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WO2025024763A2 - Système et procédé de désulfuration directe - Google Patents

Système et procédé de désulfuration directe Download PDF

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Publication number
WO2025024763A2
WO2025024763A2 PCT/US2024/039742 US2024039742W WO2025024763A2 WO 2025024763 A2 WO2025024763 A2 WO 2025024763A2 US 2024039742 W US2024039742 W US 2024039742W WO 2025024763 A2 WO2025024763 A2 WO 2025024763A2
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WIPO (PCT)
Prior art keywords
stream
desulfurization system
desulfurization
sulfur
fluid stream
Prior art date
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PCT/US2024/039742
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English (en)
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WO2025024763A3 (fr
Inventor
Strom W. Smith
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Individual
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Publication of WO2025024763A2 publication Critical patent/WO2025024763A2/fr
Publication of WO2025024763A3 publication Critical patent/WO2025024763A3/fr
Pending legal-status Critical Current
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Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
    • 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 OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/103—Sulfur containing contaminants
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G29/00—Refining of hydrocarbon oils, in the absence of hydrogen, with other chemicals
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G29/00—Refining of hydrocarbon oils, in the absence of hydrogen, with other chemicals
    • C10G29/02—Non-metals
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/207—Acid gases, e.g. H2S, COS, SO2, HCN
    • 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 OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel

Definitions

  • H2S hydrogen sulfide
  • Embodiments of a desulfurization system of the present invention generally include a series of components designed to utilize an input of fluid comprising hydrogen sulfide as an impurity, such as a refinery fuel gas stream, and an input of a gaseous stream comprising sulfur dioxide, whereby the combined streams progress through the individual components such that within one or more such components molecular sulfur (S2) created within the system, in molten form, is removable therefrom.
  • an impurity such as a refinery fuel gas stream
  • a gaseous stream comprising sulfur dioxide
  • Figure l is a depiction of an embodiment of a direct desulfurization system of the present invention.
  • Figure 2 is a depiction of an embodiment of a direct desulfurization system of the present invention that includes post-desulfurization equipment.
  • orientation indicators such as “top,” “bottom,” “up,’ “down,” “upper,” “lower,” “front,” “back,” etc. are used for illustration purposes only; the invention, however, is not so limited, and other possible orientations are contemplated.
  • a direct desulfurization system 100 comprises a mixing vessel 2.
  • a mixing vessel 2 may comprise any useful size, shape, dimensions or internal mixing features for combining a gas stream with a liquid stream, as would be understood by one skilled in the art.
  • a direct desulfurization system 100 comprises a (first) heating vessel (reheater) 4, a (first) reactor 6 and a (first) condenser 8.
  • the section of an embodiment of a direct desulfurization system 100 comprising a reheater, a reactor and a condenser constitutes a desulfurization zone 22.
  • direct desulfurization system 100 comprises additional desulfurization zones 22, namely, a second reheater 10, a second reactor 12 and a second condenser 14, as well as a third reheater 16, a third reactor 18 and a third condenser 20, although the invention is not so limited and a direct desulfurization system 100 may comprise a single desulfurization zone 22 or any useful number of desulfurization zones 22.
  • a reheater 4, 10 and/or 16 may comprise a vessel adapted and configured to adequately heat the process stream (not separately labeled) flowed thereinto.
  • a reactor 6, 12 and/or 18 may comprise a vessel adapted and configured to effect the catalyzed reaction between H2S and SO2 whereby S2 and H2O are produced, in accordance with the chemical reaction stoichiometry shown below: 2H 2 S + SO2 I.5S2 + 2H2O
  • a reactor of the present invention comprises a conventional Claus catalytic reactor, as would be understood by one skilled in the art, although the invention is not so limited and other types of catalytic reactors may be employed.
  • a condenser 8, 14 and/or 20 may comprise a separation vessel adapted and configured to provide for the condensation of S2 and separation thereof from the remainder of the process stream, as would be understood by one skilled in the art.
  • a direct desulfurization system 100 may comprise a “back-end” system 24 which may be utilized to further process the fluid stream.
  • the back-end system 24 may be fluidly connected to the final condenser in the series of components that constitutes the desulfurization system 100, although the invention is not so limited and the back-end system 24 may be otherwise fluidly connected to the desulfurization system 100 and/or fluidly connected to two or more components of the desulfurization system 100.
  • a back-end system 24 comprises a heater (pre-heater) 26, a hydrogenation reactor 28, a cooler 30 and a contacter (/. ⁇ ?., mixing device providing for physical contact and interaction of fluids) 32.
  • a pre-heater 26 may comprise a vessel adapted and configured to adequately heat the process stream 40 flowing from the desulfurization system 100.
  • a hydrogenation reactor 28 may comprise a vessel adapted and configured to mix an input stream comprising hydrogen gas (H2) (not shown) with the heated desulfurization system 100 output stream 40.
  • H2 hydrogen gas
  • a hydrogenation reactor 28 may comprise an existing refinery hydrogenation reactor, although the invention is not so limited and other types and/or purposed hydrogenation reactors may be employed.
  • a cooler 30 may comprise a vessel adapted and configured to cool the fluid stream exiting the hydrogenation reactor 28.
  • a back-end system 24 may comprise a quench tank, in additional to, or in lieu of, a cooler 30, as would be understood by one skilled in the art.
  • a contacter 32 comprises a vessel adapted and configured to separate the fluid gas stream into an overhead gas stream 34 and a bottoms liquid stream 36.
  • a back-end system 24 comprises a contacter inlet line 38 that directs liquid from an external source (now shown) into the contacter 32.
  • a back-end system 24A comprises one or more cold bed absorbers 48.
  • two cold bed absorbers 48A and 48B are utilized.
  • fluid output stream 40 is first only directed to cold bed absorber 48A, wherein that cold bed absorber is operated below the dew point of sulfur ( ⁇ 250°F to ⁇ 300°F), and sulfur contained in fluid output stream 40 is deposited as S2 therein.
  • the fluid contained within fluid output stream 40 that makes it past the cold bed absorber (without being deposited as S2) flows through cold bed absorber 48A drain piping 49A and enters cold bed absorber fluid output stream 50.
  • the S2 may be deposited in pores within a catalyst contained within the cold bed absorber 48A, z.e., the “bed,” as would be understood by one skilled in the art. This process continues until a desired amount of S2 has been deposited. In one aspect, such determination can be made through monitoring of deactivation of the catalyst. At this time, the fluid output stream 40 is diverted to cold bed absorber 48B to undergo similar processing.
  • a vessel may be provided between one or more of the cold bed absorbers 48 and the cold bed absorber fluid output stream 50, i.e., along drain piping 49A and/or 49B, to collect fluid from one cold bed absorber 48 while S2 is being collected from the other cold bed absorber 48.
  • cold bed absorber 48B In one embodiment, once the flow of fluid output stream 40 is diverted to cold bed absorber 48B, a hot gas is passed through the cold bed absorber 48A, thereby vaporizing the S2 contained there within and flowing it into cold bed absorber fluid output stream 50. Therein, the fluid is introduced to a cold bed absorber condenser 52 in fluid communication with cold bed absorber fluid output stream 50, and liquid S2 is diverted therefrom as another S2 output stream 46.
  • the cold bed absorbers 48A, 48B are operated alternatively in this fashion to continuously process fluid output stream 40, as would be understood by one skilled in the art.
  • crystallizers 54A and 54B are utilized.
  • a crystallizer 54 may comprise an exchanger whereby, similar to the process that occurs with the cold bed absorbers 48, the crystallizer 54 is operated alternatively in a “cold” mode (z.e., below the dew point of sulfur) and “hot” mode.
  • temperature control of a crystallizer 54 may be maintained via introduction of a hot fluid (e.g., steam) and a cold fluid (e.
  • any sulfur entering the crystallizer 54 is deposited therein as S2.
  • any solid S2 in the crystallizer is liquidized and flows though crystallizer drain piping 55A or 55B into crystallizer fluid output stream 56.
  • the liquidized S2 is introduced to a crystallizer condenser 58 in fluid communication with crystallizer fluid output stream 56, and S2 is diverted therefrom as another S2 output stream 46.
  • the crystallizers 54A, 54B are operated alternatively in this fashion to continuously process cold be absorber fluid output stream 56, as would be understood by one skilled in the art.
  • a vessel may be provided between one or more of the crystallizers 54 and the crystallizer fluid output stream 56, i.e., along drain piping 55A and/or 55B, to collect fluid from one crystallizer 54 while S2 is being collected from the other crystallizer 54.
  • back-end system 24A includes both one or more cold bed absorbers and one or more crystallizers, the embodiment is not so limited an in other embodiments (not shown), a back-end system 24A may comprise only one or more cold bed absorbers or one or more crystallizers.
  • a back-end system 24A may comprise only one or more cold bed absorbers or one or more crystallizers.
  • the sequence of the cold bed absorber(s) operationally preceding the crystallizer(s) can be reversed.
  • back-end system 24A comprises a quench tower 60.
  • a quench tower 60 may be provided to remove any remaining SO2 in the gas stream by circulating a slightly basic stream therethrough.
  • NaOH may be employed therefor.
  • this quench system (not separately numbered) comprises a quench tower 60, a circulating pump 62, a heat exchanger 64 and a filter 66.
  • the circulation loop comprises a waste output line 68, an overhead output line 70 and a base input line 72, as would be understood by one skilled in the art.
  • the total dissolved solids may be controlled by purging some of the circulating solution and making up with fresh water.
  • a base such as NaOH may be added.
  • a filter 66 on the circulating water stream can remove the remaining sulfur vapor that will be solidified when it is contacted with the water stream.
  • fluid flowing out of waste output line 68 can be treated as waste and fluid flowing out of overhead output line 70 may be further processed (not shown).
  • a mixing vessel 2 may comprise any useful mixing component(s) and/or mixing technology that can be configured and adapted to thoroughly mix the tow fluid streams, as would be understood by one skilled in the art.
  • a first stream 42 comprises a hydrocarbon and, as an impurity, hydrogen sulfide.
  • the first fluid stream 42 consists substantially of a gas, such as, but not limited to, natural gas.
  • the gas comprises a refinery fuel gas stream, although the invention is not so limited and other gas streams may be employed.
  • the first gas stream is supplied to the mixing vessel 2 under a pressure of about 60-100 psig, although other gas supply pressures may be employed.
  • the first gas stream 42 is supplied to the mixing vessel 2 at a temperature of about 75-150°F, although the invention is not so limited and other first stream 42 temperatures may be employed.
  • the first gas stream 42 may comprise about five percent hydrogen sulfide, although the invention is not so limited and the first stream 42 may comprise other concentrations of hydrogen sulfide.
  • a second stream 44 comprises gaseous sulfur dioxide.
  • the sulfur dioxide stream 44 may originate in an SO2 production unit, although any sulfur dioxide source(s) may be utilized.
  • the second gas stream is supplied to the mixing vessel 2 under a pressure of about 60-100 psig, although other gas supply pressures may be employed.
  • the second gas stream 44 is supplied to the mixing vessel 2 at a temperature of about 120-300°F, although the invention is not so limited and other second stream 44 temperatures may be employed.
  • the combined streams 42 and 44 are mixed within mixing vessel 2 and then the mixed fluid stream is flowed therefrom into a first desulfurization zone 22 which comprises a first reheater 4, a first reactor 6 and a first condenser 8.
  • this entails flow of the mixed fluid stream output of mixing vessel 2 being directed to the first reheater 4.
  • the reheater 4 heats the mixed fluid stream to about 550°F, although other reheating temperature profiles may be employed.
  • the fluid stream output of the first reheater 4 is directed to the first
  • the reheater 4 is operated such that the temperature in the converter 6 is maintained about 30°F above the sulfur dew point to prevent temporary deactivation of the Claus reactor catalyst.
  • the output fluid stream of the first converter 6 is maintained at about 600°F as it is flowed into the first condenser 8, although other converter temperature profiles may be employed.
  • the fluid stream is cooled within the condenser 8 to about 300-310°F, although other condenser temperature profiles may be employed.
  • a liquid (molten) sulfur output stream 46 flows from the first condenser 8 and the S2 thus obtained may be handled as desired, as would be understood by one skilled in the art.
  • a desulfurization system 100 may comprise a series of three desulfurization zones 22, but the invention is not so limited and in other embodiments (not shown) a desulfurization system 100 may comprise any configuration employing one or more desulfurization zones 22. Factors which may influence the number of desulfurization zones 22 employed include, but are not limited to, the composition of the hydrocarbon input stream 42, purity of the SO2 input stream 44 and the desired removal efficiency of the desulfurization system 100, as would be understood by one skilled in the art.
  • the fluid stream exiting the first condenser 4 is directed to a second reheater 10 wherein it is heated to about 460°F, although other reheating temperature profiles may be employed.
  • the fluid stream exiting the second reheater 10 is directed to a second converter 12, wherefrom it exits at about 470°F, (although other converter temperature profiles may be employed) and is directed to a second condenser 14.
  • the fluid stream is cooled to about 300-310°F by the second condenser 14, although other condenser temperature profiles may be employed.
  • a liquid (molten) sulfur output stream 46 flows from the second condenser 14 and the S2 as described above with regard to the first condenser 8.
  • the fluid stream exiting the second condenser 14 is directed to a third reheater 16 wherein it is heated to about 400°F, although other reheating temperature profiles may be employed.
  • the fluid stream exiting the third reheater 16 is directed to a third converter 18, wherefrom it exits at about 410°F, (although other converter temperature profiles may be employed) and is directed to a third condenser 20.
  • the fluid stream is cooled to about 270°F by the third condenser 20, although other condenser temperature profiles may be employed.
  • a liquid (molten) sulfur output stream 46 flows from the third condenser 14 and the S2 as described above with regard to the first condenser 8 and second condenser 14.
  • a substantially desulfurized fluid stream 40 exits from the third condenser 20, which, as described below regarding Figure 2, may be further manipulated.
  • the desulfurization system 100 can remove about 98% of the H2S introduced thereto.
  • a desulfurization system 100 comprising a back-end system 24 may be operated such that the fluid stream 40 exiting the third condenser 20 is directed to a pre-heater 26, wherein it is heated to about 450°F, although other pre-heating temperature profiles may be employed.
  • the fluid stream exiting the pre-heater 26 is directed to a hydrogenation reactor 28.
  • a hydrogen source (not shown) flows hydrogen gas (H2) into the hydrogenation reactor 28 wherein any residual SO2 and/or sulfur vapor is hydrogenated and thereby converted to hydrogen sulfide.
  • the hydrogen source may be a refinery gas stream, although any useful hydrogen source may be employed.
  • the hydrogenated fluid stream exits the hydrogenation reactor 28 at about 400-500°F although other hydrogenation temperature profiles may be employed.
  • the fluid stream exiting the hydrogenation reactor 28 is directed to a cooler 30, wherein the fluid stream is cooled to about 300°F.
  • the cooler 30 may be employed to produce steam, as would be understood by one skilled in the art.
  • the fluid stream exiting the cooler 30 is flowed directly to a contacter 32, although the invention is not so limited, and in other embodiments (not shown) additional equipment may be employed between the cooler 30 and the contacter 32 to further cool the fluid stream.
  • a water source (not shown) may be utilized to introduce water into the quench tank.
  • water within the quench tank serves to ensure that substantially all SO2 is removed from the vapor therewithin.
  • a small amount of caustic (NaOH) may be introduced into the quench tank to control the pH of the liquid therewithin.
  • a fluid stream 38 comprising an amine such as, but not limited to, diethylamine (DEA), is introduced into the contacter 32.
  • the amine-containing fluid stream 38 may originate in an industrial amine unit, although any source of amine may be employed.
  • the contacter 32 bottoms effluent 36 may be further manipulated, as would be understood by one skilled in the art.
  • the liquid bottoms effluent 36 may be directed back to the same amine unit from which the fluid stream 38 originates.
  • an overhead gaseous stream 34 exits the contacter 32 which may be further manipulated, as would be understood by one skilled in the art.
  • the overhead gaseous effluent 34 may be directed back to the same refinery fuel gas stream 42.
  • a desulfurization system 100 comprising a back-end system 24A may be operated as described above therefor.
  • a cold bed absorber 48 in an “absorption mode,” is operated below the sulfur dew point, at about 250°F to about 300°F. In one aspect, this greatly increases the Claus conversion which is favored by low temperature. Since the bed is operated below the sulfur dew point, sulfur is deposited in the converter bed which temporarily deactivates the catalyst.
  • a hot gas in one embodiment, ⁇ 600°F
  • the S2 is vaporized. The thus vaporized S2 flows as described above into cold bed absorber condenser 52 and is collected therefrom.
  • fluid that is provided to a crystallizer 54 experiences a first cold mode (typically 200°F to 230°F) wherein sulfur vapor solidifies, and then a hot mode (typically about 275°F to about 300°F), whereby the solid S2 liquifies and flows as described above into crystallizer condenser 58 and is collected therefrom.
  • gas exiting the crystallizer(s) 54 is routed to the quench tower 60 and processed as described above to remove residual SO2 contained therein.
  • partially and/or substantially desulfurized fluid streams may be obtained from any or all condensers within any or all desulfurization zones 22 of a desulfurization system 100.
  • back-end systems 24 and/or 24A may be employed with any or all desulfurization zones 22 of a desulfurization system
  • An exemplary method utilizing an embodiment of a desulfurization system of the present invention comprises:
  • a Desulfurization System Provision Step comprising providing a desulfurization system, such as desulfurization system 100, comprising a mixing vessel, such as mixing vessel 2, and one or more desulfurization zones, such as desulfurization zones 22, each comprising, in sequence, a reheater, such as reheater 4, a reactor, such as reactor 6, and a condenser, such as condenser 8;
  • a desulfurization system such as desulfurization system 100, comprising a mixing vessel, such as mixing vessel 2, and one or more desulfurization zones, such as desulfurization zones 22, each comprising, in sequence, a reheater, such as reheater 4, a reactor, such as reactor 6, and a condenser, such as condenser 8;
  • a Fluid Mixing Step comprising mixing a hydrocarbon fluid stream, such as hydrocarbon input stream 42, with a sulfur dioxide stream, such as SO2 input stream 44, in the mixing vessel;
  • a Desulfurization Step comprising flowing the mixed stream output from the mixing vessel though at least one desulfurization zone;
  • a Sulfur Removal Step comprising removing sulfur at least one desulfurization zone condenser.
  • a Hydrogenation Step comprising flowing a fluid output stream, such as fluid output stream 40, into a hydrogenation reactor, such as hydrogenation reactor 28, wherein hydrogen is reacted therewith;
  • a Cold Bed Absorption Step comprising flowing a fluid output stream, such as fluid output stream 40, into a cold be absorber, such as cold bed absorber 48, and first depositing S2 therein and then flow liquified S2 therefrom;
  • a Crystallization Step comprising flowing a fluid output stream, such as fluid output stream 50, into a crystallizer, such as crystallizer 54, and first depositing S2 therein and then flow liquified S2 therefrom;
  • a Sulfur Dioxide Removal Step comprising flowing the hydrogenated fluid stream exiting the hydrogenation reactor into a contacter, such as contacter 32, wherein the fluid stream is combined with water and/or an amine-containing fluid, such that SO2 is substantially nonexistent in a gaseous overhead stream exiting the contacter.
  • a Sulfur Dioxide Removal Step comprising flowing the stream exiting either a cold be absorber, such as cold bed absorber 48, or a crystallizer, such as crystallizer 54, into a circulating loop comprising a quench tower, such as quench tower 60, such that SO2 is substantially nonexistent in a gaseous overhead stream exiting the quench tower.
  • a cold be absorber such as cold bed absorber 48
  • a crystallizer such as crystallizer 54

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Gas Separation By Absorption (AREA)

Abstract

Des modes de réalisation d'un système de désulfuration de la présente invention comprennent généralement un récipient de mélange et une ou plusieurs zones de désulfuration, chaque zone de désulfuration comprenant, en séquence, un réchauffeur, un réacteur et un condenseur, le système de désulfuration pouvant fonctionner pour faire réagir du dioxyde de soufre avec un flux de gaz hydrocarboné contenant du sulfure d'hydrogène afin d'éliminer le sulfure d'hydrogène de celui-ci. Dans certains modes de réalisation, le système de désulfuration comprend également un système dorsal qui comprend un équipement conçu pour traiter en outre le flux de gaz hydrocarboné purifié. L'invention concerne également des procédés d'utilisation des modes de réalisation du système de désulfuration de la présente invention.
PCT/US2024/039742 2023-07-26 2024-07-26 Système et procédé de désulfuration directe Pending WO2025024763A2 (fr)

Applications Claiming Priority (4)

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US202363528989P 2023-07-26 2023-07-26
US63/528,989 2023-07-26
US18/785,293 2024-07-26
US18/785,293 US20250326979A1 (en) 2023-07-26 2024-07-26 Direct Desulfurization System and Method

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WO2025024763A2 true WO2025024763A2 (fr) 2025-01-30
WO2025024763A3 WO2025024763A3 (fr) 2025-05-01

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WO2025024763A3 (fr) * 2023-07-26 2025-05-01 Smith Strom W Système et procédé de désulfuration directe

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US20250326979A1 (en) * 2023-07-26 2025-10-23 Strom W. Smith Direct Desulfurization System and Method

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WO2025024763A3 (fr) * 2023-07-26 2025-05-01 Smith Strom W Système et procédé de désulfuration directe

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