done cautiously, since as discussed previously, sufficient concentration of a particular form of naphthenic acids within some crude oil that have lower Total Acid Number values could result to higher rates of Total Acid Number. The injection of corrosion inhibitors into the streams of the crude oil is also an approach that is used in decreasing the deterioration rates of naphthenic acid. For instance, the economic matters and impacts of an inhibitor on a downstream process have to be put into consideration. Since Total Acid Number happens at higher temperatures and deposits of iron sulfide aren’t generated on the surfaces, the application of a traditional filming amine inhibitor isn’t appropriate. Inhibitors that contain or don’t contain Phosphorous are very efficient in mitigating Total Acid Number. Though, those inhibitors that contain phosphorous have extra inhibition effectiveness, their impacts on the poisoning of any catalyst that could be downstream are being put into consideration. Sulfur Crude oil generally contains sulfides that could result to deterioration at high temperatures and thus the process is referred to as the "sulfidation". Sulfidation is an eminent deterioration in various components in the oil refinery sectors. The quantity of aggregate sulfur found in the crude oils is dependent on the form of oil fields and it has a variation within the range of 0.05% to 14%. Obviously, sulfur quantities as low as 0.2% significant in causing sulfidation deterioration in any plain steel or low alloy steel. These forms of steel are generally suggested to be of use in many parts of refinery machinery. Majority of the sulfur inside the crude oil has the structure of organic molecules (for example mercaptans, alkyd sulfides, sulfoxides and thiophenes), and trace quantities of them are fundamental hydrogen sulfide (H2S) and sulfur. However, not all forms of sulfur subtances result to corrosion; only a fraction of sulfur reacts with a metallic compound so as to result to the sulfidation corrosion. These sulfur compounds are referred to as the "active sulfur". Active sulfur comprises of the basic sulfurs, low-molecular mercaptans and the H2S. In spite of that, if H2 gas is present, majority of the organic sulfides – that are are grouped into the inactive sulfide- those that decomposes to H2S, active sulfur that which leads to sulfidation. Thus, sulfidation turns out to be worse when hydrogen gas is present. Hydrogen gas has its application in hydrocracking as well as in the hydrofining components within the oil refineries. Sulfidation occurs at any temperature that is at least 446°F (230°C) and its rates accelerate whenever the temperatures are raised to almost 896°F (480°C). At a temperature that exceeds 698°F (370°C), H2S undergoes decomposition into the basic sulfur that is the most violent sulfur compound. In actual fact, the sulfidation rates reache their peak at almost 752°F (400°C). Within the course of sulfidation, there is a formation of protective iron sulfide scales on the surfaces of the substrates and lowers the rates of the deterioration rates. These scales are also referred to as the diffusion barrier layers and their growth follow the parabolic kinetics (that is d=kt½). On the other hand, some aspects could result to the malfunctioning of the FeS. One of these aspects is the high velocities of fluids that could keep those protective scales separated from the metallic surfaced. The other aspect has a relation to the availability of the naphthenic acids inside the crude oil containers. As aforementioned, the above acids could react with the FeS in creating soluble compounds. The last aspect that is linked to hydrogen, that has the ability of penetrating into the sulfide scales and creating permeable iron sulfide scales. The main widespread technique of controlling the high temperatures sulfidation is the selection of appropriate materials that are resistant to the sulfidation process. One of the vital equipments in the selection of suitable steel is by use of "McConomy" curves. The McConomy curves express the discrepancy of the sulfidation corrosion rates as being a function of the temperatures and whole sulfur substance. The abovementioned curves give you an idea in regard to the fact that any steel that contains additional chromium is more corrosion resistant to the sulfidation reactions. Additionally, the deterioration rates increase with the increase of the sulfur substance and temperatures. Acording to the McConomy curves, the deterioration rates depend on the overall sulfur substances. On the other hand, only the active sulfides (for example the H2S) can result to the sulfidation phenomenon. Alternatively, the McConomy curves overrate lofty corrosion rates. Consequently, the deterioration rates within the McConomy curves are lowered through a 2.5 factor, amounting to the "Modified McConomy" curve. Another negative factor of the McConomy curves is that the impacts of the fluid velocities and the availability of H2 gas haven’t been put into consideration in the McConomy curves. Consequently, the NACE T-8 commission in regard to the Refining Industry Corrosion is an introduction of the "Couper-Gorman" curves on the basis of a sequence of experimental investigations. In accordance to the Couper-Gorman curves, FeS does not have thermodynamic stability and no sulfidation reaction happens at an extremely low level of H2S and temperature exceeding 519°F (315°C). It is worth noting that the approximations reached using the Couper-Gorman or the McConomy curves are uniform deterioration rates or thickness losses, at the same time as the localized deterioration that frequently occurs and can happen at higher rates isn’t put into consideration whenever one is approximating the first leaks or deterioration allowance. This effect is mitigated by ensuring that the percent of oxygen in the crude oil is kept below 1%. Electrolytic corrosion One of the major challenges faced by the refining industries is the establishment of public assurance that the risk resulting from the internal electrolytic corrosion within the oil transmission pipeline is less and that this threat can be continuously under control at the lower levels by use of the conventional engineering routines. Under the ordinary oil transmission pipelines operation conditions, deterioration happens through electrochemical mechanisms. Crude oil (as well as the dilbit), since it is non-conducting electrolyte, doesn’t support deterioration. On the other hand, whenever the crude oil is containing water, consequently, deterioration might occur within the sites where the water is dropping out of the crude oil and would come in contact with the metallic plane. The immense crude oil might not directly have effect on the deterioration through some influence on the sites that water might pile up and by affecting the degree of deterioration of the water in these sites. The operators of pipelines keep the risks of the internal electrolytic corrosion within a oil transmission pipeline at lower levels through their limiting of the quantity of water to Read More

Another approach used in reducing this form of corrosion is whereby one rinses the crude oil with water and sending it to some desalting vessels with a motive of removing the brackish water. In spite of all this, a smaller concentration of the residual chloride compounds in the crude oil is significant in causing failures within the upstream components. Carbon Dioxide (CO2) Carbon dioxide originates from three dissimilar sources: It is usually trapped within the various oil reservoirs trivially, it is one of the by-products of the chemical reactions within the well acidizing activities resulting from the HCl in stimulating the carbonates, limestones, or dolomite reservoirs and since it is a cheaper gas, it is usually injected into the crude oil wells with the motive of enhanced oil recovery (EOR). Carbon dioxide gas results to a critical form of degradation that is referred to as the "sweet corrosion". The carbon dioxide gas is capable of reacting with water and consequently produces carbonic acid (H2CO3). The rates of these reactions depend on the temperatures and the partial pressure of carbon dioxide gas. Usually, whenever the partial pressure of carbon dioxide is exceeding 0.5 bars (7 psi), there is a high possibility of the occurrence of sweet corrosion. It is worth mentioning that in various instances, the partial pressures of carbon dioxide gas in the crude oil is to some extent exceeding 400 bars. The Carbonic acid, which is an example of the weaker acids, maintains its pH almost constant within acidic regions, reacts with steel and forms iron carbonate, that is, the siderite (FeCO3), as the major corrosion product. Detection of the production of iron carbonate on the outer surface of the steel has turned out to be one of the various methods of recognizing the phenomenon of sweet corrosion. This degradation product is generally perceived as the semi-protective layers that have the potential of preventing additional degradation. On the other hand, the dissolved oxygen or higher fluid velocities (exceeding a velocity of 10 m/s) might help in removing this layer. Additionally, the localized degradation could similarly happen under the corrosion product. Iron is naturally (thermodynamically) adequately active for the reaction suddenly with water (degradation), and generates soluble iron ions as well as the hydrogen gas. The helpfulness of an iron alloy is dependent on the minimization of the corrosion magnitude. Deterioration of steel is usually an “electrochemical process,” that involves the transmission of electrons from an iron atom within the metal to the hydrogen ions otherwise oxygen in water. The deterioration reactions of iron reacting with acid is elucidated by the following equation ....................(1) Thie above reaction is entailing two distinct processes, as follows ....................(2) [the production of the soluble iron and the electrons (this becomes the “anodic” progression—the oxidation of the metals)] in addition to ....................(3) [the using up of the electrons by the acid to produce the hydrogen gas (this remains one of the “cathodic” processes—the reduction of proton)]. This division of the whole corrosion processes into two processes in’t an electrochemical tinge; the two reactions usually happen at separated places on the same part of the metal. The above separation needs the availability of a medium for the completion of electrical circuit between the anodes (place for the dissolution of iron) and cathodes (place for the reduction of corrodant). The electrons move within the metal phase, while those ions that are involved in the deterioration process can’t. Ions need the availability of water; thus, deterioration needs the availability of water. This whole process is portrayed comprehensively in the figure below. The space that is evident between the anodes and cathodes might be smaller or larger based on various aspects. Illustration of the separation of the position of the anodic and cathodic deterioration sites. Read More