Classifications

• • 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
• • 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
  • B01D53/1425—Regeneration of liquid absorbents
• • 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
  • B01D53/1468—Removing hydrogen sulfide
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
  • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
  • C10L3/10—Working-up natural gas or synthetic natural gas
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
  • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
  • C10L3/10—Working-up natural gas or synthetic natural gas
  • C10L3/101—Removal of contaminants
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
  • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
  • C10L3/10—Working-up natural gas or synthetic natural gas
  • C10L3/101—Removal of contaminants
  • C10L3/102—Removal of contaminants of acid contaminants
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
  • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
  • C10L3/10—Working-up natural gas or synthetic natural gas
  • C10L3/101—Removal of contaminants
  • C10L3/102—Removal of contaminants of acid contaminants
  • C10L3/103—Sulfur containing contaminants
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
  • B01D2252/20—Organic absorbents
  • B01D2252/202—Alcohols or their derivatives
  • B01D2252/2023—Glycols, diols or their derivatives
  • B01D2252/2026—Polyethylene glycol, ethers or esters thereof, e.g. Selexol
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
  • B01D2252/20—Organic absorbents
  • B01D2252/204—Amines
  • B01D2252/2041—Diamines
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
  • B01D2252/20—Organic absorbents
  • B01D2252/204—Amines
  • B01D2252/20415—Tri- or polyamines
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
  • B01D2252/20—Organic absorbents
  • B01D2252/204—Amines
  • B01D2252/20431—Tertiary amines
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
  • B01D2252/20—Organic absorbents
  • B01D2252/204—Amines
  • B01D2252/20478—Alkanolamines
  • B01D2252/20489—Alkanolamines with two or more hydroxyl groups
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
  • B01D2252/20—Organic absorbents
  • B01D2252/205—Other organic compounds not covered by B01D2252/00 - B01D2252/20494
  • B01D2252/2056—Sulfur compounds, e.g. Sulfolane, thiols
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
  • B01D2252/40—Absorbents explicitly excluding the presence of water
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
  • C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
  • C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel
• • 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
  • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
  • Y02C20/00—Capture or disposal of greenhouse gases
  • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

• the present invention relates to an absorbent and a process for the selective removal of hydrogen sulfide from a fluid stream, in particular for the selective removal of hydrogen sulfide from carbon dioxide.
• CO2 has to be removed from natural gas, because a high concentration of CO2 when used as a pipeline or sales gas reduces the calorific value of the gas.
• CO2 can lead to corrosion of pipes and fittings.
• too low a concentration of CO2 is also undesirable because it may cause the calorific value of the gas to be too high.
• the CO 2 concentrations for pipeline or sales gas are between 1, 5 and 3.5 vol .-%.
• washes are used with aqueous solutions of inorganic or organic bases.
• ions form with the bases.
• the absorbent may be regenerated by depressurization to a lower pressure and / or stripping whereby the ionic species react back to sour gases and / or are stripped out by steam. After the regeneration process, the absorbent can be reused.
• a process in which all acid gases, especially CO2 and H2S, are removed as far as possible is called "total absorption". In certain cases, however, it may be desirable to preferentially absorb H2S from CO2, e.g. B. to obtain a calorific value optimized C02 / H2S ratio for a downstream Claus plant.
• An unfavorable CC ⁇ / L-S ratio may affect the performance and efficiency of the Claus plant by formation of COS / CS2 and coking of the Claus catalyst or by a too low calorific value.
• the selective removal of hydrogen sulfide is often used in fluid streams with low sour gas partial pressures, such as. B. in tail gas or in the sour gas enrichment (Acid Gas Enrichment, AGE), for example, for the enrichment of H2S before the Claus process.
• sour gas partial pressures such as. B. in tail gas or in the sour gas enrichment (Acid Gas Enrichment, AGE), for example, for the enrichment of H2S before the Claus process.
• Natural gas treatment for pipeline gas may also require selective removal of H2S from CO2.
• natural gas treatment seeks to simultaneously remove H2S and CO2 while meeting F S limits and eliminating the need for complete removal of CO2.
• the piping gas specification requires sour gas removal to about 1.5 to 3.5 vol.% CO2 and less than 4 vppm H2S. In these cases maximum h S selectivity is not desired.
• DE 37 17 556 A1 describes a process for the selective removal of sulfur compounds from CO 2 -containing gases by means of an aqueous washing solution containing tertiary amines and / or sterically hindered primary or secondary amines in the form of diamino ethers or amino alcohols. Im et al. describe in Energy Environ.
• US 2015/0027055 A1 describes a process for the selective removal of H 2 S from a CO 2 -containing gas mixture by means of an absorption medium which comprises sterically hindered, terminally etherified alkanolamines. It was stated that the terminal Etherification of the alkanolamines or the exclusion of water allows higher h S selectivity.
• Amines which are suitable for the selective removal of H2S from fluid streams and their solutions in non-aqueous solvents often have a relatively high viscosity. In order to enable an energetically favorable process, however, the viscosity of the H S-selective amine or the absorbent should be as low as possible.
• the invention is based on the object to provide an absorbent which is suitable for the selective removal of hydrogen sulfide from a carbon dioxide and hydrogen sulfide-containing fluid stream.
• the absorbent should have high loadability, high cyclic capacity, good regenerability and low viscosity. It is also intended to provide a method of selectively removing hydrogen sulfide from a fluid stream containing carbon dioxide and hydrogen sulfide.
• an absorbent for the selective removal of hydrogen sulfide from a fluid stream containing carbon dioxide and hydrogen sulfide which contains: a) an amine compound of the formula (I)
• Ci-Cs-alkyl; R3, R 4 and R 5 are independently selected from hydrogen and Ci-Cs alkyl; R6 and R7 independently represent Ci-Cs-alkyl; Re is a Ci-Cs-alkyl; x and y are integers from 2 to 4 and z is an integer from 1 to 3;
• R1 is hydrogen
• R2 is C3-Cs-alkyl directly attached to the nitrogen atom via a secondary or tertiary carbon atom
• a non-aqueous solvent wherein the absorbent contains less than 20% by weight of water.
• the amine compound is a compound of the general formula (II)
• Rg and R independently of one another are alkyl;
• RH is hydrogen or alkyl;
• R12, R13 and Ru are independently selected from hydrogen and Cis-Cs-alkyl;
• R 15 and R 16 independently of one another are C 1 -C 8 -alkyl;
• x and y are integers from 2 to 4 and z is an integer from 1 to 3.
• R12, R13 and R14 are hydrogen.
• R15 and R16 are independently methyl or ethyl.
• x 2.
• Y 2 is preferred.
• Z is preferably 1 or 2, in particular 1.
• Rg and R10 are methyl and RH is hydrogen; or Rg, R10 and RH are methyl; or Rg and R10 are methyl and RH is ethyl.
• the compound of general formula (II) is selected from 2- (2-tert-butylaminoethoxy) ethyl-N, N-dimethylamine, 2- (2-tert-butylaminoethoxy) ethyl-N, N-diethylamine, 2- (2 tert-butylaminoethoxy) ethyl-N, N-dipropylamine, 2- (2-isopropylaminoethoxy) ethyl-N, N-dimethylamine, 2- (2-isopropylaminoethoxy) ethyl-N, N-diethylamine, 2- (2-isopropylaminoethoxy) ethyl N, N-dipropylamine, 2- (2- (2-tert-butylaminoethoxy) ethoxy) ethyl ⁇ , ⁇ -dimethylamine, 2- (2- (2-tert-butylaminoethoxy) e
• the compound of formula (II) is 2- (2-tert-butylaminoethoxy) ethyl-N, N-dimethylamine (TBAEEDA).
• the amine compound is a compound of the general formula (III)
• R 17 and R 18 independently of one another are C 1 -C 8 -alkyl; R19, R20 and R22 are independently selected from hydrogen and Ci-Cs-alkyl; R21 is Ci-Cs-alkyl; R23 and R24 independently represent Ci-Cs-alkyl; x and y are integers from 2 to 4 and z is an integer from 1 to 3.
• R17, R18, R21, R23 and R24 independently of one another are methyl or ethyl.
• R19, R20 and R22 are hydrogen.
• x 2.
• Y 2 is preferred.
• Z is preferably 1 or 2, in particular 1.
• the compound of formula (III) is selected under
• Pentamethyldiethylenetriamine (PMDETA), Pentaethyldiethylentriamin, Pentamethyldipropylen- triamine, Pentamethyldibutylentriamin, Hexamethylentriethylentetraamin, Hexaethylentriethyl- entetraamine, Hexamethylentripropylentetraamin and Hexaethylentripropentra.
• the compound of formula (III) is pentamethyldiethylenetriamine (PMDETA).
• the amine compound is a compound of the general formula (IV)
• R25 and R26 independently represent Ci-Cs-alkyl
• R27, R28 and R29 are independently selected from hydrogen and Ci-Cs-alkyl
• R30 and R31 independently represent Ci-Cs-alkyl
• x and y are integers from 2 to 4 and z is an integer from 1 to 3.
• R25, R26, R30 and R31 are independently methyl or ethyl.
• R27, R28 and R29 are hydrogen.
• x 2.
• Y 2 is preferred.
• Z is preferably 1 or 2, in particular 1.
• the compound of the formula (IV) is preferably selected from bis (2- (dimethylamino) ethyl) ether (BDMAEE), bis (2- (diethylamino) ethyl) ether, bis (2- (dipropylamino) ethyl) ether, Bis (2- (dimethylamino) propyl) ether, bis (2- (dimethylamino) butyl) ether, 2- (2- (dimethylamino) ethoxy) ethoxy-N, N-dimethylamine, 2- (2- (diethylamino ) - ethoxy) ethoxy-N, N -diethylamine, 2- (2- (dimethylamino) propoxy) propoxy-N, N-dimethylamine and 2- (2- (diethylamino) propoxy) propoxy-N, N -diethylamine.
• BDMAEE bis (2- (diethylamino) ethy
• the compound of formula (IV) is bis (2- (dimethylamino) ethyl) ether (BDMAEE).
• the compounds of the general formula (I) comprise exclusively amino groups which are present as sterically hindered secondary amino groups or tertiary amino groups.
• a secondary carbon atom is understood to mean a carbon atom which has two carbon-carbon bonds in addition to the bond to the sterically hindered position.
• a tertiary carbon atom is understood as meaning a carbon atom which has three carbon-carbon bonds in addition to the bond to the sterically hindered position.
• a hindered secondary amino group is meant the presence of at least one secondary or tertiary carbon atom in the immediate vicinity of the nitrogen atom of the amino group.
• Suitable amine compounds include, besides hindered amines, also compounds which are referred to in the art as hindered amines and have a steric parameter (taffeta constant) of greater than 1.75.
• the compounds of general formula (I) have high basicity.
• the first pKa of the amines at 20 ° C is at least 8, more preferably at least 9, and most preferably at least 10.
• the second pKa of the amines is at least 6.5, more preferably at least 7 and most preferably at least 8.
• the pKa values of the amines are generally determined by titration with hydrochloric acid, as shown for example in the working examples.
• the compounds of general formula (I) are further distinguished by a low viscosity. Low viscosity is advantageous for handleability.
• the compounds of the general formula (I) preferably have a dynamic viscosity in the range from 0.5 to 12 mPa.s at 25 ° C., more preferably in the range from 0.6 to 8 mPa.s and very particularly preferably in the range from 0 , 7 to 5 mPa.s, determined at 25 ° C. Suitable methods for determining the viscosity are mentioned in the exemplary embodiments.
• the compounds of general formula (I) are generally completely miscible with water.
• the compounds of the general formula (I) can be prepared in various ways.
• a suitable diol in a first step, is reacted with a secondary amine R1 R2NH according to the following scheme.
• the reaction is suitably carried out in the presence of hydrogen in the presence of a hydrogenation / dehydrogenation catalyst, for.
• a hydrogenation / dehydrogenation catalyst for.
• a copper-containing hydrogenation / dehydrogenation catalyst at 160 to 220 ° C:
• the resulting compound can be reacted with an amine R6R7NH according to the following scheme to give a compound of general formula (I).
• the reaction is suitably carried out in the presence of hydrogen in the presence of a hydrogenation / dehydrogenation catalyst, for.
• a hydrogenation / dehydrogenation catalyst for.
• a copper-containing hydrogenation / dehydrogenation catalyst at 160 to 220 ° C.
• radicals Ri to R7 and the coefficients x, y and z correspond to the abovementioned definitions and their preferences.
• the absorbent preferably contains from 10 to 70% by weight, more preferably from 15 to 65% by weight, and most preferably from 20 to 60% by weight of the compound of general formula (I), based on the weight of the absorbent.
• the absorbent comprises a tertiary amine other than the compounds of general formula (I) or strongly hindered primary and / or highly hindered secondary amine.
• a strong steric hindrance is meant a tertiary carbon atom in the immediate vicinity of a primary or secondary nitrogen atom.
• the absorbent comprises the tertiary amine or highly hindered amine other than the compounds of general formula (I), generally in an amount of from 5 to 50% by weight, preferably from 10 to 40% by weight, and more preferably 20% to 40 wt .-%, based on the weight of the absorbent.
• Suitable tertiary amines other than the compounds of general formula (I) include, in particular:
• Tertiary alkanolamines d. H.
• Amines having at least one hydroxyalkyl group attached to the nitrogen atom are generally preferred. Particularly preferred is methyldiethanolamine (MDEA).
• MDEA methyldiethanolamine
• suitable highly sterically hindered amines other than the compounds of the general formula (I) include in particular: 1. Highly hindered secondary alkanolamines such as
• 2-amino-2-methylpropanol (2-AMP); 2-amino-2-ethylpropanol; and 2-amino-2-propylpropanol;
• the absorbent does not contain a sterically unhindered primary amine or sterically unhindered secondary amine.
• a sterically unhindered primary amine is understood to mean compounds which have primary amino groups to which only hydrogen atoms or primary or secondary carbon atoms are bonded.
• a sterically unhindered secondary amine are meant compounds which have secondary amino groups to which only hydrogen atoms or primary carbon atoms are attached.
• Sterically unhindered primary amines or sterically unhindered secondary amines act as potent activators of CO 2 absorption. By their presence in the absorbent, the h S selectivity of the absorbent can be lost.
• the viscosity of the absorbent should not exceed certain limits. As the viscosity of the absorbent increases, the thickness of the liquid boundary increases due to the lower diffusion rate of the reactants in the more viscous fluid. This causes a reduced mass transfer of compounds from the fluid stream into the absorbent. This can be counteracted by, for example, increasing the number of trays or increasing the packing height, which, however, unfavorably leads to an increase in the absorption apparatus. In addition, higher viscosities of the absorbent can cause pressure losses in the heat exchangers of the apparatus and a poorer heat transfer.
• the absorbents of the invention surprisingly show low viscosities even at high concentrations of compounds of general formula (I).
• the viscosity of the absorbent is relatively low.
• the dynamic viscosity of the (non-loaded) absorbent at 25 ° C. is preferably in the range from 0.5 to 40 mPas, more preferably in the range from 0.6 to 30 mPas and most preferably in the range from 0, 7 to 20 mPa-s.
• Sterically hindered amines and tertiary amines show kinetic selectivity for H2S over CO2. These amines do not react directly with CO2; rather, CO2 is converted into ionic products in a slow reaction with the amine and with a proton donor, such as water.
• Hydroxyl groups which are introduced into the absorbent via compounds of the general formula (I) and / or the solvent, represent proton donors. It is assumed that a low supply of hydroxyl groups in the absorbent impedes CO 2 absorption. A low hydroxyl group density therefore leads to an increase in H2S selectivity.
• the hydroxyl group density can be used to set the desired selectivity of the adsorbent for H2S over CO2. Water has a particularly high hydroxyl group density. The use of non-aqueous solvents therefore causes high H2S selectivities.
• the absorbent comprises less than 20% by weight of water, preferably less than 15% by weight of water, particularly preferably less than 10% by weight of water, more preferably less than 5% by weight of water, for example less than 3% by weight of water.
• a large supply of the proton donor water in the absorbent reduces h S selectivity.
• the non-aqueous solvent is preferably selected from
• C4-Cio-alcohols such as n-butanol, n-pentanol and n-hexanol; Ketones, such as cyclohexanone; Esters such as ethyl acetate and butyl acetate;
• Lactones such as ⁇ -butyrolactone, ⁇ -valerolactone and ⁇ -caprolactone;
• Amides such as tertiary carboxylic acid amides, for example, ⁇ , ⁇ -dimethylformamide; or N-formylmorpholine and N-acetylmorpholine;
• Lactams such as ⁇ -butyrolactam, ⁇ -valerolactam and ⁇ -caprolactam and N-methyl-2-pyrrolidone (NMP); Sulfones, such as sulfolane;
• Sulfoxides such as dimethylsulfoxide (DMSO); Glycols such as ethylene glycol (EG) and propylene glycol;
• Polyalkylene glycols such as diethylene glycol (DEG) and triethylene glycol (TEG);
• Di- or mono (C 1-4 -alkyl ether) -glycols such as ethylene glycol dimethyl ether
• Di- or mono (C 1-4 -alkyl ether) -polyalkylene glycols such as diethylene glycol dimethyl ether and triethylene glycol dimethyl ether
• cyclic ureas such as N, N-dimethylimidazolidin-2-one and dimethylpropyleneurea (DMPU);
• Thioalkanols such as ethylenedithioethanol, thiodiethyleneglycol (thiodiglycol, TDG) and methylthioethanol; and mixtures thereof.
• the nonaqueous solvent is particularly preferably selected from among sulphones, glycols and polyalkylene glycols. Most preferably, the non-aqueous solvent is selected from sulfones. A preferred non-aqueous solvent is sulfolane.
• the absorbent may also contain additives such as corrosion inhibitors, enzymes, antifoams, etc.
• additives such as corrosion inhibitors, enzymes, antifoams, etc.
• the amount of such additives ranges from about 0.005 to 3% by weight of the absorbent.
• the absorbent preferably has a H 2 S: CO 2 loading ratio of at least 1.1, more preferably at least 2, and most preferably at least 5.
• H2S: CO 2 loading ratio is understood to mean the quotient of the maximum h S loading through the maximum CO 2 loading under equilibrium conditions when the absorbent is charged with CO 2 or H 2 S at 40 ° C. and ambient pressure (about 1 bar). Suitable test methods are mentioned in the exemplary embodiments.
• the H2S: C02 loading ratio serves as an indication of the expected h S selectivity; the higher the H2S: C02 loading ratio, the higher the expected h S selectivity.
• the maximum h S loading capacity of the absorbent is at least 5 Nm 3 / t, more preferably at least 8 Nm 3 / t, and most preferably at least 12 Nm 3 / t.
• the present invention also relates to a process for the selective removal of hydrogen sulfide from a fluid stream containing carbon dioxide and hydrogen sulfide, in which the fluid stream is contacted with the absorbent and receives a loaded absorbent and a treated fluid stream.
• the inventive method is suitable for the selective removal of hydrogen sulfide to CO2.
• selective removal of hydrogen sulfide is understood here to mean the value of the following quotient: y (H2S) feed-y (H2S) treat
• y (H2S) f ee d for the molar fraction (mol / mol) of H2S in the starting fluid
• y (H2S) t re at for the molar fraction in the treated fluid
• y (C02) feed for the molar fraction of CO2 in the starting fluid
• y ( C02) treat for the mole fraction of CO2 in the treated fluid.
• the selectivity for hydrogen sulfide is preferably at least 1.1, most preferably at least 2 and most preferably at least 4.
• the removal of sour gas from natural gas for use as a pipeline or sales gas total absorption of carbon dioxide is undesirable.
• the residual content of carbon dioxide in the treated fluid stream is at least 0.5% by volume, preferably at least 1.0% by volume and more preferably at least 1.5% by volume.
• the method according to the invention is suitable for the treatment of fluids of all kinds.
• Fluids are on the one hand gases, such as natural gas, synthesis gas, coke oven gas, cracked gas, coal gasification gas, cycle gas, landfill gas and combustion gases, and on the other hand with the Absorpti- onsffen substantially immiscible liquids, such as LPG ( Liquefied Petroleum Gas) or NGL (Natural Gas Liquids).
• LPG Liquefied Petroleum Gas
• NGL Natural Gas Liquids
• the process according to the invention is particularly suitable for the treatment of hydrocarbon-containing fluid streams.
• the hydrocarbons contained are z.
• aliphatic hydrocarbons such as Ci-C4 hydrocarbons such as methane, unsaturated hydrocarbons such as ethylene or propylene, or aromatic hydrocarbons such as benzene, toluene or xylene.
• the inventive method is suitable for the removal of CO2 and H2S.
• CO2 and H2S Besides carbon dioxide and hydrogen sulfide, other acidic gases may be present in the fluid stream, such as COS and mercaptans.
• SO3, SO2, CS2 and HCN can also be removed.
• the fluid stream is a hydrocarbon-containing fluid stream; in particular a natural gas stream.
• the fluid stream contains more than 1.0% by volume of hydrocarbons, more preferably more than 5.0% by volume of hydrocarbons, most preferably more than 15% by volume of hydrocarbons.
• the hydrogen sulfide partial pressure in the fluid stream is usually at least 2.5 mbar.
• a hydrogen sulfide partial pressure of at least 0.1 bar, in particular at least 1 bar, and a carbon dioxide partial pressure of at least 0.2 bar, in particular at least 1 bar are present in the fluid stream.
• Very particular preference is given to a hydrogen sulfide partial pressure of at least 0.5 bar and a carbon dioxide partial pressure of at least 1 bar in the fluid idstrom.
• the stated partial pressures refer to the fluid flow upon first contact with the absorbent in the absorption step.
• the fluid stream has a total pressure of at least 1.0 bar, more preferably at least 3.0 bar, even more preferably at least 5.0 bar, and most preferably at least 20 bar.
• the fluid flow has a total pressure of at most 180 bar. The total pressure refers to the fluid flow upon initial contact with the absorbent in the absorption step.
• the fluid stream is brought into contact with the absorbent in an absorption step in an absorber, whereby carbon dioxide and hydrogen sulfide are at least partially washed out.
• the absorber is a washing device used in conventional gas scrubbing processes. Suitable washing devices are, for example, packed, packed and tray columns, membrane contactors, radial flow scrubbers, jet scrubbers, venturi scrubbers and rotary scrubbers, preferably packed, packed and tray columns, particularly preferably tray and packed columns.
• the treatment of the fluid stream with the absorbent is preferably carried out in a column in countercurrent.
• the fluid is generally fed into the lower region and the absorbent in the upper region of the column.
• tray columns sieve bell or valve trays are installed, over which the liquid flows.
• Packed columns can be filled with different shaped bodies. Heat and mass transfer are improved by the enlargement of the surface due to the usually about 25 to 80 mm large moldings.
• Raschig ring a hollow cylinder
• Pall ring a hollow cylinder
• Hiflow ring a hollow ring
• Intalox saddle a hollow cylinder
• the packing can be ordered, but also random (as a bed) are introduced into the column.
• materials come in question glass, ceramics, metal and Plastics.
• Structured packings are a further development of the ordered packing. They have a regularly shaped structure. This makes it possible for packings to reduce pressure losses in the gas flow.
• the material used can be metal, plastic, glass and ceramics.
• the temperature of the absorbent in the absorption step is generally about 30 to 100 ° C, using a column, for example 30 to 70 ° C at the top of the column and 50 to 100 ° C at the bottom of the column.
• the process according to the invention may comprise one or more, in particular two, successive absorption steps.
• the absorption can be carried out in several successive sub-steps, wherein the raw gas containing the acidic gas constituents in each of the substeps is brought into contact with a partial stream of the absorbent.
• the absorbent, with which the raw gas is brought into contact may already be partially loaded with acidic gases, d. H. it may, for example, be an absorbent, which has been recycled from a subsequent absorption step to the first absorption step, or partially regenerated absorbent.
• the performance of the two-stage absorption reference is made to the publications EP 0 159 495, EP 0 190 434, EP 0 359 991 and WO 00100271.
• the person skilled in the art can achieve a high degree of separation of hydrogen sulfide at a defined selectivity by determining the conditions in the absorption step, in particular the absorber / fluid flow ratio, the column height of the absorber, the type of contact-promoting internals in the absorber, such as fillers, trays or packings, and / or the residual loading of the regenerated absorbent varies.
• a low absorber / fluid flow ratio leads to increased selectivity, a higher absorber / fluid flow ratio leads to a more unselective absorption. Since CO2 is absorbed at a slower rate than H2S, more CO 2 is absorbed with a longer residence time than with a shorter residence time. A higher column therefore causes a more selective absorption. Bottoms or packs with larger liquid holdup also result in less selective absorption. By means of the heating energy introduced during the regeneration, the residual charge of the regenerated absorption medium can be adjusted. A lower residual loading of the regenerated absorbent leads to improved absorption.
• the method preferably comprises a regeneration step in which the CO2 and F S-laden absorbent is regenerated.
• the regenerated absorbent is then returned to the absorption step.
• the regeneration step comprises at least one of heating, relaxing and stripping with an inert fluid.
• the regeneration step preferably comprises heating the absorbent laden with the acidic gas constituents, e.g. By means of a reboiler, natural circulation evaporator, forced circulation evaporator, or forced circulation flash evaporator.
• the absorbed acid gases are stripped off by means of the vapor obtained by heating the solution.
• an inert fluid such as nitrogen may also be used.
• the absolute pressure in the desorber is normally 0.1 to 3.5 bar, preferably 1, 0 to 2.5 bar.
• the temperature is usually from 50 ° C to 170 ° C, preferably from 80 ° C to 130 ° C, the temperature of course being dependent on the pressure.
• the regeneration step may alternatively or additionally include a pressure release. This involves at least a pressure release of the loaded absorbent from a high pressure, as it prevails in the implementation of the absorption step, to a lower pressure.
• the pressure release can be done for example by means of a throttle valve and / or an expansion turbine.
• the regeneration with a relaxation stage is described, for example, in the publications US Pat. Nos. 4,537,753 and 4,553,984.
• the release of the acidic gas constituents in the regeneration step for example, in a flash column, z. B. a vertically or horizontally installed flash tank or a countercurrent column with internals, done.
• the regeneration column may likewise be a packed, packed or tray column.
• the regeneration column has a heater at the bottom, z. B. a forced circulation evaporator with circulation pump. At the top, the regeneration column has an outlet for the released acid gases. Entrained absorbent vapors are condensed in a condenser and returned to the column.
• FIG. 1 is a schematic representation of an apparatus suitable for carrying out the method according to the invention.
• a suitably pretreated gas containing hydrogen sulphide and carbon dioxide is brought into contact with the supply line Z in an absorber A1 with regenerated absorption medium, which is supplied via the absorption medium line 1.01.
• the absorbent removes hydrogen sulfide and carbon dioxide by absorption from the gas; In this case, via the exhaust pipe 1 .02 a depleted in hydrogen sulfide and carbon dioxide clean gas.
• the heat exchanger 1 .04 in which the CO2- and H2S-laden absorbent is heated with the heat of the guided through the absorbent line 1.05, regenerated absorbent, and the absorbent line
• one or more expansion tanks may be provided (not shown in Fig. 1), in which the CO2 and F S-laden absorbent on z. B. 3 to 15 bar is relaxed. From the lower part of the desorption column D, the absorbent is in the reboiler
• a mixed phase stream of regenerated absorbent and steam is injected into the Returned bottom of the desorption column D, where the phase separation between the vapor and the absorbent takes place.
• the regenerated absorbent to the heat exchanger 1.04 is withdrawn either from the recycle stream from the bottom of the desorption column D to the evaporator, or passed through a separate line directly from the bottom of the desorption column D to the heat exchanger 1 .04.
• the released in the desorption column D CO2 and h S-containing gas leaves the desorption column D via the exhaust pipe 1 .10. It is passed into a capacitor with integrated phase separation 1.1 1, where it is separated by entrained absorbent vapor. In this and all other systems suitable for carrying out the process according to the invention, condensation and phase separation may also be present separately from one another. Subsequently, the condensate is passed through the absorbent line 1 .12 in the upper region of the desorption column D, and carried out a CO2 and h S-containing gas via the gas line 1 .13.
• BDMAEE bis (2- (N, N-dimethylamino) ethyl) ether
• TBAAEDA 2- (2-tert-butylaminoethoxy) ethyl-N, N-dimethylamine
• TDG Thiodiglycol
• TEG triethylene glycol
• GC analysis shows a conversion of 96% based on the DMAEE used, giving 2- (2-tert-butylaminoethoxy) ethyl-N, N-dimethylamine (TBAEEDA) in a selectivity of 73%.
• TSAEEDA 2- (2-tert-butylaminoethoxy) ethyl-N, N-dimethylamine
• the crude product was purified by distillation. After removal of excess tert-butylamine at atmospheric pressure, the target product was isolated at a bottom temperature of 95 ° C and a transition temperature of 84 ° C at 8 mbar in a purity of> 97%.
• Example 2 pKs values and temperature dependence of the pKs values
• the pKa values of various amine compounds were determined at concentrations of 0.01 mol / kg at 20 ° C. or 120 ° C. by determination of the pH at the half-equivalence point of the dissociation stage to be considered by adding hydrochloric acid (1 st dissociation stage 0.005 mol / l). kg, 2. dissociation level 0.015 mol / kg, 3. dissociation level 0.025 mol / kg).
• a thermostated, closed jacketed vessel is used, in which the liquid was blanketed with nitrogen.
• the pH electrode Hamilton Polylite Plus 120 was used, which was calibrated with pH 7 and pH 12 buffer solutions.
• a pronounced temperature-dependence of the pKs value means that at relatively lower temperatures, as prevail in the absorption step, the higher pKa value promotes efficient acid gas absorption, while at relatively higher temperatures, as prevail in the desorption step, the lower pKs Value supports the release of the absorbed acid gases. It is expected that a large pKa value difference of an amine between absorption and desorption temperatures results in a lower regeneration energy.
• Example 3 Loading Capacity, Cyclic Capacity and H2S: CO2 Loading Ratio.
• a loading test and then a stripping test were carried out. On a glass cylinder with double jacket for thermostatting, a glass cooler was placed, which was operated at 5 ° C. As a result, a falsification of the measurement results was prevented by a partial evaporation of the absorbent. About 100 ml of uncharged absorbent (30% by weight of amine in water) were initially introduced into the glass cylinder. To determine the absorption capacity at ambient pressure and 40 ° C over a period of about 4 h 8 Nl / h of CO2 or H2S were passed through a frit through the absorption liquid. Subsequently, the loading of CO2 or H2S was determined as follows:
• the h S determination was carried out by titration with silver nitrate solution.
• the sample to be analyzed was weighed into an aqueous solution containing about 2% by weight of sodium acetate and about 3% by weight of ammonia.
• the H2S content was determined by a potentiometric inflection point titration using silver nitrate solution. At the inflection point, H2S is completely bound as Ag2S.
• the C02 content was determined as Total Inorganic Carbon (TOC-V Series Shimadzu).
• the loaded absorbent was filled in and stripped by means of an IS flow (8 Nl / h). After 60 minutes, a sample was taken and the CO2 or F S loading of the absorbent was determined as described above. The difference between the load at the end of the loading test and the load at the end of the stripping test results in the respective cyclic capacities.
• the H2S: C02 loading ratio was calculated as the quotient of the h S loading by the CO 2 loading.
• the product of cyclic h S capacity and H2S: C02 loading ratio is called efficiency factor ⁇ .
• the H2S: C02 loading ratio serves as an indication of the expected h S selectivity.
• the efficiency factor ⁇ can be used to estimate absorbents for their suitability for selective F S removal from a fluid stream, taking into account the H2S: CO 2 loading ratio and the F S capacity. The results are shown in Table 1.
• the absorbent (30% by weight of amine solution, 8 ml) was initially introduced into a Hastelloy cylinder (10 ml) and the cylinder was closed. The cylinder was heated to 160 ° C for 125 h.
• the sour gas loading of the solutions was 20 Nm 3 / ti_excellentmittei CO2 and 20 Nm 3 / ti_excellentmittei H2S.
• the degree of decomposition of the amines was calculated from the amine concentration measured by gas chromatography before and after the experiment. The results are shown in the following table.

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• 2016
  • 2016-09-26 BR BR112018003582A patent/BR112018003582A2/pt not_active Application Discontinuation
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