WO2017072649A1 - Methods and systems for producing syngas from carbon dioxide and hydrogen - Google Patents

Methods and systems for producing syngas from carbon dioxide and hydrogen Download PDF

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Publication number
WO2017072649A1
WO2017072649A1 PCT/IB2016/056387 IB2016056387W WO2017072649A1 WO 2017072649 A1 WO2017072649 A1 WO 2017072649A1 IB 2016056387 W IB2016056387 W IB 2016056387W WO 2017072649 A1 WO2017072649 A1 WO 2017072649A1
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Prior art keywords
stream
feedstream
carbon dioxide
syngas
temperature
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PCT/IB2016/056387
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French (fr)
Inventor
Mubarik Ali BASHIR
Awais Ahmed
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Sabic Global Technologies B.V.
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Publication of WO2017072649A1 publication Critical patent/WO2017072649A1/en

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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
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K3/00—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide
    • C10K3/02—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide by catalytic treatment
    • C10K3/026—Increasing the carbon monoxide content, e.g. reverse water-gas shift [RWGS]

Definitions

  • the presently disclosed subject matter relates to methods and systems for generating syngas from carbon dioxide and hydrogen through a reverse water gas shift (RWGS) reaction.
  • RWGS reverse water gas shift
  • Syngas includes hydrogen (H 2 ) and carbon monoxide (CO) and can further contain other gas components, e.g., carbon dioxide (C0 2 ), steam (H 2 0), methane (CH 4 ) and/or nitrogen (N 2 ).
  • Syngas Natural gas and light hydrocarbons are the predominant starting materials for producing syngas.
  • Syngas is often produced from natural gas through steam reforming, partial oxidation, dry reforming or by an auto-thermal reforming reaction.
  • Syngas can also be produced by the hydrogenation of C0 2 .
  • the syngas produced by these methods can be used in the production of chemical products, such as methanol, oxo alcohol, olefins, dimethyl ether and methyl ethyl glycol, or can be used in the Fischer- Tropsch process to generate higher hydrocarbons, such as fuels.
  • the stoichiometric ratio of 3 ⁇ 4 to CO of the syngas in the reactant stream is important in determining which hydrocarbons are produced. Thus, it is desirable to precisely control the stoichiometric ratio of 3 ⁇ 4 to CO in the syngas.
  • U.S. patent publication No. 2003/0110694 discloses a method of steam reforming methane to form syngas, which includes enriching the stream with oxygen to increase the rate of syngas production.
  • U.S. Patent 6,981,994 discloses a process for driving the steam reforming reaction with heat from the combustion of fuel and oxygen.
  • WO 2014/111310 discloses reacting methane and carbon dioxide to generate syngas by reforming methane in the presence of a catalyst.
  • U.S. Patent Publication No. 2007/0244208 discloses methods for the production of fuel such as high octane gasoline that include the conversion of carbon dioxide and hydrogen into intermediates, such as carbon monoxide and water and/or methanol.
  • the presently disclosed subject matter provides methods for generating syngas from carbon dioxide and hydrogen through a reverse water gas shift (RWGS) reaction.
  • RWGS reverse water gas shift
  • methods for producing syngas from a first feedstream containing carbon dioxide, a second feedstream containing oxygen and a third feedstream containing natural gas include combusting the first, second and third feedstreams to produce an effluent stream containing carbon dioxide.
  • the method can further include combining the effluent stream with a stream containing hydrogen to generate a reactant stream containing carbon dioxide and hydrogen.
  • the method can include contacting the reactant stream with a catalyst to produce a product stream that contains syngas.
  • the syngas in the product stream has a hydrogen to carbon monoxide ratio of about 1 : 1 to about 3: 1.
  • the method can further include pressurizing one or more of the first, second and third feedstreams to a pressure of about 10 to about 40 bar prior to the combustion of the first, second and third feedstreams.
  • the method can further include increasing the temperature of the first feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the first feedstream.
  • the method can further include increasing the temperature of the second feedstream to a temperature from about 250 °C to about 350 °C prior to combustion of the second feedstream.
  • the method can further include increasing the temperature of the third feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the third feedstream.
  • the method can include combining the first and second feedstreams prior to feeding the first and second feedstreams into the combustion zone. In certain embodiments, the method can further include increasing the temperature of the stream containing hydrogen to a temperature from about 350 °C to about 650 °C. In certain embodiments, the reactant stream has a temperature greater than about 1100 °C.
  • the method can further include recovering heat from the product stream to reduce the temperature of the product stream and generate a cooled product stream.
  • the recovered heat can be used to increase the temperature of one or more of the first, second, and third feedstreams prior to combustion.
  • the recovered heat is used to generate steam.
  • the method can include recovering unconverted carbon dioxide from the cooled product stream.
  • the presently disclosed subject matter further provides methods for producing syngas from a first feedstream containing carbon dioxide, a second feedstream containing oxygen and a third feedstream containing natural gas.
  • Some example methods include increasing the temperature of the first feedstream, second feedstream and third feedstream.
  • the method can further include feeding the heated first, second and third feedstreams into a combustion zone to produce an effluent stream containing carbon dioxide.
  • the method can include combining the effluent stream with a stream containing hydrogen to generate a reactant stream containing carbon dioxide and hydrogen.
  • the method can further include contacting the reactant stream with a catalyst to produce a product stream containing syngas and steam.
  • the method can include reducing the temperature of the product stream to generate a cooled product stream to condense the steam in the product stream into water and include separating the water from the syngas in the cooled product stream to produce a syngas stream.
  • the presently disclosed subject matter further provides a system for producing syngas that includes a combustion zone for producing a stream of heated carbon dioxide from one or more feedstreams containing hydrocarbons, e.g., natural gas, oxygen, and carbon dioxide.
  • the system can further include a mixing zone, coupled to the combustion zone, for mixing the stream of heated carbon dioxide with a stream containing hydrogen.
  • the system can include a reaction zone, coupled to the mixing zone, for reacting carbon dioxide and hydrogen to form a product stream containing syngas.
  • the system can further include one or more heat exchangers, coupled to the combustion zone, for heating the one or more feedstreams containing hydrocarbons, oxygen, and carbon dioxide.
  • the system can include a heat exchanger, coupled to the mixing zone, for heating the stream containing hydrogen.
  • the system can include a heat recovery unit coupled to the reaction zone, e.g., for recovering heat from the product stream.
  • the system can further include a transfer line coupled to the heat recovery unit, for transferring recovered heat to the one or more heat exchangers coupled to the combustion zone.
  • the system can include a transfer line coupled to the heat recovery unit, for transferring recovered heat to the heat exchanger coupled to the mixing zone.
  • the system can further include a steam generator, coupled to the heat recovery unit, for producing steam from the recovered heat.
  • the system can further include a separation unit, coupled to the reaction zone, for separating a syngas stream from the product stream.
  • the separation unit includes a condenser for removing water from the product stream.
  • the separation unit includes a carbon dioxide separation unit for removing carbon dioxide from the product stream.
  • the system can further include a transfer line, coupled to the carbon dioxide separation unit, for transferring a stream containing carbon dioxide to the combustion zone.
  • Embodiment 1 is a method for producing syngas from a first feedstream comprising carbon dioxide, a second feedstream comprising oxygen and a third feedstream comprising natural gas, comprising: (a) combusting the first, second and third feedstreams to produce an effluent stream comprising carbon dioxide; (b) combining the effluent stream with a stream comprising hydrogen to generate a reactant stream comprising carbon dioxide and hydrogen; and (c) catalyzing the reactant stream to produce a product stream comprising syngas.
  • Embodiment 2 is the method of embodiment 1, further comprising pressurizing one or more of the first, second and third feedstreams to a pressure of about 10 to about 40 bar prior to combustion of the first, second and third feedstreams.
  • Embodiment 3 is the method of embodiment 1, further comprising increasing the temperature of the first feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the first feedstream.
  • Embodiment 4 is the method of embodiment 1, further comprising increasing the temperature of the second feedstream to a temperature from about 250 °C to about 350 °C prior to combustion of the second feedstream.
  • Embodiment 5 is the method of embodiment 1, further comprising increasing the temperature of the third feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the third feedstream.
  • Embodiment 6 is the method of embodiment 1, wherein the reactant stream has a temperature greater than about 1100 °C.
  • Embodiment 7 is the method of embodiment 1, further comprising combining the first and second feedstreams prior to combustion.
  • Embodiment 8 is the method of embodiment 1, further comprising increasing the temperature of the stream comprising hydrogen to a temperature from about 350 °C to about 650 °C.
  • Embodiment 9 is the method of embodiment 1, wherein the catalyzing comprises using as a catalyst.
  • Embodiment 10 is the method of embodiment 1, wherein the syngas in the product stream has a molar ratio of hydrogen to carbon monoxide of about 1 : 1 to about 3: 1.
  • Embodiment 11 is the method of embodiment 1, further comprising recovering heat from the product stream to produce a cooled product stream.
  • Embodiment 12 is the method of embodiment 11, further comprising using the recovered heat to increase the temperature of one or more of the first, second, and third feedstreams prior to combustion.
  • Embodiment 13 is the method of embodiment 11, wherein the recovered heat is used to generate steam.
  • Embodiment 14 is the method of embodiment 11, wherein the temperature of cooled product stream is less than about 100 °C.
  • Embodiment 15 is the method of embodiment 11 , further comprising recovering unconverted carbon dioxide from the cooled product stream to generate a syngas stream.
  • Embodiment 16 is a method for producing syngas from a first feedstream comprising carbon dioxide, a second feedstream comprising oxygen and a third feedstream comprising natural gas, comprising: (a) increasing the temperature of the first feedstream, second feedstream and third feedstream; (b) feeding the heated first, second and third feedstreams into a combustion zone to produce an effluent stream comprising carbon dioxide; (c) combining the effluent stream with a stream comprising hydrogen to generate a reactant stream comprising carbon dioxide and hydrogen; (d) catalyzing the reactant stream to produce a product stream comprising syngas and steam; (e) reducing the temperature of the product stream to generate a cooled product stream and to condense the steam in the product stream into water; and (f) separating the water from the syngas in the cooled product stream to produce a purified syngas stream.
  • Embodiment 17 is a system for producing syngas, comprising: (a) a combustion zone for producing a stream of heated carbon dioxide from one or more feedstreams comprising hydrocarbons, oxygen, and carbon dioxide; (b) a mixing zone, coupled to the combustion zone, for mixing the stream of heated carbon dioxide with a stream containing hydrogen; and (c) a reaction zone, coupled to the mixing zone, for reacting carbon dioxide and hydrogen to produce a product stream comprising syngas.
  • Embodiment 18 is the system of embodiment 17, further comprising one or more heat exchangers, coupled to the combustion zone, for heating the one or more feedstreams comprising hydrocarbons, oxygen, and carbon dioxide.
  • Embodiment 19 is the system of embodiment 17 or 18, further comprising a heat exchanger, coupled to the mixing zone, for heating the stream containing hydrogen.
  • Embodiment 20 is the system of embodiment 17 or 18, further comprising a heat recovery unit coupled to the reaction zone.
  • Embodiment 21 is the system of embodiment 20, further comprising a transfer line, coupled to the heat recovery unit, for transferring recovered heat to the one or more heat exchangers coupled to the combustion zone.
  • Embodiment 22 is the system of embodiment 20, further comprising a transfer line, coupled to the heat recovery unit, for transferring recovered heat to the heat exchanger coupled to the mixing zone.
  • Embodiment 23 is the system of embodiment 20, further comprising a steam generator, coupled to the heat recovery unit, for producing steam from the recovered heat.
  • Embodiment 24 is the system of embodiment 17 or 20, further comprising a separation unit coupled to the reaction zone.
  • Embodiment 25 is the system of embodiment 24, wherein the separation unit comprises a condenser for removing water from the product stream.
  • Embodiment 26 is the system of embodiment 24, wherein the separation unit comprises a carbon dioxide separation unit for removing carbon dioxide from the product stream.
  • Embodiment 27 is the system of embodiment 26, further comprising a transfer line coupled to the carbon dioxide separation unit for transferring a stream comprising carbon dioxide to the combustion zone.
  • FIG. 1 is a schematic diagram depicting an exemplary system in accordance with a non-limiting embodiment of the disclosed subject matter.
  • FIG. 2 is a schematic diagram depicting an exemplary method in accordance with a non-limiting embodiment of the disclosed subject matter.
  • the presently disclosed subject matter relates to methods for generating syngas from carbon dioxide and hydrogen through a reverse water gas shift (RWGS) reaction.
  • RWGS reverse water gas shift
  • the presently disclosed subject matter provides a method for adjusting the stoichiometric ratio of hydrogen to carbon monoxide in the generated syngas by controlling the temperature of the RWGS reaction and the ratio of the reactants, hydrogen and carbon dioxide.
  • Carbon dioxide (C0 2 ) can be selectively converted into carbon monoxide (CO) by a RWGS reaction in the presence of a catalyst and hydrogen (H 2 ) under certain reaction conditions.
  • the resulting product of this C0 2 hydrogenation process is a gas mixture called syngas, which can also be referred to as synthesis gas.
  • Syngas formed by the RWGS reaction includes carbon monoxide and hydrogen, and can further contain water and non-converted carbon dioxide.
  • the RWGS reaction can be represented by the following equation:
  • FIG. 2 is a schematic representation of a method according to a non-limiting embodiment of the disclosed subject matter.
  • the method 200 can include providing one or more feedstreams 201.
  • the method 200 can include providing 3 or more feedstreams, e.g., a first feedstream, a second feedstream and a third feedstream.
  • the first feedstream can include carbon dioxide.
  • the second feedstream can include oxygen.
  • the third feedstream can include hydrocarbons.
  • the first feedstream, second feedstream and third feedstream can be provided as a single combined feedstream containing oxygen, carbon dioxide and hydrocarbons.
  • the first and second feedstream can be provided as a single combined feedstream containing oxygen and carbon dioxide.
  • the C0 2 used in the method of the presently disclosed subject matter can originate from various sources.
  • the C0 2 can come from a waste gas stream, e.g., from a plant on the same site, or after recovering C0 2 from a gas stream. Recycling C0 2 as starting material in the methods of the presently disclosed subject matter can contribute to reducing the amount of C0 2 emitted to the atmosphere, e.g., from a chemical production site.
  • the C0 2 used within the feedstream can also, at least partly, originate from the effluent gas or product of the disclosed methods and recycled back to the reactor in the feedstream.
  • the C0 2 feedstream is pressurized to have a pressure from about 2 to about 100 bar, from about 5 to about 70 bar, from about 10 to about 40 bar or from about 20 to about 30 bar.
  • the term “about” or “approximately” means within an acceptable error range for the particular value as determined by one of ordinary skill in the art, which will depend in part on how the value is measured or determined, i.e., the limitations of the measurement system. For example, “about” can mean a range of up to 20%, up to 10%, up to 5% and/or up to 1% of a given value.
  • the 0 2 used in the method of the presently disclosed subject matter can originate from various sources.
  • air containing oxygen can be used.
  • the 0 2 feedstream is pressurized to have a pressure from about 2 to about 100 bar, from about 5 to about 70 bar, from about 10 to about 40 bar or from about 20 to about 30 bar.
  • the hydrocarbons used in the method of the presently disclosed subject matter can originate from various sources.
  • the third feedstream contains natural gas, e.g., desulfurized natural gas, or methane (CH 4 ).
  • the CH 4 can originate from various sources, for example, and not by way of limitation, the CH 4 can be obtained from associated natural gas, non-associated natural gas, shale gas, biogas, coal bed gas and/or methane hydrate.
  • the third feedstream contains desulfurized C2 to C5 hydrocarbons.
  • the third feedstream contains a mixture of natural gas, CH 4 , and C2 to C5 hydrocarbons.
  • the hydrocarbon feedstream is pressurized to have a pressure from about 2 to about 100 bar, from about 5 to about 70 bar, from about 10 to about 40 bar or from about 20 to about 30 bar.
  • the first, second and/or third feedstreams can be preheated, e.g., in one or more heat exchangers.
  • each feedstream can be preheated in a separate heat exchanger.
  • the first and second feedstream can be combined and preheated in a single heat exchanger.
  • the first, second and third feedstreams can be preheated to a temperature from about 100 to about 1000 °C, e.g., from about 250 to about 650 °C, from about 250 to about 350 °C or from about 350 to about 650 °C.
  • the third feedstream can be preheated to a temperature from about 250 to about 350 °C.
  • the first feedstream can be preheated to a temperature from about 350 to about 650 °C.
  • the second feedstream can be preheated to a temperature from about 350 to about 650 °C.
  • the combined first and second feedstreams can be preheated to a temperature from about 350 to about 650 °C.
  • the method 200 can include combusting one or more of the feedstreams, e.g., the first, second and/or third feedstreams, to produce an effluent stream 202.
  • the first, second and third feedstreams can be combusted in a combustion zone, e.g., within a pressure vessel.
  • the flow ratio of the second feedstream (containing 0 2 ) to the third feedstream (containing hydrocarbons) transferred to the combustion zone can be stoichiometric or sub-stoichiometric.
  • the flow rate of the first feedstream (containing C0 2 ) can be moderated to control the temperature of the combustion zone and effluent stream.
  • the effluent stream can also include water, oxygen and/or uncombusted hydrocarbons.
  • the effluent stream can include greater than about 50% C0 2 , greater than about 70% C0 2 , greater than about 85% C0 2 or greater than about 90% C0 2 .
  • the temperature of the effluent stream can range from about 500 to about 2000 °C, from about 1000 to about 1700 °C, or from about 1100 to about 1500 °C.
  • the method 200 can further include mixing the effluent stream with a stream containing hydrogen to produce a reactant stream 203.
  • the effluent stream and the hydrogen stream can take place in a mixing zone that is downstream from the combustion zone, e.g., both within a pressure vessel.
  • the hydrogen in the hydrogen stream used in the methods of the presently disclosed subject matter can originate from various sources, including gaseous streams coming from other chemical processes, e.g., ethane cracking, methanol synthesis or conversion of CH 4 to aromatics.
  • the amount of H 2 in the hydrogen stream is greater than about 70%, greater than about 80%, greater than about 85%, greater than about 90%, greater than about 95% or greater than about 99%.
  • the H 2 can be preheated to a temperature from about 100 to about 1000 °C, from about 250 to about 650 °C or from about 350 to about 650 °C.
  • the H 2 can be preheated in a heat exchanger.
  • the ratio of C0 2 to H 2 in the reactant stream can be about 1 :2, about 1 :3, about 1 :4, about 1 :5 or about 1 :6.
  • the reactant stream can have a temperature from about 500 to about 1100 °C.
  • the temperature of the reactant stream can be greater than about 500 °C, greater than about 900 °C, or greater than about 1100 °C.
  • the temperature of the reactant stream can be controlled by adjusting the flow rate of the first feedstream (containing C0 2 ) to the combustion zone and/or by adjusting the flow rate and/or temperature of the hydrogen stream.
  • the method 200 further includes contacting the reactant stream with a catalyst to product a product stream 204.
  • the reactant stream is contacted with one or more catalysts in a reaction zone, e.g., that is downstream from the mixing zone in the pressure vessel.
  • the product stream can include, but is not limited to, H 2 , CO and unconverted C0 2 and water.
  • the product stream can include from about 10% to about 100% CO and H 2 .
  • the product stream can include from about 10% to about 100% C0 2 .
  • the catalysts to be used in the methods of the disclosed subject matter can be any catalyst suitable for hydrogenation of carbon dioxide known to one of ordinary skill in the art.
  • catalyst compositions suitable for catalyzing hydrogenation of carbon dioxide include metal oxides, carbides, hydroxides or combinations thereof.
  • suitable metals include oxides of chromium (Cr), copper (Cu), manganese (Mn), potassium (K), palladium (Pd), cobalt (Co), cerium (Ce), tungsten (W), platinum (Pt), sodium (Na) and cesium (Cs).
  • the catalysts compositions can further include an inert carrier or support material.
  • Suitable supports can be any support materials, which exhibit good stability at the reaction conditions of the disclosed methods, and are known by one of ordinary skill in the art.
  • the support material can include aluminium oxide (alumina), magnesia, silica, titania, zirconia and mixtures or combinations thereof.
  • the catalyst compositions of the present disclosure further include one or more promoters.
  • suitable promoters include lanthanides, alkaline earth metals and combinations thereof.
  • the contact time for contacting the reactant stream with the catalyst can depend on a number of factors, including but not limited to, the temperature, the pressure and the amount of catalyst and reactants, e.g., H 2 and C0 2 , within the reactant stream.
  • the reactant stream can contact the catalyst from about 1 second to about 10 minutes.
  • the method 200 can further include recovering heat from the product stream 205, e.g., to produce a cooled product stream.
  • the method can include transferring the product stream from the reaction zone to a heat recovery unit.
  • the heat recovered can be used to preheat the first feedstream, the second feedstream, the third feedstream and/or the hydrogen feedstream, e.g., via a heat exchanger.
  • heat recovered in the heat recovery unit can be used to generate steam.
  • the cooled product stream can have a temperature less than 100 °C, less than 70 °C, less than 60 °C, less than 50 °C, or less than 45 °C.
  • the method 200 can include separating unconverted C0 2 and/or condensed water from the H 2 and CO of the cooled product stream to produce a syngas stream 206.
  • the cooled product stream can be transferred from the heat recovery unit to a separation unit.
  • condensed water in the cooled product stream can be removed from the cooled product stream in the separation unit.
  • unconverted C0 2 can be recovered from the cooled product stream in the separation unit.
  • C0 2 can be recovered through an acid gas removal process.
  • C0 2 recovered from the cooled product stream can be recycled to a feedstream containing C0 2 , e.g., the first feedstream.
  • the ratio of H 2 to CO in the syngas stream can range from about 1 : 1 to about 3: 1. In certain embodiments, the ratio of H 2 to CO in the syngas stream is greater than about 3: 1.
  • This syngas can be suitable for use in carbonylation reactions, for example, carbonylation of methanol into acetic acid.
  • This syngas can be suitable for producing oxygenates, like dimethyl ether.
  • This syngas is suitable for olefin or methanol synthesis processes.
  • the reactant stream can contain C0 2 and H 2 in molar ratio of less than 1 :3, e.g., to result in a syngas stream having a H 2 to CO ratio of greater than 2: 1.
  • the composition of the syngas stream can be further controlled by adjusting the temperature of the RWGS reaction zone, such as by adjusting the flow rate of the first feedstream (containing C0 2 ) to the combustion zone and/or by adjusting the flow rate and/or temperature of the hydrogen stream.
  • FIG. 1 depicts a system according to a non-limiting embodiment of the disclosed subject matter.
  • the system 100 includes one or more feed lines 106, 107, 108, e.g., for transferring one or more feedstreams.
  • the system 100 can include 3 feed lines e.g., a first feed line 106 for transferring a first feedstream containing C0 2 , a second feed line 107 for transferring a second feedstream containing 0 2 , and a third feed line 108 for transferring a third feedstream containing hydrocarbons.
  • the system 100 can include two feed lines, 1 for transferring a combined feedstream containing C0 2 and 0 2 , and a second feed line for transferring a feedstream containing hydrocarbons.
  • one or more feed lines 106, 107, 108 are coupled together to mix one or more feedstreams prior to transfer.
  • the feed lines can have a cross-sectional diameter of about 1 inch to about 50 inches.
  • Coupled refers to the connection of a system component to another system component by any means known in the art.
  • the type of coupling used to connect two or more system components can depend on the scale and operability of the system.
  • coupling of two or more components of a system can include one or more joints, valves, transfer lines or sealing elements.
  • joints include threaded joints, soldered joints, welded joints, compression joints and mechanical joints.
  • fittings include coupling fittings, reducing coupling fittings, union fittings, tee fittings, cross fittings and flange fittings.
  • Non-limiting examples of valves include gate valves, globe valves, ball valves, butterfly valves and check valves.
  • the system 100 can further include a combustion zone or chamber 101.
  • the one or more feed lines 106, 107, 108 are coupled to the combustion zone to transfer the feedstreams to the combustion zone.
  • the combustion zone of the presently disclosed subject matter is adapted to the combustion of hydrocarbons and can include any equipment known to be suitable by one of ordinary skill in the art.
  • the combustion zone can include a combustor, burner, combustion chamber or flame holder.
  • the combustion zone is adapted to provide combustion temperatures greater than about 1100 °C.
  • the one or more one or more feed lines 106, 107, 108 can be coupled to one or more heat exchangers 109, 110, 111, which, in turn, can be coupled to the combustion zone 101.
  • the heat exchanger(s) for use in the presently disclosed subject matter can be any type suitable for heating gaseous or liquid streams known to one of ordinary skill in the art.
  • heat exchangers include shell and tube heat exchangers, plate heat exchangers, plate and shell heat exchangers, adiabatic wheel heat exchangers, and plate fin heat exchangers.
  • the system 100 can further include a mixing zone 102.
  • the combustion zone 101 is coupled to the mixing zone 102.
  • a fourth feed line 112 can be coupled directly to the mixing zone 102, e.g., for transferring a hydrogen stream to the mixing zone 102.
  • the hydrogen feed line can be coupled to a heat exchanger 113, which, in turn, can be coupled to the mixing zone 102.
  • the mixing zone 102 is configured to mix the gases in the fourth feed line, e.g., hydrogen, with the effluent stream leaving the combustion zone via the transfer line 116.
  • the mixing zone 102 is coupled to a reaction zone 103, e.g., via a transfer line 117.
  • the reaction zone 103 can contain a reactor unit that can be any reactor type used for a reverse water gas shift (RWGS) reaction.
  • RWGS reverse water gas shift
  • such reactors include fixed bed reactors, such as tubular fixed bed reactors and multi-tubular fixed bed reactors, fluidized bed reactors, such as entrained fluidized bed reactors and fixed fluidized bed reactors, and slurry bed reactors such as three-phase slurry bubble columns and ebullated bed reactors.
  • the dimensions and structure of the reactor unit of the presently disclosed subject matter can vary depending on the capacity of the reactor.
  • the capacity of the reactor unit can be determined by the reaction rate, the stoichiometric quantities of the reactants and/or the feed flow rate.
  • the reaction zone 103 is coupled to a heat recovery unit 104, e.g., via a transfer line 114.
  • the heat recovery unit 104 includes one or more heat exchangers, which can be of any type suitable for cooling gaseous streams known to one of ordinary skill in the art.
  • the heat recovery unit 104 is coupled to a transfer line to transfer the heat recovered to one or more feed lines 106, 107, 108, 112.
  • the heat recovery unit 104 is coupled to a steam generator.
  • the heat recovery unit 104 is coupled to a separation unit 105, e.g., via a transfer line 115.
  • the heat recovery unit 104 includes a condenser adapted to separate water from syngas in the product stream by cooling and condensing the water.
  • the separation unit 104 includes a separator for removing unconverted carbon dioxide from the product stream and producing purified syngas.
  • a transfer line is coupled to the separation unit to transfer recovered carbon dioxide to the combustion zone and/or the first feedstream.
  • the combustion zone 101, mixing zone 102 and reaction zone 103 are contained in a pressure vessel.
  • the pressure vessel can be any type suitable for high temperatures known to one of ordinary skill in the art.
  • the pressure vessel can be made of any suitable material, including but not limited to metals, such as steel or copper, carbon fiber, polymers, concrete, ceramic, glass, or a combination thereof.
  • the pressure vessel includes a refractory lining, e.g., a refractory lined pressure vessel.
  • the pressure vessel for use in the present disclosure can include components and accessories including, but not limited to, gas exhaust lines, cyclones, product discharge lines, reaction zones and heating elements.
  • the pressure vessel can also include one or more measurement accessories.
  • the one or more measurement accessories can be any suitable measurement accessory known to one of ordinary skill in the art including, but not limited to, pH meters, pressure indicators, pressure transmitters, thermowells, temperature- indicating controllers, gas detectors, analyzers and viscometers.
  • the components and accessories can be coupled to the pressure vessel at various locations on the pressure vessel.

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  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)

Abstract

The presently disclosed subject matter relates to methods for generating syngas from carbon dioxide and hydrogen through a reverse water gas shift (RWGS) reaction. In one non-limiting exemplary embodiment, the method includes combusting a first feedstream containing carbon dioxide, a second feedstream containing oxygen and a third feedstream containing hydrocarbons into an effluent stream containing carbon dioxide; mixing the effluent stream with a stream containing hydrogen to produce a reactant stream; and contacting the reactant stream with a catalyst to produce a product stream containing syngas.

Description

METHODS AND SYSTEMS FOR PRODUCING SYNGAS FROM CARBON DIOXIDE
AND HYDROGEN
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 62/248,469, filed October 30, 2015. The contents of the referenced application are incorporated into the present application by reference.
FIELD
[0002] The presently disclosed subject matter relates to methods and systems for generating syngas from carbon dioxide and hydrogen through a reverse water gas shift (RWGS) reaction.
BACKGROUND
[0003] Increased awareness of the environmental impact of carbon dioxide emissions has led to research and efforts to convert carbon dioxide into useful chemical materials. Techniques for converting carbon dioxide into syngas, also known as synthesis gas, have been applied in certain chemical factories and oil refineries where a relatively large amount of carbon dioxide is generated. Syngas includes hydrogen (H2) and carbon monoxide (CO) and can further contain other gas components, e.g., carbon dioxide (C02), steam (H20), methane (CH4) and/or nitrogen (N2).
[0004] Natural gas and light hydrocarbons are the predominant starting materials for producing syngas. Syngas is often produced from natural gas through steam reforming, partial oxidation, dry reforming or by an auto-thermal reforming reaction. Syngas can also be produced by the hydrogenation of C02. The syngas produced by these methods can be used in the production of chemical products, such as methanol, oxo alcohol, olefins, dimethyl ether and methyl ethyl glycol, or can be used in the Fischer- Tropsch process to generate higher hydrocarbons, such as fuels. In these chemical processes, the stoichiometric ratio of ¾ to CO of the syngas in the reactant stream is important in determining which hydrocarbons are produced. Thus, it is desirable to precisely control the stoichiometric ratio of ¾ to CO in the syngas.
[0005] Certain methods for the production of syngas are known in the art. U.S. patent publication No. 2003/0110694 discloses a method of steam reforming methane to form syngas, which includes enriching the stream with oxygen to increase the rate of syngas production. U.S. Patent 6,981,994 discloses a process for driving the steam reforming reaction with heat from the combustion of fuel and oxygen. WO 2014/111310 discloses reacting methane and carbon dioxide to generate syngas by reforming methane in the presence of a catalyst. U.S. Patent Publication No. 2007/0244208 discloses methods for the production of fuel such as high octane gasoline that include the conversion of carbon dioxide and hydrogen into intermediates, such as carbon monoxide and water and/or methanol.
[0006] There remains a need for improved methods of generating syngas from carbon dioxide that can precisely control the stoichiometric ratio of ¾ to CO in the syngas product stream.
SUMMARY OF THE DISCLOSED SUBJECT MATTER
[0007] The presently disclosed subject matter provides methods for generating syngas from carbon dioxide and hydrogen through a reverse water gas shift (RWGS) reaction.
[0008] In certain embodiments, methods for producing syngas from a first feedstream containing carbon dioxide, a second feedstream containing oxygen and a third feedstream containing natural gas are provided. Example methods include combusting the first, second and third feedstreams to produce an effluent stream containing carbon dioxide. The method can further include combining the effluent stream with a stream containing hydrogen to generate a reactant stream containing carbon dioxide and hydrogen. The method can include contacting the reactant stream with a catalyst to produce a product stream that contains syngas. In certain embodiments, the syngas in the product stream has a hydrogen to carbon monoxide ratio of about 1 : 1 to about 3: 1.
[0009] In certain embodiments, the method can further include pressurizing one or more of the first, second and third feedstreams to a pressure of about 10 to about 40 bar prior to the combustion of the first, second and third feedstreams. In certain embodiments, the method can further include increasing the temperature of the first feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the first feedstream. In certain embodiments, the method can further include increasing the temperature of the second feedstream to a temperature from about 250 °C to about 350 °C prior to combustion of the second feedstream. In certain embodiments, the method can further include increasing the temperature of the third feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the third feedstream.
[0010] In certain embodiments, the method can include combining the first and second feedstreams prior to feeding the first and second feedstreams into the combustion zone. In certain embodiments, the method can further include increasing the temperature of the stream containing hydrogen to a temperature from about 350 °C to about 650 °C. In certain embodiments, the reactant stream has a temperature greater than about 1100 °C.
[0011] In certain embodiments, the method can further include recovering heat from the product stream to reduce the temperature of the product stream and generate a cooled product stream. In certain embodiments, the recovered heat can be used to increase the temperature of one or more of the first, second, and third feedstreams prior to combustion. In certain embodiments, the recovered heat is used to generate steam. In certain embodiments, the method can include recovering unconverted carbon dioxide from the cooled product stream.
[0012] The presently disclosed subject matter further provides methods for producing syngas from a first feedstream containing carbon dioxide, a second feedstream containing oxygen and a third feedstream containing natural gas. Some example methods include increasing the temperature of the first feedstream, second feedstream and third feedstream. The method can further include feeding the heated first, second and third feedstreams into a combustion zone to produce an effluent stream containing carbon dioxide. In certain embodiments, the method can include combining the effluent stream with a stream containing hydrogen to generate a reactant stream containing carbon dioxide and hydrogen. The method can further include contacting the reactant stream with a catalyst to produce a product stream containing syngas and steam. The method can include reducing the temperature of the product stream to generate a cooled product stream to condense the steam in the product stream into water and include separating the water from the syngas in the cooled product stream to produce a syngas stream.
[0013] The presently disclosed subject matter further provides a system for producing syngas that includes a combustion zone for producing a stream of heated carbon dioxide from one or more feedstreams containing hydrocarbons, e.g., natural gas, oxygen, and carbon dioxide. The system can further include a mixing zone, coupled to the combustion zone, for mixing the stream of heated carbon dioxide with a stream containing hydrogen. The system can include a reaction zone, coupled to the mixing zone, for reacting carbon dioxide and hydrogen to form a product stream containing syngas.
[0014] In certain embodiments, the system can further include one or more heat exchangers, coupled to the combustion zone, for heating the one or more feedstreams containing hydrocarbons, oxygen, and carbon dioxide. In certain embodiments, the system can include a heat exchanger, coupled to the mixing zone, for heating the stream containing hydrogen.
[0015] In certain embodiments, the system can include a heat recovery unit coupled to the reaction zone, e.g., for recovering heat from the product stream. In certain embodiments, the system can further include a transfer line coupled to the heat recovery unit, for transferring recovered heat to the one or more heat exchangers coupled to the combustion zone. In certain embodiments, the system can include a transfer line coupled to the heat recovery unit, for transferring recovered heat to the heat exchanger coupled to the mixing zone. In certain embodiments, the system can further include a steam generator, coupled to the heat recovery unit, for producing steam from the recovered heat.
[0016] In certain embodiments, the system can further include a separation unit, coupled to the reaction zone, for separating a syngas stream from the product stream. In certain embodiments, the separation unit includes a condenser for removing water from the product stream. In certain embodiments, the separation unit includes a carbon dioxide separation unit for removing carbon dioxide from the product stream. In certain embodiments, the system can further include a transfer line, coupled to the carbon dioxide separation unit, for transferring a stream containing carbon dioxide to the combustion zone.
[0017] Also disclosed in the context of the present invention are embodiments 1 to 27. Embodiment 1 is a method for producing syngas from a first feedstream comprising carbon dioxide, a second feedstream comprising oxygen and a third feedstream comprising natural gas, comprising: (a) combusting the first, second and third feedstreams to produce an effluent stream comprising carbon dioxide; (b) combining the effluent stream with a stream comprising hydrogen to generate a reactant stream comprising carbon dioxide and hydrogen; and (c) catalyzing the reactant stream to produce a product stream comprising syngas. Embodiment 2 is the method of embodiment 1, further comprising pressurizing one or more of the first, second and third feedstreams to a pressure of about 10 to about 40 bar prior to combustion of the first, second and third feedstreams. Embodiment 3 is the method of embodiment 1, further comprising increasing the temperature of the first feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the first feedstream. Embodiment 4 is the method of embodiment 1, further comprising increasing the temperature of the second feedstream to a temperature from about 250 °C to about 350 °C prior to combustion of the second feedstream. Embodiment 5 is the method of embodiment 1, further comprising increasing the temperature of the third feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the third feedstream. Embodiment 6 is the method of embodiment 1, wherein the reactant stream has a temperature greater than about 1100 °C. Embodiment 7 is the method of embodiment 1, further comprising combining the first and second feedstreams prior to combustion. Embodiment 8 is the method of embodiment 1, further comprising increasing the temperature of the stream comprising hydrogen to a temperature from about 350 °C to about 650 °C. Embodiment 9 is the method of embodiment 1, wherein the catalyzing comprises using as a catalyst. Embodiment 10 is the method of embodiment 1, wherein the syngas in the product stream has a molar ratio of hydrogen to carbon monoxide of about 1 : 1 to about 3: 1. Embodiment 11 is the method of embodiment 1, further comprising recovering heat from the product stream to produce a cooled product stream. Embodiment 12 is the method of embodiment 11, further comprising using the recovered heat to increase the temperature of one or more of the first, second, and third feedstreams prior to combustion. Embodiment 13 is the method of embodiment 11, wherein the recovered heat is used to generate steam. Embodiment 14 is the method of embodiment 11, wherein the temperature of cooled product stream is less than about 100 °C. Embodiment 15 is the method of embodiment 11 , further comprising recovering unconverted carbon dioxide from the cooled product stream to generate a syngas stream.
[0018] Embodiment 16 is a method for producing syngas from a first feedstream comprising carbon dioxide, a second feedstream comprising oxygen and a third feedstream comprising natural gas, comprising: (a) increasing the temperature of the first feedstream, second feedstream and third feedstream; (b) feeding the heated first, second and third feedstreams into a combustion zone to produce an effluent stream comprising carbon dioxide; (c) combining the effluent stream with a stream comprising hydrogen to generate a reactant stream comprising carbon dioxide and hydrogen; (d) catalyzing the reactant stream to produce a product stream comprising syngas and steam; (e) reducing the temperature of the product stream to generate a cooled product stream and to condense the steam in the product stream into water; and (f) separating the water from the syngas in the cooled product stream to produce a purified syngas stream.
[0019] Embodiment 17 is a system for producing syngas, comprising: (a) a combustion zone for producing a stream of heated carbon dioxide from one or more feedstreams comprising hydrocarbons, oxygen, and carbon dioxide; (b) a mixing zone, coupled to the combustion zone, for mixing the stream of heated carbon dioxide with a stream containing hydrogen; and (c) a reaction zone, coupled to the mixing zone, for reacting carbon dioxide and hydrogen to produce a product stream comprising syngas. Embodiment 18 is the system of embodiment 17, further comprising one or more heat exchangers, coupled to the combustion zone, for heating the one or more feedstreams comprising hydrocarbons, oxygen, and carbon dioxide. Embodiment 19 is the system of embodiment 17 or 18, further comprising a heat exchanger, coupled to the mixing zone, for heating the stream containing hydrogen. Embodiment 20 is the system of embodiment 17 or 18, further comprising a heat recovery unit coupled to the reaction zone. Embodiment 21 is the system of embodiment 20, further comprising a transfer line, coupled to the heat recovery unit, for transferring recovered heat to the one or more heat exchangers coupled to the combustion zone. Embodiment 22 is the system of embodiment 20, further comprising a transfer line, coupled to the heat recovery unit, for transferring recovered heat to the heat exchanger coupled to the mixing zone. Embodiment 23 is the system of embodiment 20, further comprising a steam generator, coupled to the heat recovery unit, for producing steam from the recovered heat. Embodiment 24 is the system of embodiment 17 or 20, further comprising a separation unit coupled to the reaction zone. Embodiment 25 is the system of embodiment 24, wherein the separation unit comprises a condenser for removing water from the product stream. Embodiment 26 is the system of embodiment 24, wherein the separation unit comprises a carbon dioxide separation unit for removing carbon dioxide from the product stream Embodiment 27 is the system of embodiment 26, further comprising a transfer line coupled to the carbon dioxide separation unit for transferring a stream comprising carbon dioxide to the combustion zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] FIG. 1 is a schematic diagram depicting an exemplary system in accordance with a non-limiting embodiment of the disclosed subject matter.
[0021] FIG. 2 is a schematic diagram depicting an exemplary method in accordance with a non-limiting embodiment of the disclosed subject matter.
DETAILED DESCRD7TION
[0022] The presently disclosed subject matter relates to methods for generating syngas from carbon dioxide and hydrogen through a reverse water gas shift (RWGS) reaction. In certain embodiments, the presently disclosed subject matter provides a method for adjusting the stoichiometric ratio of hydrogen to carbon monoxide in the generated syngas by controlling the temperature of the RWGS reaction and the ratio of the reactants, hydrogen and carbon dioxide.
[0023] Carbon dioxide (C02) can be selectively converted into carbon monoxide (CO) by a RWGS reaction in the presence of a catalyst and hydrogen (H2) under certain reaction conditions. The resulting product of this C02 hydrogenation process is a gas mixture called syngas, which can also be referred to as synthesis gas. Syngas formed by the RWGS reaction includes carbon monoxide and hydrogen, and can further contain water and non-converted carbon dioxide. The RWGS reaction can be represented by the following equation:
C02 + nH2 Ϊ-* CO + (n- 1 )H2 + H20 [Reaction Formula 1 ]
In Reaction Formula 1, n can vary, e.g., from n=l to n=7, to result in a syngas composition, e.g., expressed as its H2/CO ratio or as the stoichiometric ratio denoted by the formula (H2- C02)/(C02+CO), that can consequently vary within wide limits.
[0024] For the purpose of illustration and not limitation, FIG. 2 is a schematic representation of a method according to a non-limiting embodiment of the disclosed subject matter. In certain embodiments, the method 200 can include providing one or more feedstreams 201. For example, and not by way of limitation, the method 200 can include providing 3 or more feedstreams, e.g., a first feedstream, a second feedstream and a third feedstream. In certain embodiments, the first feedstream can include carbon dioxide. In certain embodiments, the second feedstream can include oxygen. In certain embodiments, the third feedstream can include hydrocarbons. In certain embodiments, the first feedstream, second feedstream and third feedstream can be provided as a single combined feedstream containing oxygen, carbon dioxide and hydrocarbons. Alternatively, the first and second feedstream can be provided as a single combined feedstream containing oxygen and carbon dioxide. [0025] The C02 used in the method of the presently disclosed subject matter can originate from various sources. In certain embodiments, the C02 can come from a waste gas stream, e.g., from a plant on the same site, or after recovering C02 from a gas stream. Recycling C02 as starting material in the methods of the presently disclosed subject matter can contribute to reducing the amount of C02 emitted to the atmosphere, e.g., from a chemical production site. The C02 used within the feedstream can also, at least partly, originate from the effluent gas or product of the disclosed methods and recycled back to the reactor in the feedstream. In certain embodiments, the C02 feedstream is pressurized to have a pressure from about 2 to about 100 bar, from about 5 to about 70 bar, from about 10 to about 40 bar or from about 20 to about 30 bar.
[0026] As used herein, the term "about" or "approximately" means within an acceptable error range for the particular value as determined by one of ordinary skill in the art, which will depend in part on how the value is measured or determined, i.e., the limitations of the measurement system. For example, "about" can mean a range of up to 20%, up to 10%, up to 5% and/or up to 1% of a given value.
[0027] The 02 used in the method of the presently disclosed subject matter can originate from various sources. In certain embodiments, air containing oxygen can be used. In certain embodiments, the 02 feedstream is pressurized to have a pressure from about 2 to about 100 bar, from about 5 to about 70 bar, from about 10 to about 40 bar or from about 20 to about 30 bar.
[0028] The hydrocarbons used in the method of the presently disclosed subject matter can originate from various sources. In certain embodiments, the third feedstream contains natural gas, e.g., desulfurized natural gas, or methane (CH4). The CH4 can originate from various sources, for example, and not by way of limitation, the CH4 can be obtained from associated natural gas, non-associated natural gas, shale gas, biogas, coal bed gas and/or methane hydrate. In certain other embodiments, the third feedstream contains desulfurized C2 to C5 hydrocarbons. In certain other embodiments, the third feedstream contains a mixture of natural gas, CH4, and C2 to C5 hydrocarbons. In certain embodiments, the hydrocarbon feedstream is pressurized to have a pressure from about 2 to about 100 bar, from about 5 to about 70 bar, from about 10 to about 40 bar or from about 20 to about 30 bar.
[0029] In certain embodiments, the first, second and/or third feedstreams can be preheated, e.g., in one or more heat exchangers. For example, and not by way of limitation, each feedstream can be preheated in a separate heat exchanger. Alternatively, the first and second feedstream can be combined and preheated in a single heat exchanger. In certain embodiments, the first, second and third feedstreams can be preheated to a temperature from about 100 to about 1000 °C, e.g., from about 250 to about 650 °C, from about 250 to about 350 °C or from about 350 to about 650 °C. In certain embodiments, the third feedstream can be preheated to a temperature from about 250 to about 350 °C. In certain embodiments, the first feedstream can be preheated to a temperature from about 350 to about 650 °C. In certain embodiments, the second feedstream can be preheated to a temperature from about 350 to about 650 °C. In certain embodiments, the combined first and second feedstreams can be preheated to a temperature from about 350 to about 650 °C.
[0030] In certain embodiments, the method 200 can include combusting one or more of the feedstreams, e.g., the first, second and/or third feedstreams, to produce an effluent stream 202. For example, and not by way of limitation, the first, second and third feedstreams can be combusted in a combustion zone, e.g., within a pressure vessel. In certain embodiments, the flow ratio of the second feedstream (containing 02) to the third feedstream (containing hydrocarbons) transferred to the combustion zone can be stoichiometric or sub-stoichiometric. The flow rate of the first feedstream (containing C02) can be moderated to control the temperature of the combustion zone and effluent stream.
[0031] In certain embodiments, the effluent stream can also include water, oxygen and/or uncombusted hydrocarbons. For example, and not by way of limitation, the effluent stream can include greater than about 50% C02, greater than about 70% C02, greater than about 85% C02 or greater than about 90% C02. In certain embodiments, the temperature of the effluent stream can range from about 500 to about 2000 °C, from about 1000 to about 1700 °C, or from about 1100 to about 1500 °C.
[0032] In certain embodiments, the method 200 can further include mixing the effluent stream with a stream containing hydrogen to produce a reactant stream 203. For example, and not by way of limitation, the effluent stream and the hydrogen stream can take place in a mixing zone that is downstream from the combustion zone, e.g., both within a pressure vessel. The hydrogen in the hydrogen stream used in the methods of the presently disclosed subject matter can originate from various sources, including gaseous streams coming from other chemical processes, e.g., ethane cracking, methanol synthesis or conversion of CH4 to aromatics. In certain embodiments, the amount of H2 in the hydrogen stream is greater than about 70%, greater than about 80%, greater than about 85%, greater than about 90%, greater than about 95% or greater than about 99%. In certain embodiments, the H2 can be preheated to a temperature from about 100 to about 1000 °C, from about 250 to about 650 °C or from about 350 to about 650 °C. In certain embodiments, the H2 can be preheated in a heat exchanger.
[0033] In certain embodiments, the reactant stream can include C02 to H2 at a ratio from about 1 : 1 (n=l in Reaction Formula 1) to about 1 :7 (n=7 in Reaction Formula 1). For example, and not by way of limitation, the ratio of C02 to H2 in the reactant stream can be about 1 :2, about 1 :3, about 1 :4, about 1 :5 or about 1 :6. In certain embodiments, the reactant stream can have a temperature from about 500 to about 1100 °C. For example, and not by way of limitation, the temperature of the reactant stream can be greater than about 500 °C, greater than about 900 °C, or greater than about 1100 °C. In certain embodiments, the temperature of the reactant stream can be controlled by adjusting the flow rate of the first feedstream (containing C02) to the combustion zone and/or by adjusting the flow rate and/or temperature of the hydrogen stream.
[0034] In certain embodiments, the method 200 further includes contacting the reactant stream with a catalyst to product a product stream 204. In certain embodiments, the reactant stream is contacted with one or more catalysts in a reaction zone, e.g., that is downstream from the mixing zone in the pressure vessel. The product stream can include, but is not limited to, H2, CO and unconverted C02 and water. In certain embodiments, the product stream can include from about 10% to about 100% CO and H2. In certain embodiments, the product stream can include from about 10% to about 100% C02.
[0035] The catalysts to be used in the methods of the disclosed subject matter can be any catalyst suitable for hydrogenation of carbon dioxide known to one of ordinary skill in the art. For example, catalyst compositions suitable for catalyzing hydrogenation of carbon dioxide include metal oxides, carbides, hydroxides or combinations thereof. Non-limiting examples of suitable metals include oxides of chromium (Cr), copper (Cu), manganese (Mn), potassium (K), palladium (Pd), cobalt (Co), cerium (Ce), tungsten (W), platinum (Pt), sodium (Na) and cesium (Cs). The catalysts compositions can further include an inert carrier or support material. Suitable supports can be any support materials, which exhibit good stability at the reaction conditions of the disclosed methods, and are known by one of ordinary skill in the art. In certain embodiments, the support material can include aluminium oxide (alumina), magnesia, silica, titania, zirconia and mixtures or combinations thereof. In certain embodiments, the catalyst compositions of the present disclosure further include one or more promoters. Non-limiting examples of suitable promoters include lanthanides, alkaline earth metals and combinations thereof. U.S. Patent Nos. 8,551,434 and 8,288,446, incorporated herein by reference in their entireties, disclose catalysts that can be used in the methods of the present disclosure. Additional non-limiting examples of catalyst compositions include Cr2C>3, Cr/Al203, Cr/Si02, Cu-Mn/Al203 and Cr/MgO.
[0036] The contact time for contacting the reactant stream with the catalyst can depend on a number of factors, including but not limited to, the temperature, the pressure and the amount of catalyst and reactants, e.g., H2 and C02, within the reactant stream. In certain embodiments, the reactant stream can contact the catalyst from about 1 second to about 10 minutes.
[0037] In certain embodiments, the method 200 can further include recovering heat from the product stream 205, e.g., to produce a cooled product stream. For example, and not by way of limitation, the method can include transferring the product stream from the reaction zone to a heat recovery unit. In certain embodiments, the heat recovered can be used to preheat the first feedstream, the second feedstream, the third feedstream and/or the hydrogen feedstream, e.g., via a heat exchanger. In certain embodiments, heat recovered in the heat recovery unit can be used to generate steam. In certain embodiments, the cooled product stream can have a temperature less than 100 °C, less than 70 °C, less than 60 °C, less than 50 °C, or less than 45 °C.
[0038] In certain embodiments, the method 200 can include separating unconverted C02 and/or condensed water from the H2 and CO of the cooled product stream to produce a syngas stream 206. For example, and not by way of limitation, the cooled product stream can be transferred from the heat recovery unit to a separation unit. In certain embodiments, condensed water in the cooled product stream can be removed from the cooled product stream in the separation unit. Alternatively and/or additionally, unconverted C02 can be recovered from the cooled product stream in the separation unit. By way of example and not limitation, C02 can be recovered through an acid gas removal process. A non-limiting examples of an acid gas removal process include the OASE®(aMDEA®)/PU ATREAT™ A acid gas removal process, the RECTISOL® acid gas removal process and the BENFIELD™ acid gas removal process, which are incorporated herein by reference in their entireties. In certain embodiments, C02 recovered from the cooled product stream can be recycled to a feedstream containing C02, e.g., the first feedstream.
[0039] In certain embodiments, the ratio of H2 to CO in the syngas stream can range from about 1 : 1 to about 3: 1. In certain embodiments, the ratio of H2 to CO in the syngas stream is greater than about 3: 1. The stoichiometric ratio of H2 to CO in the generated syngas stream depends, in part, on the ratio of C02 to H2 in the reactant stream. As noted above, in certain embodiments, the ratio of C02 to H2 in the reactant stream can range from about 1 : 1 (n=l in Reaction Formula 1) to about 1 :5 (n=5 in Reaction Formula 1). For example, and not by way of limitation, the reactant stream can contain equimolar amounts of C02 and H2 (n=l in Reaction Formula 1) to result in a syngas stream that includes greater than about 90% CO. This syngas can be suitable for use in carbonylation reactions, for example, carbonylation of methanol into acetic acid. In certain embodiments, the reactant stream contains C02 and H2 in molar ratio of 1 :2 (n=2 in Reaction Formula 1), resulting in a syngas stream having a H2 to CO ratio of about 1 : 1. This syngas can be suitable for producing oxygenates, like dimethyl ether. In certain embodiments, the reactant stream contains C02 and H2 in molar ratio of 1 :3 (n=3 in Reaction Formula 1), e.g., to result in a syngas stream having a H2 to CO ratio of about 2: 1. This syngas is suitable for olefin or methanol synthesis processes. In certain embodiments, the reactant stream can contain C02 and H2 in molar ratio of less than 1 :3, e.g., to result in a syngas stream having a H2 to CO ratio of greater than 2: 1. In certain embodiments, the composition of the syngas stream can be further controlled by adjusting the temperature of the RWGS reaction zone, such as by adjusting the flow rate of the first feedstream (containing C02) to the combustion zone and/or by adjusting the flow rate and/or temperature of the hydrogen stream.
[0040] For the purpose of illustration and not limitation, FIG. 1 depicts a system according to a non-limiting embodiment of the disclosed subject matter. In certain embodiments, the system 100 includes one or more feed lines 106, 107, 108, e.g., for transferring one or more feedstreams. For example, and not by way of limitation, the system 100 can include 3 feed lines e.g., a first feed line 106 for transferring a first feedstream containing C02, a second feed line 107 for transferring a second feedstream containing 02, and a third feed line 108 for transferring a third feedstream containing hydrocarbons. Alternatively, the system 100 can include two feed lines, 1 for transferring a combined feedstream containing C02 and 02, and a second feed line for transferring a feedstream containing hydrocarbons. In other non-limiting embodiments, one or more feed lines 106, 107, 108 are coupled together to mix one or more feedstreams prior to transfer. In certain embodiments, the feed lines can have a cross-sectional diameter of about 1 inch to about 50 inches.
[0041] "Coupled" as used herein refers to the connection of a system component to another system component by any means known in the art. The type of coupling used to connect two or more system components can depend on the scale and operability of the system. For example, and not by way of limitation, coupling of two or more components of a system can include one or more joints, valves, transfer lines or sealing elements. Non-limiting examples of joints include threaded joints, soldered joints, welded joints, compression joints and mechanical joints. Non-limiting examples of fittings include coupling fittings, reducing coupling fittings, union fittings, tee fittings, cross fittings and flange fittings. Non-limiting examples of valves include gate valves, globe valves, ball valves, butterfly valves and check valves.
[0042] In certain embodiments, the system 100 can further include a combustion zone or chamber 101. In certain embodiments, the one or more feed lines 106, 107, 108 are coupled to the combustion zone to transfer the feedstreams to the combustion zone. The combustion zone of the presently disclosed subject matter is adapted to the combustion of hydrocarbons and can include any equipment known to be suitable by one of ordinary skill in the art. For example, but not by way of limitation, the combustion zone can include a combustor, burner, combustion chamber or flame holder. In certain embodiments, the combustion zone is adapted to provide combustion temperatures greater than about 1100 °C.
[0043] Alternatively and/or additionally, the one or more one or more feed lines 106, 107, 108 can be coupled to one or more heat exchangers 109, 110, 111, which, in turn, can be coupled to the combustion zone 101. The heat exchanger(s) for use in the presently disclosed subject matter can be any type suitable for heating gaseous or liquid streams known to one of ordinary skill in the art. For example, but not by way of limitation, such heat exchangers include shell and tube heat exchangers, plate heat exchangers, plate and shell heat exchangers, adiabatic wheel heat exchangers, and plate fin heat exchangers.
[0044] In certain embodiments, the system 100 can further include a mixing zone 102. For example, and not by way of limitation, the combustion zone 101 is coupled to the mixing zone 102. In certain embodiments, a fourth feed line 112 can be coupled directly to the mixing zone 102, e.g., for transferring a hydrogen stream to the mixing zone 102. Alternatively, the hydrogen feed line can be coupled to a heat exchanger 113, which, in turn, can be coupled to the mixing zone 102. In certain embodiments, the mixing zone 102 is configured to mix the gases in the fourth feed line, e.g., hydrogen, with the effluent stream leaving the combustion zone via the transfer line 116.
[0045] In certain embodiments, the mixing zone 102 is coupled to a reaction zone 103, e.g., via a transfer line 117. In certain embodiments, the reaction zone 103 can contain a reactor unit that can be any reactor type used for a reverse water gas shift (RWGS) reaction. For example, but not by way of limitation, such reactors include fixed bed reactors, such as tubular fixed bed reactors and multi-tubular fixed bed reactors, fluidized bed reactors, such as entrained fluidized bed reactors and fixed fluidized bed reactors, and slurry bed reactors such as three-phase slurry bubble columns and ebullated bed reactors. The dimensions and structure of the reactor unit of the presently disclosed subject matter can vary depending on the capacity of the reactor. The capacity of the reactor unit can be determined by the reaction rate, the stoichiometric quantities of the reactants and/or the feed flow rate.
[0046] In certain embodiments, the reaction zone 103 is coupled to a heat recovery unit 104, e.g., via a transfer line 114. In certain embodiments, the heat recovery unit 104 includes one or more heat exchangers, which can be of any type suitable for cooling gaseous streams known to one of ordinary skill in the art. In particular embodiments, the heat recovery unit 104 is coupled to a transfer line to transfer the heat recovered to one or more feed lines 106, 107, 108, 112. In other particular non-limiting embodiments, the heat recovery unit 104 is coupled to a steam generator. [0047] In certain embodiments, the heat recovery unit 104 is coupled to a separation unit 105, e.g., via a transfer line 115. In particular embodiments, the heat recovery unit 104 includes a condenser adapted to separate water from syngas in the product stream by cooling and condensing the water. In particular non-limiting embodiments, the separation unit 104 includes a separator for removing unconverted carbon dioxide from the product stream and producing purified syngas. In particular embodiments, a transfer line is coupled to the separation unit to transfer recovered carbon dioxide to the combustion zone and/or the first feedstream.
[0048] In certain embodiments, the combustion zone 101, mixing zone 102 and reaction zone 103 are contained in a pressure vessel. The pressure vessel can be any type suitable for high temperatures known to one of ordinary skill in the art. The pressure vessel can be made of any suitable material, including but not limited to metals, such as steel or copper, carbon fiber, polymers, concrete, ceramic, glass, or a combination thereof. In certain embodiments, the pressure vessel includes a refractory lining, e.g., a refractory lined pressure vessel.
[0049] In certain embodiments, the pressure vessel for use in the present disclosure can include components and accessories including, but not limited to, gas exhaust lines, cyclones, product discharge lines, reaction zones and heating elements. The pressure vessel can also include one or more measurement accessories. The one or more measurement accessories can be any suitable measurement accessory known to one of ordinary skill in the art including, but not limited to, pH meters, pressure indicators, pressure transmitters, thermowells, temperature- indicating controllers, gas detectors, analyzers and viscometers. The components and accessories can be coupled to the pressure vessel at various locations on the pressure vessel.
[0050] In addition to the various embodiments depicted and claimed, the disclosed subject matter is also directed to other embodiments having other combinations of the features disclosed and claimed herein. As such, the particular features presented herein can be combined with each other in other manners within the scope of the disclosed subject matter such that the disclosed subject matter includes any suitable combination of the features disclosed herein. The foregoing description of specific embodiments of the disclosed subject matter has been presented for purposes of illustration and description. It is not intended to be exhaustive or to limit the disclosed subject matter to those embodiments disclosed.
[0051] It will be apparent to those skilled in the art that various modifications and variations can be made in the systems and methods of the disclosed subject matter without departing from the spirit or scope of the disclosed subject matter. Thus, it is intended that the disclosed subject matter include modifications and variations that are within the scope of the appended claims and their equivalents.
[0052] Various patents and patent applications are cited herein, the contents of which are hereby incorporated by reference herein in their entireties.

Claims

1. A method for producing syngas from a first feedstream comprising carbon dioxide, a second feedstream comprising oxygen, and a third feedstream comprising natural gas, the method comprising:
(a) combusting the first, second, and third feedstreams to produce an effluent stream comprising carbon dioxide;
(b) combining the effluent stream with a stream comprising hydrogen to generate a reactant stream comprising carbon dioxide and hydrogen; and
(c) catalyzing the reactant stream to produce a product stream comprising syngas.
2. The method of claim 1 , further comprising pressurizing one or more of the first, second, and third feedstreams to a pressure of about 10 to about 40 bar prior to combustion of the first, second, and third feedstreams.
3. The method of claim 1, further comprising increasing the temperature of the first feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the first feedstream.
4. The method of claim 1, further comprising increasing the temperature of the second feedstream to a temperature from about 250 °C to about 350 °C prior to combustion of the second feedstream.
5. The method of claim 1, further comprising increasing the temperature of the third feedstream to a temperature from about 350 °C to about 650 °C prior to combustion of the third feedstream.
6. The method of claim 1, wherein the reactant stream has a temperature greater than about 1100 °C.
7. The method of claim 1, further comprising combining the first and second feedstreams prior to combustion.
8 The method of claim 1, further comprising increasing the temperature of the stream comprising hydrogen to a temperature from about 350 °C to about 650 °C.
9. The method of claim 1, wherein the catalyzing comprises using as a catalyst.
10. The method of claim 1, wherein the syngas in the product stream has a molar ratio of hydrogen to carbon monoxide of about 1 : 1 to about 3: 1.
11. The method of claim 1, further comprising recovering heat from the product stream to produce a cooled product stream.
12. The method of claim 11, further comprising using the recovered heat to increase the temperature of one or more of the first, second, and third feedstreams prior to combustion.
13. The method of claim 11, wherein the recovered heat is used to generate steam.
14. The method of claim 11, wherein the temperature of cooled product stream is less than about 100 °C.
15. The method of claim 11, further comprising recovering unconverted carbon dioxide from the cooled product stream to generate a syngas stream.
16. A method for producing syngas from a first feedstream comprising carbon dioxide, a second feedstream comprising oxygen, and a third feedstream comprising natural gas, the method comprising:
(a) increasing the temperature of the first feedstream, second feedstream, and third feedstream;
(b) feeding the heated first, second, and third feedstreams into a combustion zone to produce an effluent stream comprising carbon dioxide;
(c) combining the effluent stream with a stream comprising hydrogen to generate a reactant stream comprising carbon dioxide and hydrogen; (d) catalyzing the reactant stream to produce a product stream comprising syngas and steam;
(e) reducing the temperature of the product stream to generate a cooled product stream and to condense the steam in the product stream into water; and
(f) separating the water from the syngas in the cooled product stream to produce a purified syngas stream.
17. A system for producing syngas, comprising:
(a) a combustion zone for producing a stream of heated carbon dioxide from one or more feedstreams comprising hydrocarbons, oxygen, and carbon dioxide;
(b) a mixing zone, coupled to the combustion zone, for mixing the stream of heated carbon dioxide with a stream containing hydrogen; and
(c) a reaction zone, coupled to the mixing zone, for reacting carbon dioxide and hydrogen to produce a product stream comprising syngas.
18. The system of claim 17, further comprising one or more heat exchangers, coupled to the combustion zone, for heating the one or more feedstreams comprising hydrocarbons, oxygen, and carbon dioxide.
19. The system of claim 17 or 18, further comprising:
(a) a heat exchanger, coupled to the mixing zone, for heating the stream containing hydrogen; and/or (b) a heat recovery unit coupled to the reaction zone.
20. The system of claim 19, further comprising a transfer line, coupled to the heat recovery unit, for transferring recovered heat to the (a) one or more heat exchangers coupled to the combustion zone and/or (b) heat exchanger coupled to the mixing zone.
PCT/IB2016/056387 2015-10-30 2016-10-24 Methods and systems for producing syngas from carbon dioxide and hydrogen WO2017072649A1 (en)

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