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Description of a typical amine treater[ edit ] Gases containing H 2S or both H 2S and CO 2 are commonly referred to as sour gases or acid gases in the hydrocarbon processing industries. The chemistry involved in the amine treating of such gases varies somewhat with the particular amine being used.
In the absorber, the downflowing amine solution absorbs H 2S and CO 2 from the upflowing sour gas to produce a sweetened gas stream i. 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 is concentrated H 2S and CO 2. Process flow diagram of a typical amine treating process used in petroleum refineries, natural gas processing plants and other industrial facilities.
Alternative processes[ edit ] Alternative stripper configurations include matrix, internal exchange, flashing feed, and multipressure 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. 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 overheads stream, and therefore less steam is required.
The multipressure configuration with split feed reduces the flow into 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 multipressure configuration is more attractive for solvents with a higher heats of absorption. It 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 H2S and CO2 or whether the unit is treating gases with a high percentage of CO2 such as the offgas from the steam reforming process used in ammonia production or the flue gases from power plants.
However, in an amine treating unit, CO2 is the stronger acid of the two. H2S 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 CO2, corrosion inhibitors are often used and that permits the use of higher concentrations of amine in the circulating solution. Another factor involved in choosing an amine concentration is the relative solubility of H2S and CO2 in the selected amine. 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. They are also more corrosive and chemically unstable compared to other amines. This H2S-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,, metric tons of sulfur produced worldwide in was byproduct sulfur from refineries and other hydrocarbon processing plants. In some plants, more than one amine absorber unit may share a common regenerator unit. The current emphasis on removing CO2 from the flue gases emitted by fossil fuel power plants has led to much interest in using amines for removing CO2.
See also: Carbon capture and storage and Conventional coal-fired power plant. In 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 the natural. The removal of the sometimes high content of hydrogen sulfide is necessary to prevent corrosion of metallic parts after burning the bio gas.
For example, Monoethanolamine MEA reacts strongly with acid gases like CO2 and has a fast reaction time and an ability to remove high percentages of CO2, even at the low CO2 concentrations.
O2 from the inlet gas will cause degradation as well. The degraded amine is no longer able to capture CO2, which decreases the overall carbon capture efficiency. One major focus is on lowering the energy required for solvent regeneration, which has a major impact on process costs.
However, there are tradeoffs to consider. For example, the energy required for regeneration is typically related to the driving forces for achieving high capture capacities. Thus, reducing 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 CO2, thus, increasing the capital cost.
Sour gas sweetening
Description of a typical amine treater[ edit ] Gases containing H 2S or both H 2S and CO 2 are commonly referred to as sour gases or acid gases in the hydrocarbon processing industries. The chemistry involved in the amine treating of such gases varies somewhat with the particular amine being used. In the absorber, the downflowing amine solution absorbs H 2S and CO 2 from the upflowing sour gas to produce a sweetened gas stream i. 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 is concentrated H 2S and CO 2. Process flow diagram of a typical amine treating process used in petroleum refineries, natural gas processing plants and other industrial facilities. Alternative processes[ edit ] Alternative stripper configurations include matrix, internal exchange, flashing feed, and multipressure with split feed.
Throughout the world, regulations generally limit the flaring of H2S. Sweetening of gas streams containing very low concentrations of H2S can be done in many ways, depending on the general conditions. For very low H2S content sour gas, a scavenger chemical is usually used. In such cases, the chemical is consumed, and the method for ultimate disposal of the spent chemical is a consideration. Typical process equipment for sweetening sour gas with a regenerative solvent A schematic drawing of typical process equipment for sweetening sour gas with regenerative solvent is shown in Fig. The first vessel is the inlet separator, which performs the important function of separating the fluid phases on the basis of density difference between the liquid and the gas.