Amine gas treating

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Amine gas plant at a natural gas field Amine Plant.jpg
Amine gas plant at a natural gas field

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 (H2S) and carbon dioxide (CO2) from gases. [1] [2] [3] It is a common unit process used in refineries, and is also used in petrochemical plants, natural gas processing plants and other industries.

Contents

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 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 remove sour gases from liquid hydrocarbons such as liquified petroleum gas (LPG).

Description of a typical amine treater

Gases containing H2S or both H2S and CO2 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. For one of the more common amines, monoethanolamine (MEA) denoted as RNH2, 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:

RNH2 + H2S RNH+
3
+ HS
RNH2 + H
2
CO
3
RNH+
3
+ HCO
3

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, the sweetened gas is thus depleted in H2S and CO2.

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 H2S 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 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 H2S and CO2.

Process flow diagram of a typical amine treating process used in petroleum refineries, natural gas processing plants and other industrial facilities. AmineTreating.svg
Process flow diagram of a typical amine treating process used in petroleum refineries, natural gas processing plants and other industrial facilities.

Alternative processes

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 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]

Amines

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]

  • Monoethanolamine: About 20 % for removing H2S and CO2, and about 32 % for removing only CO2.
  • Diethanolamine: About 20 to 25 % removing H2S and CO2
  • Methyldiethanolamine: About 30 to 55 % for removing H2S and CO2
  • Diglycolamine: About 50 % for removing H2S and CO2

The choice of amine concentration in the circulating aqueous solution depends upon several factors and may be quite arbitrary. 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. [1]

Both H2S and CO2 are acid gases and hence corrosive to carbon steel. 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. [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

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 CO2 per mole of amine. [6] 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. [6]

Uses

In oil refineries, that stripped gas is mostly H2S, much of which often comes from a sulfur-removing process called hydrodesulfurization. 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 64,000,000 metric tons of sulfur produced worldwide in 2005 was byproduct sulfur from refineries and other hydrocarbon processing plants. [7] [8] Another sulfur-removing process 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 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 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. [9]

Carbon capture and storage

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. [10]

There are multiple classifications of amines, each of which has different characteristics relevant to CO2 capture. 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. 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. [11]

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. [12]

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. [12]

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. [11]

See also

Related Research Articles

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Hydrogen sulfide is a chemical compound with the formula H2S. It is a colorless chalcogen-hydride gas, and is poisonous, corrosive, and flammable, with trace amounts in ambient atmosphere having a characteristic foul odor of rotten eggs. Swedish chemist Carl Wilhelm Scheele is credited with having discovered the chemical composition of purified hydrogen sulfide in 1777.

<span class="mw-page-title-main">Ethanolamine</span> Chemical compound

Ethanolamine is a naturally occurring organic chemical compound with the formula HOCH
2
CH
2
NH
2
or C
2
H
7
NO
. The molecule is bifunctional, containing both a primary amine and a primary alcohol. Ethanolamine is a colorless, viscous liquid with an odor reminiscent of ammonia.

<span class="mw-page-title-main">Piperazine</span> Chemical compound

Piperazine is an organic compound that consists of a six-membered ring containing two nitrogen atoms at opposite positions in the ring. Piperazine exists as small alkaline deliquescent crystals with a saline taste.

Acid gas is a particular typology of natural gas or any other gas mixture containing significant quantities of hydrogen sulfide (H2S), carbon dioxide (CO2), or similar acidic gases. A gas is determined to be acidic or not after it is mixed with water. The pH scale ranges from 0 to 14, anything above 7 is basic while anything below 7 is acidic. Water has a neutral pH of 7 so once a gas is mixed with water, if the resulting mixture has a pH of less than 7 that means it is an acidic gas.

Sour gas is natural gas or any other gas containing significant amounts of hydrogen sulfide (H2S).

<span class="mw-page-title-main">Claus process</span> Gas desulfurizing process leading to the formation of elemental sulfur

The Claus process is the most significant gas desulfurizing process, recovering elemental sulfur from gaseous hydrogen sulfide. First patented in 1883 by the chemist Carl Friedrich Claus, the Claus process has become the industry standard.

<span class="mw-page-title-main">Hydrodesulfurization</span> Chemical process used to remove sulfur in natural gas and oil refining

Hydrodesulfurization (HDS), also called hydrotreatment or hydrotreating, is a catalytic chemical process widely used to remove sulfur (S) from natural gas and from refined petroleum products, such as gasoline or petrol, jet fuel, kerosene, diesel fuel, and fuel oils. The purpose of removing the sulfur, and creating products such as ultra-low-sulfur diesel, is to reduce the sulfur dioxide emissions that result from using those fuels in automotive vehicles, aircraft, railroad locomotives, ships, gas or oil burning power plants, residential and industrial furnaces, and other forms of fuel combustion.

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<span class="mw-page-title-main">Natural-gas processing</span> Industrial processes designed to purify raw natural gas

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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.

Rectisol is the trade name for an acid gas removal process that uses methanol as a solvent to separate acid gases such as hydrogen sulfide and carbon dioxide from valuable feed gas streams. By doing so, the feed gas is made more suitable for combustion and/or further processing. Rectisol is used most often to treat synthesis gas (primarily hydrogen and carbon monoxide) produced by gasification of coal or heavy hydrocarbons, as the methanol solvent is well able to remove trace contaminants such as ammonia, mercury, and hydrogen cyanide usually found in these gases. As an acid gas and large component of valuable feed gas streams, CO2 is separated during the methanol solvent regeneration.

The Shell–Paques process, also known by the trade name of Thiopaq O&G, is a gas desulfurization technology for the removal of hydrogen sulfide from natural-, refinery-, synthesis- and biogas. The process was initially named after the Shell Oil and Paques purification companies. After accession of a dedicated joint venture by the founders, Paqell B.V., the trade name for applications in the Oil & Gas industry was changed to "THIOPAQ O&G". It is based on the biocatalytical conversion of sulfide into elemental sulfur. It operates at near-ambient conditions of temperature, about 30-40 °C, and pressure which results in inherent safety. It is an alternative to, for example, the Claus process.

<span class="mw-page-title-main">Methyldiethanolamine</span> Chemical compound

Methyldiethanolamine, also known as N-methyl diethanolamine and more commonly as MDEA, is the organic compound with the formula CH3N(C2H4OH)2. It is a colorless liquid with an ammonia odor. It is miscible with water, ethanol and benzene. A tertiary amine, it is widely used as a sweetening agent in chemical, oil refinery, syngas production and natural gas.

A biogas upgrader is a facility that is used to concentrate the methane in biogas to natural gas standards. The system removes carbon dioxide, hydrogen sulphide, water and contaminants from the biogas. One technique for doing this uses amine gas treating. This purified biogas is also called biomethane. It can be used interchangeably with natural gas.

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The use of ionic liquids in carbon capture is a potential application of ionic liquids as absorbents for use in carbon capture and sequestration. Ionic liquids, which are salts that exist as liquids near room temperature, are polar, nonvolatile materials that have been considered for many applications. The urgency of climate change has spurred research into their use in energy-related applications such as carbon capture and storage.

References

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  2. Gary, J.H.; Handwerk, G.E. (1984). Petroleum Refining Technology and Economics (2nd ed.). Marcel Dekker, Inc. ISBN   0-8247-7150-8.
  3. US 4080424,Loren N. Miller&Thomas S. Zawacki,"Process for acid gas removal from gaseous mixtures",issued 21 Mar 1978, assigned to Institute of Gas Technology
  4. Baker, R. W. (2002). "Future Directions of Membrane Gas Separation Technology". Ind. Eng. Chem. Res. 41 (6): 1393–1411. doi:10.1021/ie0108088.
  5. Oyenekan, Babatunde; Rochelle, Gary T. (2007). "Alternative Stripper Configurations for CO2 Capture by Aqueous Amines". AIChE Journal. 53 (12): 3144–154. doi:10.1002/aic.11316.
  6. 1 2 Idem, Raphael (2006). "Pilot Plant Studies of the CO2 Capture Performance of Aqueoues MEA and Mixed MEA/MDEA Solvents at the University of Regina CO2 Capture Technology Development Plant and the Boundary Dam CO2 Capture Demonstration Plant". Ind. Eng. Chem. Res. 45 (8): 2414–2420. doi:10.1021/ie050569e.
  7. Sulfur production report by the United States Geological Survey
  8. Discussion of recovered byproduct sulfur
  9. Abatzoglou, Nicolas; Boivin, Steve (2009). "A review of biogas purification processes". Biofuels, Bioproducts and Biorefining. 3 (1): 42–71. doi:10.1002/bbb.117. ISSN   1932-104X. S2CID   84907789.
  10. Rochelle, G. T. (2009). "Amine Scrubbing for CO2 Capture". Science. 325 (5948): 1652–1654. Bibcode:2009Sci...325.1652R. doi:10.1126/science.1176731. ISSN   0036-8075. PMID   19779188. S2CID   206521374.
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