Encyclopedia Of Hydrocarbons Eni Pdf Converter

| Posted on by

  1. Encyclopedia Of Hydrocarbons Eni Pdf Converter Download
  2. Editions Eni Pdf
  3. Emmanuel Eni Pdf
  4. 1761 Net Eni Pdf
  5. Encyclopedia Of Hydrocarbons Eni Pdf Converter Pdf

S SAAC → signal amplification by allosteric ca- talysis Sabatier, Paul (1854–1941), professor of chem- istry in Toulouse (France). Worked on catalysis, *hydrogenations.

Sulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feeds with BTEX in a Claus unit Download PDF

Info

Publication number
US9593015B2
US9593015B2US14/686,950US201514686950AUS9593015B2US 9593015 B2US9593015 B2US 9593015B2US 201514686950 AUS201514686950 AUS 201514686950AUS 9593015 B2US9593015 B2US 9593015B2
Authority
US
United States
Prior art keywords
stream
selective separation
US20150298972A1 (en
Inventor
Milind M. Vaidya
Aadesh Harale
Veera Venkata R. Tammana
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Saudi Arabian Oil Co
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Critical
CriticalSaudi Arabian Oil Co
Publication of US20150298972A1publicationAssigned to SAUDI ARABIAN OIL COMPANYreassignmentSAUDI ARABIAN OIL COMPANYAssignors: HARALE, AADESH, DUVAL, SEBASTIEN A., KHAWAJAH, ANWAR H., TAMMANA, VEERA VENKATA R., VAIDYA, MILIND M., BALLAGUET, JEAN-PIERRE R.
Critical
Criticalpatent/US9593015B2/en
Critical
Critical

Links

  • AbstractDescription230000035611feedingEffects0ClaimsTitle48
  • AbstractDescription238000000034methodsMethods0ClaimsTitle56
  • AbstractDescription229910000037hydrogen sulfideInorganic materials0Description229910052717sulfurInorganic materials0Description239000011593sulfurSubstances0Description239000004215Carbon black (E152)Substances0Claims239000002253acidSubstances0Claims239000004452animal feeding substancesSubstances0Claims239000001569carbon dioxideSubstances0ClaimsCURLTUGMZLYLDI-UHFFFAOYSA-Ncarbon dioxideChemical compounddata:image/svg+xml;base64,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:image/svg+xml;base64,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C=OCURLTUGMZLYLDI-UHFFFAOYSA-N0Claims238000004891communicationMethods0Claims150000002430hydrocarbonsChemical class0Claims238000000926separation methodMethods0Claims229940074993Carbon DisulfideDrugs0Description8
  • ClaimsUHOVQNZJYSORNB-UHFFFAOYSA-NbenzeneChemical compounddata:image/svg+xml;base64,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data:image/svg+xml;base64,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CC=CC=C1UHOVQNZJYSORNB-UHFFFAOYSA-N0Description8
  • Claims229910002092carbon dioxidesInorganic materials0Description155
  • Claims229920001577copolymersPolymers0Description5
  • Claims229920001971elastomersPolymers0Description9
  • ClaimsYNQLUTRBYVCPMQ-UHFFFAOYSA-NethylbenzeneChemical compounddata:image/svg+xml;base64,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data:image/svg+xml;base64,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CC=CC=C1YNQLUTRBYVCPMQ-UHFFFAOYSA-N0Description8
  • Claims239000002608ionic liquidSubstances0Description20
  • Title1
  • Claims229920005548perfluoropolymerPolymers0Description6
  • Claims229920002627poly(phosphazenes)Polymers0Description15
  • Claims229920002647polyamidesPolymers0Description6
  • Claims229920005597polymer membranePolymers0Description4
  • Claims239000008094tolueneSubstances0Description9
  • Claims239000002912waste gasSubstances0Description3
  • Claims2
  • Claims2
  • Description2
  • Description1
  • Description2
  • Description1
  • Description1
  • Description2
  • Description1
  • Description1
  • Description1
  • Description2
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description2
  • Description1
  • Description69
  • Description1
  • Description1
  • Description1
  • Description10
  • Description15
  • Description1
  • Description1
  • Description3
  • Description1
  • Description1
  • Description2
  • Description2
  • Description1
  • Description2
  • Description3
  • Description2
  • Description2
  • Description2
  • Description1
  • Description1
  • Description2
  • Description5
  • Description1
  • Description1
  • Description2
  • Description6
  • Description6
  • Description6
  • Description1
  • Description4
  • Description1
  • Description2
  • Description1
  • Description1
  • Description2
  • Description1
  • Description3
  • Description7
  • Description1
  • Description3
  • Description3
  • Description2
  • Description1
  • Description4
  • Description39
  • Description6
  • Description1
  • Description1
  • Description1
  • Description5
  • Description1
  • Description3
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description2
  • Description1
  • Description1
  • Description10
  • Description3
  • Description1
  • Description2
  • Description1
  • Description2
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description3
  • Description2
  • Description1
  • Description1
  • Description2
  • Description2
  • Description1
  • Description2
  • Description2
  • Description1
  • Description1
  • Description2
  • Description1
  • Description1
  • Description1
  • Description1
  • Description7
  • Description1
  • Description2
  • Description8
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description2
  • Description1
  • Description15
  • Description1
  • Description3
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description2
  • Description6
  • Description6
  • Description6
  • Description1
  • Description1
  • Description2
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description14
  • Description3
  • Description3
  • Description4
  • Description2
  • Description1
  • Description2
  • Description2
  • Description4
  • Description1
  • Description1
  • Description2
  • Description1
  • Description1
  • Description4
  • Description5
  • Description1
  • Description3
  • Description1
  • Description1
  • Description1
  • Description1
  • Description4
  • Description3
  • Description3
  • Description2
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description1
  • Description5
  • Description1

Images

Classifications

    • C—CHEMISTRY; METALLURGY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/02—Preparation of sulfur; Purification
    • 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
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • 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
    • B01D53/04—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 adsorption, e.g. preparative gas chromatography with stationary adsorbents
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • 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
    • B01D53/04—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 adsorption, e.g. preparative gas chromatography with stationary adsorbents
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • 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
    • B01D53/225—Multiple stage diffusion
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • 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
    • B01D53/228—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 diffusion characterised by specific membranes
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01D—SEPARATION
    • B01D53/22—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 diffusion
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01J19/00—Chemical, physical or physico-chemical processes in general; Their relevant apparatus
    • C07—ORGANIC CHEMISTRY
    • C07C7/00—Purification; Separation; Use of additives
    • C07—ORGANIC CHEMISTRY
    • C07C7/00—Purification; Separation; Use of additives
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D2257/00—Components to be removed
    • B01D2257/304—Hydrogen sulfide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01D—SEPARATION
    • B01D2257/50—Carbon oxides
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D2257/00—Components to be removed
    • B01D2257/702—Hydrocarbons
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01D—SEPARATION
    • B01D2257/70—Organic compounds not provided for in groups B01D2257/00 - B01D2257/602
    • B01D2257/7027—Aromatic hydrocarbons
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J2219/24—Stationary reactors without moving elements inside
    • 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
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C10/08—Capture by adsorption
    • 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
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C10/10—Capture by membranes or diffusion
    • 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
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/10—General improvement of production processes causing greenhouse gases [GHG] emissions
    • Y02P20/151—Reduction of greenhouse gas [GHG] emissions
    • This application claims priority to U.S. provisional application Ser. No. 61/980,089, filed Apr. 16, 2014, which is incorporated herein by reference in its entirety.

      FIELD OF THE INVENTION

      This invention relates to a system and method for treating acid gas streams. More specifically, this invention provides a system and method for treating acid gas streams with low mole percent hydrogen sulfide. More specifically, this invention provides a system and method for treating acid gas streams with low mole percent hydrogen sulfide and BTEX contaminants.

      BACKGROUND OF THE INVENTION

      A Claus unit is the primary processing system for recovering sulfur in a form of elemental sulfur from an acid gas stream containing hydrogen sulfide. Hydrogen sulfide gas occurs naturally in natural gas or is formed as a by-product in some gas processing systems. Hydrogen sulfide is highly toxic and requires removal and treatment from the gas stream. The need to efficiently process hydrogen sulfide and other sulfur containing compounds is important in reducing emissions to meet increasingly stringent fuel regulations and growing environmental concerns. Elemental sulfur is the ultimate state of recovery from sulfur containing species.

      In a Claus unit, an acid gas feed stream containing hydrogen sulfide and a source of oxygen, such as air, are fed to a furnace. Acid gas feed streams have a wide range of compositions. Many acid gas feed streams originate from solvent absorption processes, such as amine absorption.

      The absorption processes extract hydrogen sulfide from the by-product gases of petroleum refining, natural gas processing, and other industrial processes. Alternately, the acid gas feed stream can come from a sour water stripper unit.

      Once fed to the furnace, the hydrogen sulfide undergoes partial combustion to form sulfur, sulfur dioxide, and water. To ensure efficient performance of the Claus reaction, the furnace temperature profile is maintained in the range of 850-1,200° C. To ensure full combustion of the contaminants, the temperature needs to be above 950° C. The temperature reached depends upon the other components present in the feed such as carbon dioxide (CO2), water (H2O), hydrocarbons, and other sulfur containing compounds. Combustible gases tend to increase temperature by means of combustion and inert gases tend to decrease temperature by means of dilution. Temperature is an important process parameter, because the conversion of hydrogen sulfide to sulfur is a function of temperature, with pressure playing a smaller role. The residence time in the furnace is typically on the order of 0.5 second.

      The ratio of combustion products depends on the amount of oxygen available in the furnace. Other products formed in the furnace can include hydrogen, carbonyl sulfide, and carbon disulfide. The furnace also breaks down contaminants present in the acid gas stream, such as mercaptans.

      The reaction products are fed to a first condenser, in which elemental sulfur condenses, is separated, and is collected in a sulfur pit, and the gaseous products are reheated and fed to a catalytic converter. The catalytic converter is maintained at an average temperature of about 305° C. The temperature is limited by the need to limit the exit temperature in order to avoid catalytic bed damages. In the catalytic converter, hydrogen sulfide reacts with sulfur dioxide in the presence of a catalyst and forms elemental sulfur and water. The products from the catalytic converter are fed again to a condenser in which elemental sulfur condenses and is collected in the sulfur pit. At the end of the process, an incinerator is included.

      The heating, catalytic, and condensing stages can be repeated. In a conventional Claus unit, the stages are repeated a maximum of three times, with conversion of 96-98% of the hydrogen sulfide gas, depending on the feed composition. In a modified Claus unit, a tail gas treatment unit is included at the end of the process, between the final catalytic converter and the incinerator. In configurations with a tail gas treatment unit, the heating, catalytic, and condensing stages are usually only repeated twice. Modified Claus units with a tail gas treatment unit can reach up to 99.9% conversion of hydrogen sulfide into elemental sulfur. The tail gas treatment unit minimizes sulfur dioxide emissions from the incinerator.

      To increase overall energy efficiency, heat capture processes can be combined with the Claus unit, such as steam generation in a waste heat boiler and the condensers.

      Maintaining the temperature in the furnace is important to ensure the reaction to elemental sulfur and the destruction of other contaminants. As noted above, the furnace temperature is affected by the composition of the feed stream and significantly by the concentration of hydrogen sulfide in the feed stream. When the concentration of hydrogen sulfide in the acid gas stream is below about 55% by volume, the temperature profile in the furnace is reduced. The concentration of the hydrogen sulfide is affected by the amount of contaminants present in the acid gas. The type and amount of contaminants are affected by the source that generated the acid gas, and by the processing steps that produced the acid gas for processing in the Claus unit.

      Contaminants in the feed stream include hydrocarbons. Hydrocarbons pose several problems for a Claus unit. First, it is not clear that hydrocarbons will fully combust because the C—H bond is generally stronger than the S—H bond, thus some hydrocarbons get carried through the furnace to the catalytic units. Second, the hydrocarbons have the potential to contribute to competing side reactions to produce carbon monoxide (CO), carbon disulfide (CS2), carbonyl sulfide (COS), and elemental carbon. Third, for some hydrocarbon combustion processes, such as those involving benzene, toluene, ethyl benzene, or xylene (BTEX or BTX), the furnace must be maintained at a high temperature. If the furnace temperature is too low due to a low concentration of hydrogen sulfide, the temperature may not be sufficient for BTEX degradation reactions to occur. BTX removal is important because BTX has a plugging effect on the catalyst in the catalytic converters. Catalyst poisoning from carbon compounds in the catalytic beds results in a loss of activity and high pressure drop requiring frequent catalyst rejuvenation and replacement.

      Currently, several processes exist for addressing these concerns, but they all suffer from drawbacks. Acid gas bypass or split flow is used when the concentration of hydrogen sulfide is low in the feed stream. In a split flow operation, part of the stream is sent to the furnace of the Claus unit while the remaining portion of the stream is sent directly to the catalytic converters. Split flow suffers two drawbacks. First, there is an upper limit of two-thirds of the feed gas for bypass, requiring the furnace to operate under reducing conditions. Second, the increased presence of contaminants decreases the efficiency of the catalytic converters and contributes to catalytic deactivation and plugging.

      Activated carbon can be used to separate BTEX from a process stream, but requires regeneration of the activated carbon, resulting in changing feed conditions to the Claus unit during the regeneration process, or shut down of the feed all together. Amine or solvent enrichment processes use solvent absorption to enrich the hydrogen sulfide concentration. Amine enrichment suffers because it introduces liquids to the process, requires significant maintenance, and requires a significant amount of energy for the operation and for the solvent regeneration.

      Oxygen or air enrichment may enhance the flame temperature in the Claus unit, but requires expenditures for additional oxygen and oxygen recovery units. Natural Gas injection to the furnace can also enhance the temperature, but may increase the amount of contaminants entering the feed and components for potential competing side reactions and can increase the size of Claus unit. Methods of pre-heating the feed gas to ensure the temperature in the furnace require additional energy consumption adding substantially to the cost.

      Therefore, a process which enriches the concentration of hydrogen sulfide in the acid gas stream and removes contaminants without requiring excessive amounts of energy, equipment and materials, or process shutdown is desired. Preferably, such a process, would maintain the overall sulfur capacity of the Claus unit, while increasing the overall sulfur recovery efficiency due to eliminated or reduced contaminants.

      SUMMARY OF THE INVENTION

      This invention relates to a system and method for treating acid gas streams. More specifically, this invention provides a system and method for treating acid gas streams with low mole percent hydrogen sulfide. More specifically, this invention provides a system and method for treating acid gas streams with low mole percent hydrogen sulfide and BTEX contaminants.

      In one aspect of the present invention, an enrichment apparatus for enriching a hydrogen sulfide concentration in an acid gas stream to create a hydrogen sulfide rich stream for feed to a Claus unit is provided. The enrichment apparatus includes a hydrocarbon selective separation unit, the hydrocarbon selective separation unit operable to separate the acid gas stream into a hydrocarbon rich stream and a purified acid gas stream, wherein the acid gas stream includes hydrogen sulfide, carbon dioxide, and hydrocarbons. The enrichment apparatus also includes a hydrogen sulfide selective separation unit in fluid communication with the hydrocarbon selective separation unit, the hydrogen sulfide selective separation unit operable to separate the purified acid gas stream to create the hydrogen sulfide rich stream and a hydrogen sulfide lean stream, the hydrogen sulfide rich stream having a concentration of hydrogen sulfide. The enrichment apparatus further includes the Claus unit in fluid communication with the hydrogen sulfide selective separation unit, the Claus unit operable to recover elemental sulfur from the hydrogen sulfide rich stream.

      In certain aspects of the present invention, the enrichment apparatus further includes a carbon dioxide selective separation unit in fluid communication with the hydrogen sulfide selective separation unit, the carbon dioxide selective separation unit operable to separate the hydrogen sulfide rich stream to create a carbon dioxide rich permeate and a hydrogen sulfide rich retentate, the hydrogen sulfide rich retentate having a concentration of hydrogen sulfide. In certain aspects of the present invention, the hydrogen sulfide selective separation unit is selected from the group consisting of polyphosphazene type polymer membranes, polyether-polyamide copolymer membranes, ionic liquid membranes, ionic liquid membrane contactors, and combinations thereof. In certain aspects of the present invention, the carbon dioxide selective separation unit is selected from the group consisting of an amorphous fluoroplastic membrane, an amorphous perfluoropolymer membrane, a random fluorocopolymer membrane, a perfluorinated copolymer membrane, and combinations thereof. In certain aspects of the present invention, the hydrocarbon selective separation unit comprises a polydimethylsiloxane (PDMS) type rubbery polymer membrane. In certain aspects of the present invention, the acid gas stream further comprises contaminants selected from the group consisting of mercaptans, thiols, carbonyl sulfide, carbon disulfide, and combinations thereof. In certain aspects of the invention, non-sulfur containing contaminants can also be present. In certain aspects of the present invention, the hydrocarbon rich stream comprises benzene, toluene, ethyl benzene, and xylene. In certain aspects of the present invention, the hydrogen sulfide concentration in the acid gas stream is between 15% to 55% by volume. In certain aspects of the present invention, the concentration of hydrogen sulfide in the hydrogen sulfide rich stream is greater than 55% by volume.

      In a second aspect of the present invention, a process for enriching a hydrogen sulfide concentration in an acid gas stream to create a hydrogen sulfide rich stream for feeding to a Claus unit is provided. The process including the steps of feeding the acid gas stream to a hydrocarbon selective separation unit, the acid gas stream includes hydrogen sulfide, carbon dioxide, and hydrocarbons, separating the acid gas stream in the hydrocarbon selective separation unit to create a hydrocarbon rich stream and a purified acid gas stream, feeding the purified acid gas stream to a hydrogen sulfide selective separation unit fluidly connected to the hydrocarbon selective separation unit, the hydrogen sulfide selective separation unit operable to separate the purified acid gas stream, and separating the purified acid gas stream in the hydrogen sulfide selective separation unit to create the hydrogen sulfide rich stream and a hydrogen sulfide lean stream, the hydrogen sulfide rich stream having a concentration of hydrogen sulfide, and feeding the hydrogen sulfide rich stream to a furnace of the Claus unit, the Claus unit operable to separate elemental sulfur from the hydrogen sulfide rich stream to create an elemental sulfur stream and a waste gas stream.

      In certain aspects of the present invention, the process further includes the steps of feeding the hydrogen sulfide rich stream to a carbon dioxide selective separation unit in fluid communication with the hydrogen sulfide selective separation unit, the carbon dioxide selective separation unit operable to separate the hydrogen sulfide rich stream, separating the hydrogen sulfide rich stream to create a carbon dioxide rich permeate and a hydrogen sulfide rich retentate, the hydrogen sulfide rich retentate having a concentration of hydrogen sulfide, and feeding the hydrogen sulfide rich retentate to the furnace of the Claus unit. In certain aspects of the present invention, the hydrogen sulfide selective separation unit is selected from the group consisting of polyphosphazene type polymer membranes, polyether-polyamide copolymer membranes, ionic liquid membranes, ionic liquid membrane contactors, and combinations thereof. In certain aspects of the present invention, the carbon dioxide selective separation unit is selected from the group consisting of an amorphous fluoroplastic membrane, an amorphous perfluoropolymer membrane, a random fluorocopolymer membrane, a perfluorinated copolymer membrane, and combinations thereof. In certain aspects of the present invention, the hydrocarbon selective separation unit comprises a rubbery membrane. In certain aspects of the present invention, the acid gas stream further comprises contaminants selected from the group consisting of mercaptans, thiols, carbonyl sulfide, carbon disulfide, and combinations thereof. In certain aspects of the present invention, the hydrocarbon rich stream comprises benzene, toluene, ethyl benzene, and xylene. In certain aspects of the present invention, the hydrogen sulfide concentration in the acid gas stream is between 15% to 55% by volume. In certain aspects of the present invention, the concentration of hydrogen sulfide in the hydrogen sulfide rich stream is greater than 55% by volume.

      In a third aspect of the present invention, an enrichment apparatus for enriching a hydrogen sulfide concentration in an acid gas stream to create a hydrogen sulfide rich stream for feed to a Claus unit is provided. The enrichment apparatus includes a hydrocarbon selective separation unit, the hydrocarbon selective separation unit operable to separate the acid gas stream into a hydrocarbon rich stream and a purified acid gas stream, wherein the acid gas stream includes hydrogen sulfide, carbon dioxide, and hydrocarbons. The enrichment apparatus further includes a carbon dioxide selective separation unit in fluid communication with the hydrocarbon selective separation unit, the carbon dioxide selective separation unit operable to separate the purified acid gas stream to create a carbon dioxide rich stream and a carbon dioxide lean stream, the carbon dioxide lean stream having a concentration of hydrogen sulfide, and the Claus unit in fluid communication with the carbon dioxide selective separation unit, the Claus unit operable to recover sulfur from the carbon dioxide lean stream.

      In certain aspects of the present invention, the enrichment apparatus further includes a hydrogen sulfide selective separation unit in fluid communication with the carbon dioxide separation unit, the hydrogen sulfide selective separation unit operable to separate the carbon dioxide rich stream to create a hydrogen sulfide rich permeate and a carbon dioxide rich retentate, the hydrogen sulfide rich permeate having a concentration of hydrogen sulfide.

      BRIEF DESCRIPTION OF THE DRAWINGS

      These and other features, aspects, and advantages of the present invention will become better understood with regard to the following descriptions, claims, and accompanying drawings. It is to be noted, however, that the drawings illustrate only several embodiments of the invention and are therefore not to be considered limiting of the invention's scope as it can admit to other equally effective embodiments.

      FIG. 1 is a process flow diagram of the present invention.

      FIG. 2 is a process flow diagram of one embodiment of enrichment apparatus 100.

      FIG. 3 is a process flow diagram of an embodiment of enrichment apparatus 100.

      FIG. 4 is a process flow diagram of an embodiment of enrichment apparatus 100.

      FIG. 5 is a process flow diagram of an embodiment of enrichment apparatus 100.

      FIG. 6 is a process flow diagram of an embodiment of enrichment apparatus 100.

      FIG. 7 is a process flow diagram of an embodiment of enrichment apparatus 100.

      DETAILED DESCRIPTION OF THE INVENTION

      While the invention will be described with several embodiments, it is understood that one of ordinary skill in the relevant art will appreciate that many examples, variations and alterations to the apparatus and methods described herein are within the scope and spirit of the invention. Accordingly, the exemplary embodiments of the invention described herein are set forth without any loss of generality, and without imposing limitations, on the claimed invention.

      Referring to FIG. 1, the process flow diagram for enrichment apparatus 100 for enriching the hydrogen sulfide concentration in acid gas stream 10 to create hydrogen sulfide rich stream 18 for feed to Claus unit 200 is provided. Acid gas stream 10 is fed to enrichment apparatus 100. Acid gas stream 10 is any gas stream containing hydrogen sulfide (H2S). In at least one embodiment of the present invention, acid gas stream 10 is from the outlet of an amine unit. In at least one embodiment of the present invention, acid gas stream 10 contains less than about 55% by volume H2S. In some embodiments of the present invention, acid gas stream 10 contains between about 15% and about 55% by volume H2S, alternately between about 15% and about 40% by volume H2S, alternately between about 15% and about 30% by volume H2S, alternately between about 15% and about 25% by volume H2S, alternately between about 15% and about 20% by volume H2S, and alternately between about 25% and about 40% by volume H2S. In at least one embodiment of the present invention, acid gas stream 10 contains greater than 15% by volume H2S. Acid gas stream 10 contains H2S, carbon dioxide (CO2), hydrocarbons, and other contaminants. In at least one embodiment of the present invention, the hydrocarbons present in acid gas stream 10 include benzene, toluene, ethyl benzene, and xylene, collectively referred to as BTEX or BTX. As used herein, BTEX means that a combination of benzene, toluene, ethyl benzene, and xylene are present in a stream, including the absence of one or more of the components. In some embodiments of the present invention, the hydrocarbons present in acid gas stream 10 include alkanes, alkenes, olefins, and BTEX. In some embodiments of the present invention, the contaminants present in acid gas stream 10 include mercaptans, thiols, carbonyl sulfide, carbon disulfide, and combinations thereof.

      Enrichment apparatus 100 separates the components of acid gas stream 10 creating a stream rich in CO2, a stream rich in hydrocarbons, and a stream rich in H2S. In at least one embodiment of the present invention, the stream rich in CO2 is hydrogen sulfide lean stream 16, the stream rich in hydrocarbons is hydrocarbon rich stream 14, and the stream rich in H2S is hydrogen sulfide rich stream 18. Hydrogen sulfide lean stream 16 contains CO2 along with H2S and other components. Hydrogen sulfide lean stream 16 contains between about 50% and about 99% by volume CO2, alternately between about 75% and about 99% by volume CO2, alternately greater than about 96% by volume CO2. In at least one embodiment of the present invention, hydrogen sulfide lean stream 16 is in the absence of BTEX components. Hydrogen sulfide lean stream 16 is fed to the catalytic converters (not shown) of catalytic stage 220 of Claus unit 200. Feeding hydrogen sulfide lean stream 16 directly to the catalytic converters provides a dilution gas to the catalytic converters and removes a source of carbon for formation of carbonyl sulfide (COS) and carbon disulfide (CS2) in the furnace. The catalytic converter of Claus unit 200 to which hydrogen sulfide lean stream 16 is fed is a function of the concentration of hydrogen sulfide in lean stream 16 or the need for dilution within that catalytic converter.

      Editions eni pdf

      Hydrocarbon rich stream 14 includes an amount of the BTEX present in acid gas stream 10. Hydrocarbon rich stream 14 includes other hydrocarbons, such as C2+ alkanes, alkenes, olefins, and aromatics, H2S, CO2, and other contaminants present in acid gas stream 10. Hydrocarbon rich stream 14 is fed to furnace 210 of Claus unit 200. In some embodiments of the present invention, hydrocarbon rich stream 14 is sent to an alternate disposal operation, such as an incinerator. In some embodiments, hydrocarbon rich stream 14 is sent to a BTX recovery process (not shown) to recover additional hydrocarbons. A BTX recovery process is any process capable of separating BTEX and other hydrocarbons from a process stream. Exemplary processing units for hydrocarbon recovery in a BTX recovery process include condensation, adsorption, and absorption units. The recovered BTEX can be treated further, can be processed for sale, or can be sent to storage.

      Hydrogen sulfide rich stream 18 is fed to furnace 210 of Claus unit 200. Hydrogen sulfide rich stream 18 contains an amount of the H2S present in acid gas stream 10, along with CO2, and hydrocarbons. Hydrogen sulfide rich stream 18 has a greater concentration of H2S as compared to acid gas stream 10. In some embodiments of the present invention, the H2S concentration in hydrogen sulfide rich stream 18 is greater than about 25% by volume, alternately greater than about 30% by volume, alternately greater than about 35% by volume, alternately greater than about 40% by volume, alternately greater than about 45% by volume, alternately greater than about 50% by volume, alternately greater than about 55% by volume, alternately greater than about 56% by volume, alternately greater than about 57% by volume, alternately greater than about 58% by volume, and alternately greater than about 60% by volume.

      Claus unit 200 uses feed air 60 in furnace 210 to process hydrocarbon rich stream 14 and hydrogen sulfide rich stream 18. In some embodiments of the present invention, hydrocarbon rich stream 14 and hydrogen sulfide rich stream 18 can be separately introduced to furnace 210 of Claus unit 200. In some embodiments of the present invention, hydrocarbon rich stream 14 and hydrogen sulfide rich stream 18 can be combined upstream of furnace 210 of Claus unit 200, such that one combined stream is fed to Claus unit 200. Claus unit 200 produces waste gas stream 70 and elemental sulfur stream 80.

      One of skill in the art will appreciate that Claus units are well-known processing systems and the system equipment associated with Claus units can be designed based on the needs and layout of the process site. The present invention can be used with an existing Claus unit or as part of a retrofitted Claus unit, and thus the present invention contemplates that Claus unit 200 contains similar basic elements known to one of skill in the art.

      In some embodiments of the present invention, hydrocarbon rich stream 14 and hydrogen sulfide rich stream 18 can be combined (not shown) before being fed to furnace 210. In embodiments where the streams are combined, the concentration of hydrogen sulfide in the combined stream is greater than about is greater than about 25% by volume, alternately greater than about 30% by volume, alternately greater than about 35% by volume, alternately greater than about 40% by volume, alternately greater than about 45% by volume, alternately greater than about 50% by volume, alternately greater than about 55% by volume, alternately greater than about 56% by volume, alternately greater than about 57% by volume, alternately greater than about 58% by volume, and alternately greater than about 60% by volume.

      In at least one embodiment of the present invention, hydrocarbon rich stream 14 can be fed to a section of furnace 210 having a temperature greater than 950° C., alternately greater than 1000° C., and alternately greater than 1050° C. According to embodiments of the present invention, enrichment apparatus 100 concentrates BTEX and other contaminants in hydrocarbon rich stream 14, concentrates hydrogen sulfide in hydrogen sulfide rich stream 18, and concentrates carbon dioxide in hydrogen sulfide lean stream 16. Concentrating the components in the various streams enables directing the feeds to the appropriate place in the Claus unit for destruction or recovery of components, as the case may be. By way of example, concentrating hydrocarbons and other contaminants in hydrocarbon rich stream 14 allows the stream to be fed directly to a section of furnace 210 with a temperature greater than 950° C. and maintaining a section of furnace 210 at a temperature greater than 950° C. is facilitated because of the concentrated hydrogen sulfide in the hydrogen sulfide rich stream 18.

      Referring to FIG. 2, an embodiment of enrichment apparatus 100 is provided. Hydrocarbon selective separation unit 102 separates acid gas stream 10 into hydrocarbon rich stream 14, and purified acid gas stream 12. In at least one embodiment of the present invention, hydrocarbon selective separation unit 102 is a rubbery membrane. As used herein, “rubbery” refers to a polymer having a Young's modulus in the range of 105 to 107 Pa (106 to 108 dyn/cm2). In at least one embodiment of the present invention, hydrocarbon selective separation unit 102 is a silicone rubber polydimethylsiloxane (PDMS) type rubbery polymer. In at least one embodiment of the present invention, the permeability of the rubbery membrane of carbon dioxide is 3,200 Barrer and the selectivity of toluene to carbon dioxide is 456. In at least one embodiment of the present invention, hydrocarbon selective separation unit 102 is a pressure swing adsorption (PSA) process. In at least one embodiment, the PSA process uses activated carbon as the adsorbent. In at least one embodiment of the present invention, hydrocarbon selective separation unit 102 is a temperature swing adsorption (TSA) process. In at least one embodiment of the present invention, the TSA process uses activated carbon as the adsorbent. In at least one embodiment of the present invention, hydrocarbon selective separation unit 102 is a condensing absorption process. Hydrocarbon rich stream 14 is fed to Claus unit 200 as described with reference to FIG. 1.

      Purified acid gas stream 12 contains most of the H2S and CO2 present in acid gas stream 10. Purified acid gas stream 12 is fed to hydrogen sulfide selective separation unit 106. Hydrogen sulfide selective separation unit 106 separates purified acid gas stream 12 into hydrogen sulfide rich stream 18 as the permeate stream and hydrogen sulfide lean stream 16 as the retentate stream.

      Hydrogen sulfide selective separation unit 106 is any membrane capable of separating hydrogen sulfide from acid gas stream 10. Exemplary membranes include membranes based upon polyphosphazenes, polyether-polyamide copolymers, ionic liquid membranes, and ionic liquid membrane contactors.

      Ionic liquid membranes are membranes that are doped with liquid ionic compounds. Liquid ionic compounds have a preferential solubility for hydrogen sulfide. Liquid ionic compounds have the structural formula:

      where R1 is selected from the group consisting of —H, —CH2—CH2—CF3, —CH2—CH2—CH2F, —CH3, —CH2—CH3, propyl, pentyl, hexyl, heptyl, octyl, C9-C18 alkyl, alkenyl, and cycloalkyl; R2 is selected from the group consisting of —H, —CH2—CH2—CF3, —CH2—CH2—CH2F, —CH3, —CH2—CH3, propyl, pentyl, hexyl, heptyl, octyl, C9-C18 alkyl, alkenyl, and cycloalkyl; and X is selected from the group consisting of BF4, PF6, (CF3SO2)N, CF3(CO)O.

      In at least one embodiment of the present invention, the liquid ionic compound of Formula I is where R1 is selected from hydrogen or a C1-C18 alkyl group; R2 is selected from a C1-C18 alkyl group, a C2-C6 alkenyl, a C3-C6 cycloalkyl, a C3-C8 cycloalkenyl, an aryl, a substituted aryl, aryl (C1-C4 alkyl), or a substituted aryl (C1-C4 alkyl); and X is an anion selected from the group consisting of hydroxide, chloride, bromide, iodide, borate, tetrafluoroborate, cuprate, Cu(I)Cl2 anion, phosphate, hexafluorophosphate, hexafluoroantimonate, perchlorate, nitrite, nitrate, sulfate, a carboxylate, a sulfonate, a sulfonimide, and a phosphonate.

      The term “aryl” refers to a cyclic aromatic radical, optionally containing one or more heteroatoms, such as oxygen, nitrogen, and sulfur, such as phenyl, naphthyl, pyridyl, and the like.

      The term “substituted aryl” refers to aryl as described herein, where from one to about three hydrogen atoms on the aryl are substituted with monovalent groups, such as halo, alkyl, haloalkyl, alkoxy, haloalkoxy, alkylthio, haloalkylthio, alkylamino, alkanoyl, cyano, nitro, and the like.

      Carboxylates useful as anions include alkylcarboxylates, such as acetate, substituted alkylcarboxylates, such as lactate, and haloalkylcarboxylates, such as trifluoroacetate, and the like.

      Sulfonates useful as anions include alkylsulfonates, such as mesylate, haloalkylsulfonates, such as triflate and nonaflate, and arylsulfonates, such as tosylate and mesitylate, and the like.

      Sulfonimides useful as anions may be mono- or disubstituted sulfonimides, such as methanesulfonimide and bis-ethanesulfonimide, optionally halogenated sulfonimides, such as bis-trifluoromethanesulfonimide, arylsulfonimides, such as bis-(4-methoxybenzene)sulfonamide, and the like.

      In a preferred embodiment, hydrogen sulfide selective separation unit 106 includes an ionic liquid membrane impregnated with one or more fluorinated liquid ionic compounds having non-nucleophilic anions.

      Exemplary liquid ionic compounds useful for the present invention include imidazolium salts, pyrazolium salts, oxazolium salts, thiazolium salts, triazolium salts, pyridinium salts, pyridazinium salts, pyrimidinium salts, and pyrazinium salts. Illustrative of such compounds are 1-butyl-3-methylimidazolium tetrafluoroborate, 1-ethyl-3-methylimidazolium tetrafluoroborate, 1-butyl-3-methylimidazolium hexafluorophosphate, 1-octyl-3-methylimidazolium hexafluorophosphate, 1-octyl-3-methylimidazolium tetrafluoroborate, 1-butyl-3-methylimidazolium triflate, 1-butyl-3-methylimidazolium trifluoroacetate, and 1-butyl-3-methylimidazolium bis(trifluoromethanesulfonimide), 1-trifluooproyl-3-methylimidazolium bis(trifluoromethanesulfonimide), 1-trifluooproyl-3-methylimidazolium hexafluorophosphate, 1-trifluooproyl-3-methylimidazolium tetrafluoroborate, 1-trifluooproyl-3-methylimidazolium trifluoroacetate and the like. In a preferred embodiment, the fluorinated liquid ionic compound for use in the ionic liquid membrane is 1-butyl-3-methylimidazolium tetrafluoroborate.

      One of skill in the art will appreciate that the size, permeability, and selectivity of hydrogen sulfide selective separation unit 106 are design features based on the requirements of the system. The type of membrane selected is in consideration of the desired permeability and selectivity of the membrane and the acid gas feed composition. Membranes suitable for use as hydrogen sulfide selective separation unit 106 are membranes with a H2S/CO2 selectivity from between about 3.0 to about 9.5, alternately between about 3.0 to about 7.0, alternately between about 3.0 to about 5.0.

      Hydrogen sulfide rich stream 18 and hydrogen sulfide lean stream 16 are sent to Claus unit 200 as described with reference to FIG. 1.

      Referring to FIG. 3, an alternate embodiment of enrichment apparatus 100 is provided. With reference to those elements previously described above, purified acid gas stream 12 is fed to carbon dioxide selective separation unit 104. Carbon dioxide selective separation unit 104 separates purified acid gas stream 12 to create carbon dioxide rich stream 30 in the permeate and carbon dioxide lean stream 32 in the retentate. Carbon dioxide lean stream 32 contains an amount of the H2S present in acid gas stream 10, along with CO2, and hydrocarbons. Carbon dioxide lean stream 32 is fed to the furnace of Claus unit 200. Without being bound to one particular theory, feeding carbon dioxide lean stream 32 and hydrocarbon rich stream 14 to the furnace separately allows mixing of the streams with the flame, which increases combustion and maximizes contaminant destruction. In some embodiments, carbon dioxide lean stream 32 is mixed with hydrocarbon rich stream 14 upstream of the furnace, so that one stream is fed to the furnace. In at least one embodiment of the present invention, the concentration of H2S in carbon dioxide lean stream 32 is greater than 55% by volume.

      Carbon dioxide selective separation unit 104 can be any type of separation membrane capable of separating carbon dioxide from acid gas stream 10. Exemplary membranes of carbon dioxide selective separation unit 104 include amorphous fluoroplastic membranes, amorphous perfluoropolymer membranes, and random fluorocopolymer membranes. In at least one embodiment of the present invention, carbon dioxide selective separation unit 104 is a glassy amorphous fluoroplastic membrane, specifically a 2,2 bis(trifluoro-methyl)-4,5 difluoro-1,3 dioxole membrane. In at least one embodiment of the present invention, carbon dioxide selective separation unit 104 is a perfluoropolymer membrane, specifically a perfluorocopolymer of tetrafluoroethylene and perfluoromethoxydioxole. In at least one embodiment of the present invention, carbon dioxide selective separation unit 104 is a rubbery random fluorocoplymer membrane of tetrafluoroethylene and perfluoromethyl vinyl ether. Membranes suitable for use as carbon dioxide selective separation unit 104 are membranes with a CO2/H2S selectivity from between about 3.0 to about 8.0.

      Carbon dioxide rich stream 30 contains CO2, H2S, hydrocarbons, and other contaminants. In at least one embodiment of the present invention, the concentration of CO2 present in carbon dioxide rich stream 30 is greater than 70% by volume, alternately greater than 75% by volume, alternately greater than 80% by volume, alternately greater than 85% by volume, alternately greater than 90%, alternately greater than 95% by volume. Carbon dioxide rich stream 30 is fed to the catalytic converters of Claus unit 200. Feeding carbon dioxide rich stream 30 directly to the catalytic converters provides a dilution gas to the catalytic converters and removes a source of carbon for formation of COS and CS2 in the furnace. The catalytic converter of Claus unit 200 to which carbon dioxide rich stream 30 is fed is a function of the concentration of carbon dioxide in carbon dioxide rich stream 30 or the need for dilution within that catalytic converter.

      Referring to FIG. 4, an alternate embodiment of enrichment apparatus 100 is provided. With reference to those elements previously described above, purified acid gas stream 12 is fed to hydrogen sulfide selective separation unit 106. Hydrogen sulfide selective separation unit 106 separates purified acid gas stream 12 into hydrogen sulfide rich stream 18 in the permeate and hydrogen sulfide lean stream 16 in the retentate. Hydrogen sulfide rich stream 18 is fed to second hydrogen sulfide selective separation unit 108. Second hydrogen sulfide selective separation unit 108 separates hydrogen sulfide rich stream 18 into enriched hydrogen sulfide stream 22 in the permeate and carbon dioxide retentate 20 in the retentate. Enriched hydrogen sulfide stream 22 and hydrocarbon rich stream 14 are fed to the furnace of Claus Unit 200. Hydrogen sulfide lean stream 16 and carbon dioxide retentate 20 are fed to the catalytic converters of Claus Unit 200.

      Referring to FIG. 5, an alternate embodiment of enrichment apparatus 100 is provided. With reference to those elements previously described above, enriched hydrogen sulfide stream 22 and hydrocarbon rich stream 14 are mixed and fed to the furnace of Claus unit 200 as mixed furnace feed stream 24. Hydrogen sulfide lean stream 16 and carbon dioxide retentate 20 are mixed and fed to the catalytic converters of Claus unit 200 as mixed catalytic converter feed stream 26.

      Referring to FIG. 6, an alternate embodiment of enrichment apparatus 100 is provided. With reference to those elements previously described above, purified acid gas stream 12 is fed to carbon dioxide selective separation unit 104. Carbon dioxide selective separation unit 104 separates purified acid gas stream 12 into carbon dioxide rich stream 30 in the permeate and carbon dioxide lean stream 32 in the retentate. Carbon dioxide rich stream 30 is fed to hydrogen sulfide selective separation unit 106. Hydrogen sulfide selective separation unit 106 separates carbon dioxide rich stream 30 into hydrogen sulfide rich permeate 34 in the permeate and carbon dioxide rich retentate 36 in the retentate. Carbon dioxide lean stream 32, hydrogen sulfide rich permeate 34, and hydrocarbon rich stream 14 are fed to the furnace of Claus Unit 200. Carbon dioxide rich retentate 36 is fed to the catalytic converters of Claus Unit 200.

      Referring to FIG. 7, an alternate embodiment of enrichment apparatus 100 is provided. With reference to those elements previously described above, purified acid gas stream 12 is fed to hydrogen sulfide selective separation unit 106. Hydrogen sulfide selective separation unit 106 separates purified acid gas stream 12 into hydrogen sulfide rich stream 18 in the permeate and hydrogen sulfide lean stream 16 in the retentate. Hydrogen sulfide rich stream 18 is fed to carbon dioxide selective separation unit 104. Carbon dioxide selective separation unit 104 separates hydrogen sulfide rich stream 18 into carbon dioxide rich permeate 38 in the permeate and hydrogen sulfide rich retentate 40 in the retentate. Hydrocarbon rich stream 14 and hydrogen sulfide rich retentate 40 are fed to the furnace of Claus Unit 200. Hydrogen sulfide lean stream 16 and carbon dioxide rich permeate 38 are fed to the catalytic converters of Claus Unit 200.

      The total number of hydrogen sulfide selective separation units and carbon dioxide selective separation units (hereinafter “separation units”) and the configuration of the separation units, including the flow path of the permeate and retentate streams, depends on the composition of acid gas stream 10, and the target concentration of CO2 or H2S in the feed stream to the furnace or the feed stream to catalytic converters. In at least one embodiment of the present invention, more than two separation units are arranged in series.

      Editions

      The membranes of the present invention are in the absence of methanol. In at least one embodiment of the present invention, hydrogen sulfide selective separation unit 106 is in the absence of a selective solvent absorption process. In at least one embodiment of the present invention, the membranes of the present invention are in the absence of regeneration steps as part of steady state operation.

      EXAMPLES

      Throughout the examples, references will be made to types of membranes for use in the various separation units. Table 1 includes a list of selected properties for exemplary membranes useful in the separation units of the present invention. The data in Table 1 was collected from independently developed data. Examples of polyether-polyamide copolymers are represented by membranes made with Pebax® polymers. Examples of amorphous fluoroplastics are represented by membranes made using DuPont™ Teflon® resins. Polyphosphazene 1, 2, and 3 are copolymers with 2-(2-methoxyethoxy)ethanol (MEE), 4-methoxyphenol and 2-allyphenol.

      TABLE 1
      Properties of exemplary membranes
      CO2 per-H2S per-
      meabilitymeabilityCO2/H2SH2S/CO2
      (Barrer)(Barrer)SelectivitySelectivity
      PDMS3,200—0.631.6
      Pebax ® 165769—0.273.7
      Pebax ® 1074122—0.224.6
      Pebax ® 4011140310.224.6
      Pebax ® 4011 (pure gas1750180.10289.5
      data)
      DuPont ™ 991828—80.125
      Teflon ® AF1600580—6.80.147
      Teflon ® AF24002,300—60.17
      Polyphosphazene 17.514.10.531.89
      Polyphosphazene 2152.3587.60.263.85
      Polyphosphazene 325011300.224.6
      BMImBF4 (Ionic Liquid~6~8000.0075133
      Membrane)

      Table 2 contains the permeation constants for hydrocarbon selective separation unit 102 as used throughout the examples.

      TABLE 2
      Permeation Constants for Hydrocarbon
      Selective Separation Unit 102
      Permeation Constant
      Componentcm3/(cm2*s*psia)
      CO20.31
      H2S0.49
      BTX100.00
      C50.42
      C40.42
      Example 1

      Example 1 was simulated based on the configuration embodied in FIG. 2 and described herein. Acid gas stream 10 from an amine separation process at 37.78° C. and 29.70 psia was fed to hydrocarbon selective separation unit 102 at a rate of 248.52 MMscfd (292.66 Msm3/h). Hydrocarbon selective separation unit 102 was modeled as a PDMS type rubbery polymer membrane with an H2S/CO2 selectivity of 1.6 and BTX permeability of 100 cm3/(cm2*s*psia). See Table 2 for the permeation constants of the components. Hydrocarbon selective separation unit 102 produced hydrocarbon rich stream 14 in the permeate and purified acid gas stream 12 in the retentate. Purified acid gas stream 12 was then fed to hydrogen sulfide selective separation unit 106. The properties of hydrogen sulfide selective separation unit 106 were modeled after a Pebax® 1657 or polyphosphazene type membrane with an H2S/CO2 selectivity of 1.6 and BTX permeability of 100 cm3/(cm2*s*psia). Hydrogen sulfide selective separation unit 106 separated purified acid gas stream 12 into hydrogen sulfide rich stream 18 in the permeate and hydrogen sulfide lean stream 16 in the retentate. Hydrogen sulfide rich stream 18 and hydrocarbon rich stream 14 were fed to the furnace of Claus Unit 200. Hydrogen sulfide lean stream 16 was fed to the catalytic converters of Claus Unit 200. The streams to the furnace had a combined H2S concentration greater than 28%. The resulting concentrations of components % vol for selected streams are shown in Table 3.

      TABLE 3
      Concentration of Components in Selected Streams, by % vol.
      Furnace
      StreamStreamStream(StreamsStream
      10141814 & 18)16
      Temper-37.7837.7837.7837.7837.78
      ature (° C.)
      Flow Rate248.529.78186.43196.2152.32
      (MMscfd)
      CO20.7470.6440.7170.7140.872
      H2S0.2510.3410.2810.2840.127
      BTX0.0010.0120.0000.0010.000
      C50.0010.0010.0010.0010.001
      C40.0010.0010.0010.0010.001
      Example 2

      Referring to FIG. 2 and the simulation parameters described in Example 1, in Example 2 hydrogen sulfide selective separation unit 106 was modeled as a rubbery type membrane with a H2S/CO2 selectivity of 3.18. The permeation constants for hydrogen sulfide selective separation unit 106 for selected components are included in Table 4. Hydrocarbon rich stream 14 and hydrogen sulfide rich stream 18 were fed to the furnace of Claus unit 200. The streams had a combined H2S concentration of greater than 30%. The resulting concentrations of components by % vol for selected streams are shown in Table 5.

      TABLE 4
      Permeation Constants - Hydrogen Sulfide
      Selective Separation Unit 106
      Permeation Constant
      Componentcm3/(cm2*s*psia)
      CO20.31
      H2S0.98
      C50.42
      C40.42
      TABLE 5
      Concentration of Components in Selected Streams, by % vol.
      Furnace
      StreamStreamStreamStream(Streams
      1014181614 and 18)
      Temper-37.837.837.7837.7837.78
      ature (° C.)
      Flow Rate248.529.2186.353.02195.5
      (MMscfd)
      CO20.7470.4850.6940.9770.684
      H2S0.2510.5000.3040.0210.313
      BTX0.0010.0130.0000.0000.001
      C50.0010.0010.0010.0010.001
      C40.0010.0010.0010.0010.001
      Example 3

      Referring to FIG. 2 and the simulation parameters described in Example 1, in Example 3 hydrogen sulfide selective separation unit 106 was modeled as a Pebax® type membrane with a H2S/CO2 selectivity of 5.0. The permeation constants for hydrogen sulfide selective separation unit 106 for selected components are provided in Table 6. Hydrocarbon rich stream 14 and hydrogen sulfide rich stream 18 were fed to the furnace of Claus unit 200. The streams had a combined H2S concentration of greater than about 40%. The resulting concentrations of components for selected streams in vol % are shown in Table 7.

      TABLE 6
      Permeation Constants - Hydrogen Sulfide
      Selective Separation Unit 106
      Permeation Constant
      Componentcm3/(cm2*s*psia)
      CO20.31
      H2S1.54
      C50.42
      C40.42
      TABLE 7
      Concentration of Components in Selected Streams, by % vol.
      Furnace
      StreamStreamStreamStream(Streams
      1014181614 & 18)
      Temper-37.837.837.7837.7837.78
      ature (° C.)
      Flow Rate248.529.05135.3104.16144.34
      (MMscfd)
      CO20.7470.3800.6010.9680.587
      H2S0.2510.6060.3970.0300.410
      BTX0.0010.0130.0000.0000.001
      C50.0010.0010.0010.0010.001
      C40.0010.0010.0010.0010.001
      Example 4

      Example 4 was simulated as hydrocarbon selective separation unit 102 coupled with a one-step carbon dioxide selective separation unit 104 as shown in FIG. 3. Acid gas stream 10 at 37.78° C. and 29.70 psia was fed to hydrocarbon selective separation unit 102. Hydrocarbon selective separation unit 102 was modeled as a PDMS type rubbery polymer membrane with a H2S/CO2 selectivity of 1.6 and BTX permeability of 100 cm3/(cm2*s*psia). See Table 2 for permeation constants for hydrocarbon selective separation unit 102. Hydrocarbon selective separation unit 102 separated acid gas stream 10 into hydrocarbon rich stream 14 in the permeate and purified acid gas stream 12 in the retentate. Purified acid gas stream 12 was fed to carbon dioxide selective separation unit 104. Carbon dioxide selective separation unit 104 was modeled as a glassy type membrane with a CO2/H2S selectivity of 6. Permeation constants for carbon dioxide selective separation unit 104 for select components are provided in Table 8. Carbon dioxide selective separation unit 104 separated purified acid gas stream 12 into carbon dioxide rich stream 30 in the permeate and carbon dioxide lean stream 32 in the retentate. Carbon dioxide lean stream 32 and hydrocarbon rich stream 14 were fed to the furnace of Claus Unit 200. Carbon dioxide rich stream 30 was fed to the catalytic converters of Claus Unit 200. The streams to the furnace had a combined H2S concentration greater than 30%. The resulting concentrations of components for selected streams are shown in Table 9.

      TABLE 8
      Permeation Constants - Carbon Dioxide
      Selective Separation Unit 104
      Permeation Constant
      Componentcm3/(cm2*s*psia)
      CO21.2
      H2S0.2
      C50.2
      C40.2
      TABLE 9
      Concentration of Components in Selected Streams, by % vol.
      Furnace
      StreamStreamStreamStream(Streams
      1014303214 & 32)
      Temper-37.837.837.7837.7835.76
      ature (° C.)
      Flow Rate248.59.854.14184.6194.38
      (MMscfd)
      CO20.74690.64410.94020.69560.6931
      H2S0.25060.34110.05940.30190.3069
      BTX0.00100.01250.00000.00000.0006
      C50.00100.00120.00020.00120.0012
      C40.00100.00120.00020.00120.0012
      Example 5

      Referring to FIG. 4, a process diagram of the layout used to model Example 5 is provided. Acid gas stream 10 from an amine separation process at 37.78° C. and 29.70 psia was fed to hydrocarbon selective separation unit 102 at a rate of 248.47 MMscfd (274.23 Msm3/h). Hydrocarbon selective separation unit 102 was modeled as a PDMS type rubbery polymer membrane, with an H2S/CO2 selectivity of 1.6 and a BTX permeability of 100 cm3/(cm2*s*psia). See Table 2 for the permeation constants of selected components. Hydrocarbon selective separation unit 102 separated acid gas stream 10 into hydrocarbon rich stream 14 in the permeate and purified acid gas stream 12 in the retentate. Purified acid gas stream 12 was then sent to hydrogen sulfide selective separation unit 106. The properties of hydrogen sulfide selective separation unit 106 were modeled after a Pebax® 1657 or polyphosphazene type membrane with an H2S/CO2 selectivity of 3.99. Permeation constants for selected components in hydrogen sulfide selective separation unit 106 are contained in Table 10. Hydrogen sulfide selective separation unit 106 separated purified acid gas stream 12 into hydrogen sulfide rich stream 18 in the permeate and hydrogen sulfide lean stream 16 in the retentate. Hydrogen sulfide rich stream 18 was fed to second hydrogen sulfide selective separation unit 108. The properties of second hydrogen sulfide selective separation unit 108 were modeled after a Pebax® 1657 or polyphosphazene type membrane with an H2S/CO2 selectivity of 3.99. Permeation constants for selected components in second hydrogen sulfide selective separation unit 108 are contained in Table 10. Second hydrogen sulfide selective separation unit 108 separated hydrogen sulfide rich stream 18 into enriched hydrogen sulfide stream 22 in the permeate and carbon dioxide retentate 20 in the retentate.

      TABLE 10
      Permeation Constants - Hydrogen Sulfide Selective Separation Unit
      106 and Second Hydrogen Sulfide Selective Separation Unit 108
      Permeation Constant
      Componentcm3/(cm2*s*psia)
      CO20.31
      H2S1.23
      C50.42
      C40.42

      Enriched hydrogen sulfide stream 22 and hydrocarbon rich stream 14 were fed to the furnace of Claus Unit 200. Hydrogen sulfide lean stream 16 and carbon dioxide retentate 20 were fed to the catalytic converters of Claus Unit 200. The streams to the furnace had a combined H2S concentration greater than 55%. Table 11 shows the composition of select streams in % vol.

      TABLE 11
      Concentration of Components in Selected Streams, by % vol.
      Furnace
      StreamStreamStreamStream(Streams
      1014161814 & 22)
      Temper-37.7837.7837.7837.7839.99
      ature (° C.)
      Flow Rate248.479.1363.13176.19152.42
      (MMscfd)
      CO20.64040.31290.96590.54090.4354
      H2S0.35710.67310.03200.45710.5620
      BTX0.00050.01270.00000.00000.0008
      C50.00100.00070.00110.00100.0009
      C40.00100.00070.00110.00100.0009
      Example 6

      Referring to FIG. 5 and the simulation parameters described with reference to Example 5, in Example 6 hydrogen sulfide selective separation unit 106 and second hydrogen sulfide selective separation unit 108 were modeled after a Pebax® 4011, Pebax® 1074, polyphosphazene type membrane, or an ionic liquid membrane/ionic liquid membrane contactors type membrane with an H2S/CO2 selectivity of 5.0. Table 12 contains the permeation constants for hydrogen sulfide selective separation unit 106 and second hydrogen sulfide selective separation unit 108.

      TABLE 12
      Permeation Constants - Hydrogen Sulfide Selective Separation Unit
      106 and Second Hydrogen Sulfide Selective Separation Unit 108
      Permeation Constant
      Componentcm3/(cm2*s*psia)
      CO20.31
      H2S1.54
      C50.42
      C40.42

      Enriched hydrogen sulfide stream 22 and hydrocarbon rich stream 14 are mixed and fed to the furnace of Claus unit 200 as mixed furnace feed stream 24 Mixed furnace feed stream 24 has an H2S concentration of greater than 55%. Hydrogen sulfide lean stream 16 and carbon dioxide retentate 20 are mixed and fed to the catalytic converters of Claus unit 200 as mixed catalytic converter feed stream 26. The resulting concentrations of components for selected streams by % volume are shown in Table 13.

      TABLE 13
      Concentration of Components in Selected Streams, by % vol.
      Stream 10Stream 16Stream 14Stream 18Stream 24Stream 26
      Temperature (° C.) 37.7837.7837.7837.7837.7837.78
      Flow Rate248.5252.329.78186.43145.3103.14
      (MMscfd)
      CO20.64040.9663 0.27210.59850.41090.9641
      H2S0.35710.0019 0.71760.3994 0.5865 0.0336
      BTX0.00050.00000.00920.0000 0.00080.0000
      C50.00100.0009 0.00060.0010 0.0009 0.0012
      C40.00100.00090.00060.0010 0.00090.0012
      Example 7

      Example 7 was simulated based on the configuration embodied in FIG. 6. Acid gas stream 10 at 37.78° C. and 29.70 psia was fed to hydrocarbon selective separation unit 102 at a rate of 248.5 MMscfd (292.66 Msm3/h). Hydrocarbon selective separation unit 102 was modeled as a PDMS type rubbery polymer membrane with an H2S/CO2 selectivity of 1.6 and a BTX permeability of 100 cm3/(cm2*s*psia). Hydrocarbon selective separation unit 102 separated acid gas stream 10 into hydrocarbon rich stream 14 in the permeate and purified acid gas stream 12 in the retentate. Purified acid gas stream 12 was then fed to carbon dioxide selective separation unit 104. Carbon dioxide selective separation unit 104 was modeled as a glassy type membrane with a CO2/H2S selectivity of 6. Carbon dioxide selective separation unit 104 separated purified acid gas stream 12 into carbon dioxide rich stream 30 in the permeate and carbon dioxide lean stream 32 in the retentate. Carbon dioxide rich stream 30 is fed to hydrogen sulfide selective separation unit 106. Hydrogen sulfide selective separation unit 106 is a Pebax® 4011, Pebax® 1074, polyphosphazene based, ionic liquid membrane, or ionic liquid membrane contactor type membrane with an H2S/CO2 selectivity of 5.0. Permeation constants for carbon dioxide selective separation unit 104 and hydrogen sulfide selective separation unit 106 are contained in Table 14 for select components. Hydrogen sulfide selective separation unit 106 separated carbon dioxide rich stream 30 into hydrogen sulfide rich permeate 34 in the permeate and carbon dioxide rich retentate 36 in the retentate. Carbon dioxide lean stream 32, hydrogen sulfide rich permeate 34, and hydrocarbon rich stream 14 were fed to the furnace of Claus Unit 200. Carbon dioxide rich retentate 36 was fed to the catalytic converters of Claus Unit 200. The streams to the furnace had a combined H2S concentration greater than 40%. The resulting concentrations of components for selected streams by % volume are shown in Table 15.

      TABLE 14
      Permeation Constants
      Carbon dioxide selectiveHydrogen Sulfide Selective
      separation unit 104Separation Unit 106
      Componentcm3/(cm2*s*psia)cm3/(cm2*s*psia)
      CO21.20.31
      H2S0.21.54
      C50.20.3
      C40.20.3
      TABLE 15
      Concentration of Components in Selected Streams, by % vol.
      Furnace
      (Streams 14,
      Stream 10Stream 14Stream 30Stream 3432, & 34)Stream 36
      Temperature37.837.837.7837.7837.7837.78
      (° C.)
      Flow Rate248.4710.7850.0415.77214.234.27
      (MMscfd)
      CO20.64040.52480.90410.57680.58790.9688
      H2S0.35710.46110.09540.42080.40930.0306
      BTX0.00050.01120.00000.00000.00060.0000
      C50.00100.00110.00030.00120.00110.0003
      C40.00100.00110.00030.00120.00110.0003
      Example 8

      Example 8 was simulated based on the configuration embodied in FIG. 7. Acid gas stream 10 at 37.78° C. and 29.70 psia was fed to hydrocarbon selective separation unit 102 at a rate of 248.5 MMscfd (292.66 Msm3/h). Hydrocarbon selective separation unit 102 was modeled as a PDMS type rubbery polymer membrane with an H2S/CO2 selectivity of 1.6 and a BTX permeability of 100 cm3/(cm2*s*psia). Hydrocarbon selective separation unit 102 separated acid gas stream 10 into hydrocarbon rich stream 14 in the permeate and purified acid gas stream 12 in the retentate. Purified acid gas stream 12 was then fed to hydrogen sulfide selective separation unit 106. The properties of hydrogen sulfide selective separation unit 106 were modeled after a Pebax® 4011, Pebax® 1074, polyphosphazene type, ionic liquid membrane, or an ionic liquid membrane contactor type membrane with a H2S/CO2 selectivity of 5.0. Hydrogen sulfide selective separation unit 106 separated purified acid gas stream 12 into hydrogen sulfide rich stream 18 in the permeate and hydrogen sulfide lean stream 16 in the retentate. Hydrogen sulfide rich stream 18 was fed to carbon dioxide selective separation unit 104. Carbon dioxide selective separation unit 104 was modeled as a glassy type membrane with a CO2/H2S selectivity of 6.0. Permeation constants for hydrogen sulfide selective separation unit 106 and carbon dioxide selective separation unit 104 are contained in Table 16. Carbon dioxide selective separation unit 104 separated hydrogen sulfide rich stream 18 into carbon dioxide rich permeate 38 in the permeate and hydrogen sulfide rich retentate 40 in the retentate. Hydrocarbon rich stream 14 and hydrogen sulfide rich retentate 40 were fed to the furnace of Claus Unit 200. Hydrogen sulfide lean stream 16 and carbon dioxide rich permeate 38 were fed to the catalytic converters of Claus Unit 200. The streams to the furnace had a combined H2S concentration greater than 68%. The resulting concentrations of components for selected streams by % volume are shown in Table 17.

      TABLE 16
      Permeation Constants
      Carbon dioxide selectiveHydrogen Sulfide Selective
      separation unit 104Separation Unit 106
      Componentcm3/(cm2*s*psia)cm3/(cm2*s*psia)
      CO21.20.31
      H2S0.21.54
      C50.20.3
      C40.20.3
      TABLE 17
      Concentration of Components in Selected Streams, by % vol.
      Cat.
      FurnaceConverters
      StreamStreamStream(Streams(Streams
      10161414 & 40)16 & 38)
      Temper-37.7837.7837.7837.7837.78
      ature (° C.)
      Flow Rate248.5134.210.892.4156.1
      (MMscfd)
      CO20.64040.85180.52480.30900.8366
      H2S0.35710.14560.46170.68800.1609
      BTX0.00050.00000.01120.00130.0000
      C50.00100.00130.00110.00070.0012
      C40.00100.00130.00110.00070.0012
      Example 9

      Example 9 observed the effect of membrane surface on the concentration of components in selected streams. Referring to FIG. 7 and the simulation parameters described with reference to Example 8, in Example 9 the membranes used for hydrogen sulfide selective separation unit 106 and carbon dioxide selective separation unit 104 were modeled with a total surface area 1.55 times the surface area used in Example 8. The streams to furnace had a combined H2S concentration greater than 58%. The streams to the catalytic converters had a combined H2S of less than 7.2%.

      TABLE 18
      Concentration of Components in Selected Streams, by % vol.
      Cat.
      FurnaceConverters
      StreamStreamStream(Streams(Streams
      10161414 & 40)16 & 38)
      Temper-37.7837.7837.7837.7236.8
      ature (° C.)
      Flow Rate248.582.510.8139.2109.2
      (MMscfd)
      CO20.64040.95810.52480.41680.9259
      H2S0.35710.03890.46170.58060.0718
      BTX0.00050.00000.01120.00090.0000
      C50.00100.00150.00110.00080.0012
      C40.00100.00150.00110.00080.0012

      Although the present invention has been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the invention. Accordingly, the scope of the present invention should be determined by the following claims and their appropriate legal equivalents.

      The singular forms “a,” “an,” and “the” include plural referents, unless the context clearly dictates otherwise.

      Hydrocarbons

      Optional or optionally means that the subsequently described event or circumstances can or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur.

      Ranges may be expressed herein as from about one particular value, and/or to about another particular value. When such a range is expressed, it is to be understood that another embodiment is from the one particular value and/or to the other particular value, along with all combinations within said range.

      As used herein and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

      As used herein, terms such as “first” and “second” are arbitrarily assigned and are merely intended to differentiate between two or more components of an apparatus. It is to be understood that the words “first” and “second” serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location or position of the component. Furthermore, it is to be understood that that the mere use of the term “first” and “second” does not require that there be any “third” component, although that possibility is contemplated under the scope of the present invention.

      Claims (19)

      What is claimed:1. An enrichment apparatus for enriching a hydrogen sulfide concentration in an acid gas stream to create a hydrogen sulfide rich stream for feed to a Claus unit, the enrichment apparatus comprising:a hydrocarbon selective separation unit, the hydrocarbon selective separation unit operable to separate the acid gas stream into a hydrocarbon rich stream and a purified acid gas stream,
      wherein the acid gas stream comprises hydrogen sulfide, carbon dioxide, and hydrocarbons,
      wherein the hydrocarbon rich stream comprises benzene, toluene, ethyl benzene, and xylene;
      a hydrogen sulfide selective separation unit in fluid communication with the hydrocarbon selective separation unit, the hydrogen sulfide selective separation unit operable to separate the purified acid gas stream to create the hydrogen sulfide rich stream and a hydrogen sulfide lean stream, the hydrogen sulfide rich stream having a concentration of hydrogen sulfide; and
      the Claus unit in fluid communication with the hydrogen sulfide selective separation unit, the Claus unit operable to recover elemental sulfur from the hydrogen sulfide rich stream.
      2. The enrichment apparatus of claim 1, further comprising:
      a carbon dioxide selective separation unit in fluid communication with the hydrogen sulfide selective separation unit, the carbon dioxide selective separation unit operable to separate the hydrogen sulfide rich stream to create a carbon dioxide rich permeate and a hydrogen sulfide rich retentate, the hydrogen sulfide rich retentate having a concentration of hydrogen sulfide.
      3. The enrichment apparatus of claim 2, wherein the carbon dioxide selective separation unit is selected from the group consisting of an amorphous fluoroplastic membrane, an amorphous perfluoropolymer membrane, a random fluorocopolymer membrane, a perfluorinated copolymer membrane, and combinations thereof.
      4. The enrichment apparatus of claim 1, wherein the hydrogen sulfide selective separation unit is selected from the group consisting of polyphosphazene type polymer membranes, polyether-polyamide copolymer membranes, ionic liquid membranes, ionic liquid membrane contactors, and combinations thereof.
      5. The enrichment apparatus of claim 1, wherein the hydrocarbon selective separation unit comprises a PDMS type rubbery polymer membrane.
      6. The enrichment apparatus of claim 1, wherein the acid gas stream further comprises contaminants selected from the group consisting of mercaptans, thiols, carbonyl sulfide, carbon disulfide, and combinations thereof.
      7. The enrichment apparatus of claim 1, wherein the hydrogen sulfide concentration in the acid gas stream is between 15% to 55% by volume.
      8. The enrichment apparatus of claim 1, wherein the concentration of hydrogen sulfide in the hydrogen sulfide rich stream is greater than 55% by volume.
      9. A process for enriching a hydrogen sulfide concentration in an acid gas stream to create a hydrogen sulfide rich stream for feeding to a Claus unit, the process comprising the steps of:
      feeding the acid gas stream to a hydrocarbon selective separation unit, the acid gas stream comprising hydrogen sulfide, carbon dioxide, and hydrocarbons;
      separating the acid gas stream in the hydrocarbon selective separation unit to create a hydrocarbon rich stream and a purified acid gas stream, wherein the hydrocarbon rich stream comprises benzene, toluene, ethyl benzene, and xylene;
      feeding the purified acid gas stream to a hydrogen sulfide selective separation unit fluidly connected to the hydrocarbon selective separation unit, the hydrogen sulfide selective separation unit operable to separate the purified acid gas stream;
      separating the purified acid gas stream in the hydrogen sulfide selective separation unit to create the hydrogen sulfide rich stream and a hydrogen sulfide lean stream, the hydrogen sulfide rich stream having a concentration of hydrogen sulfide; and
      feeding the hydrogen sulfide rich stream to a furnace of the Claus unit, the Claus unit operable to recover elemental sulfur from the hydrogen sulfide rich stream to create an elemental sulfur stream and a waste gas stream.
      10. The process of claim 9, further comprising the steps of:
      feeding the hydrogen sulfide rich stream to a carbon dioxide selective separation unit in fluid communication with the hydrogen sulfide selective separation unit, the carbon dioxide selective separation unit operable to separate the hydrogen sulfide rich stream;
      separating the hydrogen sulfide rich stream to create a carbon dioxide rich permeate and a hydrogen sulfide rich retentate, the hydrogen sulfide rich retentate having a concentration of hydrogen sulfide; and
      feeding the hydrogen sulfide rich retentate to the furnace of the Claus unit.
      11. The process of claim 10, wherein the carbon dioxide selective separation unit is selected from the group consisting of an amorphous fluoroplastic membrane, an amorphous perfluoropolymer membrane, a random fluorocopolymer membrane, a perfluorinated copolymer membrane, and combinations thereof.
      12. The process of claim 9 further comprising the step of feeding the hydrocarbon rich stream to a BTX recovery process, the BTX recovery process operable to recover hydrocarbons from the hydrocarbon rich stream.
      13. The process of claim 9, wherein the hydrogen sulfide selective separation unit is selected from the group consisting of polyphosphazene type polymer membranes, polyether-polyamide copolymer membranes, ionic liquid membranes, ionic liquid membrane contactors, and combinations thereof.
      14. The process of claim 9, wherein the hydrocarbon selective separation unit comprises a PDMS type rubbery polymer membrane.
      15. The process of claim 9, wherein the acid gas stream further comprises contaminants is selected from the group consisting of mercaptans, thiols, carbonyl sulfide, carbon disulfide, and combinations thereof.
      16. The process of claim 9, wherein the hydrogen sulfide concentration in the acid gas stream is between 15% to 55% by volume.
      17. The process of claim 9, wherein the hydrogen sulfide rich stream has a hydrogen sulfide concentration greater than 55% by volume.
      18. An enrichment apparatus for enriching a hydrogen sulfide concentration in an acid gas stream to create a hydrogen sulfide rich stream for feed to a Claus unit, the enrichment apparatus comprising:a hydrocarbon selective separation unit, the hydrocarbon selective separation unit operable to separate the acid gas stream into a hydrocarbon rich stream and a purified acid gas stream,
      wherein the acid gas stream comprises hydrogen sulfide, carbon dioxide, and hydrocarbons,
      wherein the hydrocarbon rich stream comprises benzene, toluene, ethyl benzene, and xylenel;
      a carbon dioxide selective separation unit in fluid communication with the hydrocarbon selective separation unit, the carbon dioxide selective separation unit operable to separate the purified acid gas stream to create a carbon dioxide rich stream and a carbon dioxide lean stream, the carbon dioxide lean stream having a concentration of hydrogen sulfide; and
      the Claus unit in fluid communication with the carbon dioxide selective separation unit, the Claus unit operable to recover elemental sulfur from the carbon dioxide lean stream.
      19. The enrichment apparatus of claim 18, further comprising:
      a hydrogen sulfide selective separation unit in fluid communication with the carbon dioxide selective separation unit, the hydrogen sulfide selective separation unit operable to separate the carbon dioxide rich stream into a hydrogen sulfide rich permeate and a carbon dioxide rich retentate, the hydrogen sulfide rich permeate having a concentration of hydrogen sulfide.
      US14/686,9502014-04-162015-04-15Sulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feeds with BTEX in a Claus unit Active2035-05-12US9593015B2 (en)

      Priority Applications (2)

      Application NumberPriority DateFiling DateTitle
      US14/686,950US9593015B2 (en) 2014-04-162015-04-15Sulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feeds with BTEX in a Claus unit

      Applications Claiming Priority (2)

      Application NumberPriority DateFiling DateTitle
      US15/418,936US9981848B2 (en) 2014-04-162017-01-30Sulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feeds with BTEX in a claus unit

      Related Child Applications (1)

      Encyclopedia Of Hydrocarbons Eni Pdf Converter Download

      ID=53008876

      Family Applications (2)

      Application NumberTitlePriority DateFiling Date
      US20150298972A1US20150298972A1 (en) 2015-10-22
      Application NumberTitlePriority DateFiling Date
      US15/418,936ActiveUS9981848B2 (en) 2014-04-162017-01-30Sulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feeds with BTEX in a claus unit

      Family Applications After (1)

      Application NumberTitlePriority DateFiling Date
      US (2) US9593015B2 (en)
      JP (2) JP6358631B2 (en)
      CN (2) CN108579348A (en)
      WO (1) WO2015160645A1 (en)

      Cited By (4)

      * Cited by examiner, † Cited by third party
      Publication numberPriority datePublication dateAssigneeTitle
      US9981848B2 (en) *2014-04-162018-05-29Saudi Arabian Oil CompanySulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feeds with BTEX in a claus unit
      US10106410B2 (en) 2017-03-102018-10-23Saudi Arabian Oil CompanyEnhancement of Claus tail gas treatment by sulfur dioxide-selective membrane technology

      Families Citing this family (2)

      * Cited by examiner, † Cited by third party
      Publication numberPriority datePublication dateAssigneeTitle
      US9387430B2 (en) 2014-11-192016-07-12Apache CorporationMethods and systems of enhanced carbon dioxide recovery

      Citations (32)

      * Cited by examiner, † Cited by third party
      Publication numberPriority datePublication dateAssigneeTitle
      US3896215A (en) 1972-11-031975-07-22Metallgesellschaft AgProcess for the removal of hydrogen sulfide from a gas stream
      US4507275A (en) 1983-08-301985-03-26Standard Oil Company (Indiana)Process for producing and recovering elemental sulfur from acid gas
      US4589896A (en) 1985-01-281986-05-20Air Products And Chemicals, Inc.Process for separating CO2 and H2 S from hydrocarbons
      GB2248444A (en) 1990-09-041992-04-08Exxon Production Research CoProcess for removing hydrogen sulfide from a gaseous mixture and producing sulfur therefrom
      US5304361A (en) 1992-06-261994-04-19Union Carbide Chemicals & Plastics Technology CorporationRemoval of hydrogen sulfide
      US5558698A (en) 1993-10-251996-09-24Membrane Technology And Research, Inc.Acid gas fractionation process
      US6287365B1 (en) 1999-01-132001-09-11Uop LlcSulfur production process
      US6508863B1 (en) 2001-10-112003-01-21Engelhard CorporationClaus feed gas hydrocarbon removal
      US7306651B2 (en) 2002-02-152007-12-11L'Air Liquide, Société Anonyme à Directoire et Conseil de Surveillance pour l'Etude et l'Exploitation des Procédés Georges ClaudeMethod for treatment of a gaseous mixture comprising hydrogen and hydrogen sulphide
      US20090313895A1 (en) *2006-09-122009-12-24Pex Petrus Paulus Antonius CatProcess for obtaining a hydrocarbon-enriched fraction from a gaseous feedstock comprising a hydrocarbon fraction and carbon dioxide
      US20100310439A1 (en) 2007-08-302010-12-09Theodorus Johannes BrokProcess for removal of hydrogen sulphide and carbon dioxide from an acid gas stream
      US7988767B2 (en) 2006-08-312011-08-02Fluor Technologies CorporationHydrocarbon based sulfur solvent systems and methods
      US20120085973A1 (en) 2009-04-282012-04-12Lurgi GmbhMethod for producing process gas for the claus process
      US8206669B2 (en) 2010-07-272012-06-26Air Products And Chemicals, Inc.Method and apparatus for treating a sour gas
      US20130071308A1 (en) 2011-09-212013-03-21Linde AktiengesellschaftCo2 recovery using the sure process
      US20150299596A1 (en) *2014-03-122015-10-22Rustam H. SethnaMethods for removing contaminants from natural gas

      Family Cites Families (10)

      * Cited by examiner, † Cited by third party
      Publication numberPriority datePublication dateAssigneeTitle
      GB8803767D0 (en) *1988-02-181988-03-16Ici PlcDesulphurisation
      CN1382105A (en) *1999-10-222002-11-27孟山都公司Process for production of sulfur
      US20080155984A1 (en) *2007-01-032008-07-03Ke LiuReforming system for combined cycle plant with partial CO2 capture
      MX338688B (en) *2010-01-222016-04-27Exxonmobil Upstream Res CoRemoval of acid gases from a gas stream, with co2 capture and sequestration.
      SG11201607810VA (en) *2014-04-162016-10-28Saudi Arabian Oil CoImproved sulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feeds with btex in a claus unit
      • 2015-04-10SGSG11201607810VApatent/SG11201607810VA/enunknown
      • 2015-04-10JPJP2016562897Apatent/JP6358631B2/enactiveActive
      • 2015-04-10CNCN201810224172.5Apatent/CN108579348A/enactiveSearch and Examination
      • 2015-04-10SGSG10201705644UApatent/SG10201705644UA/enunknown
      • 2015-04-10CNCN201580019770.3Apatent/CN106457126B/enactiveIP Right Grant
      • 2017
        • 2018
          • Editions Eni Pdf
            * Cited by examiner, † Cited by third party
            Publication numberPriority datePublication dateAssigneeTitle
            US3896215A (en) 1972-11-031975-07-22Metallgesellschaft AgProcess for the removal of hydrogen sulfide from a gas stream
            US4507275A (en) 1983-08-301985-03-26Standard Oil Company (Indiana)Process for producing and recovering elemental sulfur from acid gas
            US4589896A (en) 1985-01-281986-05-20Air Products And Chemicals, Inc.Process for separating CO2 and H2 S from hydrocarbons
            GB2248444A (en) 1990-09-041992-04-08Exxon Production Research CoProcess for removing hydrogen sulfide from a gaseous mixture and producing sulfur therefrom
            US5304361A (en) 1992-06-261994-04-19Union Carbide Chemicals & Plastics Technology CorporationRemoval of hydrogen sulfide
            US5558698A (en) 1993-10-251996-09-24Membrane Technology And Research, Inc.Acid gas fractionation process
            US6287365B1 (en) 1999-01-132001-09-11Uop LlcSulfur production process
            US6387159B1 (en) 2000-06-262002-05-14Engelhard CorporationClaus feed gas hydrocarbon removal
            US7306651B2 (en) 2002-02-152007-12-11L'Air Liquide, Société Anonyme à Directoire et Conseil de Surveillance pour l'Etude et l'Exploitation des Procédés Georges ClaudeMethod for treatment of a gaseous mixture comprising hydrogen and hydrogen sulphide
            US20090092524A1 (en) *2005-04-202009-04-09Fluor Technologies CorporationConfigurations And Methods for Claus Plant Operation with Variable Sulfur Content
            US20090313895A1 (en) *2006-09-122009-12-24Pex Petrus Paulus Antonius CatProcess for obtaining a hydrocarbon-enriched fraction from a gaseous feedstock comprising a hydrocarbon fraction and carbon dioxide
            US20100310439A1 (en) 2007-08-302010-12-09Theodorus Johannes BrokProcess for removal of hydrogen sulphide and carbon dioxide from an acid gas stream
            US7901646B2 (en) 2009-08-052011-03-08General Electric CompanySystem and method for sulfur recovery
            US20130022534A1 (en) 2010-03-292013-01-24Thyssenkrupp Uhde GmbhProcess for workup of a carbon dioxide-rich gas to be freed of sulfur components
            US20120103185A1 (en) 2010-11-012012-05-03Saudi Arabian Oil CompanySour Gas and Acid Natural Gas Separation Membrane Process by Pre Removal of Dissolved Elemental Sulfur for Plugging Prevention
            US20130071308A1 (en) 2011-09-212013-03-21Linde AktiengesellschaftCo2 recovery using the sure process
            US20150299596A1 (en) *2014-03-122015-10-22Rustam H. SethnaMethods for removing contaminants from natural gas

            Emmanuel Eni Pdf

            Non-Patent Citations (22)

            1761 Net Eni Pdf
            * Cited by examiner, † Cited by third party
            Title
            G. Chatterjee el al.; 'Poly(ether urethane) and ploy (ether urethane urea) membranes with high H2S/CH4 selectivity'; Journal of Membrane Science 135 (1997) 99-106.
            Sulpher, Jan.-Feb. 2009, No. 320, World Markets on p. 4.
            US9981848B2 (en) *2014-04-162018-05-29Saudi Arabian Oil CompanySulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feeds with BTEX in a claus unit
            US9943802B1 (en) *2017-03-132018-04-17Saudi Arabian Oil CompanyEnhancement of claus tail gas treatment with membrane and reducing step
            SG10201705644UA (en) 2017-08-30
            KR101929644B1 (en) 2019-03-12
            EP3131658A1 (en) 2017-02-22
            JP2018184341A (en) 2018-11-22
            CN106457126A (en) 2017-02-22
            US9981848B2 (en) 2018-05-29
            KR20180134429A (en) 2018-12-18
            WO2015160645A1 (en) 2015-10-22
            Encyclopedia Of Hydrocarbons Eni Pdf Converter Pdf
            PublicationPublication DateTitle
            EP3069780B1 (en) Methods for acid gas enrichment
            EP2164608B1 (en) Method for recovering a gaseous component from a gas stream
            US7846407B2 (en) Self-concentrating absorbent for acid gas separation
            US20060188423A1 (en) Method of decarbonating a combustion fume with extraction of the solvent contained in the purified fume
            CN101301562B (en) Methods and systems for reducing carbon dioxide in combustion flue gases
            EP2310110B1 (en) Absorbent solution based on n,n,n',n'-tetramethylhexane-1,6-diamine and on one particular amine comprising primary or secondary amine functional groups and process for removing acid compounds from a gaseous effluent
            AU2009303874B2 (en) Methods and systems for deacidizing gaseous mixtures
            US7147691B2 (en) Acid gas enrichment process
            US8899557B2 (en) In-line device for gas-liquid contacting, and gas processing facility employing co-current contactors
            US7485275B2 (en) Method for removing acid gases and ammonia from a fluid stream
            CN101365526A (en) Reclaiming amines in carbon dioxide recovery
            JP4845438B2 (en) Method for removing sulfur compounds from natural gas
            Owner name: SAUDI ARABIAN OIL COMPANY, SAUDI ARABIA

            DateCodeTitleDescription
            STCFInformation on status: patent grant

            : Ps4 Emulator Pc Download No Survey

          • : Bill Of Sale As Is Pdf
          • : Pokemon Feuerrot Rom Fr Gameboy
          • : Microsoft Office Onenote 2003 Serial Key
          • : Duval Triangle Software Free Download
          • : Garrison Thermostat User Manual