WO2011072046A1 - Fractionnement de gaz sulfureux riche en sulfure d'hydrogène, et méthodes d'utilisation - Google Patents

Fractionnement de gaz sulfureux riche en sulfure d'hydrogène, et méthodes d'utilisation Download PDF

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Publication number
WO2011072046A1
WO2011072046A1 PCT/US2010/059523 US2010059523W WO2011072046A1 WO 2011072046 A1 WO2011072046 A1 WO 2011072046A1 US 2010059523 W US2010059523 W US 2010059523W WO 2011072046 A1 WO2011072046 A1 WO 2011072046A1
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Prior art keywords
distillation column
stream
hydrogen sulfide
withdrawing
liquid bottoms
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PCT/US2010/059523
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English (en)
Inventor
Shawn S. Huang
Douglas Elliot
Jame Yao
Wei Yan
Naushad A. Kassamali
Mark S. Elkins
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Conocophillips Company
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Priority to CA2780902A priority Critical patent/CA2780902A1/fr
Publication of WO2011072046A1 publication Critical patent/WO2011072046A1/fr

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/103—Sulfur containing contaminants
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B01D53/1462—Removing mixtures of hydrogen sulfide and carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/104—Carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/12—Liquefied petroleum gas

Definitions

  • the present invention relates generally to the treatment of sour gas and more particularly, but not by way of limitation, embodiments of the present invention include methods and systems for treating hydrogen sulfide rich sour gas through fractionation.
  • Sour gas is natural gas or any other hydrocarbon gas containing significant amounts of hydrogen sulfide (H 2 S). These gases, because of the rotten egg smell provided by its sulfur content, is commonly called “sour gas.” Typically, the sulfur that exists in a sour gas stream can be extracted and marketed on its own. In fact, according to the U.S. Geological Survey, U.S. sulfur production from gas processing plants accounts for about 15 percent of the total U.S. production of sulfur. Natural gas is usually considered sour if there are more than 5.7 milligrams of H 2 S per cubic meter of natural gas, which is equivalent to approximately 4 ppm by volume. On the other hand, natural gas that does not contain significant amounts of hydrogen sulfide is called “sweet gas.” In contrast, acid gas is any gas that contains significant amounts of acidic gases such as carbon dioxide (C0 2 ) or hydrogen sulfide.
  • the raw gas Before a raw natural gas containing hydrogen sulfide and/or carbon dioxide can be used, the raw gas must be treated to remove those impurities to acceptable levels. This treatment to remove hydrogen sulfide is referred to as a sweetening process.
  • the removed hydrogen sulfide is most often subsequently converted to by-product elemental sulfur in a Claus process or it can be treated in a WSA Process unit where the by-product is sulfuric acid.
  • Treatment of sour gas to remove hydrogen sulfide is important because the presence of sour gas is usually undesirable in fuel streams because sulfur compounds can be extremely harmful, even lethal, to breathe. Moreover, sour gas can be extremely corrosive. Therefore, gas processing is an instrumental piece of the natural gas value chain. It is instrumental in ensuring that the natural gas intended for use is as clean and pure as possible, making it the clean burning and environmentally sound energy choice.
  • the most common conventional method for treating sour gas to remove the hydrogen sulfide is by an amine gas treating process.
  • Other conventional methods of sour gas treatment include limited cryogenic fractionation processes.
  • the amine process is used in about 95 percent of U.S. gas sweetening operations.
  • the sour gas is run through a tower, which contains the amine solution.
  • This solution has an affinity for hydrogen sulfide, and absorbs it much like glycol absorbing water.
  • two principle amine solutions used include monoethanolamine (MEA) and diethanolamine (DEA). Either of these compounds, in aqueous solution, will absorb sulfur compounds from natural gas as it passes through. The effluent gas is virtually free of sulfur compounds, and thus loses its sour gas status.
  • the amine solution used can be regenerated (that is, the absorbed sulfur is removed), allowing it to be reused to treat more sour gas.
  • the carbon dioxide stream that is produced by an amine plant is typically produced at pressures close to ambient pressure. Consequently, sequestration of the carbon dioxide becomes problematic, because substantially elevated pressures are required to sequester carbon dioxide. Accordingly, sequestration of carbon dioxide from an amine plant requires additional costly equipment to compress the carbon dioxide to allow it to be captured, held, or subsequently used.
  • amine treatment processes are also problematic with regards to solvent treatment. Because amine plants reuse their absorption solvents, the solvents must be regenerated by removing the absorbed sulfur compounds. This solvent regeneration in turn requires significant additional equipment, resulting in increased costs.
  • amine plants are ill-suited for some environments such as the arctic cold. Because amine plants require certain elevated temperatures, additional heaters would be required to maintain the target operating temperatures of the process equipment if the plant were operated in such a cold region.
  • any carbon dioxide present in sour gas simply passes through an amine plant, staying with the produced hydrogen sulfide stream. Accordingly, any sulfur plant downstream of an amine plant must be sized to handle the additional throughput required by the presence of the carbon dioxide in the sulfur plant feed stream. Although some carbon dioxide can be tolerated in sweet gas streams, the increase in equipment size to handle the presence of the additional carbon dioxide can, in some cases, be quite substantial, resulting in undesirable equipment costs.
  • azeotrope is a mixture of two or more liquids in such a ratio that its composition cannot be changed by simple distillation. This inability to separate components by distillation occurs because, when an azeotrope is boiled, the resulting vapor has the same ratio of constituents as the original mixture.
  • azeotrope that complicates the treatment of sour gas
  • carbon dioxide / ethane azeotrope is the carbon dioxide / ethane azeotrope.
  • the separation of carbon dioxide from ethane by distillation has proven to be a difficult problem in practice. This difficulty is caused by the fact that carbon dioxide and ethane form an azeotrope of approximately two thirds carbon dioxide and one third ethane on a mole basis. For a feed mixture containing ethane and carbon dioxide, this azeotrope tends to form in the upper portion of the column, usually making further separation beyond the azeotrope composition impossible.
  • azeotrope complicating the treatment of sour gas is the ethylene / carbon dioxide azeotrope. Additionally, it is known that the acid gas hydrogen sulfide forms azeotropes with both ethane and propane. These and other possible azeotropes between acid gases and light hydrocarbons present limitations similar to those described for the carbon dioxide/ethane system when efforts are made to perform distillative separations on such systems.
  • the present invention relates generally to the treatment of sour gas and more particularly, but not by way of limitation, embodiments of the present invention include methods and systems for treating hydrogen sulfide rich sour gas through fractionation.
  • One example of a process for the recovery of hydrogen sulfide from sour gas through fractionation comprises the steps of: introducing a multi-component feed stream to a first distillation column, wherein the first distillation column is a demethanizer column, wherein the multi-component feed stream comprises carbon dioxide, methane, ethane, propane, and hydrogen sulfide; introducing an alkyl hydrocarbon mixture into the first distillation column, wherein the alkyl hydrocarbon mixture comprises ethane; withdrawing a first vapor overhead stream from the first distillation column wherein the first vapor overhead stream is a methane-enriched stream; withdrawing a first liquid bottoms stream from the first distillation column; introducing the first liquid bottoms stream to a second distillation column, wherein the second distillation column is a C0 2 /H 2 S fractionation column; withdrawing a second vapor overhead stream from the second distillation column, wherein the second vapor overhead stream is a carbon dioxide and ethane-enriched stream;
  • One example of a process for the treatment of sour gas comprises the steps of: introducing a multi-component feed stream to a first distillation column, wherein the first distillation column is a demethanizer column, wherein the multi-component feed stream comprises carbon dioxide, methane, ethane, propane, and hydrogen sulfide; introducing an alkyl hydrocarbon mixture into the first distillation column, wherein the alkyl hydrocarbon mixture comprises ethane; withdrawing a first vapor overhead stream from the first distillation column wherein the first vapor overhead stream is a methane-enriched stream; withdrawing a first liquid bottoms stream from the first distillation column; introducing the first liquid bottoms stream to a second distillation column, wherein the second distillation column is a C0 2 /H 2 S fractionation column; withdrawing a second vapor overhead stream from the second distillation column, wherein the second vapor overhead stream is a carbon dioxide and ethane-enriched stream; withdrawing a second liquid bottoms stream from
  • Figure 1 illustrates a simplified process flow diagram for a method for treating sour gas in accordance with one embodiment of the present invention.
  • Figure 2 illustrates another simplified process flow diagram for a method for treating sour gas in accordance with one embodiment of the present invention.
  • Figure 3 illustrates an exemplary process flow diagram of a method for treating sour gas in accordance with one embodiment of the present invention.
  • the present invention relates generally to the treatment of sour gas and more particularly, but not by way of limitation, embodiments of the present invention include methods and systems for treating hydrogen sulfide rich sour gas through fractionation.
  • Methods and systems are provided for treating hydrogen sulfide rich sour gas through a series of fractionation columns.
  • the processes disclosed herein and the variations thereof provide optimized processes for the removal of hydrogen sulfide from sour gas through the introduction of innovative azeotrope breakers, novel configurations of process equipment, and optimized operating conditions.
  • Advantages of certain embodiments of the present invention include, but are not limited to, reduced equipment requirements, improved process efficiencies, reduced operating costs, and reduced capital costs. Other advantages include better process suitability to certain environmental conditions such as the arctic cold when compared to conventional amine treatment processes.
  • Figure 1 illustrates a simplified process flow diagram for a method for treating sour gas in accordance with one embodiment of the present invention. More particularly, Figure 1 illustrates a system of five interconnected fractionation columns for treating a multi- component feed stream 111 via sour gas treatment process 100.
  • Multi-component feed stream 111 is a sour gas stream to be treated, which may comprise hydrogen sulfide, carbon dioxide, and various hydrocarbons such as methane, ethane, propane, other alkyl components, and other compounds typically found in sour gas sources.
  • Sour gas treatment process 100 is particularly suited for treating multi-component feed streams rich in hydrogen sulfide, such as at least about 15% hydrogen sulfide, at least about 20% hydrogen sulfide, and higher. Unless otherwise noted, all percentages in this specification are based on a mole percent or a volume percent basis.
  • feed stream 11 1 has the following concentrations, as shown in Figure 1 : about 23% H 2 S, about 10% CQ 2 , about 60% C h about 4% C 2 , and about 3% C 3 .
  • component feed concentrations could vary greatly depending on the source of sour gas feed 111.
  • sour gas treatment process 100 recovers hydrogen sulfide from feed stream 111.
  • sour gas treatment process 100 produces hydrogen sulfide enriched stream 134 having hydrogen sulfide concentrations of at least about 95%, at least about 97% or higher.
  • Other output streams enriched in other components are likewise produced from sour gas treatment process 100 as will be described further below.
  • Parenthetical notations are shown adjacent to each stream indicating the major enriched components of each stream illustrative of the present example discussed herein.
  • the parenthetical notations and the example stream specifications are illustrative only and are intended to be non-limiting examples representative of major stream components.
  • Sour gas treatment process 100 begins with feed stream 111 being introduced into a first distillation column, referred to herein as demethanizer 110.
  • Demethanizer 110 is any distillation column adapted to substantially remove methane from sour gas feed stream 111.
  • an optional hydrocarbon stream comprising one or more alkyl hydrocarbons 112 is introduced into demethanizer 1 10.
  • optional stream 112 substantially comprises a mixture of one or more of ethane, pentane, and hexane.
  • Optional stream 112 may assist in downstream separation of C0 2 and H 2 S in a C0 2 /H 2 S splitter 120 as will be described further below.
  • demethanizer 110 is a distillation column having about 18 ideal stages, an overheads temperature from about -94°F to about 6°F, a bottoms temperature from about 35°F to about 135°F, and a pressure from about 300 psia to about 600 psia.
  • all distillation column pressures refer to the overhead pressure of the distillation column unless otherwise noted.
  • Demethanizer 1 10 produces first overhead vapor stream 114 and first liquid bottoms stream 1 17.
  • First overhead vapor stream 114 is substantially enriched in methane, whereas first liquid bottoms stream 117 is substantially reduced in methane concentration.
  • First overhead vapor stream 114 may be further treated to reduce impurities so as to obtain a methane stream of desired purity.
  • demethanizer 110 accomplishes the first step of treating the sour gas, namely substantially removing methane from multi-component feed stream 111.
  • First liquid bottoms stream 117 is then routed to a second distillation column, referred to herein as C0 2 /H 2 S splitter 120.
  • C0 2 H 2 S splitter 120 is a distillation column having about 30 ideal stages, an overheads temperature from about -43 °F to about 57°F, a bottoms temperature from about 70°F to about 170°F, and a pressure from about 235 psia to about 535 psia.
  • C0 2 /H 2 S splitter 120 produces second overhead vapor stream 124 and second liquid bottoms stream 127.
  • Second overhead vapor stream 124 is substantially enriched in carbon dioxide and ethane
  • second liquid bottoms stream 127 is substantially enriched in hydrogen sulfide and propane and heavier hydrocarbons.
  • C0 2 /H 2 S splitter 120 substantially removes C0 2 and ethane from first liquid bottoms stream 117.
  • Second liquid bottoms stream 127 then proceeds to the third distillation column, referred to herein as De-H 2 S column 130, while second overhead vapor stream 124 then proceeds to the fourth distillation column, referred to herein as De-C0 2 column 140.
  • De-C0 2 column 140 is a distillation column having about 36 ideal stages, an overheads temperature from about -18°F to about 82°F, a bottoms temperature from about 86°F to about 186°F, and a pressure from about 210 psia to about 510 psia.
  • De-C0 2 column 140 produces fourth overhead vapor stream 144 and fourth liquid bottoms stream 147.
  • Second azeotrope breaker 142 is introduced to De-C0 2 column 140 to break the carbon dioxide / ethane azeotrope.
  • second azeotrope breaker 142 comprises one or more alkyl hydrocarbons, and in still other embodiments, comprises a mixture of pentane and heavier hydrocarbons.
  • Fourth overhead vapor stream 144 is substantially enriched in carbon dioxide, whereas fourth liquid bottoms stream 147 is substantially enriched in the remaining hydrocarbons.
  • the carbon dioxide produced in fourth overhead vapor stream 144 comprises an output stream having any of the following impurity concentrations: less than about 30 ppm hydrogen sulfide, less than about 20 ppm hydrogen sulfide, or less than about 10 ppm hydrogen sulfide.
  • De-C0 2 column 140 substantially removes carbon dioxide and ethane from third vapor overhead stream 124.
  • De-C0 2 column 140 is operated at high pressure, fourth overhead vapor stream 144 is produced at a pressure of from about 300 to about 400 psia. This high pressure is highly advantageous for the subsequent sequestration of this carbon dioxide stream, that is, the capturing, holding, or subsequent use of the carbon dioxide for other applications. Many conventional processes for the recovery of carbon dioxide from sour gas produce carbon dioxide at ambient pressure, which effectively prevents sequestration of the carbon dioxide without additional equipment such as sizeable compressors.
  • Second liquid bottoms stream 127 from C0 2 /H 2 S splitter 120 this stream 127 then proceeds to De-H 2 S column 130 for separation of the remaining hydrocarbons from the hydrogen sulfide present in second liquid bottoms stream 127.
  • First azeotrope breaker 158 may be introduced to De-H 2 S column 130 to assist in breaking any azeotropes present in De-H 2 S column 130. Examples of azeotropes present in De-H 2 S column 130 include the H 2 S/ethane azeotrope and the H 2 S/propane azeotrope.
  • First azeotrope breaker 158 may comprise any one or more alkyl hydrocarbons that assist in enhancing the separation of H 2 S from ethane and/or propane.
  • suitable azeotrope breakers include, but are not limited to, hexane, heptane, any akyl hydrocarbon having 8 or more carbons, or any mixture thereof.
  • De-H 2 S column 130 is a distillation column having about 40 ideal stages, an overheads temperature from about 20°F to about 120°F, a bottoms temperature from about 275°F to about 375°F, and a pressure from about 115 psia to about 415 psia.
  • De-H 2 S column 130 produces third overhead vapor stream 134 and third liquid bottoms stream 137.
  • Third overhead vapor stream 134 is substantially enriched in hydrogen sulfide, whereas third liquid bottoms stream 137 is substantially enriched in the remaining hydrocarbons.
  • the hydrogen sulfide concentration of third overhead vapor stream 134 comprises an output stream having any one of the following concentrations: at least about 95% hydrogen sulfide, at least about 97% hydrogen sulfide, or at least 99% hydrogen sulfide. In this way, De-H 2 S column 130 substantially recovers hydrogen sulfide from second liquid bottoms stream 127.
  • Third overhead vapor stream 134 which is enriched in hydrogen sulfide may be subsequently converted to by-product elemental sulfur in a Claus process. Alternatively, it can be treated in a WSA Process unit where the by-product is sulfuric acid or otherwise used as desired.
  • Third liquid bottoms stream 137 may optionally be subjected to further processing in a fifth distillation column, referred to herein as debutanizer 150.
  • debutanizer 150 is a distillation column having about 27 ideal stages, an overheads temperature from about 118°F to about 218°F, a bottoms temperature from about 290°F to about 390°F, and a pressure from about 50 psia to about 350 psia.
  • debutanizer 150 separates third liquid bottoms stream 137 into fifth vapor overhead stream 154 and fifth liquid bottoms stream 157.
  • Fifth liquid bottoms stream 157 is substantially enriched with pentane and heavier hydrocarbons, whereas fifth vapor overhead stream 154 comprises butane and lighter hydrocarbons. Fifth vapor overhead stream 154 may be condensed and sent to liquid treatment for further processing or sold as liquefied petroleum gas, commonly known as LPG.
  • sour gas treatment process 100 separates sour gas multi- component feed stream in a multitude of useful and valuable product streams.
  • Figure 1 depicts one simplified flow diagram, it is explicitly recognized that the invention herein may be practiced by any subset of the columns depicted in Figure 1. For example, in some embodiments, optional fractionation columns 110, 140, and 150 may be excluded.
  • Figure 2 illustrates another simplified process flow diagram for a method for treating sour gas in accordance with one embodiment of the present invention. Like the simplified process flow diagram depicted in Figure 1, Figure 2 likewise depicts a five distillation column process 200 utilizing analogous numbering to the numbering shown in Figure 1, with the exceptions noted below. Sour gas treatment process 200 of Figure 2, however, also includes optional polishing process 270 and additional recycle streams as discussed directly below.
  • first vapor overhead stream from demethanizer 210 is substantially enriched in methane.
  • first vapor overhead stream 214 may be subjected to additional treatment.
  • the additional treatment may comprise optional polishing process 270, which comprises an amine treating process for substantial removal of any remaining hydrogen sulfide and carbon dioxide from first vapor overhead stream 214.
  • optional polishing process 270 comprises a two-stage absorption process comprising a methyldiethanolamine (MDEA) absorber and a diglycolamine (DGA) absorber.
  • MDEA methyldiethanolamine
  • DGA diglycolamine
  • MDEA Absorber 271 substantially removes hydrogen sulfide via hydrogen sulfide stream 273, which may be combined with third vapor overhead stream 234 if desired. Gas stream 272 is then directed to DGA Absorber 276 for recovery of any remaining carbon dioxide, primarily methane gas as methane product stream 278 of optional polishing process 270.
  • methane product stream 278 comprises less than about 10 ppm hydrogen sulfide, less than about 4 ppm hydrogen sulfide, or less than about 2 ppm hydrogen sulfide. Additionally, methane product stream 278 may comprise less than about 150 ppm carbon dioxide, less than about 100 ppm carbon dioxide, or less than about 50 ppm carbon dioxide. Where methane product stream 278 comprises less than about 4 ppm hydrogen sulfide, methane product stream 278 may be referred to as "sweet gas.”
  • optional hydrocarbon stream 212 is provided by at least a portion of fourth liquid bottoms stream 212.
  • optional stream 212 substantially comprises a mixture of one or more of ethane, pentane, and hexane.
  • recycle stream 212 has been found to offer additional separation enhancement, particularly with respect to the downstream separation of C0 2 and H 2 S in a C0 2 /H 2 S splitter 220.
  • First azeotrope breaker 158 and second azeotrope breaker 242 are provided by at least a portion of fifth liquid bottoms stream 257.
  • Figure 3 illustrates an exemplary process flow diagram of a method for treating sour gas in accordance with one embodiment of the present invention.
  • the detailed process flow diagram of Figure 3 was modeled using HYSYS ® simulation software.
  • Table 1 shows an equipment list corresponding to the equipment depicted in Figure 3.
  • those reference numerals beginning with "E-” refer to heat exchangers (e.g. reboilers, condensers); reference numerals beginning with “V-” refer to flash drums; reference numerals beginning with “P-” refer to pumps, reference numerals beginning with “M-” refer to motors, and reference numerals beginning with “C-” refer to compressors.
  • E-305 heat exchangers (e.g. reboilers, condensers); reference numerals beginning with “V-” refer to flash drums; reference numerals beginning with “P-” refer to pumps, reference numerals beginning with “M-” refer to motors, and reference numerals beginning with “C-” refer to compressor
  • Sour gas treatment process 300 depicts a five stage distillation process, although the invention may be practiced any one or more of the five stages. Similar to the previous embodiments, Demethanizer Column T-301 works in conjunction with CO 2 /H 2 S Splitter T-302, De-H 2 S Column T-303, De-C0 2 Column T-304, and Debutanizer T-305. Table 2 below shows a heat and material balance corresponding to the process flow diagram depicted in Figure 3 that was generated using the modeling software with the input streams as indicated. In this way, Figure 3 along with the heat and material balance shown in Table 2 demonstrates the efficacy of the methods disclosed herein for the treatment of sour gas.
  • the values shown throughout the heat and material balance may vary under variations of operating conditions and feed inputs.
  • the operating conditions, the flow rates, and the component percentages shown in Table 2 may vary from about ⁇ 5% to about ⁇ 10% from those values in Table 2, and in still other embodiments from about ⁇ 1% to about ⁇ 20% from those values in Table 2.
  • Table 4 shows a comparison of the major capital equipment required for a conventional amine process as compared to one example of an equivalent improved fractionation treatment process. As can be seen in Table 4, the improved fractionation process requires substantially less capital equipment than the comparable conventional chemical solvent treating.

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Abstract

L'invention porte sur des méthodes et des systèmes de traitement de gaz sulfureux riche en sulfure d'hydrogène dans une série de colonnes de fractionnement. Les procédés décrits et leurs variantes sont des procédés optimisant l'extraction du sulfure d'hydrogène de gaz sulfureux par l'introduction de destructeurs d'azéotropes, par de nouvelles configurations des équipements de traitement et par une optimisation des conditions d'exploitation. Les avantages de certaines exécutions de la présente invention comprennent: des besoins réduits en équipement, de meilleurs rendements de traitement; des coûts d'exploitation moindres, et des investissements en capitaux réduits D'autres avantages comprennent une adaptabilité à certaines conditions environnementales telles que le froid arctique, meilleure que celle des procédés de traitement classiques aux amines.
PCT/US2010/059523 2009-12-10 2010-12-08 Fractionnement de gaz sulfureux riche en sulfure d'hydrogène, et méthodes d'utilisation WO2011072046A1 (fr)

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