View source for Amine gas treating

{{Short description|Removal of impurities from gases by scrubbing them in aqueous solutions of various alkylamines}}
[[File:Amine Plant.jpg|thumb|right|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 [[Amine#Aliphatic amines|alkylamines]] (commonly referred to simply as [[amine]]s) to remove [[hydrogen sulfide]] (H<sub>2</sub>S) and [[carbon dioxide]] (CO<sub>2</sub>) from gases.<ref name=Kohl>{{cite book|author1=Arthur Kohl |author2=Richard Nielson |title=Gas Purification|edition=5th|publisher=Gulf Publishing|year=1997|isbn=0-88415-220-0}}</ref><ref name=Gary>{{cite book|author1=Gary, J.H.  |author2=Handwerk, G.E.|title=Petroleum Refining Technology and Economics|edition=2nd|publisher=Marcel Dekker, Inc|year=1984|isbn=0-8247-7150-8}}</ref><ref>{{cite patent
| country = US
| number = 4080424
| status =
| title = Process for acid gas removal from gaseous mixtures
| pubdate =
| gdate =  21 Mar 1978
| fdate = 11 Feb 1976
| pridate =
| inventor = Loren N. Miller
| invent1 = Robert A. Macriss
| invent2 = Thomas S. Zawacki
| assign1 =  Institute of Gas Technology
| assign2 =
| class =
}}</ref>   It is a common [[unit process]] used in [[oil refinery|refineries]], and is also used in [[petrochemical]] plants, [[natural gas processing|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 involves [[membrane technology]]. However, membrane separation is less attractive due to the relatively high capital and operating costs as well as other technical factors.<ref>{{cite journal | last1 = Baker | first1 = R. W. | year = 2002 | title = Future Directions of Membrane Gas Separation Technology | journal = Ind. Eng. Chem. Res. | volume = 41 | issue = 6| pages = 1393–1411 | doi = 10.1021/ie0108088 }}</ref>
Many different amines are used in gas treating:
* [[Diethanolamine]] (DEA)
* [[Ethanolamine|Monoethanolamine]] (MEA)
* [[Methyl diethanolamine|Methyldiethanolamine]] (MDEA)
* [[Diisopropanolamine]] (DIPA)
* Aminoethoxyethanol (Diglycolamine) (DGA)
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 gas]]es 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 gas]]es'' or ''[[acid gas]]es'' 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 '''RNH<sub>2</sub>''', the [[acid-base reaction]] involving the [[protonation]] of the amine [[electron pair]] to form a positively charged ammonium group '''(RNH{{su|p=+|b=3}})''' can be expressed as:
:RNH<sub>2</sub> + {{H2S}} {{eqm}} RNH{{su|p=+|b=3}} + HS<sup>−</sup>
:RNH<sub>2</sub> + {{chem|H|2|CO|3}} {{eqm}} RNH{{su|p=+|b=3}} + {{chem|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 [[Process Flow diagram|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}}.
[[Image:AmineTreating.svg|frame|center|[[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 [[Thermal efficiency|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.<ref name="Oyenekan2007">{{cite journal|last1=Oyenekan|first1=Babatunde|last2=Rochelle|first2=Gary T.|title=Alternative Stripper Configurations for CO2 Capture by Aqueous Amines|journal=AIChE Journal|volume=53|issue=12|year=2007|pages=3144–154 |doi=10.1002/aic.11316}}</ref>
== 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:<ref name=Kohl/>
:* Monoethanolamine: About 20 % for removing H<sub>2</sub>S and CO<sub>2</sub>, and about 32 % for removing only CO<sub>2</sub>.
:* Diethanolamine: About 20 to 25 % removing H<sub>2</sub>S and CO<sub>2</sub>
:* Methyldiethanolamine: About 30 to 55 % for removing H<sub>2</sub>S and CO<sub>2</sub>
:* Diglycolamine: About 50 % for removing H<sub>2</sub>S and CO<sub>2</sub>
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 refining processes|petroleum refinery]] by-product gases that contain relatively low concentrations of both H<sub>2</sub>S and CO<sub>2</sub> or whether the unit is treating gases with a high percentage of CO<sub>2</sub> such as the offgas from the steam reforming process used in [[ammonia production]] or the [[flue gas]]es from [[Conventional coal-fired power plant|power plants]].<ref name=Kohl/>
Both H<sub>2</sub>S and CO<sub>2</sub> are acid gases and hence corrosive to [[carbon steel]]. However, in an amine treating unit, CO<sub>2</sub> is the stronger acid of the two. H<sub>2</sub>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<sub>2</sub>, 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 H<sub>2</sub>S and CO<sub>2</sub> in the selected amine.<ref name=Kohl/> 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<sub>2</sub>S alone or CO<sub>2</sub> 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&nbsp;mol CO<sub>2</sub> per mole of amine.<ref name="Idem2006">{{cite journal|last1=Idem|first1=Raphael|title=Pilot Plant Studies of the CO<sub>2</sub> Capture Performance of Aqueoues MEA and Mixed MEA/MDEA Solvents at the University of Regina CO<sub>2</sub> Capture Technology Development Plant and the Boundary Dam CO<sub>2</sub> Capture Demonstration Plant|journal=Ind. Eng. Chem. Res.|volume=45|year=2006|issue=8|pages=2414–2420|doi=10.1021/ie050569e}}</ref>  MEA and DEA also require a large amount of energy to strip the CO<sub>2</sub> during regeneration, which can be up to 70% of total operating costs. They are also more corrosive and chemically unstable compared to other amines.<ref name="Idem2006"/>
== Uses ==
In oil refineries, that stripped gas is mostly H<sub>2</sub>S, much of which often comes from a sulfur-removing process called [[hydrodesulfurization]].  This H<sub>2</sub>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.<ref>[http://minerals.usgs.gov/minerals/pubs/commodity/sulfur/sulfumcs06.pdf Sulfur production report] by the [[United States Geological Survey]]</ref><ref>[http://www.agiweb.org/geotimes/july03/resources.html Discussion of recovered byproduct sulfur]</ref> 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 CO<sub>2</sub> from the flue gases emitted by fossil fuel power plants has led to much interest in using amines for removing CO<sub>2</sub> (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.<ref name="AbatzoglouBoivin2009">{{cite journal|last1=Abatzoglou|first1=Nicolas|last2=Boivin|first2=Steve|title=A review of biogas purification processes|journal=Biofuels, Bioproducts and Biorefining|volume=3|issue=1|year=2009|pages=42–71|issn=1932-104X|doi=10.1002/bbb.117|s2cid=84907789 }}</ref>
=== Carbon capture and storage ===
Amines are used to remove CO<sub>2</sub> in various areas ranging from natural gas production to the food and beverage industry, and have been since 1930.<ref name="Rochelle2009">{{cite journal|last1=Rochelle|first1=G. T.|title=Amine Scrubbing for CO<sub>2</sub> Capture|journal=Science|volume=325|issue=5948|year=2009|pages=1652–1654|issn=0036-8075|doi=10.1126/science.1176731|pmid=19779188|bibcode=2009Sci...325.1652R|s2cid=206521374}}</ref>
There are multiple classifications of amines, each of which has different characteristics relevant to CO<sub>2</sub> capture. For example, monoethanolamine (MEA) reacts strongly with acid gases like CO<sub>2</sub> and has a fast reaction time and an ability to remove high percentages of CO<sub>2</sub>, even at the low CO<sub>2</sub> concentrations. Typically, monoethanolamine (MEA) can capture 85% to 90% of the CO<sub>2</sub> from the flue gas of a coal-fired plant, which is one of the most effective solvent to capture CO<sub>2</sub>.<ref name=folger>{{cite journal| first = P. | last = Folger| title =Carbon Capture: a Technology Assessment | journal = Congressional Research Service Report for Congress | volume= 5 | year= 2009 | pages = 26–44}}</ref>
Challenges of carbon capture using amine include:
* Low pressure gas increases difficulty of transferring CO<sub>2</sub> from the gas into amine
* Oxygen content of the gas can cause amine degradation and acid formation
* CO<sub>2</sub> degradation of primary (and secondary) amines
* High energy consumption
* Very large facilities
* Finding a suitable location (enhanced oil recovery, deep saline aquifers, basaltic rocks...) to dispose of the removed CO<sub>2</sub><ref name="WuCarroll2011">{{cite book|first1=Ying |last1=Wu|first2=John J.|last2= Carroll|title=Carbon Dioxide Sequestration and Related Technologies|url=https://books.google.com/books?id=TrTpKKHj7zgC|date=5 July 2011|publisher=John Wiley & Sons|isbn=978-0-470-93876-8 | pages= 128–131}}</ref>
The partial pressure is the driving force to transfer CO<sub>2</sub> 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.<ref name="WuCarroll2011" />
Primary and secondary amines, for example, MEA and DEA, will react with CO<sub>2</sub> and form degradation products. O<sub>2</sub> from the inlet gas will cause degradation as well. The degraded amine is no longer able to capture CO<sub>2</sub>, which decreases the overall carbon capture efficiency.<ref name="WuCarroll2011" />
Currently,  a variety of amine mixtures are being synthesized and tested to achieve a more desirable set of overall properties for use in CO<sub>2</sub> 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 CO<sub>2</sub>, thus, increasing the capital cost.<ref name=folger />
==See also==
*[[Ammonia production]]
*[[Hydrodesulfurization]]
*[[WSA Process]]
*[[Claus process]]
*[[Selexol]]
*[[Rectisol]]
*[[Amine]]
*[[Ionic liquids in carbon capture]]
*[[Solid sorbents for carbon capture]]
==References==
{{Reflist}}
==External links==
* [https://web.archive.org/web/20110811211837/http://articles.compressionjobs.com/articles/oilfield-101/2711-gas-dehydration-lts-hydrates-sweetening-amine?start=6 Description of Gas Sweetening Equipment and Operating Conditions]
* [https://web.archive.org/web/20061110085505/http://www.bre.com/technicalpapers/technicalpaper.asp?articlenumber=52 Selecting Amines for Sweetening Units], Polasek, J. (Bryan Research & Engineering) and Bullin, J.A. (Texas A&M University), Gas Processors Association Regional Meeting, Sept. 1994.
* [https://web.archive.org/web/20110101053431/http://naturalgas.org/naturalgas/processing_ng.asp Natural Gas Supply Association] Scroll down to ''Sulfur and Carbon Dioxide Removal''
* [http://www.gulfpub.com/default.asp?page=14&productID=2743&VS=  Description of the classic book on gas treating] {{Webarchive|url=https://web.archive.org/web/20080316061016/http://www.gulfpub.com/default.asp?page=14&productID=2743&VS= |date=2008-03-16 }} by {{cite book|author1=Arthur Kohl |author2=Richard Nielsen |title=Gas Purification|edition=Fifth|publisher=Gulf Publishing|isbn=0-88415-220-0}}
{{Petroleum refining}}
{{DEFAULTSORT:Amine Gas Treating}}
[[Category:Acid gas control]]
[[Category:Biogas technology]]
[[Category:Carbon capture and storage]]
[[Category:Chemical processes]]
[[Category:Gas technologies]]
[[Category:Natural gas technology]]
[[Category:Oil refining]]