Amine gas treating , also known as amine scrubbing , gas sweetening and acid gas removal , refers to a group of processes that use aqueous solutions of various alkylamines (commonly referred to simply as amines ) to remove hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) from gases. It is a common unit process used in refineries , and is also used in petrochemical plants, natural gas processing plants and other industries.
31-411: Selexol is the trade name for an acid gas removal solvent that can separate acid gases such as hydrogen sulfide and carbon dioxide from feed gas streams such as synthesis gas produced by gasification of coal, coke, or heavy hydrocarbon oils. By doing so, the feed gas is made more suitable for combustion and/or further processing. It is made up of dimethyl ethers of polyethylene glycol. In
62-420: A distillation column reboiler. A pump is required to circulate the column bottoms through the heat transfer tubes in the furnace's convection and radiant sections. The heat source for the fired heater reboiler may be either fuel gas or fuel oil. A forced circulation reboiler (Image 4) uses a pump to circulate the column bottoms liquid through the reboilers. This is useful if the reboiler must be located far from
93-460: A fast reaction time and an ability to remove high percentages of CO 2 , even at the low CO 2 concentrations. Typically, monoethanolamine (MEA) can capture 85% to 90% of the CO 2 from the flue gas of a coal-fired plant, which is one of the most effective solvent to capture CO 2 . Challenges of carbon capture using amine include: The partial pressure is the driving force to transfer CO 2 into
124-407: A higher pressure and does not have inefficiencies associated with multi-pressure stripper. Energy and costs are reduced since the reboiler duty cycle is slightly less than normal pressure stripper. An Internal Exchange stripper has a smaller ratio of water vapor to CO 2 in the overhead stream, and therefore less steam is required. The multi-pressure configuration with split feed reduces the flow into
155-460: A variety of amine mixtures are being synthesized and tested to achieve a more desirable set of overall properties for use in CO 2 capture systems. One major focus is on lowering the energy required for solvent regeneration, which has a major impact on process costs. However, there are trade-offs to consider. For example, the energy required for regeneration is typically related to the driving forces for achieving high capture capacities. Thus, reducing
186-511: Is a mixture of the dimethyl ethers of polyethylene glycol . Selexol is a physical solvent, unlike amine based acid gas removal solvents that rely on a chemical reaction with the acid gases. Since no chemical reactions are involved, Selexol usually requires less energy than the amine based processes. However, at feed gas pressures below about 300 psia (2.07 MPa), the Selexol solvent capacity (in amount of acid gas absorbed per volume of solvent)
217-455: Is an important parameter in the design and operation of an amine gas treating process. Depending on which one of the following four amines the unit was designed to use and what gases it was designed to remove, these are some typical amine concentrations, expressed as weight percent of pure amine in the aqueous solution: The choice of amine concentration in the circulating aqueous solution depends upon several factors and may be quite arbitrary. It
248-577: Is concentrated H 2 S and CO 2 . Alternative stripper configurations include matrix, internal exchange, flashing feed, and multi-pressure with split feed. Many of these configurations offer more energy efficiency for specific solvents or operating conditions. Vacuum operation favors solvents with low heats of absorption while operation at normal pressure favors solvents with high heats of absorption. Solvents with high heats of absorption require less energy for stripping from temperature swing at fixed capacity. The matrix stripper recovers 40% of CO 2 at
279-521: Is less attractive due to the relatively high capital and operating costs as well as other technical factors. Many different amines are used in gas treating: The most commonly used amines in industrial plants are the alkanolamines DEA, MEA, and MDEA. These amines are also used in many oil refineries to remove sour gases from liquid hydrocarbons such as liquified petroleum gas (LPG). Gases containing H 2 S or both H 2 S and CO 2 are commonly referred to as sour gases or acid gases in
310-436: Is mostly H 2 S, much of which often comes from a sulfur-removing process called hydrodesulfurization . This H 2 S-rich stripped gas stream is then usually routed into a Claus process to convert it into elemental sulfur . In fact, the vast majority of the 64,000,000 metric tons of sulfur produced worldwide in 2005 was byproduct sulfur from refineries and other hydrocarbon processing plants. Another sulfur-removing process
341-426: Is reduced and the amine based processes will usually be superior. Amine gas treating Processes within oil refineries or chemical processing plants that remove Hydrogen Sulfide are referred to as "sweetening" processes because the odor of the processed products is improved by the absence of "sour" hydrogen sulfide. An alternative to the use of amines involves membrane technology . However, membrane separation
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#1732797919797372-482: Is the WSA Process which recovers sulfur in any form as concentrated sulfuric acid . In some plants, more than one amine absorber unit may share a common regenerator unit. The current emphasis on removing CO 2 from the flue gases emitted by fossil fuel power plants has led to much interest in using amines for removing CO 2 (see also: carbon capture and storage and conventional coal-fired power plant ). In
403-400: Is usually made simply on the basis of experience. The factors involved include whether the amine unit is treating raw natural gas or petroleum refinery by-product gases that contain relatively low concentrations of both H 2 S and CO 2 or whether the unit is treating gases with a high percentage of CO 2 such as the offgas from the steam reforming process used in ammonia production or
434-403: The flue gases from power plants . Both H 2 S and CO 2 are acid gases and hence corrosive to carbon steel . However, in an amine treating unit, CO 2 is the stronger acid of the two. H 2 S forms a film of iron sulfide on the surface of the steel that acts to protect the steel. When treating gases with a high percentage of CO 2 , corrosion inhibitors are often used and that permits
465-508: The hydrocarbon processing industries. The chemistry involved in the amine treating of such gases varies somewhat with the particular amine being used. For one of the more common amines, monoethanolamine (MEA) denoted as RNH 2 , the acid-base reaction involving the protonation of the amine electron pair to form a positively charged ammonium group (RNH 3 ) can be expressed as: The resulting dissociated and ionized species being more soluble in solution are trapped, or scrubbed, by
496-455: The Selexol process (now licensed by UOP LLC ), the Selexol solvent dissolves (absorbs) the acid gases from the feed gas at relatively high pressure, usually 300 to 2000 psia (2.07 to 13.8 MPa). The rich solvent containing the acid gases is then let down in pressure and/or steam stripped to release and recover the acid gases. The Selexol process can operate selectively to recover hydrogen sulfide and carbon dioxide as separate streams, so that
527-593: The amine concentration, the reader is referred to Kohl and Nielsen's book. MEA and DEA are primary and secondary amines. They are very reactive and can effectively remove a high volume of gas due to a high reaction rate. However, due to stoichiometry , the loading capacity is limited to 0.5 mol CO 2 per mole of amine. MEA and DEA also require a large amount of energy to strip the CO 2 during regeneration, which can be up to 70% of total operating costs. They are also more corrosive and chemically unstable compared to other amines. In oil refineries, that stripped gas
558-487: The amine solution and so easily removed from the gas phase. At the outlet of the amine scrubber, the sweetened gas is thus depleted in H 2 S and CO 2 . A typical amine gas treating process (the Girbotol process , as shown in the flow diagram below) includes an absorber unit and a regenerator unit as well as accessory equipment. In the absorber, the downflowing amine solution absorbs H 2 S and CO 2 from
589-410: The bottom section, which also reduces the equivalent work. Flashing feed requires less heat input because it uses the latent heat of water vapor to help strip some of the CO 2 in the rich stream entering the stripper at the bottom of the column. The multi-pressure configuration is more attractive for solvents with a higher heats of absorption. The amine concentration in the absorbent aqueous solution
620-416: The column bottoms liquid into the kettle, or there may be sufficient liquid head to deliver the liquid into the reboiler. In this reboiler type, steam flows through the tube bundle and exits as condensate. The liquid from the bottom of the tower, commonly called the bottoms , flows through the shell side. There is a retaining wall or overflow weir separating the tube bundle from the reboiler section where
651-492: The column to drive the distillation separation . The heat supplied to the column by the reboiler at the bottom of the column is removed by the condenser at the top of the column. Proper reboiler operation is vital to effective distillation. In a typical classical distillation column, all the vapor driving the separation comes from the reboiler. The reboiler receives a liquid stream from the column bottom and may partially or completely vaporize that stream. Steam usually provides
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#1732797919797682-631: The heat required for the vaporization. The most critical element of reboiler design is the selection of the proper type of reboiler for a specific service. Most reboilers are of the shell and tube heat exchanger type and normally steam is used as the heat source in such reboilers. However, other heat transfer fluids like hot oil or Dowtherm (TM) may be used. Fuel-fired furnaces may also be used as reboilers in some cases. Commonly used heat exchanger type reboilers are: Kettle reboilers (Image 1) are very simple and reliable. they are similar to shell and tube type heat exchangers. They may require pumping of
713-455: The hydrogen sulfide can be sent to either a Claus unit for conversion to elemental sulfur or to a wet sulfuric acid process unit for conversion to sulfuric acid while, at the same time, the carbon dioxide can be sequestered or used for enhanced oil recovery . The Selexol process is similar to the Rectisol process, which uses refrigerated methanol as the solvent. The Selexol solvent
744-448: The liquid phase. Under low pressure, this transfer is hard to achieve without increasing the reboilers' heat duty, which will result in higher costs. Primary and secondary amines, for example, MEA and DEA, will react with CO 2 and form degradation products. O 2 from the inlet gas will cause degradation as well. The degraded amine is no longer able to capture CO 2 , which decreases the overall carbon capture efficiency. Currently,
775-449: The reboiler outlet liquid-vapor mixture to provide sufficient liquid head to deliver the tower bottoms into the reboiler. Thermosyphon reboilers (also known as calandrias ) are more complex than kettle reboilers and require more attention from the plant operators. There are many types of thermosyphon reboilers including vertical, horizontal, once-through or recirculating. Fired heaters (Image 3), also known as furnaces, may be used as
806-436: The regeneration energy can lower the driving force and thereby increase the amount of solvent and size of absorber needed to capture a given amount of CO 2 , thus, increasing the capital cost. Reboiler Reboilers are heat exchangers typically used to provide heat to the bottom of industrial distillation columns. They boil the liquid from the bottom of a distillation column to generate vapors which are returned to
837-424: The residual reboiled liquid (called the bottoms product) is withdrawn, so that the tube bundle is kept covered with liquid and reduce the amount of low-boiling compounds in the bottoms product. Thermosyphon reboilers (Image 2) do not require pumping of the column bottoms liquid into the reboiler. Natural circulation is obtained by using the density difference between the reboiler inlet column bottoms liquid and
868-487: The sometimes high content of hydrogen sulfide is necessary to prevent corrosion of metallic parts after burning the bio gas. Amines are used to remove CO 2 in various areas ranging from natural gas production to the food and beverage industry, and have been since 1930. There are multiple classifications of amines, each of which has different characteristics relevant to CO 2 capture. For example, monoethanolamine (MEA) reacts strongly with acid gases like CO 2 and has
899-430: The specific case of the industrial synthesis of ammonia , for the steam reforming process of hydrocarbons to produce gaseous hydrogen , amine treating is one of the commonly used processes for removing excess carbon dioxide in the final purification of the gaseous hydrogen. In the biogas production it is sometimes necessary to remove carbon dioxide from the biogas to make it comparable with natural gas. The removal of
930-409: The upflowing sour gas to produce a sweetened gas stream (i.e., a gas free of hydrogen sulfide and carbon dioxide) as a product and an amine solution rich in the absorbed acid gases. The resultant "rich" amine is then routed into the regenerator (a stripper with a reboiler ) to produce regenerated or "lean" amine that is recycled for reuse in the absorber. The stripped overhead gas from the regenerator
961-467: The use of higher concentrations of amine in the circulating solution. Another factor involved in choosing an amine concentration is the relative solubility of H 2 S and CO 2 in the selected amine. The choice of the type of amine will affect the required circulation rate of amine solution, the energy consumption for the regeneration and the ability to selectively remove either H 2 S alone or CO 2 alone if desired. For more information about selecting