WO2016174120A1 - Élimination d'hydrocarbures aromatiques à partir d'une charge de gaz acide pauvre pour récupération de soufre - Google Patents

Élimination d'hydrocarbures aromatiques à partir d'une charge de gaz acide pauvre pour récupération de soufre Download PDF

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Publication number
WO2016174120A1
WO2016174120A1 PCT/EP2016/059461 EP2016059461W WO2016174120A1 WO 2016174120 A1 WO2016174120 A1 WO 2016174120A1 EP 2016059461 W EP2016059461 W EP 2016059461W WO 2016174120 A1 WO2016174120 A1 WO 2016174120A1
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aromatic hydrocarbons
absorbent solution
gas stream
mol
depleted
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PCT/EP2016/059461
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English (en)
Inventor
Emile FILLATRE
Gauthier Perdu
Benoit MARES
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Prosernat
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Application filed by Prosernat filed Critical Prosernat
Priority to RU2017135359A priority Critical patent/RU2705974C2/ru
Priority to US15/570,645 priority patent/US10543452B2/en
Priority to EP16722094.6A priority patent/EP3288667A1/fr
Priority to MX2017013900A priority patent/MX2017013900A/es
Priority to CA2982686A priority patent/CA2982686A1/fr
Priority to AU2016256240A priority patent/AU2016256240A1/en
Priority to CN201680024440.8A priority patent/CN107580522B/zh
Publication of WO2016174120A1 publication Critical patent/WO2016174120A1/fr

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    • 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
    • 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
    • B01D53/1406—Multiple stage absorption
    • 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
    • B01D53/1418—Recovery of products
    • 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
    • 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
    • B01D53/1487—Removing organic compounds
    • 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
    • C01B17/0426—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 characterised by the catalytic conversion
    • C01B17/043—Catalytic converters
    • 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
    • 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
    • B01D2256/00—Main component in the product gas stream after treatment
    • B01D2256/22—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/70—Organic compounds not provided for in groups B01D2257/00 - B01D2257/602
    • B01D2257/702—Hydrocarbons
    • B01D2257/7022—Aliphatic hydrocarbons
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/70—Organic compounds not provided for in groups B01D2257/00 - B01D2257/602
    • B01D2257/702—Hydrocarbons
    • B01D2257/7027—Aromatic hydrocarbons
    • 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
    • C10L2290/12—Regeneration of a solvent, catalyst, adsorbent or any other component used to treat or prepare a fuel
    • 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
    • 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
    • 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
    • C10L3/104—Carbon dioxide
    • 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 a process for the removal of aromatic hydrocarbons, such as benzene, toluene, ethyl benzene and xylene (BTX) and aliphatic hydrocarbons having 4 carbon atoms or more (C 4 + ) from a lean acid gas containing C0 2 and less than 20 mol.% of H 2 S prior to sulfur recovery.
  • aromatic hydrocarbons such as benzene, toluene, ethyl benzene and xylene (BTX) and aliphatic hydrocarbons having 4 carbon atoms or more (C 4 + ) from a lean acid gas containing C0 2 and less than 20 mol.% of H 2 S prior to sulfur recovery.
  • Natural gas is composed primarily of light aliphatic hydrocarbons such as methane, propane, butane, pentane, and their isomers. Certain contaminants are naturally present in the gas, and must be removed prior to delivery of the purified gas for private use or commercial conditioning. These contaminants include aliphatic hydrocarbons having 4 carbon atoms or more (C 4 + ) and aromatic hydrocarbons such as benzene, toluene, ethyl benzene and xylenes collectively referred to as "BTX”, but more importantly acid components such as hydrogen sulfide (H 2 S) and carbon dioxide (C0 2 ).
  • aliphatic hydrocarbons having 4 carbon atoms or more (C 4 + )
  • aromatic hydrocarbons such as benzene, toluene, ethyl benzene and xylenes
  • acid components such as hydrogen sulfide (H 2 S) and carbon dioxide (C0 2 ).
  • H 2 S from natural gas is customarily accomplished by contacting the natural gas containing the H 2 S with a liquid amine solvent at the pressure of the natural gas, which is usually from 40 to 100 bar (considered "high pressure"), thus having the H 2 S adsorbed by the amine solvent.
  • Carbon dioxide (C0 2 ), aromatic hydrocarbons and C 4 + aliphatic hydrocarbons are simultaneously adsorbed by the amine solvent due to the high pressure maintained during the absorption of H 2 S.
  • a "sweet” or purified natural gas meeting environmental standards is thus obtained and an amine containing most of the contaminants (C0 2 , H 2 S, aromatic hydrocarbons and C 4 + aliphatic hydrocarbons) is recovered.
  • the contaminated amine solvent is then carried to a regeneration zone where it is recovered under elevated temperature (generally about 130°C) and low pressure conditions (generally about 2 to 3 barA).
  • elevated temperature generally about 130°C
  • low pressure conditions generally about 2 to 3 barA.
  • An acid gas containing C0 2 , H 2 S, aromatic hydrocarbons and C 4 + aliphatic hydrocarbons is also obtained.
  • H 2 S-containing gas streams A widespread method for desulfurization of H 2 S-containing gas streams is the Claus process which operates in two major process steps.
  • the first process step is carried out in a furnace where hydrogen sulfide is converted to elemental sulfur and sulfur dioxide at temperatures of approximately 1 100 to 1400° C by the combustion of about one third of the hydrogen sulfide in the gas stream.
  • the so obtained sulfur dioxide reacts with hydrogen sulfide in the furnace to elemental sulfur by Claus reaction.
  • this first step of the Claus process about 60 to 70% of the H 2 S in the feed gas are converted and most of the aromatic and C 4 + aliphatic hydrocarbons are eliminated.
  • At least one catalytic step follows where the Claus reaction according to Eq. 1 :
  • the Claus process is very well adapted to acid gas feeds containing more than 55 mol.% of H 2 S where the first combustion step operated at a temperature higher than 1200°C can be fully conducted thus converting 60 to 70% of H 2 S and simultaneously destroying the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons.
  • recovering sulfur from an acid gas feed containing less than 55 mol.% of H 2 S applying the Claus process happens to be more complicated: the first combustion step cannot be conducted at sufficiently elevated temperatures or cannot be conducted at all due to the presence of significant amounts of C0 2 in the feed that cools down the combustion reaction below 1 100°C or even inhibits the combustion reaction when the content of C0 2 exceeds 85%.
  • aromatic hydrocarbons and C 4 + aliphatic hydrocarbons This allows the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons to avoid combustion in the first thermal step of the Claus process and to pass unreacted in the catalytic step.
  • aromatic hydrocarbons and C 4 + aliphatic hydrocarbons are however harmful to the installed unit because they deactivate the catalysts operated in the catalytic step of the Claus process. This results in poor sulfur recovery and frequent catalyst replacement.
  • an acid gas enriched in H 2 S and depleted C0 2 , aromatic hydrocarbons and C 4 + aliphatic hydrocarbons is obtained.
  • AGE processes is usually selected when it can increase the H 2 S content in the acid gas over 55 vol.% allowing the obtained acid gas to be treated conventionally by Claus, with treatment in a Claus furnace at temperatures higher than 1 100°C, thus eliminating the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons prior to the Claus catalytic step.
  • Application EP2402068 discloses the treatment of acid gases with two absorption steps. In this process, the solvent enriched in H 2 S obtained from the first absorption zone is sent to a desorption zone where heat is supplied to desorb H 2 S and promote formation of H 2 S-enriched gas.
  • H 2 S-enriched gas is then sent to another H 2 S absorption zone for further enrichment.
  • AGE however can be found unsatisfactory when the initial concentration of H 2 S in the acid gas is too low (usually less than 20 mol.%) to reach a concentration higher than 55 mol.% of H 2 S after enrichment.
  • Another proposed solution for aromatic and C 4 + aliphatic hydrocarbons removal is the gas stripping process, conventionally fuel gas stripping, of a rich amine solvent obtained from "high pressure" sour natural gas absorber before its regeneration.
  • the fuel gas stream will strip off the aromatic and C 4 + aliphatic hydrocarbons of the lean acid gas and an amine solvent depleted in aromatic and C 4 + aliphatic hydrocarbons will thus be obtained.
  • the fuel gas containing the aromatic and C 4 + aliphatic hydrocarbons will be used as a combustible for an incinerator or a utility boiler where the pollutants will be destructed.
  • the removal of the aromatic and C 4 + aliphatic hydrocarbons from the rich amine is a function of stripping fuel gas flow rate: the higher the fuel gas flowrate, the more removal can be achieved.
  • the fuel gas is used in the unit as a feed for an incinerator and/or utility boilers and, its flowrate thus remains limited by the demand of the incinerator or utility boilers.
  • a further option considered in industry is the adsorption of the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons from the acid gas in regenerable activated carbon beds or molecular sieves.
  • the object of the present invention a process for the removal of aromatic hydrocarbons, such as benzene, toluene, ethyl benzene and xylene (BTX) and aliphatic hydrocarbons having 4 carbon atoms or more (C 4 + ) from a lean acid gas containing C0 2 and less than 20 mol.% of H 2 S, which process comprises:
  • step b) contacting the stripping gas stream enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10), also containing H 2 S and C0 2 obtained in step b) with a H 2 S- selective liquid absorbent solution (28) in a second absorption zone (12) to obtain a stripping gas stream depleted in H 2 S and containing aromatic hydrocarbons, C 4 + aliphatic hydrocarbons and C0 2 (13), and an absorbent solution enriched in H 2 S (14) also containing co-absorbed aromatic hydrocarbons, C 4 + aliphatic hydrocarbons and C0 2 , said H 2 S-selective liquid absorbent solution being preferably identical to that used in step a),
  • step d) introducing the absorbent solution depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons (9) obtained in step b) into a desorption zone (16) wherein the H 2 S- selective liquid absorbent solution (17) is recovered and a lean acid gas containing H 2 S and C0 2 , depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons (21 ) is produced.
  • the invention is also directed to a process for sulfur recovery from a lean acid gas containing C0 2 and less than 20 mol.% of H 2 S , which process comprises :
  • step iv) passing the lean acid gas depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons recovered from step ii) and optionally step iii), after having optionally being preheated, into a catalytic reactor containing a catalyst system which catalyzes the direct oxidation of H 2 S with oxygen and/or the Claus reaction of H 2 S with sulfur dioxide (S0 2 ) so as to recover a lean acid gas stream depleted in H 2 S and elemental sulfur.
  • a catalytic reactor containing a catalyst system which catalyzes the direct oxidation of H 2 S with oxygen and/or the Claus reaction of H 2 S with sulfur dioxide (S0 2 ) so as to recover a lean acid gas stream depleted in H 2 S and elemental sulfur.
  • FIG. 1 schematically shows a preferred process of the present invention.
  • the dotted lines represent optional embodiments of the invention.
  • FIG. 2 shows a specific embodiment of the process of the present invention, operated in the illustrative examples.
  • the process for the removal of aromatic hydrocarbons (BTX) from a lean acid gas comprises a first step a) of contacting the lean acid gas stream (1 ) with a H 2 S-selective liquid absorbent solution (29) in a first absorption zone (2) to produce a gas stream depleted in H 2 S (3) and containing C0 2 , aromatic hydrocarbons and C 4 + aliphatic hydrocarbons, and an absorbent solution enriched in H 2 S (4), also containing co-absorbed C 4 + aliphatic hydrocarbons, aromatic hydrocarbons and C0 2 .
  • step a) is to decrease as much as possible the H 2 S content in the gas feed in order to obtain a gas stream depleted in H 2 S (3) suitable for combustion in the incinerator (33) and emission to atmosphere.
  • the gas (3) exiting the first absorption zone (2) is depleted in H 2 S and contains C0 2 , aromatic hydrocarbons and C 4 + aliphatic hydrocarbons.
  • the decrease of H 2 S content in the lean acid gas is obtained by adsorption of the H 2 S by the H 2 S-selective liquid absorbent solution (29). Therefore, at the bottom of the first absorption zone (2), a liquid absorbent solution enriched in H 2 S is obtained.
  • the first absorption step a) is operated at quite low pressure (1 to 8 barA)
  • parts of the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons contained in the lean acid gas (1 ) will be simultaneously co-absorbed by the liquid absorbent solution (29) and will need to be further treated.
  • the lean acid gas preferably contains:
  • the percentages being expressed on a dry basis, in moles, relative to the total mole of the lean acid gas.
  • the lean acid gas is generally saturated with water.
  • the lean acid gas containing C0 2 and less than 20 mol.% of H 2 S entering the process of the invention is obtained from a natural gas comprising methane (CH 4 ) and ethane (C 2 H 6 ), C0 2 , H 2 S and C 4 + aliphatic hydrocarbons and aromatic hydrocarbons.
  • such natural gas is intended to be used as a combustible and therefore should not contain any pollutant such as acid gas (C0 2 , H 2 S).
  • acid gas C0 2 , H 2 S
  • Specifications relative to H 2 S concentration in natural gas are very strict and its maximal concentration should remain below 4 ppm mol.
  • the concentration in C0 2 on the other hand should preferably remain below 2%, depending on the later use of the natural gas, and on the legislation.
  • the natural gas thus needs to be treated to remove the acid gases (C0 2 , H 2 S) contained therein.
  • a purified natural gas meeting the standards for transport, storage and also private or commercial use is then obtained, but a lean acid gas containing C0 2 , H 2 S and also aromatic hydrocarbons and C 4 + aliphatic hydrocarbons is simultaneously produced. This lean acid gas needs to be treated prior to sulfur recovery.
  • the lean acid gas containing C0 2 and less than 20 mol.% of H 2 S is obtained according to a process comprising:
  • the natural gas used to obtain a lean acid gas for the purpose of the invention contains C 4 + aliphatic hydrocarbons and aromatic hydrocarbons, and few H 2 S compared to C0 2 amount (for example, the amount of C0 2 being at least 4 times higher than the amount of H 2 S.
  • Step a) can preferably be operated:
  • the H 2 S-selective liquid absorbent solution can be any of the known absorbents conventionally used by the skilled person, such as chemical solvents, physical solvents and mixtures thereof.
  • chemical solvent when used as liquid absorbent solution, it may be associated with a physical solvent to enhance the absorption of the contaminants commonly found in the lean acid gas streams.
  • Chemical solvents can for example include alkali metal carbonate and phosphate, or alkanolamines, preferably in the form of aqueous solutions.
  • Alkanolamines are preferably chosen from tertiary alkanolamines and sterically hindered alkanolamines.
  • the sterically hindered alkanolamine can be selected from the group consisting of 2-amino-2-methylpropanol, 2-amino-2-methyl-1 ,3-propanediol, 2-amino- 2-hydroxymethyl-1 ,3-propanediol, 2-amino-2-ethyl-1 ,3-propanediol, 2-hydroxymethyl piperidine, 2-(2-hydroxyethyl) piperidine, 3-amino-3-methyl-1 -butanol and mixtures thereof.
  • Suitable alkanolamines include methyldiethanolamine (MDEA), triethanolamine, or one or more dipropanolamines, such as di-n-propanolamine or diisopropanolamine.
  • MDEA methyldiethanolamine
  • triethanolamine triethanolamine
  • dipropanolamines such as di-n-propanolamine or diisopropanolamine.
  • Physical solvents can for example include a substituted or unsubstituted tetramethylene sulfone or thioglycols,
  • the H 2 S-selective liquid absorbent solution contains an amine, preferably an alkanolamine, more preferably a tertiary alkanolamine or sterically hindered alkanolamine, and even more preferably methyldiethanolamine (MDEA).
  • MDEA methyldiethanolamine
  • Aqueous methyldiethanolamine (MDEA) solutions are preferred liquid absorbent solution according to the invention.
  • the H 2 S-selective liquid absorbent solution can be a mixture of alkanolamines and thioglycols.
  • Additives components capable of enhancing the selectivity of H 2 S adsorption towards C0 2 such as acidic components like phosphoric acid (H 3 P0 4 ) can also be introduced in the liquid absorbent solution.
  • Concentrations of aqueous alkanolamine solutions may vary widely, and those skilled in the art can adjust solution concentrations to achieve suitable absorption levels.
  • concentration of alkanolamine in aqueous solutions will be from 5 to 60% by weight, and preferably between 25 and 50% by weight.
  • a physical solvent is employed as a component of the absorbent liquid, it can be present in an amount from 2 to 50% by weight, preferably from 5 to 45% by weight.
  • the absorption step a) is preferably conducted:
  • the gas stream depleted in H 2 S (3) exiting the first absorption zone (2) preferably contains C0 2 , aromatic hydrocarbons and C 4 + aliphatic hydrocarbons, and in particular:
  • gas stream depleted in H 2 S (3) exiting the first absorption zone (2) can then be transferred to an incinerator (33) where it will be combusted to destruct remaining H 2 S as well as the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons contained therein, thus reaching the standards requirements for air emission.
  • gas stream depleted in H 2 S (3) can be compressed, injected and disposed in an underground storage reservoir rather than being incinerated and released to the atmosphere.
  • the absorbent solution enriched in H 2 S (4) exiting the first absorption zone (2) also contains co-absorbed C 4 + aliphatic hydrocarbons, aromatic hydrocarbons and C0 2 .
  • the absorbent solution enriched in H 2 S (4) exiting the first absorption zone (2) contains:
  • the absorbent solution enriched in H 2 S (4) exiting the first absorption zone (2) is then sent to a non-thermic stripping zone (8) where it is contacted with a stripping gas stream (7), preferably fuel gas, to obtain an absorbent solution depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons (9) and containing H 2 S and C0 2 and a stripping gas stream enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10), also containing H 2 S and C0 2 .
  • a stripping gas stream (7) preferably fuel gas
  • the absorbent solution enriched in H 2 S (4) also contains co-absorbed C 4 + aliphatic hydrocarbons and aromatic hydrocarbons.
  • step b) is thus to remove as much C 4 + aliphatic hydrocarbons and aromatic hydrocarbons as possible from the absorbent solution, with as few H 2 S as possible, so that when the lean acid gas is recovered, it does not contain high concentration of impurities capable of poisoning the sulfur recovery unit catalysts. This is done by contacting the absorbent solution enriched in H 2 S (4) with a countercurrent of stripping gas, such as fuel gas stream (7), in a non-thermic stripping step.
  • stripping gas such as fuel gas stream (7)
  • Prior art stripping steps are conventionally operated either simply by heating the absorbent solution enriched in H 2 S to produce steam as stripping stream, or by injecting directly stream in the stripping zone.
  • the provision of heat to the stripping zone increases the chemical desorption of acid gas, in particular H 2 S, from the absorbent solution and favors its removal with the stripping stream.
  • An absorbent solution substantially depleted in H 2 S is therefore obtained with the conventional stripping steps of the prior art.
  • the stripping step of the claimed process is athermic in the sense that no significant heat or energy is provided to the process at this stage.
  • the obtained absorbent solution (9) is depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons.
  • the stripping gas stream (7) will preferentially strip off the C 4 + aliphatic hydrocarbons and aromatic hydrocarbons over H 2 S from the absorbent solution enriched in H 2 S (4), but will however also drag away part of the H 2 S and C0 2 contained in the absorbent solution (4).
  • the stripping gas stream exiting the stripping zone (8) is thus enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10) but also contains H 2 S and C0 2 .
  • the stripping gas used in the stripping zone of the process of the invention can preferably be a fuel gas stream, but may also be any combustible gas meeting standards requirements for a combustible, for example natural gas, hydrogen, and/or synthetic gas containing mostly H 2 and CO, or any other inert gas containing mainly nitrogen or helium for example.
  • the fuel gas, or any combustible gas, used in the stripping zone can thus be used as a feed/combustible in the incinerator (33) and/or in the utility boilers.
  • the stripping gas is a fuel gas and, preferably, the fuel gas (7) used in the stripping zone (8) is the combustible gas used to run the incinerator (33) and/or utility boilers in the unit.
  • the plant where the process of the invention is conducted generally comprises incinerators and/or utility boilers for various purposes. Said incinerators and boilers have to be fed with fuel gas.
  • One advantage of the present invention is that the fuel gas that is needed to feed the incinerators and/or utility boilers of the plant is used first as a stripping gas, and then recovery and rerouted to its original path to feed the incinerators and/or utility boilers.
  • the utility boilers (not shown in the figure) produce steam which could feed boilers of the plant where the claimed process is conducted, as for example the boiler (18) in figure 1 .
  • the fuel gas flow rate in the stripping zone is limited by the combustible gas flow rate necessary to run the incinerator (33) and/or the utility boilers.
  • the fuel gas is used consecutively as a stripping gas in the stripping zone (8) and as a combustible gas to run the incinerator and/or the utility boilers, which is economically advantageous.
  • the stripping gas stream (7) is preferably introduced at the bottom of the stripping zone in order to be contacted with a countercurrent of absorbent solution enriched in H 2 S (4).
  • step b) is preferably conducted:
  • the absorbent solution enriched in H 2 S (4) may be necessary to pass it though a pump (5) or alternatively though a valve before it enters the stripping zone.
  • the absorbent solution enriched in H 2 S (4) also passes through a heater (6) to increase its temperature before entering the stripping zone (8) to efficiently remove the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons.
  • the heat provided to the stripping step should be controlled to increase the removal of aromatic hydrocarbons and C 4 + aliphatic hydrocarbons while ensuring that only a minimal amount of H 2 S is desorbed from the absorbent solution to avoid obtaining a stripping gas stream (7) that would be enriched with H 2 S.
  • the temperature increase in the heater (6) may be obtained by recirculating in the heater (6), at least a part of the H 2 S-selective liquid absorbent solution (17) recovered from the desorption zone (16), and/or exiting the heat exchanger (heater 15).
  • the H 2 S-selective liquid absorbent solution thus acts as a heating source for the heater (6).
  • the stripping gas stream (10) exiting the stripping zone (8) is enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons but also contains H 2 S and C0 2 . It preferably contains:
  • the absorbent solution (9) exiting the stripping zone (8) is depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons, and preferably contains:
  • the absorbent solution (9) exiting the stripping zone (8) contains 0.01 to 10 mol.% of the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons contained in the lean acid gas (1 ), more preferably 0.1 to 5 mol.%.
  • the stripping gas stream enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10), also containing H 2 S and C0 2 obtained in step b) is contacted with a H 2 S- selective liquid absorbent solution (28) in a second absorption zone (12) to obtain a stripping gas stream depleted in H 2 S and containing aromatic hydrocarbons, C 4 + aliphatic hydrocarbons and C0 2 (13), and an absorbent solution enriched in H 2 S (14) also containing co-absorbed aromatic hydrocarbons, C 4 + aliphatic hydrocarbons and C0 2 , said H 2 S-selective liquid absorbent solution preferably being identical to that used in step a).
  • more than 80% of the stripping gas stream enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10), preferably more than 90% and more preferably all the stripping gas stream (10) obtained in step b) is sent to the second absorption zone (12).
  • the stripping gas stream is enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10) but also contains H 2 S and C0 2 .
  • step c) is thus to remove as much H 2 S as possible from the stripping gas stream (10) so as to recover a stripping gas stream suitable for further use as a combustible, such as fuel gas for the incinerator (33) and/or the utility boilers.
  • the stripping gas stream depleted in H 2 S can be compressed, injected and disposed in an underground storage reservoir rather than being incinerated and released to the atmosphere. This is done by contacting the stripping gas stream enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10) with a countercurrent of H 2 S-selective liquid absorbent solution (28), said H 2 S-selective liquid absorbent solution being preferably the one used in step a).
  • the H 2 S-selective liquid absorbent solution (28) may for example be obtained by derivation of the main solvent stream (29) entering the first absorption zone.
  • (12) are preferably the same as those previously disclosed for the first absorption zone in step a).
  • the stripping gas stream enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10) but also containing H 2 S and C0 2 it may be necessary to pass it though a cooler (1 1 ) and, optionally, a separator to recover condensed water, before it enters the second absorption zone (12).
  • the stripping gas stream (13) exiting the second absorption zone (12) preferably contains aromatic hydrocarbons, C 4 + aliphatic hydrocarbons and C0 2 , and in particular:
  • the stripping gas stream depleted in H 2 S and containing aromatic hydrocarbons, C 4 + aliphatic hydrocarbons and C0 2 (13) exiting the second absorption zone (12) meets standards requirements as a combustible, such as fuel gas, and can thus be used as a feed in the incinerator (33) and/or in the utility boilers where associated aromatic hydrocarbons (BTX) and C 4 + aliphatic hydrocarbons, as well as remaining sulfur species, will be destructed.
  • the stripping gas stream depleted in H 2 S (13) can be compressed, injected and disposed in an underground storage reservoir rather than being incinerated and released to the atmosphere.
  • the absorbent solution enriched in H 2 S (14) exiting the second absorption zone (12) also contains co-absorbed aromatic hydrocarbons (BTX), C 4 + aliphatic hydrocarbons and C0 2 .
  • the absorbent solution enriched in H 2 S (14) exiting the second absorption zone (12) contains:
  • the absorbent solution enriched in H 2 S (14) exiting the second absorption zone (12) can be recycled back to the stripping zone (8) to supplement the absorbent solution enriched in H 2 S (4) and/or can be directly introduced into the desorption zone (16) to supplement the absorbent solution depleted in aromatic hydrocarbons (9) obtained in step b).
  • the absorbent solution enriched in H 2 S (14) exiting the second absorption zone (12) is entirely recycled to the stripping zone to supplement the absorbent solution enriched in H 2 S (4) in order to decrease aromatic (BTX) and C 4 + aliphatic hydrocarbons content in the absorbent solution enriched in H 2 S (9) sent to the desorption zone (16).
  • the stripping zone (8) and the second absorption zone (12) are designed to significantly reduce the amount of aromatic hydrocarbons (BTX) and C 4 + aliphatic hydrocarbons in the absorbent solution depleted in H 2 S entering the desorption zone (16) in comparison to their amount in the absorbent solution enriched in H 2 S (4) exiting the first absorption zone and even more in comparison with their initial amount in the lean acid gas stream (1 ).
  • BTX aromatic hydrocarbons
  • C 4 + aliphatic hydrocarbons in the absorbent solution depleted in H 2 S entering the desorption zone (16) in comparison to their amount in the absorbent solution enriched in H 2 S (4) exiting the first absorption zone and even more in comparison with their initial amount in the lean acid gas stream (1 ).
  • the absorbent solution exiting the stripping step b) and the second absorption step c) are depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons (9) but still contain H 2 S and C0 2 .
  • step d) is thus to desorb as much H 2 S and C0 2 as possible from the absorbent solution (9) so as to recover a purified absorbent solution that can be recycled back to the first and/or second absorption zones. This is done by heating the absorbent solution (9) in a desorption zone (16).
  • the desorption step d) is preferably conducted:
  • the absorbent solution depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons (9) recovered from the stripping zone (8) may also pass through a heater (15) to increase its temperature before entering the desorption zone in order to reduce the energy consumption for steam circulation in the desorption zone.
  • the temperature increase in the heater (15) can preferably be obtained by recirculating in the heater (15), at least a part of the regenerated liquid absorbent solution (17) recovered from the desorption zone (16).
  • the regenerated liquid absorbent solution (17) thus acts as a heating medium for the heater (15).
  • a steam is generated in the desorption zone (16) thus providing the energy necessary to remove H 2 S, C0 2 , hydrocarbons, and aromatics such as BTX from the absorbent solution.
  • the steam may be produced by heat exchange with the liquid absorbent solution present in the bottom of the desorption zone (16) through any heating means (steam, hot oil, furnace, burner, boiler).
  • the desorption zone (16) can thus preferably comprise a boiler (18) at its bottom in which steam circulates in order to permit the regeneration of the absorbent solution enriched in H 2 S.
  • the regenerated liquid absorbent solution (17) leaving the bottom of the desorption zone (16) may then be sent back to the first adsorption zone (2) as the H 2 S-selective liquid absorbent solution (29) and/or to the second adsorption zone (12) as the H 2 S-selective liquid absorbent solution (28).
  • the lean gas (21 ) exiting the desorption zone (16) further contains steam and vaporized absorbent solution.
  • the water issued from the steam and the vaporized absorbent solution carried with the lean gas (21 ) exiting the desorption zone (16) can be partially separated from the lean acid gas depleted in aromatic hydrocarbons (21 ) in the condenser (22) and further trapped in the reflux drum (23) which acts as an accumulator.
  • the water and the absorbent solution can then be recycled to the desorption zone (16) though a pump (25) in order to limit water and absorbent solution loss.
  • a lean acid gas depleted in aromatic hydrocarbons (26) is recovered.
  • the condenser is preferably operated at a temperature ranging from more preferably from 20 to 70°C and even more preferably from 40 to 60°C.
  • the lean acid gas (21 ) or (26) is depleted in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons and preferably contains 0.01 to 10 mol.% of the aromatic hydrocarbons (BTX) and C 4 + aliphatic hydrocarbons contained in the lean acid gas entering the process, more preferably 0.1 to 5 mol.%.
  • the lean acid gas depleted in aromatic hydrocarbons (21 ) or (26) recovered at the end of the process of the invention has preferably a H 2 S/C0 2 ratio higher than the H 2 S/C0 2 ratio of the lean acid gas (1 ) entering the process.
  • the lean acid gas depleted in aromatic hydrocarbons (21 ) or (26) recovered after the desorption zone (16) may be partially recycled to supplement the lean acid gas stream (1 ) entering the process, and/or to supplement the stripping gas stream enriched in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons (10) but also containing H 2 S and C0 2 .
  • the lean acid gas depleted in aromatic hydrocarbons and C 4 + aliphatic hydrocarbons produced is suitable for a subsequent sulfur recovery treatment because even if it is not enriched in H 2 S to reach a proportion of more than 55 mol.%, which would be necessary to be properly operated in a Claus furnace (first step of sulfur recovery), it contains a sufficiently low amount of aromatic hydrocarbons such as BTX and C 4 + aliphatic hydrocarbons to allow its use in a sulfur recovery unit operating with partial by-pass of the furnace or even no thermal step at all.
  • the stripping gas stream (7) is a combustible and its flow rate is adapted to the incinerator (33) and / or utility boilers needs.
  • the content of aromatic hydrocarbons, such as benzene, toluene, ethylbenzene and xylene (BTX) and C 4 + aliphatic hydrocarbons in the lean acid gas (21 ) or (26) recovered at the end of the process of the invention should be as low as possible and no higher than 500 mol.ppm, preferably between 1 and 500 mol. ppm, in order to prevent Claus catalyst deactivation in a further sulfur recovery unit.
  • aromatic hydrocarbons such as benzene, toluene, ethylbenzene and xylene (BTX) and C 4 + aliphatic hydrocarbons in the lean acid gas (21 ) or (26) recovered at the end of the process of the invention
  • Another object of the invention is a process for sulfur recovery from a lean acid gas containing C0 2 and less than 20 mol.% of H 2 S , which process comprises :
  • step iv) passing the lean acid gas depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons recovered from step ii) and optionally step iii), after having optionally being preheated, into a catalytic reactor containing a catalyst system which catalyzes the direct oxidation of H 2 S with oxygen and/or the Claus reaction of H 2 S with sulfur dioxide (S0 2 ) so as to recover a lean acid gas stream depleted in H 2 S (32) and elemental sulfur.
  • a catalytic reactor containing a catalyst system which catalyzes the direct oxidation of H 2 S with oxygen and/or the Claus reaction of H 2 S with sulfur dioxide (S0 2 ) so as to recover a lean acid gas stream depleted in H 2 S (32) and elemental sulfur.
  • the elemental sulfur is recovered in a condenser.
  • Step iv) may preferably be repeated several times, more preferably at least twice.
  • the sulfur recovery process can preferably be only a catalytic direct oxidation process (without thermal step iii)).
  • the lean acid gas depleted in C 4 + aliphatic hydrocarbons and aromatic hydrocarbons (21 ) or (26) may be preheated before entering the catalytic reactor.
  • catalytic direct oxidation process can be performed isothermally or pseudo-isothermally with the help of internal cooler, such as thermoplates like the SmartSulfTM technology.
  • internal cooler such as thermoplates like the SmartSulfTM technology.
  • Such technology is advantageous for catalytic reactor following a Claus thermal step (iii)), and even more advantageous in the case of direct oxidation without Claus thermal step (iii)), as it could be considered in the case of a content of H 2 S below 15 mol.% in the lean acid gas (21 ) or (26).
  • step iv) of the process for sulfur recovery from a lean acid gas containing C0 2 and less than 20 mol.% of H 2 S includes and/or is followed iv.1 transferring the lean acid gas stream containing both H 2 S and oxygen into a first section of a first reactor, after having optionally being preheated, which first section contains a non-cooled adiabatic bed containing a first catalyst which catalyzes the oxidation of H 2 S with oxygen and the oxidation of H 2 S with sulfur dioxide, wherein the maximum temperature of the adiabatic bed is T1 , iv.2transferring the lean acid gas stream from the first section of the first reactor to a second section of the first reactor, which second section contains a second catalyst which can be different from the first catalyst and which second section is kept at a temperature T2 wherein T2 ⁇ T1 and T2 is higher than the dew point temperature of elemental sulfur, whereby a gas stream depleted in H 2 S is obtained,
  • iv.4 optionally preheating the gas stream depleted in sulfur iv.5transferring the gas stream depleted in sulfur into the first section of a second reactor, which first section contains a non-cooled adiabatic bed containing the same catalyst as the first section of the first reactor, wherein the first section of the second reactor is operated at a temperature that is above the dew point of the elemental sulfur so that in the first section of the second reactor no elemental sulfur deposits as liquid or solid on the catalyst,
  • the second section of the reactors can be kept at a temperature that is at or below the dew point of elemental sulfur with the help of an internal cooler such as thermoplates.
  • steps iv.1 to iv.7 correspond to the SmartSulfTM technology.
  • Step iv.7 of switching the operation conditions of the first reactor and the second reactor and switching the gas flow simultaneously makes it possible to desorb the elemental sulfur condensed on the catalyst operated in the second reactor. Indeed, when operated in the first place (at higher temperature), the second reactor is run at higher temperatures thus desorbing the sulfur that condensed on the catalyst when the reactor was previously operated in a second place (at lower temperature).
  • the lean acid gas stream depleted in H 2 S (32) exiting the sulfur recovery unit in step iv) can then be transferred to an incinerator (33) where it will be combusted to destruct remaining H 2 S as well as the aromatic hydrocarbons and C 4 + aliphatic hydrocarbons contained therein, thus reaching the standards requirements for air emission.
  • gas stream depleted in H 2 S (3) can be compressed, injected and disposed in an underground storage reservoir rather than being incinerated and released to the atmosphere.
  • a process for sulfur recovery from a lean acid gas (1 ) as illustrated in Fig. 2 was operated using an acid gas containing:
  • This lean acid gas was sent to a first absorption zone (2) at a flow rate of 2800 kmol/h at a pressure of 1.7 bar.
  • the lean acid gas contacted a 45 wt% (1 1 mol.%) methyldiethanolamine (MDEA) aqueous solution (29), introduced at a flow rate of 480 m 3 /h, at a temperature of 45°C and at a pressure of 1.55 barA.
  • MDEA methyldiethanolamine
  • the MDEA solution (4) exiting the first absorption zone (2) absorbs almost the entire amount of H 2 S of the lean acid gas and co-absorbs about 8% of the BTX initially present in the lean acid gas.
  • the solvent reaches a temperature of about 62°C.
  • the MDEA solution (4) exiting the first absorption zone (2) then passed through a pump (5) and through a heater (6) to increase its temperature and pressure in order to enter the stripping zone (8) at a temperature of 92.0°C and at a pressure of 5 barA.
  • the temperature increase in the heater (6) was obtained by recirculating in the heater (6) the MDEA solution (20) recovered from the desorption zone (16).
  • the heated MDEA solution entered the stripping zone (8) where it was contacted with a countercurrent of a natural gas stream (7) introduced at the bottom of the stripping zone.
  • the natural gas stream (7) had the following specifications:
  • the stripper was operated at a pressure of 5.0 barA.
  • the fuel gas stream (10) exiting the stripping zone (8) had the following specifications:
  • This fuel gas stream (10) exiting the stripping zone (8) was then passed through a heat exchanger and entered a second adsorption zone (12) at a temperature of 45°C.
  • the fuel gas stream (10) exiting the stripping zone (8) contacted a methyldiethanolamine (MDEA) solution (28) introduced at a flow rate of 30 m 3 /h, at a temperature of 45°C and a pressure of 4.0 barA.
  • MDEA methyldiethanolamine
  • MDEA methyldiethanolamine
  • o 1 350 mol. ppm of BTX (85% of the BTX entering the second absorption zone in stream 16 and about 5% of the BTX entering the process in stream 1 ).
  • the fuel gas stream (13) meets standards requirements for a combustible and can thus be used as a feed in the incinerator (33) and/or in the utility boilers where associated aromatic hydrocarbons (BTX) and C 4 + aliphatic hydrocarbons, as well as remaining sulfur species, will be destructed.
  • BTX aromatic hydrocarbons
  • C 4 + aliphatic hydrocarbons as well as remaining sulfur species
  • the MDEA solution enriched in H 2 S (14) exiting the second absorption zone (12) was recycled to the stripping zone to supplement the MDEA solution enriched in H 2 S (4).
  • This MDEA solution depleted in BTX (9) was then introduced into a desorption zone (16) equipped with a boiler (18) operating at a temperature of 130°C and a pressure of 2.4 barA.
  • the regenerated MDEA solution (17) leaving the bottom of the desorption zone (16) was sent back to the first adsorption zone (2) and to the second adsorption zone (12).
  • the lean acid gas depleted in BTX (21 ) exiting the desorption zone (16) was passed through a condenser (22) and a reflux drum (23).
  • the lean acid gas depleted in BTX (26) recovered at the end of the process of the invention had a temperature of 45°C and a flow rate of 570kmol/h. It had the following composition:
  • the process of the present invention made it possible to decrease the BTX content of the lean acid gas treated of 97%.
  • the treated lean acid gas was then suitable for a subsequent treatment in a sulfur recovery unit even with an H 2 S content lower than 55mol%.
  • the obtained acid gas was then treated in a Claus process with 10% of the flow of acid gas by-passing the thermal step (furnace), and 2 reactors (SmartSulfTM technology) being used to operate the catalytic step.
  • a sulfur recovery rate of 99.3% was obtained. 107 tons per day of bright yellow solid sulfur, reaching standards for sulfur recovery were recovered without further treatment.
  • a process for sulfur recovery from a lean acid gas as illustrated in Fig. 2 was operated using an acid gas containing:
  • This lean acid gas was sent to a first absorption zone (2) at a flow rate of 2 800 kmol/h.
  • the lean acid gas contacted a 45 wt% (1 1 mol.%) methyldiethanolamine (MDEA) aqueous solution (29) introduced at a flow rate of 335 m 3 /h, at a temperature of 45°C and at a pressure ranging of 1.55 barA.
  • MDEA methyldiethanolamine
  • the MDEA solution (4) exiting the first absorption zone (2) absorbs almost the entire amount of H 2 S of the lean acid gas and co-absorbs about 8% of the BTX and reached a temperature of about 55°C.
  • the MDEA solution (4) exiting the first absorption zone (2) then passed through a pump (5) and through a heater (6) to increase its temperature and pressure in order to enter the stripping zone (8) at a temperature of 93.0°C and at a pressure of 5 barA.
  • the temperature increase in the heater (6) was obtained by recirculating in the heater (6) the MDEA solution (20) recovered from the desorption zone (16).
  • the heated MDEA solution entered the stripping zone (8) where it was contacted with a countercurrent of a natural gas stream (7) introduced at the bottom of the stripping zone.
  • the natural gas stream (7) had the following specifications:
  • the stripper was operated at a pressure of 5.0 barA.
  • the fuel gas stream exiting the stripping zone (8) had the following specifications:
  • This fuel gas stream exiting the stripping zone (8) was then passed through a heat exchanger and entered a second adsorption zone (12) at a temperature of 45°C.
  • the fuel gas stream exiting the stripping zone (8) contacted a methyldiethanolamine (MDEA) solution (28) introduced at a flow rate of 12 m 3 /h, at a temperature of 45°C and a pressure of 4.0 barA.
  • MDEA methyldiethanolamine
  • the methyldiethanolamine (MDEA) solution is the same as the one used in the first absorption zone (2).
  • the fuel gas stream (13) meets standards requirements for a combustible and can thus be used as a feed in the incinerator (33) and/or in the utility boilers where associated aromatic hydrocarbons (BTX) and C 4 + aliphatic hydrocarbons, as well as remaining sulfur species, will be destructed.
  • BTX aromatic hydrocarbons
  • C 4 + aliphatic hydrocarbons as well as remaining sulfur species
  • the MDEA solution enriched in H 2 S (14) exiting the second absorption zone (12) was recycled to the stripping zone to supplement the MDEA solution enriched in H 2 S (4).
  • This MDEA solution depleted in BTX (9) was then introduced into a desorption zone (16) equipped with a boiler (18) operating at a temperature of 130°C and a pressure of 2.4 barA.
  • the regenerated MDEA solution (17) leaving the bottom of the desorption zone (16) was sent back to the first adsorption zone (2) and to the second adsorption zone (12).
  • the lean acid gas depleted in BTX (21 ) exiting the desorption zone (16) was passed through a condenser (22) and a reflux drum (23).
  • the lean acid gas depleted in BTX (26) recovered at the end of the process of the invention had a temperature of 45°C and a flow rate of 160 kmol/h. It had the following composition:
  • the process of the present invention made it possible to decrease the BTX content of the lean acid gas treated of 99 mol.%.
  • the treated lean acid gas was then suitable for a subsequent treatment in a sulfur recovery unit even with an H 2 S content much lower than 55 mol%.
  • the obtained acid gas was then treated by direct oxidation in 2 reactors (SmartSulfTM technology). This resulted in a sulfur recovery rate of 98%. 2 tons per day of bright yellow solid sulfur, reaching standards for sulfur recovery were recovered without further treatment.

Abstract

La présente invention concerne un procédé d'élimination d'hydrocarbures aromatiques à partir d'un gaz acide pauvre contenant moins de 20 % en mole de H2S, consistant à : a) mettre en contact le flux de gaz acide pauvre (1) avec une solution absorbante de liquide sélectif de H2S (29) dans une première zone d'absorption (2) pour produire un courant de gaz appauvri en H2S (3) et une solution absorbante enrichie en H2S (4), b) introduire la solution absorbante (4) dans une zone de décapage non thermique (8) où elle est mise en contact avec un flux de gaz de décapage (7) pour obtenir une solution absorbante appauvrie en hydrocarbures aliphatiques et aromatiques C4 +(9) et un flux de gaz de décapage enrichi en hydrocarbures aromatiques et aliphatiques C4 + (10), c) mettre en contact le flux de gaz de décapage (10) obtenu dans l'étape b) avec une solution absorbante de liquide sélectif de H2S (28) dans une seconde zone d'absorption (12) pour obtenir un flux de gaz de décapage appauvri en H2S (13), et une solution absorbante enrichi en H2S (14), d) introduire la solution absorbante (9) obtenue dans l'étape b) dans une zone de désorption (16), la solution absorbante de liquide sélectif de H2S (17) étant récupérée et un gaz acide pauvre étant produit.
PCT/EP2016/059461 2015-04-30 2016-04-28 Élimination d'hydrocarbures aromatiques à partir d'une charge de gaz acide pauvre pour récupération de soufre WO2016174120A1 (fr)

Priority Applications (7)

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RU2017135359A RU2705974C2 (ru) 2015-04-30 2016-04-28 Удаление ароматических углеводородов из бедного кислого газового сырья для получения серы
US15/570,645 US10543452B2 (en) 2015-04-30 2016-04-28 Removal of aromatic hydrocarbons from lean acid gas feed for sulfur recovery
EP16722094.6A EP3288667A1 (fr) 2015-04-30 2016-04-28 Élimination d'hydrocarbures aromatiques à partir d'une charge de gaz acide pauvre pour récupération de soufre
MX2017013900A MX2017013900A (es) 2015-04-30 2016-04-28 Extraccion de hidrocarburos aromaticos de la alimentacion de gas acido pobre para la recuperacion de azufre.
CA2982686A CA2982686A1 (fr) 2015-04-30 2016-04-28 Elimination d'hydrocarbures aromatiques a partir d'une charge de gaz acide pauvre pour recuperation de soufre
AU2016256240A AU2016256240A1 (en) 2015-04-30 2016-04-28 Removal of aromatic hydrocarbons from lean acid gas feed for sulfur recovery
CN201680024440.8A CN107580522B (zh) 2015-04-30 2016-04-28 从用于硫回收的贫酸气进料中去除芳烃的方法

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US14/700974 2015-04-30

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CN110167875A (zh) * 2016-12-23 2019-08-23 道达尔公司 用于元素硫处理的集成方法

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MX2017013900A (es) 2018-03-12
RU2017135359A (ru) 2019-04-05
EP3288667A1 (fr) 2018-03-07
CN107580522A (zh) 2018-01-12
CN107580522B (zh) 2021-07-13
AU2016256240A1 (en) 2017-10-26

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