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A method for producing a purified carbon dioxide product suitable for EOR and surplus electricity uses a vaporous hydrocarbon feed and a SOFC system. A SOFC system includes a condensate removal system, an acid gas removal system, a hydrodesulfurization system, a sorption bed system, a pre-reformer, a solid oxide fuel cell, a CO2 separations system and a CO2 dehydration system operable to form the purified carbon dioxide product, where the SOFC system is operable to produce surplus electricity from the electricity produced by the solid oxide fuel cell. A method of operating the pre-reformer to maximize the internal reforming capacity of a downstream solid oxide fuel cell uses a pre-reformer fluidly coupled on the upstream side of a solid oxide fuel cell. A method of enhancing hydrocarbon fluid recovery from a hydrocarbon-bearing formation using a SOFC system.

Claims which contain your search:

1. A solid oxide fuel cell (SOFC) system for producing a purified carbon dioxide product suitable for enhanced oil recovery (EOR) and surplus electricity from a vaporous hydrocarbon feed, the SOFC system comprising: a condensate removal system that is operable to receive the vaporous hydrocarbon feed and to separate higher-carbon compounds from the vaporous hydrocarbon feed to form a dry sour gas; an acid gas removal system that fluidly couples to the condensate removal system and is operable to extract hydrogen sulfide from the dry sour gas to form a dry sweet gas; a hydrodesulfurization system that fluidly couples to the acid gas removal system and is operable to convert heterorganic compounds in the dry sweet gas using hydrogen in the presence of a hydrotreating catalyst into compounds that absorb onto a sorption bed material to form a treated process gas; a sorption bed system that fluidly couples to the hydrodesulfurization system and is operable to extract compounds that absorb onto the sorption bed material from the treated process gas to form a desulfurized process gas; a pre-reformer that fluidly couples to the sorption bed system and is operable to convert non-methane alkanes in the desulfurized process gas using steam in the presence of an active pre-reforming catalyst into methane and carbon oxides to form a reformed process gas; a solid oxide fuel cell that fluidly couples to the pre-reformer and is operable to convert methane in the reformed process gas using oxygen in the presence of a reforming catalyst and an electrochemical conversion catalyst into carbon dioxide and water to form an anode off-gas and producing electricity; a CO2 separations system that fluidly couples to the solid oxide fuel cell and is operable to extract carbon dioxide from the anode off-gas to form a carbon dioxide-rich gas; and a CO2 dehydration system that fluidly couples to the CO2 separations system and is operable to extract water from the carbon dioxide-rich gas to form the purified carbon dioxide product; where the SOFC system is operable to produce surplus electricity from the electricity produced by the solid oxide fuel cell.

2. The SOFC system of claim 1 further comprising a water-gas shift reactor system that fluidly couples to the solid oxide fuel cell on the downstream side and is operable to convert carbon monoxide in the anode off-gas using water in the presence of a water-gas shift catalyst into carbon dioxide and hydrogen to form a shifted anode off-gas, where the CO2 separations system fluidly couples to the water-gas shift reactor system instead of the solid oxide fuel cell and is operable to extract carbon dioxide from the shifted anode-off gas of the water-gas shift reactor system instead of the anode-off gas of the solid oxide fuel cell to form the carbon dioxide-rich gas.

3. The SOFC system of claim 1 where the acid gas removal system additionally is operable to extract carbon dioxide from the dry sour gas to form a carbon dioxide-rich gas and where the CO2 dehydration system additionally fluidly couples to the acid gas removal system and is operable to extract carbon dioxide from the carbon dioxide-rich gas from the acid gas removal system.

4. The SOFC system of claim 1 where the CO2 separations system additionally is operable to form a hydrogen-rich gas, and where the hydrodesulfurization system additionally fluidly couples to the CO2 separations system and is operable to use hydrogen-rich gas from the CO2 separation system as a source of hydrogen.

7. The SOFC system of claim 1 where the acid gas removal system utilizes a reactive liquid to extract hydrogen sulfide.

12. The SOFC system of claim 1 where the vaporous hydrocarbon feed is an associated gas.

13. A method of enhancing hydrocarbon fluid recovery from a hydrocarbon-bearing formation using the solid oxide fuel cell (SOFC) system of claim 1 comprising the steps of: producing a hydrocarbon fluid from the hydrocarbon-bearing formation; separating associated gas from the produced hydrocarbon fluid; introducing the associated gas into the SOFC system; operating the SOFC system to produce the purified carbon dioxide product for enhanced oil recovery and surplus electricity; and introducing into the hydrocarbon-bearing formation the purified carbon dioxide product using an injection well; where the hydrocarbon-bearing formation contains the hydrocarbon fluid, where the SOFC system is operable to receive associated gas and to produce the purified carbon dioxide product suitable for enhanced oil recovery and surplus electricity, and where a portion of the hydrocarbon fluid comprises the associated gas.

14. A method of operating a pre-reformer to maximize internal reforming capacity of a downstream solid oxide fuel cell comprising the steps of: introducing a desulfurized process gas into the pre-reformer, the desulfurized process gas having a temperature in a range of from about 200 C. to about 450 C. and comprising methane in a range of from about 51 to about 66 mole percent of the composition and non-methane alkanes in a range of from about 33 to about 45 mole percent of the composition, each on a dry basis of the desulfurized process gas; introducing a superheated steam into the pre-reformer, the superheated steam having a temperature in the range of from about 250 C. to about 500 C. and a pressure in a range of from about 8 bars to about 12 bars, such that a steam-to-carbon ratio (SCR) of the introduced superheated steam to the introduced desulfurized process gas is in a range of from about 0.5 to about 1.5; and operating the pre-reformer such that a reformed process gas forms from the desulfurized process gas and the superheated steam, the reformed process gas comprising methane in a range of from about 78 to about 88 mole percent of the composition, carbon oxides in a range of from about 9 to about 12 mole percent of the composition, and hydrogen in a range of from about 0.5 to about 10 mole percent of the composition, each on a dry basis of the reformed process gas; where that the reformed process gas has a methane selectivity in a range of from about 0.90 to about 0.99, and where the pre-reformer fluidly couples to an upstream side of a solid oxide fuel cell and is operable to both receive the desulfurized process gas and convert the non-methane alkanes using steam in the presence of an active metal pre-reforming catalyst into methane and carbon oxides.

16. The method of claim 14 where the temperature of the produced reformed process gas is in a range of from about 55 C. to about 80 C. lower than the temperature of the introduced desulfurized process gas.

17. The method of claim 14 where a mole percent ratio of methane to non-methane alkanes in the desulfurized process gas is in a range of from about 1.0 to about 2.0.

18. The method of claim 14 where the reformed process gas comprises carbon dioxide of at least about 10 mole percent of the composition on a dry basis.

19. The method of claim 14 where the reformed process gas is substantially free of non-methane alkanes on a mole basis.

20. The method of claim 14 where the reformed process gas is substantially free of sulfur and sulfur-bearing compounds on a mole basis.

...

The present invention provides a method and apparatus for producing liquid hydrocarbonaceous product (1) such as biofuel from solid biomass (2), the method comprising: gasifying solid biomass (2) in a gasifier (6) to produce raw synthesis gas (3); conditioning of the raw synthesis gas (3) to purify the raw synthesis gas (3) to obtain purified synthesis gas (4) having a molar ratio of hydrogen to carbon monoxide between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1, the conditioning comprising removing sulfur species from the raw synthesis gas (3) using a guard bed reactor (25); and subjecting the purified synthesis gas (4) to a Fischer-Tropsch synthesis in a Fischer- Tropsch reactor (5) to produce liquid hydrocarbonaceous product (1); wherein the solid biomass (2) is fed to the gasifier (6) using a lock hopper (10).

Claims which contain your search:

1. A method for producing liquid hydrocarbonaceous product (1) such as biofuel from solid biomass (2), the method comprising:feeding solid biomass (2) to a gasifier (6) using a lock hopper (10);gasifying the solid biomass (2) in the gasifier (6) to produce raw synthesis gas (3);conditioning the raw synthesis gas (3) to purify the raw synthesis gas (3) to obtain purified synthesis gas (4) having a molar ratio of hydrogen to carbon monoxide between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1, the conditioning comprising removing sulfur species from the synthesis gas using a guard bed reactor (25); andsubjecting the purified synthesis gas (4) to a Fischer-Tropsch synthesis in a Fischer-Tropsch reactor (5) to produce liquid hydrocarbonaceous product (1).

2. A method according to claim 1, characterized in that the gasification step includes gasifying of solid biomass (2) in a gasifier (6) comprising a fluidized bed reactor, wherein oxygen (7) and steam (8) are used as fluidizing media in the fluidized bed reactor, and wherein tail gas (9) from the Fischer-Tropsch reactor (5) is preferably also used as a gasification and fluidizing medium in the fluidized bed reactor.

3. A method according to claim 1 or claim 2, characterized by feeding the raw synthesis gas (3) into a first particle separator (16) to separate particles such as ash, char and bed material from the raw synthesis gas (3),

4. A method according to claim 3, characterized by feeding the raw synthesis gas (3) from the first particle separator (16) to a second particle separator (17) for performing a dust separation step which lowers the dust content of the raw synthesis gas (3).

5. A method according to any of claims 1 to 4, characterized by the conditioning of the raw synthesis gas (3) including one or more of the following:catalytic treatment of the raw synthesis gas (3) in a reformer (18) for converting tar and methane present in the raw synthesis gas (3) into carbon monoxide and hydrogen;lowering the temperature of the raw synthesis gas (3) to about 250C in a cooler (19);filtering the raw synthesis gas (3) in a filter (20) to remove particles such as ash, entrained bed material and soot from the raw synthesis gas (3);subjecting the raw synthesis gas (3) to a water-gas-shift reaction in a water-to-gas shift reactor (20) to adjust the molar ratio of hydrogen to carbon monoxide to between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1;scrubbing the raw synthesis gas (3) to remove solids and tar components from the raw synthesis gas (3); andan ultra-purification step for removing sulfur components, CO_(2) (carbon dioxide), H_(2)O (water), HCN (hydrogen cyanide), CH_(3)Cl (methyl chloride), carbonyls, Cl (chloride) and NO_(x) (nitrogen oxide) from the raw synthesis gas (3).

7. A method according to any of claims 1 to 6, wherein the guard bed reactor (25) comprises zinc oxide catalysts and active carbon.

8. An apparatus for producing liquid hydrocarbonaceous product (1) such as biofuel from solid biomass (2), the apparatus comprising:a gasifier (6) for gasifying solid biomass (2) to produce raw synthesis gas (3);a lock hopper (10) for feeding the solid biomass (2) to the gasifier (6);means for conditioning the raw synthesis gas (3) to obtain purified synthesis gas (4) having a molar ratio of hydrogen to carbon monoxide between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1, the conditioning means comprising a guard bed reactor (25) for removing sulfur species from the synthesis gas; anda Fischer-Tropsch reactor (5) for subjecting the purified synthesis gas (4) to a Fischer-Tropsch synthesis to produce liquid hydrocarbonaceous product (1).

9. An apparatus according to claim 8, characterized in that the gasifier (6) includes a fluidized bed reactor and means for feeding oxygen (7) and steam (8) into the gasifier (6) for use as fluidizing media in the fluidized bed reactor, and the apparatus preferably includes means for feeding tail gas from the Fischer-Tropsch reactor (5) into the gasifier (6) for use as a fluidizing medium in the fluidized bed reactor.

11. An apparatus according to any of claims 8 to 10, characterized by comprising a first particle separator (16) for separating particles such as ash, char and bed material particles from the raw synthesis gas (3).

12. An apparatus according to claim 11, characterized by comprising a second particle separator (17) downstream of the first particle separator (16) for separating dust from the raw synthesis gas (3).

13. An apparatus according to any of claims 8 to 11, characterized by comprising one or more of the following:a reformer (18) for catalytic treatment of the raw synthesis gas (3) to convert tar and methane present in the raw synthesis gas (3) into carbon monoxide and hydrogen;a cooler (19) for lowering the temperature of the raw synthesis gas (3) to about 250C.a filter (20) for removing ash, entrained bed material and/or soot from the raw synthesis gas (3);a water-gas-shift reactor (21) for adjusting the molar ratio of hydrogen and carbon monoxide in the raw synthesis gas (3) to between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1;a scrubber (22) for removing solids and tar components from the raw synthesis gas (3); andultra-purification means (23) for removing sulfur components, CO_(2) (carbon dioxide), H_(2)O (water), HCN (hydrogen cyanide), CH_(3)Cl (methyl chloride), carbonyls, Cl (chloride) and NO_(x) (nitrogen oxide) from the raw synthesis gas (3).

14. An apparatus according to claim 13, characterized by comprising ultra-purification means (23) and a compressor (24) for raising the pressure of the raw synthesis gas (3) to about 30 to 40 bar pressure before leading the raw synthesis gas (3) into the ultra-purification means (23).

15. An apparatus according to any of claims 8 to 14, characterized in that the guard bed reactor (25) comprises zinc oxide catalysts and active carbon.

...
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Name Score Publications Conferences Grants Patents Trademarks News Webs
230.2 10 10 10 10 10 10 10
87.5 10 10 10 10 10 10 10
64.1 10 10 10 10 10 10 10
59.8 10 10 10 10 10 10 10
57.3 10 10 10 10 10 10 10
53.0 10 10 10 10 10 10 10
45.8 10 10 10 10 10 10 10
43.4 10 10 10 10 10 10 10
41.0 10 10 10 10 10 10 10
39.2 10 10 10 10 10 10 10
36.9 10 10 10 10 10 10 10
35.0 10 10 10 10 10 10 10
31.8 10 10 10 10 10 10 10
31.5 10 10 10 10 10 10 10
31.3 10 10 10 10 10 10 10
28.7 10 10 10 10 10 10 10
28.1 10 10 10 10 10 10 10
26.4 10 10 10 10 10 10 10
26.1 10 10 10 10 10 10 10
23.4 10 10 10 10 10 10 10
23.4 10 10 10 10 10 10 10
23.3 10 10 10 10 10 10 10
22.7 10 10 10 10 10 10 10
22.4 10 10 10 10 10 10 10
21.6 10 10 10 10 10 10 10
21.0 10 10 10 10 10 10 10
20.6 10 10 10 10 10 10 10
19.6 10 10 10 10 10 10 10
19.6 10 10 10 10 10 10 10
19.5 10 10 10 10 10 10 10
19.5 10 10 10 10 10 10 10
19.1 10 10 10 10 10 10 10
18.9 10 10 10 10 10 10 10
18.9 10 10 10 10 10 10 10
17.8 10 10 10 10 10 10 10
17.7 10 10 10 10 10 10 10
17.5 10 10 10 10 10 10 10
16.9 10 10 10 10 10 10 10
16.5 10 10 10 10 10 10 10
16.5 10 10 10 10 10 10 10
16.3 10 10 10 10 10 10 10
16.0 10 10 10 10 10 10 10
15.9 10 10 10 10 10 10 10
15.5 10 10 10 10 10 10 10
15.4 10 10 10 10 10 10 10
15.1 10 10 10 10 10 10 10
15.1 10 10 10 10 10 10 10
14.9 10 10 10 10 10 10 10
14.8 10 10 10 10 10 10 10
14.8 10 10 10 10 10 10 10
14.8 10 10 10 10 10 10 10
14.5 10 10 10 10 10 10 10
14.3 10 10 10 10 10 10 10
14.1 10 10 10 10 10 10 10
14.0 10 10 10 10 10 10 10
13.9 10 10 10 10 10 10 10
13.7 10 10 10 10 10 10 10
13.7 10 10 10 10 10 10 10
13.6 10 10 10 10 10 10 10
13.5 10 10 10 10 10 10 10
Tsinghua University
13.4 11 1 - 10 10 10 10
Hitachi Ltd.
13.3 1 - - 10 10 10 10
The Regents Of The University Of California
13.0 - - - 10 10 10 10
Shiraz University
12.8 5 2 - 10 10 10 10
Dana Canada Corporation
12.8 - - - 10 10 10 10
Stichting Energieonderzoek Centrum Nederland
12.8 - - 1 10 10 10 10
University of Seville
12.5 2 - - 10 10 10 10
German Aerospace Center
12.5 1 - - 10 10 10 10
University of Queensland
12.3 3 - - 10 10 10 10
Solena Fuels Corporation
12.0 - - - 10 10 10 10
Searete LLC
11.8 - - - 10 10 10 10
Polytechnic University of Turin
11.7 4 - - 10 10 10 10
Doty Scientific, Inc.
11.6 - 2 - 10 10 10 10
Gas Technology Institute
11.6 - - - 10 10 10 10
Indian Institute of Technology Kanpur
11.6 2 - - 10 10 10 10
University of Naples Federico II
11.4 5 - - 10 10 10 10
National Chung Hsing University
11.3 8 - - 10 10 10 10
SGE ScandGreen Energy AB
11.2 - - - 10 10 10 10
Wuhan Institute of Technology
10.9 - - - 10 10 10 10
Siemens AG
10.8 - - - 10 10 10 10
RWTH Aachen
10.8 7 2 - 10 10 10 10
Midrex Technologies Inc.
10.6 - - - 10 10 10 10
Days Energy Systems
10.5 - - - 10 10 10 10
Fraunhofer Gesellschaft Zur Foerderung der Angewandten Forschung E.V.
10.4 - - 2 10 10 10 10
Chalmers University of Technology
10.4 12 - - 10 10 10 10
Norwegian University of Science and Technology
10.3 6 2 - 10 10 10 10
University of Salamanca
10.2 4 2 - 10 10 10 10
CIEMAT
10.2 4 1 - 10 10 10 10
Korea University
10.0 6 - - 10 10 10 10
Columbia University
9.9 4 2 - 10 10 10 10
Arizona State University
9.8 5 2 - 10 10 10 10
University of California at Davis
9.8 1 - - 10 10 10 10
Daewoo Shipbuilding and Marine Engineering
9.8 - - - 10 10 10 10
University of Oklahoma
9.7 1 - - 10 10 10 10
Northumbria University
9.6 1 - - 10 10 10 10
Royal Dutch Shell
9.6 1 - - 10 10 10 10
Neste Oil
9.6 - - - 10 10 10 10
University of Central Florida
9.3 - 1 1 10 10 10 10
Mainstream Engineering Corp.
9.3 - - 1 10 10 10 10
Jozef Stefan Institute
9.1 - - 1 10 10 10 10

A method for producing a purified carbon dioxide product suitable for EOR and surplus electricity uses a vaporous hydrocarbon feed and a SOFC system. A SOFC system includes a condensate removal system, an acid gas removal system, a hydrodesulfurization system, a sorption bed system, a pre-reformer, a solid oxide fuel cell, a CO2 separations system and a CO2 dehydration system operable to form the purified carbon dioxide product, where the SOFC system is operable to produce surplus electricity from the electricity produced by the solid oxide fuel cell. A method of operating the pre-reformer to maximize the internal reforming capacity of a downstream solid oxide fuel cell uses a pre-reformer fluidly coupled on the upstream side of a solid oxide fuel cell. A method of enhancing hydrocarbon fluid recovery from a hydrocarbon-bearing formation using a SOFC system.

Claims which contain your search:

1. A solid oxide fuel cell (SOFC) system for producing a purified carbon dioxide product suitable for enhanced oil recovery (EOR) and surplus electricity from a vaporous hydrocarbon feed, the SOFC system comprising: a condensate removal system that is operable to receive the vaporous hydrocarbon feed and to separate higher-carbon compounds from the vaporous hydrocarbon feed to form a dry sour gas; an acid gas removal system that fluidly couples to the condensate removal system and is operable to extract hydrogen sulfide from the dry sour gas to form a dry sweet gas; a hydrodesulfurization system that fluidly couples to the acid gas removal system and is operable to convert heterorganic compounds in the dry sweet gas using hydrogen in the presence of a hydrotreating catalyst into compounds that absorb onto a sorption bed material to form a treated process gas; a sorption bed system that fluidly couples to the hydrodesulfurization system and is operable to extract compounds that absorb onto the sorption bed material from the treated process gas to form a desulfurized process gas; a pre-reformer that fluidly couples to the sorption bed system and is operable to convert non-methane alkanes in the desulfurized process gas using steam in the presence of an active pre-reforming catalyst into methane and carbon oxides to form a reformed process gas; a solid oxide fuel cell that fluidly couples to the pre-reformer and is operable to convert methane in the reformed process gas using oxygen in the presence of a reforming catalyst and an electrochemical conversion catalyst into carbon dioxide and water to form an anode off-gas and producing electricity; a CO2 separations system that fluidly couples to the solid oxide fuel cell and is operable to extract carbon dioxide from the anode off-gas to form a carbon dioxide-rich gas; and a CO2 dehydration system that fluidly couples to the CO2 separations system and is operable to extract water from the carbon dioxide-rich gas to form the purified carbon dioxide product; where the SOFC system is operable to produce surplus electricity from the electricity produced by the solid oxide fuel cell.

2. The SOFC system of claim 1 further comprising a water-gas shift reactor system that fluidly couples to the solid oxide fuel cell on the downstream side and is operable to convert carbon monoxide in the anode off-gas using water in the presence of a water-gas shift catalyst into carbon dioxide and hydrogen to form a shifted anode off-gas, where the CO2 separations system fluidly couples to the water-gas shift reactor system instead of the solid oxide fuel cell and is operable to extract carbon dioxide from the shifted anode-off gas of the water-gas shift reactor system instead of the anode-off gas of the solid oxide fuel cell to form the carbon dioxide-rich gas.

3. The SOFC system of claim 1 where the acid gas removal system additionally is operable to extract carbon dioxide from the dry sour gas to form a carbon dioxide-rich gas and where the CO2 dehydration system additionally fluidly couples to the acid gas removal system and is operable to extract carbon dioxide from the carbon dioxide-rich gas from the acid gas removal system.

4. The SOFC system of claim 1 where the CO2 separations system additionally is operable to form a hydrogen-rich gas, and where the hydrodesulfurization system additionally fluidly couples to the CO2 separations system and is operable to use hydrogen-rich gas from the CO2 separation system as a source of hydrogen.

7. The SOFC system of claim 1 where the acid gas removal system utilizes a reactive liquid to extract hydrogen sulfide.

12. The SOFC system of claim 1 where the vaporous hydrocarbon feed is an associated gas.

13. A method of enhancing hydrocarbon fluid recovery from a hydrocarbon-bearing formation using the solid oxide fuel cell (SOFC) system of claim 1 comprising the steps of: producing a hydrocarbon fluid from the hydrocarbon-bearing formation; separating associated gas from the produced hydrocarbon fluid; introducing the associated gas into the SOFC system; operating the SOFC system to produce the purified carbon dioxide product for enhanced oil recovery and surplus electricity; and introducing into the hydrocarbon-bearing formation the purified carbon dioxide product using an injection well; where the hydrocarbon-bearing formation contains the hydrocarbon fluid, where the SOFC system is operable to receive associated gas and to produce the purified carbon dioxide product suitable for enhanced oil recovery and surplus electricity, and where a portion of the hydrocarbon fluid comprises the associated gas.

14. A method of operating a pre-reformer to maximize internal reforming capacity of a downstream solid oxide fuel cell comprising the steps of: introducing a desulfurized process gas into the pre-reformer, the desulfurized process gas having a temperature in a range of from about 200 C. to about 450 C. and comprising methane in a range of from about 51 to about 66 mole percent of the composition and non-methane alkanes in a range of from about 33 to about 45 mole percent of the composition, each on a dry basis of the desulfurized process gas; introducing a superheated steam into the pre-reformer, the superheated steam having a temperature in the range of from about 250 C. to about 500 C. and a pressure in a range of from about 8 bars to about 12 bars, such that a steam-to-carbon ratio (SCR) of the introduced superheated steam to the introduced desulfurized process gas is in a range of from about 0.5 to about 1.5; and operating the pre-reformer such that a reformed process gas forms from the desulfurized process gas and the superheated steam, the reformed process gas comprising methane in a range of from about 78 to about 88 mole percent of the composition, carbon oxides in a range of from about 9 to about 12 mole percent of the composition, and hydrogen in a range of from about 0.5 to about 10 mole percent of the composition, each on a dry basis of the reformed process gas; where that the reformed process gas has a methane selectivity in a range of from about 0.90 to about 0.99, and where the pre-reformer fluidly couples to an upstream side of a solid oxide fuel cell and is operable to both receive the desulfurized process gas and convert the non-methane alkanes using steam in the presence of an active metal pre-reforming catalyst into methane and carbon oxides.

16. The method of claim 14 where the temperature of the produced reformed process gas is in a range of from about 55 C. to about 80 C. lower than the temperature of the introduced desulfurized process gas.

17. The method of claim 14 where a mole percent ratio of methane to non-methane alkanes in the desulfurized process gas is in a range of from about 1.0 to about 2.0.

18. The method of claim 14 where the reformed process gas comprises carbon dioxide of at least about 10 mole percent of the composition on a dry basis.

19. The method of claim 14 where the reformed process gas is substantially free of non-methane alkanes on a mole basis.

20. The method of claim 14 where the reformed process gas is substantially free of sulfur and sulfur-bearing compounds on a mole basis.


The present invention provides a method and apparatus for producing liquid hydrocarbonaceous product (1) such as biofuel from solid biomass (2), the method comprising: gasifying solid biomass (2) in a gasifier (6) to produce raw synthesis gas (3); conditioning of the raw synthesis gas (3) to purify the raw synthesis gas (3) to obtain purified synthesis gas (4) having a molar ratio of hydrogen to carbon monoxide between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1, the conditioning comprising removing sulfur species from the raw synthesis gas (3) using a guard bed reactor (25); and subjecting the purified synthesis gas (4) to a Fischer-Tropsch synthesis in a Fischer- Tropsch reactor (5) to produce liquid hydrocarbonaceous product (1); wherein the solid biomass (2) is fed to the gasifier (6) using a lock hopper (10).

Claims which contain your search:

1. A method for producing liquid hydrocarbonaceous product (1) such as biofuel from solid biomass (2), the method comprising:feeding solid biomass (2) to a gasifier (6) using a lock hopper (10);gasifying the solid biomass (2) in the gasifier (6) to produce raw synthesis gas (3);conditioning the raw synthesis gas (3) to purify the raw synthesis gas (3) to obtain purified synthesis gas (4) having a molar ratio of hydrogen to carbon monoxide between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1, the conditioning comprising removing sulfur species from the synthesis gas using a guard bed reactor (25); andsubjecting the purified synthesis gas (4) to a Fischer-Tropsch synthesis in a Fischer-Tropsch reactor (5) to produce liquid hydrocarbonaceous product (1).

2. A method according to claim 1, characterized in that the gasification step includes gasifying of solid biomass (2) in a gasifier (6) comprising a fluidized bed reactor, wherein oxygen (7) and steam (8) are used as fluidizing media in the fluidized bed reactor, and wherein tail gas (9) from the Fischer-Tropsch reactor (5) is preferably also used as a gasification and fluidizing medium in the fluidized bed reactor.

3. A method according to claim 1 or claim 2, characterized by feeding the raw synthesis gas (3) into a first particle separator (16) to separate particles such as ash, char and bed material from the raw synthesis gas (3),

4. A method according to claim 3, characterized by feeding the raw synthesis gas (3) from the first particle separator (16) to a second particle separator (17) for performing a dust separation step which lowers the dust content of the raw synthesis gas (3).

5. A method according to any of claims 1 to 4, characterized by the conditioning of the raw synthesis gas (3) including one or more of the following:catalytic treatment of the raw synthesis gas (3) in a reformer (18) for converting tar and methane present in the raw synthesis gas (3) into carbon monoxide and hydrogen;lowering the temperature of the raw synthesis gas (3) to about 250C in a cooler (19);filtering the raw synthesis gas (3) in a filter (20) to remove particles such as ash, entrained bed material and soot from the raw synthesis gas (3);subjecting the raw synthesis gas (3) to a water-gas-shift reaction in a water-to-gas shift reactor (20) to adjust the molar ratio of hydrogen to carbon monoxide to between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1;scrubbing the raw synthesis gas (3) to remove solids and tar components from the raw synthesis gas (3); andan ultra-purification step for removing sulfur components, CO_(2) (carbon dioxide), H_(2)O (water), HCN (hydrogen cyanide), CH_(3)Cl (methyl chloride), carbonyls, Cl (chloride) and NO_(x) (nitrogen oxide) from the raw synthesis gas (3).

7. A method according to any of claims 1 to 6, wherein the guard bed reactor (25) comprises zinc oxide catalysts and active carbon.

8. An apparatus for producing liquid hydrocarbonaceous product (1) such as biofuel from solid biomass (2), the apparatus comprising:a gasifier (6) for gasifying solid biomass (2) to produce raw synthesis gas (3);a lock hopper (10) for feeding the solid biomass (2) to the gasifier (6);means for conditioning the raw synthesis gas (3) to obtain purified synthesis gas (4) having a molar ratio of hydrogen to carbon monoxide between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1, the conditioning means comprising a guard bed reactor (25) for removing sulfur species from the synthesis gas; anda Fischer-Tropsch reactor (5) for subjecting the purified synthesis gas (4) to a Fischer-Tropsch synthesis to produce liquid hydrocarbonaceous product (1).

9. An apparatus according to claim 8, characterized in that the gasifier (6) includes a fluidized bed reactor and means for feeding oxygen (7) and steam (8) into the gasifier (6) for use as fluidizing media in the fluidized bed reactor, and the apparatus preferably includes means for feeding tail gas from the Fischer-Tropsch reactor (5) into the gasifier (6) for use as a fluidizing medium in the fluidized bed reactor.

11. An apparatus according to any of claims 8 to 10, characterized by comprising a first particle separator (16) for separating particles such as ash, char and bed material particles from the raw synthesis gas (3).

12. An apparatus according to claim 11, characterized by comprising a second particle separator (17) downstream of the first particle separator (16) for separating dust from the raw synthesis gas (3).

13. An apparatus according to any of claims 8 to 11, characterized by comprising one or more of the following:a reformer (18) for catalytic treatment of the raw synthesis gas (3) to convert tar and methane present in the raw synthesis gas (3) into carbon monoxide and hydrogen;a cooler (19) for lowering the temperature of the raw synthesis gas (3) to about 250C.a filter (20) for removing ash, entrained bed material and/or soot from the raw synthesis gas (3);a water-gas-shift reactor (21) for adjusting the molar ratio of hydrogen and carbon monoxide in the raw synthesis gas (3) to between 2.5 to 1 and 0.5 to 1, preferably between 2.1 to 1 and 1.8 to 1, more preferably about 2 to 1;a scrubber (22) for removing solids and tar components from the raw synthesis gas (3); andultra-purification means (23) for removing sulfur components, CO_(2) (carbon dioxide), H_(2)O (water), HCN (hydrogen cyanide), CH_(3)Cl (methyl chloride), carbonyls, Cl (chloride) and NO_(x) (nitrogen oxide) from the raw synthesis gas (3).

14. An apparatus according to claim 13, characterized by comprising ultra-purification means (23) and a compressor (24) for raising the pressure of the raw synthesis gas (3) to about 30 to 40 bar pressure before leading the raw synthesis gas (3) into the ultra-purification means (23).

15. An apparatus according to any of claims 8 to 14, characterized in that the guard bed reactor (25) comprises zinc oxide catalysts and active carbon.


Patent
Dana Canada Corporation | Date: 2016-11-22

A heat exchanger is comprised of two heat exchanger sections, at least one of which is provided with a floating header to accommodate differential thermal expansion. The two heat exchanger sections are enclosed by an inner shell wall, and an external connecting passage is provided outside the inner shell wall, through which one of the fluids flows between the two heat exchanger sections. The external connecting passage is enclosed by an outer shell. The inner wall is provided with openings which communicate with the external connecting passage. The openings may be in the form of a substantially continuous gap or discrete openings. Specific examples of heat exchangers with this construction include a steam generator, a steam generator and combined catalytic converter, and a water gas shift reactor.


Patent
Stamicarbon B.V. acting under the name of MT Innovation Center | Date: 2017-05-24

The present invention provides a method for increasing the capacity of a urea production complex, the method comprising a step of adding to an existing urea production complex a CO2 production unit, which unit employs a CO2 production method comprising: i) subjecting a hydrocarbon feed to short contact time catalytic partial oxidation (SCT- CPO) to produce a first gas mixture comprising H2, CO and CO2, ii) subjecting said first gas mixture to a water gas shift reaction yielding a second gas mixture, iii) separating CO2 from said second gas mixture yielding a purified CO2 stream and a hydrogen containing stream and subsequently iv) reacting said purified CO2 stream with ammonia from the ammonia production unit to produce urea. The invention also provides a urea production complex realized by the application of this method and a urea production method.

Claims which contain your search:

1. A method for increasing the capacity of a urea production complex, the method comprising the steps of: (a) providing an existing urea complex, said urea complex comprising a syngas production unit, an ammonia production unit and a urea production unit, which units produce respectively syngas, ammonia and urea, (b) adding to said existing urea production complex a CO2 production unit, employing a CO2 production method comprising: i) subjecting a hydrocarbon feed to short contact time catalytic partial oxidation (SCT-CPO) to produce a first gas mixture comprising H2, CO and CO2, ii) subjecting said first gas mixture to a water gas shift reaction yielding a second gas mixture, iii) separating CO2 from said second gas mixture yielding a purified CO2 stream and a hydrogen containing stream, and iv) reacting said purified CO2 stream with ammonia from the ammonia production unit to produce urea in the urea production unit.

4. The method according to any one of claims 1-3, wherein the first gas mixture is cooled by quenching with water prior to the water gas shift reaction.

5. The method according to claim 4, wherein the quench water is taken from a condensed steam stream or a process condensate stream from the urea production unit.

6. The method according to any one of claims 1-3, wherein the first gas mixture is cooled by indirect heat exchange in a heat exchanger wherein the cooling medium provided to the heat exchanger is boiler feed water (BFW) from the urea production unit.

7. The method according to claim 6, wherein during the indirect heat exchange the boiler feed water is raised in pressure to produce steam with a pressure 12-22 bar and is subsequently used in the urea synthesis.

12. Urea production complex comprising a syngas production unit wherein syngas is produced, an ammonia production unit wherein ammonia is produced, and a urea production unit wherein urea is produced, the complex further comprising a CO2 production unit comprising: a SCT-CPO reactor provided with an inlet for a hydrocarbon feed, an inlet for an oxygen containing feed and an outlet for a first gas mixture, a water gas shift reactor provided with an inlet for the first gas mixture and an outlet for a second gas mixture, a CO2 removal unit, provided with an inlet for the second gas mixture, an outlet for a CO2 stream and an outlet for a hydrogen containing stream, wherein CO2 is separated from the second gas mixture, wherein the CO2 removal unit is connected with the urea production unit so that the CO2 stream obtained in the CO2 removal unit is used as a CO2 feed for urea production.

16. Method for urea production from an ammonia feed and a carbon dioxide feed, wherein at least part of the carbon dioxide feed is obtained employing a CO2 production method comprising: i) subjecting a hydrocarbon feed to short contact time catalytic partial oxidation (SCT-CPO) to produce a first gas mixture comprising H2, CO and CO2, ii) subjecting said first gas mixture to a water gas shift reaction yielding a second gas mixture, iii) separating CO2 from said second gas mixture yielding a purified CO2 stream and a hydrogen containing stream.


A method and system for producing carbon dioxide (435), purified hydrogen (213) and electricity from a reformed process gas feed (205) using a solid oxide fuel cell SOFC (2), the method and system comprising the steps of: introducing the reformed process gas (205) into the solid oxide fuel cell (2); in the solid oxide fuel cell (2) converting hydrogen and carbon monoxide of the reformed process gas (205) in combination with oxygen into an anode off-gas (208) comprising steam, carbon dioxide and unconverted process gas; introducing the anode off-gas (208) into a high temperature water gas shift reactor (8);in the high temperature water-gas shift reactor (8), converting carbon monoxide and steam into carbon dioxide and hydrogen, introducing the gas (216) exiting the high temperature water-gas shift reactor (8) into a low temperature water-gas shift membrane reactor (4), in the low temperature water-gas shift membrane reactor (4), converting carbon monoxide and steam into carbon dioxide and hydrogen, whereby the low temperature water-gas shift membrane reactor (4) comprises a hydrogen pump (9) that produces purified hydrogen (213) on a permeate side (41), while removing hydrogen from a feed side (44).

Claims which contain your search:

1. A method for producing carbon dioxide (435), purified hydrogen (213) and electricity from a reformed process gas feed (205) using a solid oxide fuel cell SOFC (2), the method comprising the steps of: - introducing the reformed process gas (205) into an anode side (23) of the solid oxide fuel cell (2); - in the solid oxide fuel cell (2), introducing air (100) into a cathode side (21) of the solid oxide fuel cell (2) and in the anode side (23) converting hydrogen and carbon monoxide of the reformed process gas (205) in combination with oxygen into an anode off-gas (208) comprising steam, carbon dioxide and unconverted process gas; characterized in: - introducing the anode off-gas (208) into a high temperature water gas shift reactor (8); - in the high temperature water-gas shift reactor (8), converting carbon monoxide and steam into carbon dioxide and hydrogen, - introducing the gas (216) exiting the high temperature water- gas shift reactor (8) into a low temperature water-gas shift membrane reactor (4), - in the low temperature water-gas shift membrane reactor (4), converting carbon monoxide and steam into carbon dioxide and hydrogen, whereby the low temperature water-gas shift membrane reactor (4) comprises a hydrogen pump (9) that produces purified hydrogen (213) on a permeate side (41), while removing hydrogen from a feed side (44), so that the anode off- gas (208) is depleted of hydrogen and carbon monoxide to create a carbon dioxide rich gas stream (21 1) comprising mainly carbon dioxide (435) and steam.

4. The method of one of claims 1 to 3, wherein the gas (216) exiting the high temperature water-gas shift reactor (8) contains less than 2% carbon monoxide and has a temperature of less than 200 C.

5. The method of one of the preceding claims, wherein a gaseous carbonaceous fuel feed (200), in particular a gaseous hydrocarbon feed (200), and steam (220) is introduced into a reformer (3); and wherein in the reformer (3) the reformed process gas (205) is generated by at least partially converting methane and steam into carbon monoxide and hydrogen.

7. The method of one of claims 1 to 4, wherein a solid carbonaceous fuel (201) and steam (220) is introduced into a gasifier (1 1), to generate a product gas, and wherein the product gas is introduced into a gas cleaning unit (12) to generate the reformed process gas (205).

8. The method of one of the preceding claims, wherein the purified hydrogen (213) is added to the reformed process gas feed (205).

9. The method of one of the preceding claims, wherein the carbon dioxide rich gas stream (21 1) is introduced into a separation system (5); - in the separation system (5), separating steam from the carbon dioxide rich gas stream (21 1), wherein the carbon dioxide is compressed in a compressor (403, 415) and a pump (431) to provide a compressed carbon dioxide (435).

1 1. A system (1) for producing carbon dioxide (435), purified hydrogen (213) and electricity from a reformed process gas feed (205), the system comprising a solid oxide fuel cell SOFC (2), - wherein the solid oxide fuel cell (2) is fluidly connected with the reformed process gas feed (205) for converting the reformed process gas (205) in combination with oxygen into an anode off- gas (208) comprising steam, carbon dioxide and unconverted process gas; characterized in that the system further comprising: - a high temperature water-gas shift reactor (8), - and a low temperature water-gas shift membrane reactor (4) comprising a permeate side (41), a feed side (44) and a electrochemical pump (9) there between, - wherein the high temperature water-gas shift reactor (8) is fluidly connected with the solid oxide fuel cell (2) for receiving the anode off-gas (208), and for converting carbon monoxide and steam into carbon dioxide and hydrogen, - wherein the feed side (44) of the low temperature water-gas shift membrane reactor (4) is fluidly connected with the high temperature water gas shift reactor (8) for receiving the gas (216) exiting the high temperature water-gas shift reactor (8), and for converting carbon monoxide and steam into carbon dioxide and hydrogen, and for separating the hydrogen by the electrochemical pump (9) to create a purified hydrogen (213) on the permeate side (41), so that the anode off-gas (208) is depleted of hydrogen and carbon monoxide to create a carbon dioxide rich gas stream (21 1) comprising mainly carbon dioxide and steam.

15. The system of one of claims 1 1 to 14, wherein the exit of the permeate side (41) of the low temperature water gas shift membrane reactor (4) is fluidly connected with the reformer (3).

17. The system of one of claims 1 1 to 16, comprising a reformer (3) for receiving a gaseous carbonaceous fuel feed (200), in particular a gaseous hydrocarbon feed (200), and steam (220), wherein the reformer (3) is fluidly connected with the solid oxide fuel cell (2) for providing the reformed process gas (205).

19. The system of one of claims 1 1 to 16, comprising a gasifier (1 1) for receiving a solid carbonaceous fuel (201) and steam (220), wherein the gasifier (1 1) is fluidly connected with a gas cleaning unit (12) for generating the reformed process gas (205), and wherein the gasifier (1 1) is fluidly connected with the solid oxide fuel cell (2).

20. The system of one of claims 1 1 to 19, wherein a separation system (5) is fluidly connected with the exit side (44b of the feed side (44) of the low temperature water-gas shift membrane reactor (4), to introduce the carbon dioxide rich gas stream (21 1) into the separation system (5) to separate steam from the carbon dioxide rich gas stream (21 1) to provide the carbon dioxide (435).


A method of producing reformed gas as part of a Fischer-Tropsch (FT) hydrocarbon synthesis is disclosed, including the steps of superheating at least a first portion of an FT tail gas produced as a by-product of an FT synthesis process, and forming a mixed gas by injecting at least a portion of an FT water stream, produced as a by-product of an FT synthesis process, into the superheated FT tail gas to form a mixed gas. The mixed gas is used as a feed to a front end of a syngas preparation unit. The amount of at least a portion of the FT water stream is selected to keep the mixed gas at least mostly and preferably entirely in a vapor phase. In some embodiments, a water-gas shift reactor converts the mixed gas to a converted mixed gas upstream of the front end. Other methods, apparatuses and systems are disclosed.

Claims which contain your search:

1. A method of producing Fischer-Tropsch (FT) hydrocarbons via FT synthesis in an FT reactor having an FT synthesis catalyst, the method comprising: a. producing a reformed gas comprising hydrogen and carbon monoxide in a syngas preparation unit having a front end and a feed comprising a carbonaceous feedstock and steam; b. conditioning the reformed gas by removing process condensate therefrom; c. producing liquid FT hydrocarbons, an FT tail gas and an FT water stream using the conditioned reformed gas in the FT reactor, under FT conditions; d. superheating at least a first portion of the FT tail gas; e. injecting at least a first portion of the FT water stream into the at least a first portion of the superheated FT tail gas to form a mixed gas, wherein the amount of the at least a first portion of the FT water stream to be injected into the at least a first portion of the superheated FT tail gas to form the mixed gas is selected to keep the mixed gas in an at least mostly vapor phase; and f. recycling the mixed gas as part of the feed to the front end of the syngas preparation unit.

2. The method of claim 1, wherein the superheating step (d) comprises superheating at least a first portion of the FT tail gas to a temperature of about 400 F.

3. The method of claim 1 or 2, further comprising: g. removing excess water from the mixed gas.

4. The method of claim 1, wherein the amount of the at least a first portion of the FT water stream to be injected into the superheated FT tail gas to form the mixed gas is selected to keep the mixed gas in an entirely vapor phase.

5. The method of claim 4, wherein the carbonaceous feedstock comprises natural gas and further comprising: g. preheating the natural gas; h. sweetening the natural gas, wherein the sweetening and preheating steps may be performed in any order; and i. adding the preheated sweet natural gas to the superheated FT tail gas, prior to an injection of at least a portion of the FT water stream.

6. The method of claim 4, wherein portions of the FT water are injected into the superheated FT tail gas in at least two stages, each injection keeping the mixed gas entirely in a vapor phase and wherein the FT tail gas is superheated upstream of each stage of injection of the portions of the FT water stream.

7. The method of claim 6, wherein the injections of the portions of the FT water stream into the superheated FT tail gas are each performed using separate desuperheaters.

13. The method of claim 12, wherein the conditioning step includes removing hydrogen from the reformed gas and further comprising: using the removed hydrogen as a fuel for the syngas preparation unit.

14. The method of claim 12, wherein the injection of the at least a first portion of the FT water stream into the superheated FT tail gas is performed using a desuperheater.

15. The method of claim 4, further comprising: g. removing a carbon dioxide stream from a second portion of the FT tail gas; and h. adding at least a first portion of the carbon dioxide stream to the FT tail gas upstream of the injection of the FT water stream.

16. The method of claim 4, further comprising: g. sending the mixed gas to a water-gas shift reactor to form a converted mixed gas; h. adding the steam to the converted mixed gas to form a converted feed; and i. using the converted feed as an additional feed to the front end of the syngas preparation unit.

17. The method of claim 4, further comprising: g. sending a second portion of the FT tail gas from the FT reactor to a CO_(2 )removal unit; h. using the CO_(2 )removal unit to remove a CO_(2 )gas stream from the second portion of the FT tail gas; i. adding at least a portion of the CO_(2 )gas stream to the FT tail gas upstream of the superheating step to form a first mixed gas, so that the first mixed gas is superheated in the superheating step; j. sweetening the carbonaceous feedstock which comprises a natural gas; k. preheating the sweet natural gas; l. adding the preheated sweetened natural gas to the superheated first mixed gas upstream of the injection of the at least a first portion of the FT water stream to form a second mixed gas, so that the injection of the at least a first portion of the FT water stream into the second mixed gas forms a third mixed gas; m. sending the third mixed gas through a water-gas shift reactor to form a converted mixed gas; n. adding steam to the converted mixed gas to form a converted feed; and o. using the converted feed as a feed to the front end of the syngas preparation unit.

18. The method of claim 17, further comprising: p. sending a third portion of the FT tail gas from the output of the FT reactor to be used as a feed for the FT reactor.

19. A method of producing reformed gas as part of a Fischer-Tropsch (FT) hydrocarbons synthesis comprising: a. superheating at least a first portion of an FT tail gas produced as a by-product of an FT synthesis process; b. preheating an FT water stream produced as a by-product of the FT synthesis process; c. forming a mixed gas comprising at least a portion of the FT water stream injected into the superheated FT tail gas, the amount of at least a the portion of the FT water selected to keep the mixed gas entirely in a vapor phase; d. forming a converted mixed gas by sending the mixed gas through a water-gas shift reactor; e. adding steam to the converted mixed gas to form a converted feed; and f. using the converted feed as a part of a feed also comprising a carbonaceous feedstock to a front end of a syngas preparation unit.

20. The method of claim 19, wherein the carbonaceous feedstock comprises a sweet natural gas and further comprising g. pre-heating the sweet natural gas; and h. adding the preheated, sweet natural gas to the superheated FT tail gas prior to forming the mixed gas.

22. The method of claim 20, further comprising: h. sending a second portion of the FT tail gas to a carbon dioxide removal unit; i. using the carbon dioxide removal unit to remove a carbon dioxide stream from the second portion of the FT tail gas; and j. adding at least a portion of the carbon dioxide stream to the at least a first portion of the FT tail gas upstream of the superheating step to form a mixture, so that the mixture is superheated in the superheating step.

23. A method of producing a syngas to make Fischer-Tropsch (FT) hydrocarbons via FT synthesis in an FT reactor, the method comprising: a. preheating a sweet natural gas in a natural gas preheater upstream of a steam methane reformer (SMR), having a front end with an SMR tube with an input and an outlet and containing an SMR catalyst; b. providing fuel to the SMR through a fuel flowline having a first flow control regulator; c. producing a syngas comprising hydrogen and carbon monoxide using the SMR, the SMR feed comprising the preheated, sweet natural gas input and steam; d. sending the syngas through the outlet in the SMR tube to the reformed gas boiler, using water from a steam drum; e. cooling the syngas in a reformed gas boiler to an intermediate temperature, forming an intermediate temperature syngas; f. sending the intermediate temperature syngas from the reformed gas boiler to a mixed gas superheater; g. separately passing the intermediate temperature syngas through the mixed gas superheater, whereby the heat from intermediate temperature syngas superheats a mixed gas stream also passing through the mixed gas superheater without mixing the intermediate temperature syngas with the mixed gas stream; h. conditioning the syngas which exits the mixed gas superheater; i. using the conditioned syngas as a feed to the FT reactor, having an FT catalyst and operating under FT conditions, to produce a liquid FT hydrocarbon stream, an FT water stream, and an FT tail gas; j. generating steam from a boiler feed water in a steam generator and sending the steam via a first steam flowline to the steam drum; k. sending steam from the steam drum to a steam superheater through a second steam flowline; l. collecting steam from the reformer gas boiler flowline in the steam drum via a third steam flowline; m. diverting a first portion of the steam in the second steam flowline upstream of the steam superheater into a fourth steam flowline, leaving a second portion of the steam in the second steam flowline; n. superheating the second portion of the steam in the steam superheater and conveying superheated steam away from the steam superheater via a fifth steam flowline that has a downstream connection with a sixth steam flowline, the sixth steam flowline having a second flow control regulator downstream of the connection with the fifth steam flowline, the fifth steam flowline having a third flow control regulator downstream of its connection with the sixth steam flowline; o. diverting a third portion of the steam from the first portion of the steam in the second steam flowline and providing the third portion of the steam via a seventh steam flowline to heat a recycled gas superheater and an FT water preheater; p. sending the FT tail gas from the FT reactor to the recycled gas superheater; q. superheating the FT tail gas in the recycled gas superheater using heat from the third portion of the steam conveyed in the seventh steam flowline; r. adding the preheated sweet natural gas to the superheated FT tail gas to create a feed gas; s. sending the feed gas to a first gas desuperheater; t. preheating the FT water in the FT water preheater using heat from the third portion of the steam to a temperature below saturation point; u. sending the preheated FT water to the first gas desuperheater and directly injecting a first portion of the preheated FT water into the feed gas at the first gas desuperheater to form a mixed gas stream, whereby the first portion of the preheated FT water is in an amount selected to keep the mixed gas stream entirely in the vapor phase, leaving a second portion of the FT water to be conveyed to a second gas desuperheater; v. superheating the mixed gas stream in a mixed gas superheater; w. sending the superheated mixed gas stream to the second gas desuperheater, wherein at least part of the second portion of the FT water is injected directly into the superheated mixed gas steam, resulting in a second mixed gas stream entirely in the vapor phase; x. sending the second mixed gas stream to a water-gas shift reactor that converts a portion of the carbon monoxide and water in the second mixed gas stream to carbon dioxide and hydrogen, in order to form a converted mixed gas stream; y. sending the converted mixed gas steam through a converted steam flowline to a mixed feed preheater coil; z. adjusting the second flow control regulator and the third flow control regulator to allow a predetermined amount of superheated steam from the fifth steam flowline through the sixth steam flowline and into the converted steam flowline, the sixth steam flowline and the converted steam flowline being connected downstream of second flow control regulator and upstream of the mixed feed preheater coil, the predetermined amount of the superheated steam and the converted mixed gas forming a second mixed feed gas; aa. sending the second mixed feed gas to the mixed feed preheater coil; bb. preheating the second mixed feed gas in the mixed feed preheater coil; cc. sending the preheated second mixed feed gas from the mixed feed preheater coil to and into the SMR tube containing the SMR catalyst; and dd. transforming the preheated second mixed feed gas as a feed to the SMR.

24. The method of claim 23, further comprising: ee. sending a second portion of the FT tail gas from the FT reactor to a carbon dioxide removal unit; ff. using the carbon dioxide removal unit to remove a carbon dioxide from the second portion of the FT tail gas; and gg. adding the carbon dioxide to the FT tail gas downstream of the FT reactor and upstream of at least one of the injections of the FT water stream.

25. A system for producing a syngas, the system comprising: a. a superheater for superheating a Fischer-Tropsch (FT) tail gas produced by an FT reactor; b. an injector for injecting at least a portion of an FT water stream produced by an FT reactor into the superheated FT tail gas to form a mixed gas for use as a feed to a front end of a syngas preparation unit.

30. The system of claim 25, wherein the injector is configured to inject a pre-selected amount of the at least a portion of the FT water stream into the superheated FT tail gas to form the mixed gas, the pre-selected amount being selected to keep the mixed gas in at least a mostly vapor phase.

31. The system of claim 30, further comprising a separator drum positioned to remove excess water from the mixed gas in the mostly vapor phase.

32. The system of claim 25, wherein the injector is configured to inject a pre-selected amount of the at least a portion of the FT water stream into the superheated FT tail gas, the pre-selected amount being selected to keep the mixed gas in an entirely vapor phase.

33. The system of claim 25, wherein the injector is configured to inject a pre-selected amount of the at least a portion of the FT water stream into the superheated FT tail gas, the pre-selected amount being selected to keep the mixed gas in a phase that is at least 75% vapor by weight.

34. The system of claim 25, further comprising: d. a connection between a first flowline and a second flowline, carrying the sweet natural gas and the FT tail gas respectively, upstream of the injection of the at least a portion of the FT water stream, so that the injection of the at least a portion of the FT water is into a mixture of the sweet natural gas and the FT tail gas.

35. The system of claim 34, wherein a carbon dioxide stream is added to the FT tail gas upstream of the injection of the at least a portion of the FT water stream.

36. The system of claim 35, wherein the carbon dioxide stream added to the FT tail gas has been recovered by a carbon dioxide removal unit from a second portion of the FT tail gas.

37. The system of claim 34, wherein the injection of at least a portion of the FT water stream is performed in two or more stages, the second stage using a second injector, with wherein both the injector and the second injector are configured to inject first and second portions of the FT water stream into the mixture of the superheated FT tail gas and sweet natural gas in first and second amounts, respectively, that keep the mixed gas in an at least mostly vapor phase, and further comprising: e. a separator drum positioned to remove excess water from the mixed gas.

38. The system of claim 25, wherein the injection of at least a portion of the FT water stream is performed in two or more stages, the second stage using a second injector, with wherein both the injector and the second injector are configured to inject first and second portions of the FT water stream into the mixture of the superheated FT tail gas and sweet natural gas in first and second amounts respectively in first and second amounts, respectively, that keep the mixed gas in an entirely vapor phase.

39. The system of claim 34, further comprising: e. a water-gas shift reactor, located downstream of the injection of the at least a portion of the FT tail gas, that forms a converted mixed gas from the mixed gas; and f. a connection downstream of the water-gas shift reactor and upstream of the front end of the syngas preparation unit by which steam is added to the converted mixed gas to form a converted feed, comprising a feed for the front end of the syngas preparation unit.

40. An apparatus for preparing a Fischer-Tropsch (FT) tail gas produced by an FT reactor and an FT water produced by an FT reactor for recycling into a front end of a syngas preparation unit, comprising: a. a superheater for superheating the FT tail gas; and b. an injector for injecting at least a portion of the FT water stream into the superheated FT tail gas to form a mixed gas, while keeping the mixed gas in at least a mostly vapor phase.

41. The apparatus of claim 40,wherein the injector injects at least a portion of the FT water stream into the superheated FT tail gas to form the mixed gas, while keeping the mixed gas in an entirely vapor phase.

42. The apparatus of claim 41, further comprising: c. a water-gas shift reactor, downstream of the injection of the at least a portion of the FT tail gas, that forms a converted mixed gas from the mixed gas; and d. a connection downstream of the water-gas shift reactor and upstream of the front end of the syngas preparation unit by which steam is added to the converted mixed gas to form a converted feed, comprising a feed for the front end of the syngas preparation unit.

43. The apparatus of claim 42, further comprising: e. a connection between a first and a second flowline, carrying a sweet natural gas and the FT tail gas respectively, upstream of the injection of the at least a portion of the FT water stream, so that the injection of the at least a portion of the FT water is into a mixture of the sweet natural gas and the FT tail gas.

44. The apparatus of claim 43, further comprising: f. a connection between the second flowline and a third flowline carrying carbon dioxide, upstream of the injection of the at least a portion of the FT water stream, so that the injection of the at least a portion of the FT water is into a mixture of the sweet natural gas, the carbon dioxide and the FT tail gas.

45. A system for producing Fischer-Tropsch (FT) hydrocarbons, comprising: a. a syngas preparation unit having a feed comprising a carbonaceous feed and a steam stream for producing a syngas; b. a syngas conditioning unit fluidly connected to the syngas output of the syngas preparation unit for removing condensate from the syngas; c. a FT reactor having an FT catalyst fluidly connected to the conditioned syngas output of the syngas conditioning unit to produce, under FT operating conditions, a stream of liquid FT hydrocarbons, with an FT tail gas and an FT water stream; d. a superheater for superheating FT tail gas; e. an injector for injecting at least a portion of the FT water stream into the superheated FT tail gas to form a mixed gas to be added to the feed of the syngas preparation unit, injector having a configuration to inject a pre-selected amount of the at least a portion of the FT water stream into the superheated FT tail gas to form the mixed gas, the pre-selected amount being selected to keep the mixed gas in at least a mostly vapor phase.

46. The system of claim 45, the injector having a configuration for injecting at least a portion of the FT water stream into the superheated FT tail gas to form the mixed gas, while keeping the mixed gas in an entirely vapor phase.


Systems, apparatuses and methods of utilizing a Fischer-Tropsch (FT) tail gas purge stream for recycling are disclosed. One or more methods include removing an FT tail gas purge stream from an FT tail gas produced by an FT reactor, treating the FT tail gas purge stream with steam in a water gas shift (WGS) reactor, having a WGS catalyst, to produce a shifted FT purge stream including carbon dioxide and hydrogen, and removing at least a portion of the carbon dioxide from the shifted FT purge stream, producing a carbon dioxide stream and a treated purge stream. Other embodiments are also disclosed.

Claims which contain your search:

1. A method of producing Fischer-Tropsch (FT) hydrocarbons via FT synthesis in an FT reactor having an FT synthesis catalyst, the method comprising: a) producing a syngas comprising hydrogen and carbon monoxide in a syngas preparation unit using a carbonaceous feed; b) producing a liquid FT hydrocarbon stream, an FT tail gas stream and an FT water stream using the syngas gas as a feed in the FT reactor under FT operating conditions; c) removing an FT tail gas purge stream from the FT tail gas stream, leaving a remainder FT tail gas stream; d) treating the FT tail gas purge stream with steam in a water gas shift (WGS) reactor, having a WGS catalyst, to produce carbon dioxide and hydrogen, which form a shifted FT purge stream; and e) treating the shifted FT purge stream in a carbon dioxide removal unit, which removes carbon dioxide from the shifted FT purge stream, producing a carbon dioxide stream and a treated purge stream.

3. The method of claim 1, further comprising recycling the carbon dioxide stream as an input to the FT reactor.

6. The method of claim 1, wherein the WGS reactor comprises a low temperature water gas shift reactor.

7. The method of claim 1, wherein the WGS reactor comprises a medium temperature water gas shift reactor.

8. The method of claim 1, wherein the WGS reactor comprises a high temperature water gas shift reactor.

9. The method of claim 1, wherein two or more WGS reactors are used in series to treat the FT tail gas purge stream.

10. The method of claim 1, further comprising recycling the remainder FT tail gas stream as an input to the syngas preparation unit.

12. The method of claim 1, further comprising using the treated purge stream to sweeten natural gas.

16. A method of enhancing a Fischer-Tropsch (FT) purge stream, comprising: a) removing an FT tail gas purge stream from an FT tail gas produced by an FT reactor, leaving a remainder FT tail gas; b) treating the FT tail gas purge stream with steam in a water gas shift (WGS) reactor, having a WGS catalyst, to produce a shifted FT purge stream including carbon dioxide and hydrogen; and c) removing at least a portion of the carbon dioxide from the shifted FT purge stream, thereby producing a carbon dioxide stream and a treated purge stream.

18. The method of claim 16, further comprising recycling the carbon dioxide stream as a feed to the FT reactor.

19. The method of claim 16, wherein the water gas shift reactor comprises a low temperature water gas shift reactor.

20. The method of claim 16, wherein the water gas shift reactor comprises a medium temperature water gas shift reactor.

21. The method of claim 16, wherein the water gas shift reactor comprises a high temperature water gas shift reactor.

22. The method of claim 16, wherein two or more WGS reactors are used in series to treat the FT tail gas purge stream.

23. The method of claim 16, further comprising recycling the remainder FT tail gas as an input to a front end of a syngas preparation unit.

27. A system for producing Fischer Tropsch (FT) hydrocarbons, the system comprising: a) a syngas preparation unit configured to produce a syngas comprising hydrogen and carbon monoxide from a carbonaceous feedstock; b) a syngas conditioning unit, fluidly connected to an output of the syngas preparation unit, configured to condition the syngas to remove a process condensate stream from the syngas and produce a conditioned syngas; c) an FT reactor, fluidly connected to an output of the syngas conditioning unit, and having an FT catalyst, configured to operate under FT conditions to receive the conditioned syngas as an input and to make FT liquid hydrocarbons, with an FT tail gas and an FT water stream as by-products; d) an FT tail gas flowline to transport the FT tail gas from the FT reactor to the syngas preparation unit for use as a feed; e) a diverting line configured to remove an FT tail gas purge stream, comprising a portion of the FT tail gas, from the FT tail gas in the FT tail gas flowline; f) a water gas shift (WGS) reactor fluidly connected to the diverting line to receive the FT tail gas purge stream, and having a water gas shift catalyst positioned therein, configured to convert carbon monoxide and water in the FT purge stream exposed to the water gas shift catalyst under WGS conditions at least in part to carbon dioxide and hydrogen to form a shifted FT purge stream; and g) a carbon dioxide removal unit fluidly connected to an output of the WGS reactor and configured to remove at least a portion of the carbon dioxide from a stream comprising the shifted FT purge stream to form a carbon dioxide stream and a treated purge stream.

32. The system of claim 27, wherein the water gas shift reactor comprises a low temperature water gas shift reactor.

33. The system of claim 27, wherein the water gas shift reactor comprises a high temperature water gas shift reactor.

34. The system of claim 27, further comprising at least a second WGS reactor in series with the WGS reactor to treat the FT tail gas purge stream.

35. The system of claim 27, further comprising recycling a remainder of the FT tail gas, from which the FT purge stream has been removed, as an input to the syngas preparation unit.

36. The system of claim 27, wherein the stream used as an input to the carbon dioxide removal unit further comprises a second portion of the FT tail gas.

40. A system for utilizing a Fischer-Tropsch (FT) tail gas purge stream, the system comprising: a) a water gas shift (WGS) reactor, having a WGS catalyst, and a WGS input for accepting the FT tail gas purge stream and steam, and a WGS output to allow issuance of a shifted FT purge stream b) a carbon dioxide removal unit, having an input and an output, for removing carbon dioxide from the shifted FT purge stream to form a carbon dioxide stream and a treated purge stream; and c) a flowline fluidly connecting the WGS output with the input of the carbon dioxide removal unit to carry the shifted FT purge stream from the output of the WGS reactor to the input of the carbon dioxide removal unit.

41. The system of claim 40, further comprising a diverting line fluidly connecting an input of the WGS reactor to an FT tail gas line to divert a portion of FT tail gas from the FT tail gas line to the WGS input as a feed.

42. The system of claim 40, further comprising a process condensate outlet in the WGS reactor.

43. An apparatus for enhancing a Fischer-Tropsch (FT) purge stream, the apparatus comprising: a) a water gas shift (WGS) reactor, having a WGS catalyst, a WGS input for accepting an FT purge gas, a second WGS input for accepting steam, a WGS output for a shifted FT purge stream and a process condensate outlet.

44. The apparatus of claim 43, further comprising: a) a carbon dioxide removal unit, having an input and an output, for removing carbon dioxide from a stream to form a carbon dioxide stream and a treated purge stream; and b) a flowline fluidly connecting the WGS output with the input of the carbon dioxide removal unit, providing a conduit for the output of the WGS reactor as a stream to the input of the carbon dioxide removal unit.


Provided are particle size-controlled, chromium oxide particles or composite particles of iron oxide-chromium alloy and chromium oxide; a preparation method thereof; and use thereof, in which the chromium oxide particles or the composite particles of iron oxide-chromium alloy and chromium oxide having a desired particle size are prepared in a simpler and more efficient manner by using porous carbon material particles having a large pore volume as a sacrificial template. When the chromium oxide particles or the composite particles of iron oxide-chromium alloy and chromium oxide thus obtained are applied to gas-phase and liquid-phase catalytic reactions, they are advantageous in terms of diffusion of reactants due to particle uniformity, high-temperature stability may be obtained, and excellent reaction results may be obtained under severe reaction environment.

Claims which contain your search:

18. A method of preparing carbon monoxide from a gas comprising carbon dioxide in a carbon dioxide conversion rate of 40% or higher, the method comprising the steps of: i) applying the catalyst for reverse water gas shift reaction comprising the chromium oxide particles of claim 10 to a reverse water gas shift reactor; and ii) providing a gas comprising carbon dioxide and hydrogen to the reactor to allow reverse water gas shift reaction by the catalyst.

19. A method of preparing carbon monoxide from a gas comprising carbon dioxide in a carbon dioxide conversion rate of 40% or higher, the method comprising the steps of: i) applying the catalyst for reverse water gas shift reaction comprising the composite particles of iron oxide-chromium alloy and chromium oxide of claim 16 to a reverse water gas shift reactor; and ii) providing a gas coma rising carbon dioxide and hydrogen to the reactor to allow reverse water gas shift reaction by the catalyst.

20. The method of claim 18, wherein step ii) is performed at a reaction temperature of 600 to 900 C. a molar ratio of carbon dioxide:hydrogen (CO _(2)/H _(2)) of 1:0.5 to 2, and gas hourly space velocity (GHSV) of 10 to 100 NLg _(cat) ^(1)h ^(1).


Patent
Honeywell | Date: 2016-12-14

Apparatus are provided for a hybrid fuel cell system. The hybrid fuel cell system includes a fuel supply system. The fuel supply system includes a fuel source, a reforming subsystem and a depressurization system. The fuel source is in fluid communication with the reforming subsystem. The reforming subsystem reforms the fuel from the fuel source to generate hydrogen enriched gases, and the reforming subsystem is in fluid communication with the depressurization system. The depressurization system reduces a pressure of the hydrogen enriched gases. The hybrid fuel cell system also includes a fuel cell stack in communication with the depressurization system to receive the hydrogen enriched gases at the reduced pressure.

Claims which contain your search:

5. The hybrid fuel cell system of Claim 2, wherein the depressurization system includes a heat exchanger and a water condenser assembly that receives the hydrogen enriched gases, the hydrogen enriched gases at the reduced pressure from the turbine and condenses water in the hydrogen enriched gases with the hydrogen enriched gases at the reduced pressure.

6. The hybrid fuel cell system of Claim 1, further comprising:a gas supply system in fluid communication with the fuel cell stack to supply the fuel cell stack with a gas.

7. The hybrid fuel cell system of Claim 6, further comprising a heat exchanger upstream from the fuel cell stack that heats the gas from the gas supply system.

8. The hybrid fuel cell system of Claim 1, wherein the reforming subsystem further comprises:a reformer in fluid communication with the fuel source and a source of steam; anda water-gas shift reactor in fluid communication with the reformer to receive a hydrogen enriched gases and steam mixture from the reformer.

9. The hybrid fuel cell system of Claim 8, further comprising a water condenser downstream from the water-gas shift reactor and upstream from the depressurization system, the water condenser receives the hydrogen enriched gases and steam mixture and outputs the hydrogen enriched gases for the depressurization system.

10. The hybrid fuel cell system of Claim 8, wherein the fuel supply system further comprises a start-up subsystem, the start-up subsystem including a steam generator for converting water from a source of water into the source of steam for the reformer.


A SOFC system for producing a refined carbon dioxide product, electrical power, and a compressed hydrogen product is presented. The system can include a hydrodesulfurization system, a steam reformer, a water-gas shift reactor system, a hydrogen purification system, a hydrogen compression and storage system, a pre-reformer, and a CO2 purification and liquidification system.

Claims which contain your search:

1. A solid oxide fuel cell (SOFC) system useful for producing a refined carbon dioxide product, electrical power suitable for electrically-powered vehicles and a compressed hydrogen product suitable for hydrogen fuel cell vehicles using steam and a hydrocarbon fuel, the SOFC system comprising: a hydrodesulfurization system that fluidly couples to a hydrogen compression and storage system and is operable to receive a hydrocarbon fuel; a steam reformer having catalytic reactor tubes and a reformer combustion chamber, where the catalytic reactor tubes fluidly couple to the hydrodesulfurization system and are operable to receive superheated steam and where the reformer combustion chamber thermally couples to the catalytic reactor tubes, fluidly couples to both an outlet of an anode side of a solid oxide fuel cell and an oxygen generation system and is operable to receive the hydrocarbon fuel; a water-gas shift reactor system that fluidly couples to the reformer catalytic reactor tubes and is operable to convert carbon monoxide into carbon dioxide and hydrogen; a hydrogen purification system that fluidly couples to the water-gas shift reactor system and is operable to produce a purified hydrogen gas; a hydrogen compression and storage system that fluidly couples to the hydrogen purification system and is operable to produce a compressed hydrogen product; a pre-reformer that fluidly couples to the outlet of the anode side of the solid oxide fuel cell and is operable to receive the hydrocarbon fuel and to produce a pre-reformer syngas product; the solid oxide fuel cell having the anode side and is operable to produce electrical power, where the anode side has an inlet that fluidly couples to both the pre-reformer, the pre-reformer followed by a sorbent bed for removing hydrogen sulfide, and a pressure-swing adsorber (PSA) off-gas conduit of the hydrogen purification system and is operable to produce an anode exhaust gas, the anode side operable to receive a methane-rich anode feed gas without a reformer, the methane-rich anode feed gas comprising the pre-reformer syngas product and an off-gas stream from the hydrogen purification system, where the off-gas stream comprises methane, carbon oxides, and inert gases, where the methane-rich anode feed gas comprises methane, carbon oxides, hydrogen, and water, the anode side further operable to reform, by a reforming catalyst in the solid oxide fuel cell, and electrochemically convert methane and water contained in the methane-rich anode feed gas into hydrogen and carbon oxides to generate the electrical power; the oxygen generation system that is operable to produce oxygen; and a CO2 purification and liquidification system that fluidly couples to the reformer combustion chamber and is operable to produce a refined carbon dioxide product, where the oxygen generation system of the SOFC system includes an electrolysis cell that electrically couples to the solid oxide fuel cell and is operable to receive water and electrical power and to produce electrolysis hydrogen and electrolysis oxygen and the hydrogen compression and storage system also fluidly couples to the oxygen generation system, where the SOFC system is operable to have water introduced therein; and where the SOFC system is operable such that electrical power passes to the oxygen generation system such that the oxygen generation system produces both an electrolysis oxygen and an electrolysis hydrogen separately; and the electrolysis hydrogen passes to the hydrogen compression and storage system.

2. The SOFC system of claim 1 where the water-gas shift reactor system comprises a high temperature shift reactor and a low temperature shift reactor that couple in series and where each reactor contains a different water-gas shift catalyst.

5. The SOFC system of claim 1 where the oxygen generation system of the SOFC system includes an electrolysis cell that electrically couples to the solid oxide fuel cell and is operable to both receive water and electrical power and produce an electrolysis hydrogen and an electrolysis oxygen, and where the hydrogen compression and storage system also fluidly couples to the oxygen generation system.

9. The SOFC system of claim 1 where a steam-to-carbon molar feed ratio in the catalytic reactor tubes is in a range of from about 2:1 to about 4:1.

10. The SOFC system of claim 1 where the catalytic reactor tubes are operable in a range of from about 775 C. to about 825 C. and at a pressure in a range of from about 8 bars to about 10 bars.

11. The SOFC system of claim 1 where the steam reformer is operable at a temperature differential of at least about 90 C. between the reformer combustion chamber and the catalytic reactor tubes.

12. The SOFC system of claim 1 where the SOFC system is operable to produce a purified hydrogen gas having a hydrogen purity in a range of from about 99.50 to about 99.99 mole percent.

13. The SOFC system of claim 1 where a steam-to-carbon molar ratio for the catalytic reactor tubes is less than a steam-to-carbon molar ratio for the pre-reformer.