WO1993010883A1 - Procede d'enrichissement de gaz acide pauvre a l'aide d'amines entravees selectives - Google Patents

Procede d'enrichissement de gaz acide pauvre a l'aide d'amines entravees selectives Download PDF

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Publication number
WO1993010883A1
WO1993010883A1 PCT/US1991/008940 US9108940W WO9310883A1 WO 1993010883 A1 WO1993010883 A1 WO 1993010883A1 US 9108940 W US9108940 W US 9108940W WO 9310883 A1 WO9310883 A1 WO 9310883A1
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gas
amine
acid
adsorbent
severely
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PCT/US1991/008940
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English (en)
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George R. Chludzinski
Jagannathan N. Iyengar
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Exxon Research And Engineering Company
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Priority to PCT/US1991/008940 priority Critical patent/WO1993010883A1/fr
Publication of WO1993010883A1 publication Critical patent/WO1993010883A1/fr

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    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/00—Sulfur; Compounds thereof
    • C01B17/02—Preparation of sulfur; Purification
    • C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
    • C01B17/0404—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process
    • C01B17/0408—Pretreatment of the hydrogen sulfide containing gases
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B01D53/1462—Removing mixtures of hydrogen sulfide and carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1493—Selection of liquid materials for use as absorbents
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/151—Reduction of greenhouse gas [GHG] emissions, e.g. CO2

Definitions

  • This invention relates to a method whereby lean acid gases containing less than 20% by volume H 2 S and the balance essentially CO 2 are enriched to contain 20% or more H 2 S by volume, preferably between 20-80% H 2 S by means of selective hindered amines, which selectively removes H 2 S from the lean acid gas stream, the enriched acid gas being suitable for treatment in Claus process units.
  • U.S. Patent 4,112,052 describes a process employing sterically hindered amines to obtain nearly complete removal of acid gases such as CO 2 and H 2 S simultaneously.
  • While selective H 2 S removal is applicable to a number of gas treating operations including treatment of hydrocarbon gases from shale pyrolysis, refinery gas, and natural gas having a low H 2 S/CO 2 ratio, it is particularly desirable in the treatment of gases wherein the partial pressure of H 2 S is relatively low compared to that of CO 2 because the capacity of an amine to absorb H 2 S from the latter type gases is very low.
  • gases with relatively low partial pressures of H 2 S include synthetic gases made by coal gasification, sulfur plant tail gas, and low-Joule fuel gases encountered in refineries where heavy residual oil is being thermally converted to lower molecular weight liquids and gases.
  • Diisopropanolamine is relatively unique among secondary aminoalcohols in that it has been used industrially, alone or with a physical solvent such as sulfolane, for selective removal of H 2 S from gases containing H 2 S and CO 2 , but contact times must be kept relatively short to take advantage of the faster reaction of H 2 S with the amine compared to the rate of CO 2 reaction shown in Equations 2 and 4 hereinabove.
  • MDEA methyldiethanolamine
  • U.K. Patent Publication 2,017,524A to Shell disclosed that aqueous solutions of dialkylmonoalkanolamines, and particularly diethylmonoethanolamine (DEAE), have higher selectivity and capacity for H 2 S removal at higher loading levels than MDEA solutions. Nevertheless, even DEAE is not very effective for the low H 2 S loading frequently encountered in the industry. Also, DEAE has a boiling point of 161°C, and as such, it is characterized as being a lowboiling, relatively highly volatile amino alcohol. Such high volatilities under most gas scrubbing conditions result in large material losses with consequent losses in economic advantages.
  • DEAE diethylmonoethanolamine
  • absorbent solutions which are selective to H 2 S removal but have selectivity and/or capacity limitations similar to those of MDEA include solutions of 1-formylpiperidine as described in U.S. Pat. No. 4,107,270, piperazine as described in U.S. Pat. No. 4,112,049, and solutions, in N-methyl-2-pyrrolidone, of cyanopyridine, an aromatic nitrile, an anhydride, or a piperazine, as described in U.S. Patent Nos. 3,656,887, 3,767,766, 3,642,431 and G.B. Pat. No. 1,560,905, respectively.
  • U.S. Patent 4,483,833 teaches that nitrogen heterocyclic tertiary aminoalkanols and aminoether alkanols have a high selectivity for H 2 S as compared to CO 2 and maintain this selectivity at high H 2 S and CO 2 loadings.
  • the nitrogen heterocyclic tertiary aminoalkanol or aminoetheralkanol is defined as a compound wherein the heterocycle portion contains 4-8 ring atoms, preferably 4-7 ring atoms, most preferably five ring atoms, of which one is nitrogen, and may be unsubstituted or substituted, e.g., with hydroxyl, alkyl or hydroxyalkyl radicals, and wherein the alkanol portion is arranged in a liner or branched fashion, connected to the heterocycle portion via a ring nitrogen or ring carbon atoms, preferably 2-10 carbon atoms, when the alkanol carbon atoms is attached to the nitrogen atom.
  • the hydroxy carbon group can be attached directly to a ring carbon atom or separated from a ring carbon atom by 1-5 carbon atoms.
  • the hydrocarbon chain of the alkanol portion may be alkoxylated, i.e., may contain one or more ether oxygen atoms.
  • the hydroxyl functionality of the alkanol chain may be primary or secondary.
  • U.S. Patent 4,405,581 teaches that severely sterically hindered amino alcohols have a high selectivity for H 2 S as compared to CO 2 , and maintain this selectivity at high H 2 S and CO 2 loadings.
  • the severely sterically hindered secondary amino alcohols herein may have either acyclic (linear or branched) or cyclic moieties attached to the nitrogen atom(s) of the amino alcohols.
  • Representative severely sterically hindered secondary amino alcohols include tertiarybutylaminoethanol, 2-(isopropylamino)-1- propanol, 3-(tertiarybutylamino)-n-butanol, 2-(tertiarybutylamino)-1- propanol, 3-(tertiarybutylamino)-1-propanol, 3-aza-2,2-dimethyl-1,6- hexanediol, and 2,5-diaza-2,4,4-trimethyl-7-heptanol.
  • U.S. Patent 4,405,811 teaches that severely sterically hindered tertiary amino compounds such as N-methyl-N-tertiarybutylaminoethoxyethanol, 2-(N-isopropyl-N-methylamino) propoxyethanol and 3-aza 2,2,3-trimethyl-1,6-hexanediol have a high selectivity for H 2 S as compared to CO 2 , and maintain this selectivity at high H 2 S and CO 2 loadings and are useful in sulfur plant tail gas clean-up operations.
  • tertiary amino compounds such as N-methyl-N-tertiarybutylaminoethoxyethanol, 2-(N-isopropyl-N-methylamino) propoxyethanol and 3-aza 2,2,3-trimethyl-1,6-hexanediol have a high selectivity for H 2 S as compared to CO 2 , and maintain this selectivity at high H 2 S and CO 2 loadings and are useful in sulfur plant tail gas clean-up operations.
  • U.S. Patent 4,405,585 teaches that severely sterically hindered aminoether alcohols have a high selectivity for H 2 S as compared to CO 2 and maintain this selectivity at high H 2 S and CO 2 loadings.
  • the amino compound is preferably one or more compounds selected from the group consisting of tertiarybutylaminoethoxyethanol, 2-(2-tertiarybutylamino)propoxyethanol, tertiaryamylaminoethoxyethanol, (1-methyl-1-ethylpropylamino)ethoxyethanol, and 2- (2- isopropylamino)propoxyethanol.
  • One of the preferred amino compounds is tertiarybutylaminoethoxyethano (TBEE).
  • U.S. Patent 4,405,580 teaches that tertiary amino azabicyclic alcohols such as tropine, pseudotropine, 9-methylgranatanin-3-ol, isoqunuclidine ethanol, trachelanthamidine, 4- hydroxymethylquinuclidine, N-hydroxyethylnortropine, N-hydroxyethyl(9- azabicyclo [3,3,1]nonane, N-hydroxyethoxyethyl(9-azabicyclo-[4.2.1]- nonane, 3-hydroxymethyl-8-methyl-8-azabicyclo [3.2.1] octane, and the like have a high selectivity for H 2 S as compared to CO 2 and maintain this selectivity at high H 2 S and CO 2 loadings.
  • tertiary amino azabicyclic alcohols such as tropine, pseudotropine, 9-methylgranatanin-3-ol, isoqunuclidine ethanol, trachelanthamidine,
  • U.S. Patent 4,417,075 teaches that di secondary aminoethers and more specifically di(secondary and tertiary alkylaminoalkoxy) alkanes such as 1,2-bis(tertiarybutylaminoethoxy)ethane, bis-(2- isopropylaminopropyl)ether and bis-(tertiarybutylaminoethyl)ether, and the like have a high selectivity for H 2 S as compared to CO 2 and maintain this selectivity at high H 2 S and CO 2 loadings.
  • U.S. Patent 4,405,583 teaches that di-severely sterically hindered secondary aminoethers have a high selectivity for H 2 S as compared to CO 2 and maintain the selectivity at high H 2 S and CO 2 loadings.
  • di-severely sterically hindered secondary aminoethers herein are mono- or polyether compounds wherein-each amino group has a severely sterically hindered secondary amino moiety.
  • di-secondary aminoethers include, for example, bis-(tertiary-butylaminoethyl)ether, 1,2-bis-(tertiarybutylaminoethoxy)ethane, 1,2-bis-(tertiarybutylaminoethoxyethoxy)ethane, bis[2-(isopropylamino)-propyl]ether, 1,2-[2-(isopropylamino)-propoxy]- ethane and the like.
  • U.S. Patent 4,405,582 teaches that diaminoethers have a high selectivity for H 2 S as compared to CO 2 and maintain this selectivity at high H 2 S and CO 2 loadings.
  • the diaminoethers herein are mono- or polyether compounds wherein at least one of the two amino groups, and preferably both, is a tertiary amine.
  • the tertiary amine may be acyclic or in the form of an N-heterocycle.
  • diaminoethers include, for example, 1,2-bis- (N,N-dimethylaminoethoxy)ethane, bis-(N-pyrrolidinylethyl)ether, N-pyrrolidinylethoxyethyl-N,N-diethylamine, 1,2-bis-(pyrrolidinylethoxy)ethane, 1,2-bis-(pyrrolidinylethoxyethoxy)ethane, 1,2-bis- (3- pyrrolidinyl-n-propoxy)ethane, 1,2-bis-(piperidinylethoxy)ethane, 1,3-bis-(piperidinyl-n-propoxy)propane, 1-(pyrrolidinylethoxy)-2-(t- butylaminoethoxy)ethane, 1,2-bis-(azepanylethoxy)ethane, 1-(pyrrolidinylethoxy)-2-(piperidinylethoxy)ethane, 1-(pyrrolidin
  • Representative severely sterically hindered acyclic secondary aminoether alcohols include tertiarybutylaminoethoxyethanol, 2-(2-tertiarybutylamino)-propoxyethanol, 2-(2-isopropylamino) propoxyethanol, tertiaryamylaminoethoxyethanol, (1-methyl-1-ethylpropylamino)ethoxyethanol.
  • U.S. Patent 4,618,481 teaches that an absorbent composition comprising a specific ratio of an amine salt and an unreacted alkaline severely hindered amino compound can be used to treat a low pressure gas in an energy efficient manner to produce a treated gas having less than 10 vppm H 2 S.
  • the absorbent composition comprises: (1) at least one severely hindered amino compound having a cumulative -E s value (Taft's steric hindrance constant) greater than 1.75, and (2) an amine salt, said amine salt being the reaction product of an amine selected from the group consisting of a severely hindered amino compound having a cumulative -E s value (Taft's steric hindrance constant) greater than 1.75, a tertiary amine and mixtures thereof and a component selected from the group consisting of an acid having at least one pKa of not more than about 7, a decomposable salt of an acid having at least one pKa of not more than about 7, a compound capable of forming an acid having a pKa of not more than about 7 and mixtures thereof, said amine salt and said severely hindered amino compound being present in said absorbent composition in a mole ratio of said amine salt to said severely hindered amino compound of at least about 0.1:1.
  • U.S. Patent 4,894,178 teaches the use of a mixture of two severely sterically hindered amines for selective removal of H 2 S in the presence of CO 2 .
  • a mixture of bis-(tertiarybutylaminoethoxy)-ethane (BTEE) and ethoxyethoxyethanol-tertiarybutylamine (EEETB) can be synthesized by the catalytic tertiarybutylamination of trietylene glycol and used in aqueous solution form to selectively separate H 2 S from streams containing H 2 S and CO 2 .
  • severely sterically hindered amino alcohols have a degree of steric hindrance such that the cumulative -E s
  • Taft's steric hindrance constant is greater than about 1.75 as calculated from the values given for primary amines in Table V from D.F. DeTar, Journal of Organic Chemistry, 45, 5174(1980), the entire disclosure of which is incorporated herein by reference.
  • amino compounds characterized by their high selectivity for H 2 S compared to CO 2 and their ability to maintain this selectivity at high H 2 S and CO 2 loadings are further characterized by their low volatility and high solubility in water at selective H 2 S removal conditions, and most of the compounds are also generally soluble in polar organic solvent systems which may or may not contain water.
  • absorbent solution includes but is not limited to solutions wherein the amino compound is dissolved in a solvent selected from water or a physical absorbent or mixtures thereof. Solvents which are physical absorbents (as opposed to the amino compounds which are chemical absorbents) are described, for example, in U.S. Pat. No.
  • 4,112,051 the entire disclosure of which is incorporated herein by reference, and include, e.g., aliphatic acid amides, N-alkylated pyrrolidones, sulfones, sulfoxides, glycols and the mono- and diethers thereof.
  • the preferred physical absorbents herein are sulfones, and most particularly, sulfolane.
  • the absorbent solution ordinarily has a concentration of amino compound of about 0.1 to 6 moles per liter of the total solution, and preferably 1 to 4 moles per liter, depending primarily on the specific amino compound employed and the solvent system utilized. If the solvent system is a mixture of water and a physical absorbent, the typical effective amount of the physical absorbent employed may vary from 0.1 to 5 moles per liter of total solution, and preferably from 0.5 to 3 moles per liter, depending mainly on the type of amino compound being utilized.
  • the dependence of the concentration of amino compound on the particular compound employed is significant because increasing the concentration of amino compound may reduce the basicity of the absorbent solution, thereby adversely affecting its selectivity for H 2 S removal, particularly if the amino compound has a specific aqueous solubility limit which will determine maximum concentration levels within the range given above. It is important, therefore, that the proper concentration level appropriate for each particular amino compound be maintained to insure satisfactory results.
  • the solution may include a variety of additives typically employed in selective gas removal processes, e.g., antifoaming agents, antioxidants, corrosion inhibitors, and the like.
  • additives typically employed in selective gas removal processes, e.g., antifoaming agents, antioxidants, corrosion inhibitors, and the like.
  • the amount of these additives will typically be in the range that they are effective, i.e., an effective amount.
  • amino compounds described herein may be admixed with other amino compounds as a blend preferably with methyldiethanolamine.
  • the mole ratio of the respective amino compounds may vary widely, for example, from 1 to 99 percent of the amino compounds described herein.
  • U.S. Patent 4,519,991 teaches an improved method for the enrichment of a gas in H 2 S comprising selective absorption by a liquid in a primary absorption zone by contacting gas containing H 2 S with an absorbent liquid, regeneration of the liquid by heating and/or stripping by an inert gas with liberation of the gases absorbed and recovery of a fraction of the liberated gases, the remainder of the liberated gases being subjected to a second absorption in a secondary absorption zone by a new or regenerated absorbent liquid identical with that utilized in the primary absorption zone, characterized in that, the steps of regeneration and secondary absorption are effected in a common operative zone in which there occur simultaneously: introduction of the liquid from the primary absorption, movement of the gases liberated during regeneration for said recovery and for contact with absorbent liquid, flow of the liquid derived from the secondary absorption and discharge from said operative zone of a fraction of the liberated gases enriched in H 2 S.
  • a stream containing 85% H 2 S is produced.
  • U.S. Patent 4,085,192 teaches a process for selectively removing H 2 S from gaseous mixtures containing H 2 S and CO 2 .
  • the process involves contacting the gaseous mixture with an H 2 S selective aqueous alkanol amine absorbent solution in an absorption column having from 3 to 20 contacting trays, said trays having an average dry tray pressure drop of from about 1.5 to about 5 inches per tray, thereby obtaining a treated gas containing less than 10% of the hydrogen sulfide present in the gaseous feed but more than 50% of the carbon dioxide present in said feed, and a hydrogen sulfide and carbon dioxide enriched-absorbent solution, passing said hydrogen sulfide and carbon dioxide-enriched absorbent solution to a regenerating zone and stripping said absorbent solution to a hydrogen sulfide content which corresponds to an equilibrium loading for a H 2 S content having less than 50% of the hydrogen sulfide content of the treated gas, and returning said regenerated absorbent liquid into contact with the hydrogen
  • the process can be used to produce a stream of high H 2 S concentration from a feed having as little as 5% H 2 S and 94% CO 2 .
  • the H 2 S concentration stream produced is suitable for Claus plant processing.
  • U.S. Patent 4,356,161 teaches a process for reducing the total sulfur content of a feed gas containing 40-95% CO 2 , 0.03 to 20% H 2 S and 0.02 to 2% COS.
  • the feed gas is first passed to an absorption column and contacted with an H 2 S selective absorbent.
  • the unabsorbed high CO 2 -content gas is then routed to a reduction step where it is combined with Claus off-gases and the sulfur compounds are reduced to H 2 S.
  • the treated gas is then passed to a second absorption column and the unabsorbed gas is vented to the atmosphere.
  • the H 2 S rich solvent from both absorption columns is stripped in a common stripper and the stripped gas is passed to a Claus unit for conversion to elemental sulfur.
  • U.K. Patent 1,551,692 teaches a process for increasing the H 2 S/CO 2 ratio in a gas mixture in order to prepare an acid gas which is a suitable feed to a Claus process.
  • the starting gas is treated in the first absorber with an amine absorbent which removes H 2 S selectively.
  • the loaded amine absorbent from the first absorber is combined with a loaded amine absorbent from a second absorber and sent to one common amine regenerator.
  • the second absorber treats a portion of the acid gas liberated in the common regenerator in order to selectively remove H 2 S and to produce a treated CO 2 stream.
  • the remainder of the acid gas stream from the regenerator having the desired H 2 S/CO 2 ratio is sent to the Claus process.
  • the excess CO 2 which was absorbed in the first absorber is rejected from the second absorber as the treated CO 2 stream.
  • a common amine absorbent which selectively removes H 2 S is used in two absorber and one common regenerator in order to enrich the Claus process feed.
  • Claus-type sulfur recovery units are designed to work on acid gases which contain H 2 S to convert the H 2 S into elemental sulfur.
  • Acid gas have primarily come from sour water strippers, flue gas desulfurization units and amine regenerators.
  • the conversion of H 2 S to elemental sulfur takes place via a combustor and a series of catalytic converters.
  • the elemental sulfur produced is condensed and pumped to storage and the resulting tail gases containing SO 2 , CO 2 and inerts is either burned, vented or cleaned further, if environmental regulations require it.
  • the claus tail gases contain inerts because the oxygen used in the Claus combustor is supplied by using air which contains about 80% N 2 by volume.
  • the Claus process being a technique to convert H 2 S into elemental sulfur, works best on a stream containing a substantial quantity of H 2 S.
  • Streams fed to conventional Claus units contain at least about 40% by volume H 2 S.
  • a relatively sweet natural gas may have a composition of about 0.5% H 2 S, 8% CO 2 , 1% N 2 , and the balance C 1 -C 4 hydrocarbons.
  • Amine treatment using MEA, DEA, MDEA etc. at about 1000 psi produces a treated pipeline gas comprising ⁇ 2% CO 2 ⁇ 4 wppm H 2 S and the balance C 1 -C 4 hydrocarbons.
  • a tail gas is recovered from the amine regenerator containing about 2.5% H 2 S and 97.5% CO 2 on a dry basis. This acid gas is not appropriate for conversion in a Claus plant, and, because of its high H 2 S content is not a candidate for either burning or venting to the atmosphere.
  • H 2 S lean acid gases consisting essentially of less than about 20% by volume H 2 S and the balance CO 2 (no inerts being present) can be upgraded to Claus plant feed by passing the lean acid gas to a selective amine extraction plant employing the severely sterically hindered tertiary amino materials described in U.S. Patents 4,417,075; 4,471,138; 4,405,580; 4,405,581; 4,405,582; 4,405,583; 4,405,585; 4,405,811; 4,483,833; and 4,618,481, preferably the severely sterically hindered tertiary amino materials described in U.S. Patent 4,618,481.
  • the severely sterically hindered amino material used as adsorbent is selected from the group consisting of di-(secondary and tertiaryalkylaminoalkoxy)alkanes, severely sterically hindered secondary aminoether alcohols, tertiary amino azabicyclic alcohols, severely sterically hindered secondary amino alcohol, diaminoethers wherein at least one amino group is a tertiary amine, di-severely sterically hindered secondary aminoethers, severely sterically hindered tertiary amino alcohols, heterocyclic tertiary aminoalkanols.
  • An integrated process wherein a sour hydrocarbon gas containing from 0.1 to 5% by volume H 2 S, 5-15% by volume CO 2 and the balance C 1 -C 4 hydrocarbons is treated in a first selective amine extraction unit with a first amine adsorbent which removes both H 2 S and CO 2 to produce a treated pipeline gas consisting of ⁇ 2% CO 2 , ⁇ 4 wppm H 2 S and the balance C 1 -C 4 hydrocarbons and an acid gas recovered from a first amine regeneration unit consisting essentially of less than 20% by volume H 2 S and the balance CO 2 .
  • the concentration of H 2 S in the acid gas will, of course, be higher than the concentration in the sour hydrocarbon gas feed.
  • the acid gas from said first amine regenerator is fed to a second H 2 S selective amine absorber using severely sterically hindered amino materials to produce an enriched acid gas recovered from a second amine regeneration unit consisting of at least 20% H 2 S, preferably 20-80% H 2 S, the balance being CO 2 and a scrubbed gas consisting essentially of CO 2 and ⁇ 10 Vppm H 2 S, preferably ⁇ 5 Vppm H 2 S, the enriched acid gas going to a Claus or Stretford plant for conversion into elemental sulfur .
  • the feed sent to the above identified initial amino compound absorber unit may be any sour gas such as tail gas, LNG gas, natural gas, synthesis gas etc. containing about 0.1-5% H 2 S, 5-20% CO 2 and the balance inert, i.e. C 1 -C 4 hydrocarbon, N 2 etc.
  • sour gas such as tail gas, LNG gas, natural gas, synthesis gas etc. containing about 0.1-5% H 2 S, 5-20% CO 2 and the balance inert, i.e. C 1 -C 4 hydrocarbon, N 2 etc.
  • This sour gas stream is sent to a first absorber operating at a pressure of about 0.1 to 1200 psig, preferably 1 to 1000 psig, a temperature of about 60 to 140oF, preferably 80 to 120°F.
  • the sour gas and the amine absorber material are contacted in the absorber zone, preferably co ⁇ ntercurrently to produce a treated gas containing very little CO 2 and trace H 2 S, typically ⁇ 2% CO 2 and ⁇ 4 wppm H 2 S.
  • the amine absorbent material is passed to an amine regenerator.
  • the absorber which is used to first process the initial sour gas feed can employ any of the less selective H 2 S amino absorber compounds such as monoethanolamine (MEA), diethanolamine (DEA) , depropanolamine (DPA) and hydroxyethoxyethylamine (DGA) or sterically hindered amines which absorb all H 2 S and some or all of the CO 2 because the purpose of the first absorber step is to sweeten the gas feed and this is accomplished by removing all H 2 S.
  • Other standard absorber compounds include diisopropanolamine (DIPA), methyldiethanolamine (MDEA) and diethylmonoethanolamine (DEAE).
  • the amine absorbent material from the absorber is passed to an amine regenerator tower where the absorbed H 2 S and CO 2 are removed from the amine absorbent. This is accomplished by heating the solvent and stripping it countercurrently with an inert medium such as steam.
  • the amine regenerator can operate at a pressure of 0 to 40 psig preferably 6 to 20 psig and temperatures of 220 to 280°F.
  • the stripped H 2 S and CO 2 plus water vapor leave the regenerator and are fed to condensers where the acid gas is cooled and water is condensed.
  • the stripped amine absorbent leaves the bottom of the regenerator and is cooled and recycled to the absorber.
  • the acid gas liberated from the amino compound contains less than about 20% by volume H 2 S and the balance CO 2 with only trace amounts of inerts present.
  • This H 2 S lean acid gas is then passed to the second H 2 S selective amino compound absorber vessel and contacted therein with a solution of the H 2 S selective amino compound absorbent.
  • the selective H 2 S absorber employs a severely sterically hindered amine absorbent which may be selected from the following: tertiary butylaminoethoxyethanol (TBEE), 2-(2-tertiarybutylamino)-propoxyethanol, 2-(2-isopropylamino)propoxyethanol, 1,2-bis-(N,N-dimethylaminoethoxy)ethane, bis-(N-pyrrolidinylethyl)ether, N-pyrrolidinylethoxyethyl-N,N-diethylamine, 1,2-bis- (pyrrolidinylethoxy)ethane, 1,2-bis-(pyrrolidinylethoxyethoxy)ethane, 1,2-bis-(3-pyrrolidinyl-n-propoxy)ethane, 1,2-bis-(piperidinylethoxy)- ethane, 1,3-bis-(piperidinyl-n-propoxy)propane, 1-(pyrrolidin
  • the preferred selective severely sterically hindered amine absorbants for use in the selective H 2 S absorber comprise at least one severely hindered amino compound having a cumulative -E s value (Taft's steric hindrance constant) greater than 1.75 and (b) an amine salt, said amine salt being the reaction product of an amine selected from the group consisting of a severely hindered amino compound having a cumulative -E s value greater than 1.75, a tertiary amine and mixtures thereof and a component selected from the group consisting of an acid having at least one pKa of not more than about 7, a decomposable salt of an acid having at least one pKa of not more than 7, a compound capable of forming an acid having a pKa of not more than about 7 and mixtures thereof, said amine salt and said severely hindered amino compound being present in said adsorbent composition in a mole ratio of said amine salt to said severely hindered amino compound of at least about 0.1:1,
  • the severely hindered amino compound can be selected from secondary amino ether alcohols such as those disclosed in USP 4,471,138 and di-secondary amino ethers such as those disclosed in USP 4,405,583, and mixtures thereof.
  • Suitable secondary amino ether alcohols include tertiary butyl aminoethoxy ethanol, 2-(2- tertiarybutylamino)-propoxyethanol, tertiaryamylaminoethoxyethanol, (1-methyl-1-ethylpropylamino)ethoxyethanol, 2-2(2-isopropylamino)- propoxyethanol and mixtures thereof.
  • di-secondary amino ethers include bis(tertiarybutylaminoethyl)ether, 1,2-bis- (tertiarybutylaminoethoxy)ethane, bis[2-(isopropylamino)propyl] ether, 1,2-[2-(isopropylamino)propoxt]ethane and the like.
  • a preferred severely hindered amino compound is tertiary butyl aminoethoxyethanol (TBEE).
  • suitable acids include inorganic acids such as sulfuric acid sulfurous acid, phosphoric acid, phosphorous acid, pyrophosphoric acid; organic acids such as acetic acid, formic acid, adipic acid, benzoic acid etc. Suitable salts of these acids include the ammonium salts.
  • the normally gaseous mixture containing from 1-20% H 2 S and the balance CO 2 from which the H 2 S is to be selectively removed may be brought into intimate contact with the absorbent solution using conventional means, such as a trayed or packed tower with, for example, rings or with sieve plates, or a bubble reactor.
  • the absorber vessel should contain from 6 to 12 trays or 12 to 35 feet of packing.
  • the trays or packing should be designed to give adequate gas-liquid contacting and minimum liquid hold-up.
  • the absorption step is conducted by feeding the normally gaseous mixture into the lower portion of the absorption tower while fresh absorbent solution is fed into the upper region of the tower.
  • the normally gaseous mixture largely freed from the H 2 S, emerges from the upper portion of the tower, and the loaded absorbent solution, which contains the selectively absorbed H 2 S, leaves the tower near or at its bottom.
  • the inlet temperature of the absorbent solution during the absorption step is in the range of from about 50° to about 210°F., and more preferably from about 75° to about 140°F.
  • Pressures may vary widely; acceptable pressures are between 5 and 2000 psia, preferably 20 to 1000 psia, and more preferably 15 to 400 psia, most preferably 15-20 psia, in the absorber.
  • the contacting takes place under conditions such that the H 2 S is selectively absorbed by the solution.
  • the absorption conditions and apparatus are designed so as to minimize the residence time of the liquid in the absorber to reduce CO 2 pickup while at the same time maintaining sufficient residence time of gas mixture with liquid to absorb a maximum amount of the H 2 S gas.
  • the amount of liquid required to be circulated to obtain a given degree of H 2 S removal will depend on the chemical structure and basicity of the amino compound and on the partial pressure of H 2 S in the feed gas.
  • a typical procedure for the selective H 2 S removal phase of the process comprises selectively absorbing H 2 S via countercurrent contact of the gaseous mixture containing H 2 S and CO 2 with the aqueous solution of the amino compound in a column containing a plurality of trays at a low temperature, e.g., below 45°C, and at a gas velocity of at least about 0.3 ft/sec (based on "active" or aerated tray surface), depending on the operating pressure of the gas, said tray column having fewer than 20 contacting trays, with, e.g., 4-16 trays being typically employed.
  • the preferred absorber operating in the pressure range of 15 to 30 psia should have from 6 to 12 trays and operate at gas velocities of 2 to 7 ft/sec. (based on "active" tray surface).
  • the preferred absorber operating in the pressure range of 30 psia to 400 psia should have from 4 to 10 trays and operate at gas velocities of 2 to 0.5 ft/sec. If a packed absorber is employed in the above ranges it have about 2 feet of packing per equivalent tray given above.
  • the solution After contacting the normally gaseous mixture with the absorbent solution, which becomes saturated or partially saturated with H 2 S, the solution may be at least partially regenerated in its own dedicated regenerator so that it may be recycled back to the absorber. As with absorption, the regeneration may take place in a single liquid phase. Regeneration or desorption of the acid gases from the absorbent solution may be accomplished by conventional means such as pressure reduction of the solution or increase of temperature to a point at which the absorbed H 2 S flashes off, or by passing the solution into a vessel of similar construction to that used in the absorption step, at the upper portion of the vessel, and passing an inert gas such as air or nitrogen or preferably steam upwardly through the vessel.
  • an inert gas such as air or nitrogen or preferably steam upwardly through the vessel.
  • the temperature of the solution during the regeneration step should be in the range from about 50° to about 170°C, and preferably from about 80° to 120°C, and the pressure of the solution on regeneration should range from about 0.5 to about 100 psia, preferably 1 to about 50 psia.
  • the absorbent solution after being cleansed of at least a portion of the H 2 S gas, may be recycled back to the second absorbing vessel. Makeup absorbent may be added as needed. Suitable ratio of steam to absorbent composition during the regeneration step may range from about 0.4 to about 3.0 pounds of steam per gallon of liquid absorbent circulated to the regeneration zone.
  • the H 2 S rich solution is sent to the regenerator wherein the absorbed components are stripped by the steam which is generated by re-boiling the solution.
  • Pressure in the flash drum and stripper is usually 13 to about 50 psia, preferably 15 to about 30 psia, and the temperature is typically in the range from about 50° to 170°C, preferably about 80° to 130°C.
  • Stripper and flash temperatures will, of course, depend on stripper pressure; thus at about 15 to 30 psia stripper pressures, the temperature will be about 80° to about 130°C during desorption.
  • Heating of the solution to be regenerated may very suitably be effected by means of indirect heating with low-pressure steam or other heat transfer medium. It is also possible, however, to use direct injection steam.
  • the enriched acid gas stream recovered from the severely sterically hindered amine absorbent regenerator (regenerator 2), having an H 2 S content now of about 20% or more is fed to a Claus plant for conversion into elemental sulfur.
  • the enriched acid gas combined with air to supply the oxygen needed for combustion is processed in the Claus plant to produce elemental sulfur, which is recovered, and a tail gas containing SO 2 which is subsequently hydrogenated back to H 2 S.
  • This hydrogenated tail gas stream contains about 90% inerts (attributable to the 80% N 2 present in the combustion air), 2% H 2 S and 8% CO 2 .
  • This gas can be treated with the severely sterically hindered amine absorbent in a separate absorber (third absorber) or can be sent to the second absorber to selectively remove the H 2 S.
  • the resulting treated tail gas contains from 1 to 300 vppm H 2 S and about 90% of the CO 2 present in the feed tail gas. In the preferred case the treated tail gas contains 1 to 10 vppm H 2 S and may be vented.
  • the loaded severely sterically hindered amine absorbent from the third absorber if a dedicated third absorber is used may be combined with the amine absorbent from the enriching absorber (second absorber) and regenerated in a common regenerator. Thus most of the H 2 S can be recovered in the Claus unit resulting in very low emissions of sulfur species to the atmosphere.
  • An example of such process treats a low Btu lean acid gas containing 1% H 2 S, 10% CO 2 the balance inerts produced by a FLEXICOKING unit with the amine absorbent at 30 psia.
  • the Claus plant tail gas containing 15% H 2 S, 8% CO 2 the balance inerts is also treated with the amine absorbent in a separate absorber at 17 psia.
  • the combined absorbent is regenerated in the single regenerator.
  • the acid gas from the regenerator containing 50% H 2 S by volume is fed to a Claus plant.
  • the treated low Btu gas containing less than 20 vppm H 2 S is burned in process furnaces while the treated Claus plant tail gas containing less than 10 vppm H 2 S is vented.

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  • Organic Chemistry (AREA)
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  • Oil, Petroleum & Natural Gas (AREA)
  • Inorganic Chemistry (AREA)
  • Gas Separation By Absorption (AREA)

Abstract

Un gaz acide pauvre, essentiellement composé de H2S et de CO2, la teneur en H2S étant inférieure à 20 % en volume environ, et le reste étant essentiellement composé de CO2, peut être enrichi à l'aide d'amines entravées sélectives pour produire un gaz acide contenant entre 20 et 80 % de H2S environ, qui peut ensuite être traité dans une installation Claus.
PCT/US1991/008940 1991-11-27 1991-11-27 Procede d'enrichissement de gaz acide pauvre a l'aide d'amines entravees selectives WO1993010883A1 (fr)

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Cited By (14)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP1572324A1 (fr) * 2002-12-17 2005-09-14 Fluor Corporation Agencements et procedes permettant d'eliminer des gaz acides et des impuretes avec une emission proche de zero
WO2008037315A2 (fr) * 2006-09-26 2008-04-03 Lurgi Ag Procédé de production d'hydrogène
WO2015017240A1 (fr) * 2013-07-29 2015-02-05 Exxonmobil Research And Engineering Company Séparation de sulfure d'hydrogène de gaz naturel
US10130897B2 (en) 2013-01-25 2018-11-20 Exxonmobil Upstream Research Company Contacting a gas stream with a liquid stream
US10155193B2 (en) 2013-05-09 2018-12-18 Exxonmobil Upstream Research Company Separating impurities from a gas stream using a vertically oriented co-current contacting system
US10300429B2 (en) 2015-01-09 2019-05-28 Exxonmobil Upstream Research Company Separating impurities from a fluid stream using multiple co-current contactors
US10343107B2 (en) 2013-05-09 2019-07-09 Exxonmobil Upstream Research Company Separating carbon dioxide and hydrogen sulfide from a natural gas stream using co-current contacting systems
US10391442B2 (en) 2015-03-13 2019-08-27 Exxonmobil Upstream Research Company Coalescer for co-current contractors
US10717039B2 (en) 2015-02-17 2020-07-21 Exxonmobil Upstream Research Company Inner surface features for co-current contractors
US10876052B2 (en) 2017-06-20 2020-12-29 Exxonmobil Upstream Research Company Compact contacting systems and methods for scavenging sulfur-containing compounds
US11000797B2 (en) 2017-08-21 2021-05-11 Exxonmobil Upstream Research Company Integration of cold solvent and acid gas removal
US11000795B2 (en) 2017-06-15 2021-05-11 Exxonmobil Upstream Research Company Fractionation system using compact co-current contacting systems
US11260342B2 (en) 2017-06-15 2022-03-01 Exxonmobil Upstream Research Company Fractionation system using bundled compact co-current contacting systems
WO2024006450A1 (fr) 2022-07-01 2024-01-04 Air Products And Chemicals, Inc. Désulfuration de gaz contenant du dioxyde de carbone

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US4085192A (en) * 1973-05-11 1978-04-18 Shell Oil Company Selective removal of hydrogen sulfide from gaseous mixtures
CA1099513A (fr) * 1977-02-04 1981-04-21 Jan Verloop Traduction non-disponible
US4425317A (en) * 1980-12-18 1984-01-10 Linde Aktiengesellschaft Recycle of hydrogenated sulfur plant tail gas to sour gas scrubbing system
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EP0134948A2 (fr) * 1983-06-30 1985-03-27 Union Carbide Corporation Composition d'absorbant pour l'élimination intensifiée de gaz acides de mélanges de gaz et procédé pour son utilisation
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Cited By (19)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP1572324B1 (fr) * 2002-12-17 2012-08-15 Fluor Corporation Procede permettant d'eliminer des gaz acides et des impuretes avec une emission proche de zero
EP1572324A1 (fr) * 2002-12-17 2005-09-14 Fluor Corporation Agencements et procedes permettant d'eliminer des gaz acides et des impuretes avec une emission proche de zero
WO2008037315A2 (fr) * 2006-09-26 2008-04-03 Lurgi Ag Procédé de production d'hydrogène
WO2008037315A3 (fr) * 2006-09-26 2008-10-02 Lurgi Ag Procédé de production d'hydrogène
US8273323B2 (en) 2006-09-26 2012-09-25 Lurgi Gmbh Hydrogen production method
US10130897B2 (en) 2013-01-25 2018-11-20 Exxonmobil Upstream Research Company Contacting a gas stream with a liquid stream
US10155193B2 (en) 2013-05-09 2018-12-18 Exxonmobil Upstream Research Company Separating impurities from a gas stream using a vertically oriented co-current contacting system
US10343107B2 (en) 2013-05-09 2019-07-09 Exxonmobil Upstream Research Company Separating carbon dioxide and hydrogen sulfide from a natural gas stream using co-current contacting systems
CN105531013A (zh) * 2013-07-29 2016-04-27 埃克森美孚研究工程公司 从天然气分离硫化氢
WO2015017240A1 (fr) * 2013-07-29 2015-02-05 Exxonmobil Research And Engineering Company Séparation de sulfure d'hydrogène de gaz naturel
US10300429B2 (en) 2015-01-09 2019-05-28 Exxonmobil Upstream Research Company Separating impurities from a fluid stream using multiple co-current contactors
US10717039B2 (en) 2015-02-17 2020-07-21 Exxonmobil Upstream Research Company Inner surface features for co-current contractors
US10391442B2 (en) 2015-03-13 2019-08-27 Exxonmobil Upstream Research Company Coalescer for co-current contractors
US10486100B1 (en) 2015-03-13 2019-11-26 Exxonmobil Upstream Research Company Coalescer for co-current contactors
US11000795B2 (en) 2017-06-15 2021-05-11 Exxonmobil Upstream Research Company Fractionation system using compact co-current contacting systems
US11260342B2 (en) 2017-06-15 2022-03-01 Exxonmobil Upstream Research Company Fractionation system using bundled compact co-current contacting systems
US10876052B2 (en) 2017-06-20 2020-12-29 Exxonmobil Upstream Research Company Compact contacting systems and methods for scavenging sulfur-containing compounds
US11000797B2 (en) 2017-08-21 2021-05-11 Exxonmobil Upstream Research Company Integration of cold solvent and acid gas removal
WO2024006450A1 (fr) 2022-07-01 2024-01-04 Air Products And Chemicals, Inc. Désulfuration de gaz contenant du dioxyde de carbone

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