WO2014198783A1 - Procédé d'oxydation du sulfure d'hydrogène - Google Patents

Procédé d'oxydation du sulfure d'hydrogène Download PDF

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Publication number
WO2014198783A1
WO2014198783A1 PCT/EP2014/062148 EP2014062148W WO2014198783A1 WO 2014198783 A1 WO2014198783 A1 WO 2014198783A1 EP 2014062148 W EP2014062148 W EP 2014062148W WO 2014198783 A1 WO2014198783 A1 WO 2014198783A1
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stream
gas
process according
feed gas
mol
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PCT/EP2014/062148
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English (en)
Inventor
Eri Ito
Diego Patricio VALENZUELA
Sipke Hidde Wadman
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Shell Internationale Research Maatschappij B.V.
Shell Oil Company
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Publication of WO2014198783A1 publication Critical patent/WO2014198783A1/fr

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    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/00—Sulfur; Compounds thereof
    • C01B17/02—Preparation of sulfur; Purification
    • C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
    • C01B17/0404—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process
    • C01B17/046—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 without intermediate formation of sulfur dioxide
    • C01B17/0469—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 without intermediate formation of sulfur dioxide at least one catalyst bed operating below the dew-point of sulfur
    • 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
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
    • B01D53/86—Catalytic processes
    • B01D53/8603—Removing sulfur compounds
    • B01D53/8612—Hydrogen sulfide
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/00—Sulfur; Compounds thereof
    • C01B17/02—Preparation of sulfur; Purification
    • C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
    • C01B17/0404—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/00—Sulfur; Compounds thereof
    • C01B17/02—Preparation of sulfur; Purification
    • C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
    • C01B17/0404—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process
    • C01B17/0426—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process characterised by the catalytic conversion
    • C01B17/0439—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process characterised by the catalytic conversion at least one catalyst bed operating below the dew-point of sulfur
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2255/00—Catalysts
    • B01D2255/20—Metals or compounds thereof
    • B01D2255/207—Transition metals
    • B01D2255/20707—Titanium

Definitions

  • the present invention relates to a process for the oxidation of hydrogen sulphide in a hydrogen sulphide- containing hydrocarbon feed gas to elemental sulphur.
  • a known industrial process for the conversion of hydrogen sulphide (3 ⁇ 4S) is the so-called Claus process.
  • 3 ⁇ 4S is reacted with sulphur dioxide (SO 2 ) to elemental sulphur and water according to the Claus reaction.
  • SO 2 sulphur dioxide
  • this reaction is performed in several stages at temperatures in the range of from 200 to 350°C and at near atmospheric pressures.
  • the elemental sulphur obtained polymerizes at these conditions.
  • 3 ⁇ 4S is typically obtained as part of a larger volume of hydrocarbon feed gas, such as natural gas.
  • hydrocarbon feed gas such as natural gas.
  • 3 ⁇ 4S is first separated from a hydrocarbon gas stream, e.g. by a solvent extraction process. After solvent regeneration, a 3 ⁇ 4S-rich gas is obtained at low pressure (typically about 1 to 2 bara) which is dealt with in the Claus process. About one third of the 3 ⁇ 4S in this gas is oxidized with air to SO 2 in a burner, according to:
  • Reaction (2) is typically performed at temperatures in the range of from 950 to 1450°C, preferably 1000 to 1200°C, and at pressures in the range of from 1 to 2 bar.
  • Reaction (2) is an exothermic reaction.
  • This S O2 is recycled to the catalytic zone in which elemental sulphur is formed according to
  • reaction (1) This generation of S O2 requires a large incinerator, and thus significant CAPEX.
  • step (b) supplying the H2 S-containing hydrocarbon feed gas as provided in step (a) and a sulphur dioxide ( S O2 ) - containing gas to a reaction zone comprising at least one catalytic zone comprising a catalyst;
  • step (c) contacting the H2 S-containing hydrocarbon feed gas comprising in the range of from 10 to 99.9 vol% of hydrocarbons and the S 02-containing gas as supplied in step (b) with a catalyst in the at least one catalytic zone,
  • the temperature in the catalytic zone being in the range of from 120 to 200°C
  • the pressure in the catalytic zone being in the range of from 4 to 200 bara
  • step (e) separating the first H2 S-depleted gaseous stream as obtained in step (d) thereby obtaining a concentrated H2 S-containing gaseous stream and a second 3 ⁇ 4S-depleted gaseous stream;
  • step (f) incinerating the concentrated H2 S-containing gaseous stream obtained in step (e) thereby obtaining a S O2 - containing stream;
  • step (g) using at least a part of the S 02-containing stream obtained in step (f) as the S 02-containing gas supplied in step (b) .
  • hydrocarbon streams with a relatively high hydrogen sulphide content i.e. above 0.5 vol% and up to 25- 50 vol%.
  • the process according to the invention does not require the separation of hydrogen sulphide or mercaptans from the hydrocarbon-comprising feed, such as in
  • hydrogen sulphide containing gas can be processed at the pressure at which it is produced or at which it becomes available.
  • Natural gas can for example be processed at the pressure at which it is produced at the well and effluents from a hydroprocessing or
  • gasification unit can be processed without depressurizing them. Additionally, the process of the present invention has the following advantages.
  • a further advantage of the process according to the present invention is that the risk of S O2 slip-through (into the first 3 ⁇ 4S-depleted gaseous stream) as compared to a process according to W02010 /060970 is avoided or at least minimized.
  • An even further advantage of the process according to the present invention is that the catalyst in the at least one catalytic zone has an expected longer service life as compared to a process according to W02010 /060970 , due to suppressed sulfation as a result of H2 S-rich operation in the catalytic zone. Sulfation is a known cause for deactivation of catalysts.
  • Another advantage is related to the natural gas sales specifications.
  • the process of the present invention it is possible to achieve very low levels of 3 ⁇ 4S, e.g. less than 4 ppm 3 ⁇ 4S, in natural gas with less extra 3 ⁇ 4S separation technology as compared to a process according to WO2010/060970.
  • a further advantage of the process according to the invention is that it is suited for the treatment of hydrocarbon feeds which comprise a relatively large amount of gasses that do not participate in the sulphur recovery reactions, such as carbon dioxide, as compared to the amount of hydrogen sulphide. There is no need to reduce the amount of such x inert' gasses before the reaction to elemental sulphur takes place.
  • 3 ⁇ 4S is oxidized to sulphur according to
  • the reaction can occur at higher pressures (e.g. 4 - 200 bara, preferably 10 - 150 bara) as compared to conventional Claus processes, thereby allowing higher capacity for a given reactor volume and ensuring that the first 3 ⁇ 4S-depleted gaseous stream maintains a high pressure .
  • higher pressures e.g. 4 - 200 bara, preferably 10 - 150 bara
  • the process according to the invention can be any process according to the invention.
  • the present invention can be used to oxidize 3 ⁇ 4S from various gaseous streams, for example light hydrocarbons, such as methane, ethane, propane, and gases derived from such light hydrocarbons; natural gas; gases derived from tar sand and shale oils; and gases associated with crude oil production.
  • light hydrocarbons such as methane, ethane, propane, and gases derived from such light hydrocarbons
  • natural gas gases derived from tar sand and shale oils
  • gases associated with crude oil production for example light hydrocarbons, such as methane, ethane, propane, and gases derived from such light hydrocarbons
  • natural gas gases derived from tar sand and shale oils
  • Fig. 1 schematically a process scheme for performing the method according to the present invention
  • Fig. 2 schematically a further process scheme for performing the method according to the present invention wherein the elemental sulphur and first 3 ⁇ 4S-depleted gaseous stream are removed from the catalytic zone as separate streams;
  • FIG. 3 schematically an even further embodiment of a process scheme for performing the method according to the present invention, wherein two catalytic zones 3A and 3B are used.
  • the present invention provides a process for the oxidation of hydrogen sulphide (3 ⁇ 4S) in an H2 S-containing hydrocarbon feed gas to elemental sulphur, the process at least comprising the steps of:
  • step (b) supplying the H2 S-containing hydrocarbon feed gas as provided in step (a) and a sulphur dioxide ( S O2 ) - containing gas to a reaction zone comprising at least one catalytic zone comprising a catalyst;
  • step (c) contacting the H2 S-containing hydrocarbon feed gas comprising in the range of from 10 to 99.9 vol% of hydrocarbons and the S 02-containing gas as supplied in step (b) with a catalyst in the at least one catalytic zone,
  • the temperature in the catalytic zone being in the range of from 120 to 200°C, and the pressure in the catalytic zone being in the range of from 4 to 200 bara, thereby forming elemental sulphur which is essentially in liquid form;
  • step (e) separating the first 3 ⁇ 4S-depleted gaseous stream as obtained in step (d) thereby obtaining a concentrated H2 S-containing gaseous stream and a second 3 ⁇ 4S-depleted gaseous stream;
  • step (f) incinerating the concentrated H2 S-containing gaseous stream obtained in step (e) thereby obtaining a S O2 - containing stream;
  • step (g) using at least a part of the S 02-containing stream obtained in step (f) as the S 02-containing gas supplied in step (b) .
  • an H2 S-containing hydrocarbon feed gas is provided.
  • the H2 S-containing hydrocarbon feed gas typically comprises - in addition to 3 ⁇ 4S and hydrocarbons - one or more of molecular hydrogen (3 ⁇ 4) , carbon monoxide
  • the H2 S-containing hydrocarbon feed gas comprises in the range of from 10 to 99.9 vol% of hydrocarbons.
  • the H2 S-containing hydrocarbon feed gas comprises at least 25 vol%, even more preferably at least 40 vol% of hydrocarbons, based on the total volume of the H2 S-containing feed gas. More preferably, the 3 ⁇ 4S- containing feed gas comprises in the range of from 40 to 99.5 vol%, even more preferably below 99 vol% of
  • the H2 S-comprising feed gas may comprise other sulphur compounds such as mercaptans, typically in the range of from 1 ppmv to 5 vol% (based on the total volume of the feed gas), COS, typically in the range of from 0.1 to 5000 ppmv (based on the total volume of the feed gas) , more typically from 0.1 to 2500 ppmv, and/or C S 2 .
  • mercaptans typically in the range of from 1 ppmv to 5 vol% (based on the total volume of the feed gas)
  • COS typically in the range of from 0.1 to 5000 ppmv (based on the total volume of the feed gas) , more typically from 0.1 to 2500 ppmv, and/or C S 2 .
  • the H2 S-containing feed gas provided in step (a) comprises from 0.1 to 50 vol% 3 ⁇ 4S based on the total volume of the H2 S-containing feed gas, preferably at least 0.5 vol% and preferably at most 30 vol ⁇ 6 , more preferably at most 25 vol%.
  • (a) may comprise from 0.1 to 89 vol% CO2 based on the total volume of the H2 S-containing feed gas, preferably in the range of from 1.0 to 50 vol%, more preferably in the range of from 1.0 to 30 vol%.
  • step (b) the H2 S-containing hydrocarbon feed gas as provided in step (a) and a S 02-containing gas are supplied to a reaction zone comprising at least one catalytic zone comprising a catalyst.
  • the combined H2 S-containing hydrocarbon feed gas and the S 02-containing gas supplied to the reaction zone comprise no more than 20 mol% water, preferably no more than 10 mol%, more preferably no more than 7.0 mol%.
  • Water is one of the reaction products of the reaction between 3 ⁇ 4S and S O2 and any water present in the gases supplied to the reaction zone negatively influences the equilibrium of reaction (1), by drawing the equilibrium toward the reactants side.
  • the molar ratio of H 2 S to S 0 2 (H 2 S/ S 0 2 ) supplied to the reaction zone in step (b) is in the range of from 2.0 to 20, preferably at least 2.3, more
  • the catalyst is a Ti0 2 -comprising catalyst.
  • a Ti0 2 -comprising catalyst typically has a high temperature stability, which is particular beneficial in case of unintended temperature rises in the reaction zone.
  • any COS or CS 2 present in the feed gas the S0 2 -containing gas supplied to the reaction zone or formed in the reaction zone is partly, substantially or fully converted to CO 2 , water and elemental sulphur.
  • Both COS and CS 2 are catalytically hydrolysed in the presence of the T1O 2 catalyst to CO 2 and 3 ⁇ 4S. The 3 ⁇ 4S is subsequently reacted with SO 2 . There is no need for a separate process to remove and/or convert COS or CS 2 prior to the process according to the invention .
  • step (c) the H 2 S-containing hydrocarbon feed gas comprising in the range of from 10 to 99.9 vol% of hydrocarbons and the S0 2 ⁇ containing gas as supplied in step (b) are contacted with a catalyst in the at least one catalytic zone, thereby forming elemental sulphur.
  • the conditions are such that the elemental sulphur formed is essentially in liquid form.
  • the temperature in the catalytic zone is in the range of from 120 to 200°C.
  • the pressure in the catalytic zone is in the range of from 4 to 200 bara.
  • the 3 ⁇ 4S reacts with the SO 2 as shown in formula (1) .
  • This reaction is exothermic.
  • Most of the heat released during the reaction is transported out of the catalytic zone together with the reaction products and the 3 ⁇ 4S depleted gas.
  • it may be preferably to provide additional means of cooling.
  • this can be achieved by using an inert liquid.
  • a gas recycle stream is used for cooling.
  • the reaction zone can be cooled using a multi-tubular reactor arrangement with catalyst and process gas inside each tubular reactor and a cooling medium such as water on the outside of the tubular reactors.
  • the reactor configuration in which the process of the present invention is performed can comprise one or more isothermal reactors, e.g. cooled reactors, and/or one or more adiabatic reactors. It is possible to combine an isothermal reactor and an adiabatic reactor in series, or as a staged reactor.
  • elemental sulphur is formed in step (c) essentially in liquid form.
  • elemental sulphur essentially in liquid form means that most of the elemental sulphur is liquid, and only a small amount is in the vapour phase at the temperature and pressure in the catalytic zone. Further, the elemental sulphur is liquid and not a gel at the temperature and pressure in the catalytic zone.
  • At least 70% of the elemental sulphur formed in step (c) has a dynamic viscosity below 1000 mPa-s (1000 milliPascal times second; i.e. 1000 cP
  • the dynamic viscosity preferably is at least 0.01 mPa-s, more preferably at least 0.5 mPa-s, even more preferably at least 1 mPa-s, at the temperature and pressure in the catalytic zone.
  • At least 80% of the elemental sulphur formed in step (c) has a dynamic viscosity below 1000 mPa-s, preferably below 500 mPa-s, even more preferably below 200 mPa-s, still more preferably below 100 mPa-s, still more preferably below 50 mPa-s, still even more preferably below 20 mPa-s at the temperature and pressure in the catalytic zone; and the dynamic viscosity
  • preferably is at least 0.01 mPa-s, more preferably at least 0.5 mPa-s, even more preferably at least 1 mPa-s, at the temperature and pressure in the catalytic zone.
  • At least 90% of the elemental sulphur formed in step (c) has a dynamic viscosity below 1000 mPa-s, preferably below 500 mPa-s, even more preferably below 200 mPa-s, still more preferably below 100 mPa-s, still more preferably below 50 mPa-s, still even more preferably below 20 mPa-s at the temperature and pressure in the catalytic zone; and the dynamic viscosity
  • preferably is at least 0.01 mPa-s, more preferably at least 0.5 mPa-s, even more preferably at least 1 mPa-s, at the temperature and pressure in the catalytic zone.
  • step (c) preferably at least 70%, more preferably at least 80%, even more preferably at least 90% of the elemental sulphur in the reaction zone(s) has a dynamic viscosity below 1000 mPa-s, preferably below 500 mPa-s, even more preferably below 200 mPa-s, still more
  • the dynamic viscosity preferably is at least 0.01 mPa-s, more preferably at least 0.5 mPa-s, even more preferably at least 1 mPa ⁇ s .
  • the process according to the invention may be a continuous process, contrary to many prior art processes for sulphur removal from gas stream, which require a batch wise process in order to allow for periodical regeneration of the catalyst due to sulphur deposits on the catalyst.
  • any mercaptans present in the feed gas to the reaction zone may be partly converted to polysulphides and 3 ⁇ 4S.
  • the 3 ⁇ 4S is subsequently reacted with SO 2 . There is no need to separate mercaptans from the feed gas prior to the present process.
  • the H 2 S-containing feed gas is contacted with the catalyst in step (c) at a normal gas hourly space velocity in the range of from 100 to 300,000
  • Nl/kg/h preferably of from 200 to 20,000 Nl/kg/h.
  • the H 2 S-containing feed gas has a residence time in the catalytic zone in step (c) of from 1 to 3000 seconds, preferably at least 5 seconds and preferably at most 60 seconds.
  • the temperature in the catalytic zone is in the range of from 120 to 200°C. In this way a significant
  • the temperature in the catalytic zone is at least 120°C, more preferably at least 125°C.
  • the temperature in the catalytic zone is at most 200°C, more preferably at most 190°C, even more preferably at most 180 °C, still more preferably at most 160 °C.
  • the temperature in the catalytic zone is in the range of from 120 to 135 °C, more preferably of from 125 to 135°C.
  • the temperature in the catalytic zone is at least 120 °C and may be up to 190 °C,
  • the pressure in the catalytic zone is in the range of from 4 to 200 bara, preferably from 10 to 150 bara.
  • step (d) a stream containing the elemental sulphur and a first 3 ⁇ 4S-depleted gaseous stream are removed from the catalytic zone.
  • the stream containing the elemental sulphur and the first 3 ⁇ 4S-depleted gaseous stream are typically removed as one stream and
  • the first 3 ⁇ 4S-depleted gaseous stream obtained in step (d) contains from 15 to 45 mol% 3 ⁇ 4S based on the amount of 3 ⁇ 4S present in the H 2 S-containing feed gas as provided in step (a) , preferably at least 20 mol%, more preferably at least 25 mol% and preferably at most 40 mol%.
  • the first 3 ⁇ 4S-depleted gaseous stream obtained in step (d) contains from 0.1 to 15 mol%, preferably at least 0.2 mol% and preferably at most 10 mol% H 2 S.
  • step (d) a part of the first 3 ⁇ 4S- depleted gaseous stream obtained in step (d) is recycled and supplied to the reaction zone in step (b) .
  • This allows for regulation of the 3 ⁇ 4S concentration at the inlet of the reaction zone, thereby optimizing the performance of the reaction zone.
  • step (e) the first H 2 S-depleted gaseous stream as obtained in step (d) is separated thereby obtaining a concentrated H 2 S-containing gaseous stream and a second 3 ⁇ 4S-depleted gaseous stream.
  • this separation can be performed in several ways, such as using solvent
  • the concentrated H 2 S-containing gaseous stream comprises from 5.0 to 100 mol% 3 ⁇ 4S, preferably at least 7.0 mol%, more preferably at least 10 mol%, even more preferably at least 20 mol% and yet even more preferably at least 25 mol% 3 ⁇ 4S.
  • the second 3 ⁇ 4S- depleted gaseous stream typically comprises 1-10,000 ppm
  • 3 ⁇ 4S more typically at least 2 ppm, even more typically at least 3 ppm and preferably at most 200 ppm, more preferably at most 20 ppm 3 ⁇ 4S.
  • the second 3 ⁇ 4S-depleted gas stream may be further treated and is usually dried (e.g. using cooling with liquid water knock-out, molsieves or glycol dehydration) .
  • the second 3 ⁇ 4S-depleted gaseous stream may be further separated to provide specific hydrocarbon products, e.g. LPG, C5+, or natural gas having sales specifications, or may be further processed to produce LNG (Liquefied
  • Any separated LPG or C5+ may be treated with e.g. amine or caustic to remove COS and mercaptans, if any.
  • the first 3 ⁇ 4S-depleted gaseous stream as obtained in step (d) is treated before it is separated in step (e) .
  • step (d) it is preferred to place a T1O2 bed downstream from step (d) to scavenge the remaining SO2 from the gas before the gas enters the amine reactor in which step (e) takes place.
  • this T1O2 bed is placed before cooling equipments.
  • step (f) the concentrated H 2 S-containing gaseous stream obtained in step (e) is incinerated thereby obtaining a S0 2 -containing stream. If needed, additional fuel may be added. Typically, in step (f) also water is obtained; this water may be removed, if desired, but this is not required.
  • the S0 2 -containing stream obtained in step (f) is separated thereby obtaining a concentrated SO 2 stream (and a C0 2 / 2 -enriched stream) .
  • the concentrated SO 2 stream comprises at least 60 mol% SO 2 , preferably at least 70 mol% SO 2 , more preferably at least
  • the concentrated SO 2 stream is pressurized before being used as the S0 2 -containing gas supplied in step (b) .
  • the concentrated SO 2 stream is compressed to sour gas feed pressure, which is typically from 10 to 150 bara.
  • Step (g) In step (g) , at least a part of the S0 2 -containing stream obtained in step (f) is used as the S0 2 -containing gas supplied in step (b) .
  • Fig. 1 schematically a process scheme for performing the method according to the present invention
  • Fig. 2 schematically a further process scheme for performing the method according to the present invention wherein the elemental sulphur and first 3 ⁇ 4S-depleted gaseous stream are removed from the catalytic zone as separate streams;
  • FIG. 3 schematically an even further embodiment of a process scheme for performing the method according to the present invention, wherein two catalytic zones 3A and 3B are used.
  • Fig. 1 schematically shows a process scheme for the oxidation of 3 ⁇ 4S in an H 2 S-containing hydrocarbon feed gas to elemental sulphur.
  • the process scheme is generally referred to with reference number 1.
  • the process scheme 1 comprises a reaction zone 2, a catalytic zone 3 (containing a fixed bed of T1O 2
  • reaction zone 2 has a single catalytic zone 3; the person skilled in the art will readily understand that two or more catalytic zones (in series or parallel) optionally with different types of reactors (such as actively cooled reactors and/or adiabatically cooled reactors) may be used (see e.g. WO 2010/060970, the teaching of which is hereby incorporated by reference and Fig. 3 hereinafter) .
  • a H2 S-containing feed gas 10 (such as natural gas containing 3 ⁇ 4S) is supplied to the catalytic zone 3 in reaction zone 2, together with a S 02-containing gas 20.
  • a H2 S-containing feed gas 10 and S O2 - containing gas 20 may be combined before supplying to the catalytic zone 3 in reaction zone 2.
  • the H2 S-containing feed gas 10 and the S 02-containing gas 20 are contacted with a catalyst and converted, thereby forming elemental sulphur, under such conditions that the elemental sulphur formed is essentially in liquid form.
  • a stream 30 containing elemental sulphur and 3 ⁇ 4S is removed from the catalytic zone 3.
  • stream 30 is separated in gas/liquid-separator 4, thereby obtaining a stream 40 enriched in elemental sulphur and a first 3 ⁇ 4S-depleted gaseous stream 50.
  • the stream 40 enriched in elemental sulphur is typically further treated and may subsequently be sold on the market. If desired (not shown), part of stream 40 may be recycled to the reaction zone 2.
  • the first 3 ⁇ 4S-depleted gaseous stream 50 is separated in separator 5 thereby obtaining a concentrated 3 ⁇ 4S- containing gaseous stream 60 and a second 3 ⁇ 4S-depleted gaseous stream 70.
  • the second 3 ⁇ 4S-depleted gaseous stream 70 may be further treated to e.g. remove residual 3 ⁇ 4S, mercaptans, water and other contaminants, if needed, and sent to the grid or further separated to provide specific hydrocarbon products or further processed to produce LNG (Liquefied Natural Gas) .
  • the concentrated H 2 S-containing gaseous stream 60 is incinerated in combustor 6 (whilst adding air or oxygen stream 110, and if desired, additional fuel) thereby obtaining a S0 2 -containing stream 80.
  • the S0 2 -containing stream 80 is separated in separator 7 (typically to remove SO 2 from the other component such as CO 2 , 2 and O 2 ) thereby obtaining a concentrated SO 2 stream 90 and a
  • the concentrated SO 2 stream 90 is subsequently compressed before being used as the SO 2 - containing gas 20 supplied to the catalytic zone 3.
  • a part 120 of the first 3 ⁇ 4S-depleted gaseous stream 50 is recycled and supplied to the reaction zone 2 to assist in cooling of the reaction zone.
  • the stream 120 is
  • Stream 30 is sent to the gas/liquid- separator 4 thereby obtaining a stream 40 enriched in elemental sulphur and a H 2 S-containing stream 45. If desired, part or all of stream 45 may be combined with the concentrated H 2 S-containing gaseous stream 60.
  • Figure 3 shows an alternative embodiment of a process scheme for performing the method according to the present invention, wherein two catalytic zones 3A and 3B are used. As can be seen, two gas/liquid separators 4A and 4B are used (instead of one in Figure 1) . After removing stream 30A (containing elemental sulphur, gaseous 3 ⁇ 4S and non-reacted gaseous components such as methane) from the first catalytic zone 3A, it is separated in first
  • gas/liquid separator 4A thereby obtaining a stream 40A enriched in elemental sulphur and a stream 35 which is passed to the second catalytic zone 3B.
  • Stream 30 and the first 3 ⁇ 4S-depleted gaseous stream 50 are removed as separated streams from the second catalytic zone 3B (but may, as shown in Figure 1, be removed as a single stream and subsequently be separated to generate stream 50).
  • Stream 30 is separated in the second gas/liquid separator 4B thereby obtaining a stream 40B enriched in elemental sulphur.
  • Streams 40A and 40B are combined to form stream 40 and may be further purified/degassed to obtain a pure sulphur product.
  • Stream 50 is processed as discussed for Fig. 1.
  • the concentrated SO 2 stream 90 is pressurized before being used as the S0 2 -containing gas streams 20A and 20B supplied to the catalytic zones 3A, 3B.
  • reaction zone 2 and the separator 4 may be placed inside one and the same pressure vessel;
  • the temperature of the process streams 10, 20, 30, 40, 45, 50, 60, 70, 80, 90, 120 may be regulated by heating or cooling;
  • the temperature and pressure of the concentrated SO 2 stream 90 may be regulated such that this stream is in liquid form to allow pumping thereof; - Coolers may be provided to cool the reaction zone 2 or parts thereof to reduce temperature increase in the reaction zone 2 ;
  • - Equipment such as O2 enrichment membranes, cryogenic air separation units or the like
  • O2 enrichment membranes such as cryogenic air separation units or the like
  • reaction zone 2 may be injected into reaction zone 2 at multiple locations ;
  • the catalytic zone 3 may be embodied in various ways.
  • Tables 1 and 2 below show actual non-limiting examples, providing information on conditions and composition of the various streams, whilst using the process scheme and stream numbers of Figure 2, for the oxidation of 3 ⁇ 4S in an H2 S-containing feed gas.
  • Table 1 shows a first embodiment wherein the feed stream contains a relatively high amount of 3 ⁇ 4S (26.3 mol%)
  • Table 2 shows a second embodiment wherein the feed stream contains a relatively low amount of 3 ⁇ 4S (0.8 mol%) .
  • the molar H2 S / S O2 ratio supplied to the reaction zone 2 was 3.0 for the high 3 ⁇ 4S embodiment of Table 1 and 3.0 for the low 3 ⁇ 4S embodiment of Table 2.
  • the normal gas hourly space velocity for feed gas stream 10 was 8000 Nl/kg/h. Further the pressure in catalytic zone was 75 bara and the temperature 130 °C. Table 1

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  • Inorganic Chemistry (AREA)
  • Environmental & Geological Engineering (AREA)
  • Materials Engineering (AREA)
  • Biomedical Technology (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • General Chemical & Material Sciences (AREA)
  • Analytical Chemistry (AREA)
  • Health & Medical Sciences (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

Cette invention concerne un procédé d'oxydation du sulfure d'hydrogène (H2S) dans un gaz d'alimentation hydrocarboné contenant du H2S en soufre élémentaire. Dans le procédé, un gaz d'alimentation hydrocarboné contenant du H2S (10) et un gaz contenant du dioxyde de soufre (20) sont mis en contact dans une zone catalytique (3) à une température de 120 à 200°C, et une pression de 4 à 200 bars, pour former ainsi du soufre élémentaire qui est essentiellement sous forme liquide. Un flux (30) contenant du soufre élémentaire et un premier flux gazeux appauvri en H2S (50) sont retirés de la zone catalytique (3). Le premier flux gazeux appauvri en H2S (50) est séparé, pour obtenir ainsi un flux gazeux contenant du H2S concentré (60) et un second flux gazeux appauvri en H2S (70). Le flux gazeux contenant du H2S concentré (60) est incinéré, pour obtenir un flux contenant du SO2 (80), une partie au moins dudit flux contenant du SO2 (80) étant utilisé à titre de gaz contenant du SO2 (20) chargé dans l'étape (b).
PCT/EP2014/062148 2013-06-14 2014-06-11 Procédé d'oxydation du sulfure d'hydrogène WO2014198783A1 (fr)

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EP13172090.6 2013-06-14
EP13172090 2013-06-14

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WO2014198783A1 true WO2014198783A1 (fr) 2014-12-18

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Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN113401879A (zh) * 2021-07-30 2021-09-17 南京汇仁化工设备有限公司 一种焚硫炉

Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20030194366A1 (en) * 2002-03-25 2003-10-16 Girish Srinivas Catalysts and process for oxidizing hydrogen sulfide to sulfur dioxide and sulfur
EP1230149B1 (fr) * 1999-10-22 2005-12-14 MECS, Inc. Procede de production du soufre
EP1642864A2 (fr) * 1999-10-22 2006-04-05 MECS, Inc. Procédé de production du soufre
US20100098618A1 (en) * 2008-10-20 2010-04-22 Keller Alfred E Sulfur removal from gases
WO2010060970A1 (fr) 2008-11-28 2010-06-03 Shell Internationale Research Maatschappij B.V. Procédé d’oxydation sélective de sulfure d'hydrogène
US8440160B1 (en) * 2012-01-06 2013-05-14 Mahin Rameshni Integrated sulfur recovery methods in power plants and low BTU gas fields

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP1230149B1 (fr) * 1999-10-22 2005-12-14 MECS, Inc. Procede de production du soufre
EP1642864A2 (fr) * 1999-10-22 2006-04-05 MECS, Inc. Procédé de production du soufre
US20030194366A1 (en) * 2002-03-25 2003-10-16 Girish Srinivas Catalysts and process for oxidizing hydrogen sulfide to sulfur dioxide and sulfur
US20100098618A1 (en) * 2008-10-20 2010-04-22 Keller Alfred E Sulfur removal from gases
WO2010060970A1 (fr) 2008-11-28 2010-06-03 Shell Internationale Research Maatschappij B.V. Procédé d’oxydation sélective de sulfure d'hydrogène
US8440160B1 (en) * 2012-01-06 2013-05-14 Mahin Rameshni Integrated sulfur recovery methods in power plants and low BTU gas fields

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN113401879A (zh) * 2021-07-30 2021-09-17 南京汇仁化工设备有限公司 一种焚硫炉
CN113401879B (zh) * 2021-07-30 2023-06-20 南京汇仁化工设备有限公司 一种焚硫炉

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