Amine gas treating, also known asamine scrubbing,gas sweetening andacid gas removal, refers to a group of processes that use aqueous solutions of variousalkylamines (commonly referred to simply asamines) to removehydrogen sulfide (H2S) andcarbon dioxide (CO2) from gases.[1][2][3] It is a commonunit process used inrefineries, and is also used inpetrochemical plants,natural gas processing plants and other industries.
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 involvesmembrane technology. However, membrane separation is less attractive due to the relatively high capital and operating costs as well as other technical factors.[4]
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 removesour gases from liquid hydrocarbons such asliquified petroleum gas (LPG).
Gases containingH2S or bothH2S and CO2 are commonly referred to assour gases oracid gases in thehydrocarbon 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 asRNH2, theacid-base reaction involving theprotonation of the amineelectron 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 the amine solution and so easily removed from the gas phase. At the outlet of the amine scrubber, thesweetened gas is thus depleted inH2S and CO2.
A typical amine gas treating process (theGirbotol process, as shown in theflow diagram below) includes an absorber unit and a regenerator unit as well as accessory equipment. In the absorber, the downflowing amine solution absorbs and reacts withH2S and CO2 from 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 areboiler) to produce regenerated or "lean" amine that is recycled for reuse in the absorber. The strippedoverhead gas from the regenerator is concentratedH2S and CO2.
Alternative stripper configurations include matrix, internal exchange, flashing feed, and multi-pressure with split feed. Many of these configurations offer moreenergy 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 CO2 at 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 CO2 in the overhead stream, and therefore less steam is required. The multi-pressure 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 CO2 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.[5]
The amine concentration in the absorbent aqueous solution 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:[1]
The choice of amine concentration in the circulating aqueous solution depends upon several factors, involving the composition of the feed gasnatural gas orpetroleum 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 inammonia production or theflue gases frompower plants.[1]
Both H2S and CO2 are acid gases and hence corrosive to unprotectedcarbon steel. Their corrosiveness are greatly enhanced in the presence of moisture. However, in an amine treating unit, CO2 is a stronger acid than H2S. Furthermore hydrogen sulfide can form apassivating film ofiron sulfide that may act to protect the steel.[6][7] When treating gases with a high percentage of CO2, control of the CO2 loading in the amine is important to protect carbon steel from corrosion. Higher amine concentrations will have lower loading compared to lower concentrations at the same circulation rate.
Another factor involved in choosing the amine concentration is the relative solubility of H2S and CO2 in the selected amine.[1] 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 H2S alone or CO2 alone if desired. For more information about selecting 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 tostoichiometry, the loading capacity is limited to 0.55 mol CO2 per mole of amine.[8] MEA and DEA also require a large amount of energy to strip the CO2 during regeneration, which can be up to 70% of total operating costs. They are also more corrosive and chemically unstable compared to other amines if the concentration is excessive.[8]
Piperazines have been proposed forcarbon capture and storage (CCS) because piperazine is very efficient at CO2 removal.[9][10] The capabilities of piperazine are within the bounds of and thus favored for carbon capture. Piperazine can be thermally regenerated throughmulti-stage flash distillation and other methods after being used in operating temperatures up to 150 °C and recycled back into the absorption process, providing for higher overall energy performance in amine gas treating processes.[11] Pilot plant studies have been conducted.[12]
In oil refineries, that stripped gas is mostly H2S, much of which often comes from a sulfur-removing process calledhydrodesulfurization. This H2S-rich stripped gas stream is then usually routed into aClaus process to convert it into elementalsulfur. 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.[13][14] Another sulfur-removing process is theWSA process which recovers sulfur in any form as concentratedsulfuric acid. 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 andconventional coal-fired power plant).
In the specific case of the industrial synthesis ofammonia, for thesteam reforming process of hydrocarbons to produce gaseoushydrogen, amine treating is one of the commonly used processes for removing excess carbon dioxide in the final purification of the gaseous hydrogen.
In thebiogas production it is sometimes necessary to remove carbon dioxide from the biogas to make it comparable with natural gas. The removal of the sometimes high content of hydrogen sulfide is necessary to prevent corrosion of metallic parts after burning the bio gas.[15]
Amines are used to remove CO2 in various areas ranging from natural gas production to the food and beverage industry, and have been since 1930.[16]
There are multiple classifications of amines, each of which has different characteristics relevant to CO2 capture. For example, monoethanolamine (MEA) reacts strongly with CO2 and has a fast reaction time and an ability to remove high percentages of CO2, even at the low CO2 concentrations. Typically, monoethanolamine (MEA) can capture 85% to 90% of the CO2 from the flue gas of a coal-fired plant, which is one of the most effective solvent to capture CO2.[17]
Challenges of carbon capture using amine include:
The partial pressure is the driving force to transfer CO2 into the liquid phase. Under low pressure, this transfer is hard to achieve without increasing the reboilers' heat duty, which will result in higher costs.[18]
Primary and secondary amines, for example, MEA and DEA, will react with CO2 and form degradation products. 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.[18]
Currently, a variety of amine mixtures are being synthesized and tested to achieve a more desirable set of overall properties for use in CO2 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 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.[17]
