Syngas Yield Enhancement In Converting Carbonaceous Feeds By Gasification And Other Oxidative Methods

Abstract

Processes are disclosed that utilize beneficial reactions downstream of carbonaceous feed (e.g., biomass) oxidative conversion technologies, and advantageously under conditions (e.g., high temperatures) and/or with the syngas effluent quality (e.g., having particulates and/or other impurities) characteristic of raw syngas exiting such technologies (e.g., prior to, or upstream of, certain syngas purification operations). Such conversion technologies utilize an oxygen-containing feed or, more broadly, an oxidant-containing feed. The beneficial reactions may be carried out by the introduction of hydrogen for performing the reverse water-gas shift (RWGS) reaction and/or by the introduction of one or more hydrocarbons (e.g., methane, ethane, and/or propane) for performing the dry reforming reaction. These and other reactions can advantageously adjust the composition of the syngas obtained (e.g., as the raw syngas from an oxidative conversion technology) in a manner benefitting its subsequent use in providing value-added products such as liquid hydrocarbons.

Claims

1. A process for conversion of a carbonaceous feed to syngas, the process comprising: in an oxidative conversion zone that is a gasification zone, a partial oxidation (POX) zone, or an autothermal reforming (ATR) zone, contacting the carbonaceous feed with an oxygen-containing feed, under respective gasification conditions, POX conditions, or ATR conditions, to provide, as a raw syngas, a respective raw gasifier effluent, raw ATR effluent, or raw POX effluent; in a CO.sub.2 reduction zone downstream of the conversion zone, introducing a CO.sub.2-consuming reactant to react with at least a portion of CO.sub.2 present in the respective raw gasifier effluent, raw ATR effluent, or raw POX effluent, via a CO.sub.2-consuming reaction under CO.sub.2-consuming reaction conditions, to provide, as a CO.sub.2-depleted syngas optionally following cooling in an CO.sub.2 cooling zone, a respective CO.sub.2-depleted gasifier effluent, CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent.

2. The process of claim 1, wherein the CO.sub.2-consuming reactant is hydrogen or a hydrocarbon.

3. The process of claim 2, wherein the CO.sub.2-consuming reactant is hydrogen and the CO.sub.2-consuming reaction is a reverse water-gas shift (RWGS) reaction.

4. The process of claim 3, wherein the RWGS reaction is carried out non-catalytically.

5. The process of claim 2, wherein the CO.sub.2-consuming reactant is hydrogen obtained from a hydrogen production process.

6. The process of claim 5, wherein the hydrogen production process is steam methane reforming or methane pyrolysis.

7. The process of claim 5, wherein the hydrogen, as the CO.sub.2-consuming reactant, is a main hydrogen portion obtained from the hydrogen production process, and possibly wherein a secondary hydrogen portion obtained from the hydrogen production process is introduced to a syngas cooling zone, to which the respective CO.sub.2-depleted gasifier effluent, CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent is fed for cooling.

8. The process of claim 7, wherein the first hydrogen portion, as the CO.sub.2-consuming reactant, is preheated to a CO.sub.2 reduction zone inlet temperature for introduction to the CO.sub.2 reduction zone, which is higher than a syngas cooling zone inlet temperature, at which the second hydrogen portion is introduced to the syngas cooling zone.

9. The process of claim 8, wherein the CO.sub.2 reduction zone inlet temperature is within 50? C., within 25? C., or within 10? C., of a minimum temperature in the CO.sub.2 reduction zone for performing the CO.sub.2-consuming reaction.

10. The process of claim 2, wherein the CO.sub.2-consuming reactant is hydrogen obtained from a water-splitting process, such as an electrochemical water-splitting process, for example electrolysis, or a thermochemical water-splitting process such as chemical looping.

11. The process of claim 10, wherein the hydrogen, as the CO.sub.2-consuming reactant, is a main hydrogen portion obtained from the water-splitting process, and possibly wherein a secondary hydrogen portion obtained from the water-splitting process is introduced to a syngas cooling zone, to which the respective CO.sub.2-depleted gasifier effluent, CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent is fed for cooling.

12. The process of claim 7, wherein the first hydrogen portion, as the CO.sub.2-consuming reactant, is preheated to a CO.sub.2 reduction zone inlet temperature for introduction to the CO.sub.2 reduction zone, which is higher than a syngas cooling zone inlet temperature, at which the second hydrogen portion is introduced to the syngas cooling zone.

13. The process of claim 11, wherein heat recovered from the conversion zone and syngas cooling zone is utilized in the water-splitting process.

14. The process of any claim 11, wherein, in addition to the CO.sub.2-consuming reactant, the water-splitting process provides oxygen that is utilized as an oxidant in the conversion zone.

15. The process of claim 2, wherein the CO.sub.2-consuming reactant is a hydrocarbon and the CO.sub.2-consuming reaction is a dry reforming reaction.

16. The process of claim 15, wherein the dry reforming reaction is carried out non-catalytically.

17. The process of claim 15, wherein the CO.sub.2-consuming reactant is methane, ethane, or propane.

18. The process of claim 15, wherein the hydrocarbon, as the CO.sub.2-consuming reactant, is preheated to a CO.sub.2 reduction zone inlet temperature, for introduction to the CO.sub.2 reduction zone.

19. The process of claim 18, wherein the CO.sub.2 reduction zone inlet temperature is within 50? C., within 25? C., or within 10? C., of a minimum temperature in the CO.sub.2 reduction zone for performing the CO.sub.2-consuming reaction.

20. The process of claim 1, wherein the CO.sub.2-depleted gasifier effluent, CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent has a concentration of CO.sub.2 that is lower than that in a raw syngas, as a respective raw gasifier effluent, raw ATR effluent, or raw POX effluent.

21-33. (canceled)

34. An integrated gasification and RWGS process to produce a syngas effluent, or CO.sub.2-depleted syngas, from a gasifier vessel with reduced CO.sub.2 content, wherein the gasifier vessel includes at least three zones: a gasification zone for a carbonaceous feed (where drying, devolatilization, oxidation reactions, and gasification reactions take place), a CO.sub.2 reduction zone, and a syngas cooling zone, the process comprising: adding H.sub.2 to the CO.sub.2 reduction zone downstream of the gasification zone to reduce the CO.sub.2 content in raw syngas from the gasification zone via RWGS reactions, optionally performed non-catalytically, to produce additional CO and H.sub.2O, and/or adding one or more hydrocarbons (e.g., methane, ethane, and/or propane) to the CO.sub.2 reduction zone downstream of the gasification zone to reduce the CO.sub.2 content in the raw syngas from the gasification zone via dry reforming reactions, optionally performed non-catalytically, to produce additional CO and H.sub.2, wherein at least one of the gasification zone, CO.sub.2 reduction zone, and syngas cooling zone constitutes a separate vessel relative to the other zones.

35. An integrated gasification, in-situ RWGS process, and in-situ dry reforming process to produce a syngas effluent, or CO.sub.2-depleted syngas, from a gasifier vessel with reduced CO.sub.2 content, wherein the gasifier vessel includes at least three zones: a gasification zone for a carbonaceous feed (where drying, devolatilization, oxidation reactions, and gasification reactions take place), a CO.sub.2 reduction zone, and a syngas cooling zone, the process comprising: adding hydrogen to the CO.sub.2 reduction zone downstream of the gasification zone to reduce the CO.sub.2 content in the raw syngas from the gasification zone via RWGS reactions, optionally performed non-catalytically, to produce more CO and H.sub.2O, and/or adding one or more hydrocarbons (e.g., methane, ethane, and/or propane) to the CO.sub.2 reduction zone downstream of the gasification zone to reduce the CO.sub.2 content in the syngas effluent from the gasification zone via dry reforming reactions, optionally performed non-catalytically, to produce additional CO and H.sub.2, wherein at least one of the gasification zone, CO.sub.2 reduction zone, and syngas cooling zone are in a single vessel.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0017] A more complete understanding of the exemplary embodiments of the present invention and the advantages thereof may be acquired by referring to the following description in consideration of the accompanying figures, in which the same reference numbers are used to indicate the same or similar features.

[0018] FIGS. 1A and 1B provide schematics that illustrate the augmentation of feedstock carbon utilization from a gasification process via ex-situ catalytic RWGS (FIG. 1A) or ex-situ catalytic dry reforming (FIG. 1B).

[0019] FIG. 2 provides a schematic that illustrates the augmentation of feedstock carbon utilization from a gasification process via in-situ RWGS, optionally being performed non-catalytically and using externally supplied H.sub.2.

[0020] FIG. 3 provides a schematic that illustrates the augmentation of feedstock carbon utilization from a gasification process via in-situ RWGS, optionally being performed non-catalytically, using externally supplied H.sub.2 from a water splitting process.

[0021] FIG. 4 shows a schematic that illustrates the augmentation of feedstock carbon utilization from a gasification process via in-situ dry reforming, optionally being performed non-catalytically and using externally supplied hydrocarbons.

[0022] Whereas the figures illustrate multiple possible features that may be implemented individually or in any combination, not all features (e.g., not all individual operations and their associated process streams and equipment) are required in, or essential to, the practice of various inventive embodiments described herein. For example, according to the embodiment illustrated in FIG. 2, in some cases it may not be necessary to have a separate, second portion 41a of generated H.sub.2 directed to syngas cooling zone 200 for direct syngas cooling. In such cases, all H.sub.2 from hydrogen production process 401 may be preheated in hydrogen preheater 451 and utilized in CO.sub.2 reduction zone 50. It should therefore be understood that various specific features can be implemented independently of others.

[0023] In order to facilitate explanation and understanding, the figures provide overviews of various features for implementation in processes, and particularly oxidative conversion technologies with integrated CO.sub.2 reduction. Some associated equipment such as certain vessels, heat exchangers, valves, instrumentation, and utilities, are not shown, as their specific description is not essential with respect to the practice of various inventive embodiments. Such details would be apparent to those skilled in the art, having knowledge of the present disclosure. Other processes for integration of CO.sub.2 reduction via RWGS or dry reforming, according to other embodiments within the scope of the invention and having configurations and constituents determined, in part, according to particular processing objectives, would likewise be apparent.

DETAILED DESCRIPTION

[0024] Particular embodiments of the present invention are directed to approaches to reduce the CO.sub.2 content in a syngas effluent from gasification, POX, or ATR processes, via in-situ non-catalytic RWGS. To enable the RWGS effect, external H.sub.2 may be imported within the gasification, POX, or ATR reactor vessel downstream of the reaction zone (e.g., gasification zone, POX zone, or ATR zone) where the syngas is generated.

[0025] Representative processes comprise, in a conversion zone such as a gasification zone or other zone for converting a carbonaceous feed using an oxidative process, contacting the carbonaceous feed with an oxygen-containing gasifier feed (containing O.sub.2) or oxidant-containing gasifier feed (e.g., containing H.sub.2O and/or CO.sub.2). More generally, in the case of oxidative conversion technologies other than gasification (e.g., POX or ATR), this oxygen-containing gasifier feed or oxidant-containing gasifier feed may simply be referred to as an oxygen-containing feed or an oxidant-containing feed. In any event, contacting is under gasification conditions or other oxidative process conditions, to provide a raw gasifier effluent or raw effluent of another oxidative process, namely raw syngas, which in any case comprises synthesis gas (i.e., syngas, comprising a mixture of H.sub.2 and CO, together with optional other components). The processes may further comprise, in a CO.sub.2 reduction zone downstream of the conversion zone, introducing a CO.sub.2-consuming reactant to react with at least a portion of CO.sub.2 present in the raw gasifier effluent or raw effluent of another oxidative process, via a CO.sub.2-consuming reaction under CO.sub.2-consuming reaction conditions, to provide a CO.sub.2-depleted raw gasifier effluent or CO.sub.2-depleted raw effluent of another oxidative process. The CO.sub.2-depleted raw gasifier effluent or CO.sub.2-depleted raw effluent of another oxidative process may alternatively be referred to as a CO.sub.2-depleted syngas or syngas having enhanced CO and/or H.sub.2 concentration. The CO.sub.2-consuming reactant may be, for example, generated H.sub.2 from a hydrogen production process or makeup hydrocarbons from a hydrocarbon source. The CO.sub.2-consuming reactant may be preheated, prior to introduction into the CO.sub.2 reduction zone or other zone, using any heat recovered (e.g., indirectly) from the conversion zone (e.g., oxidative conversion zone such as a gasification zone, POX zone, or ATR zone) and/or from a syngas cooling zone as described herein.

[0026] The carbonaceous feed may comprise coal (e.g., high quality anthracite or bituminous coal, or lesser quality subbituminous, lignite, or peat), petroleum coke, asphaltene, and/or liquid petroleum residue, or other fossil-derived substance. In a preferred embodiment, the carbonaceous feed may comprise biomass. The term biomass refers to renewable (non-fossil-derived) substances derived from organisms living above the earth's surface or within the earth's oceans, rivers, and/or lakes. Representative biomass can include any plant material, or mixture of plant materials, such as a hardwood (e.g., whitewood), a softwood, a hardwood or softwood bark, lignin, algae, and/or lemna (sea weeds). Energy crops, or otherwise agricultural residues (e.g., logging residues) or other types of plant wastes or plant-derived wastes, may also be used as plant materials. Specific exemplary plant materials include corn fiber, corn stover, and sugar cane bagasse, in addition to on-purpose energy crops such as switchgrass, miscanthus, and algae. Short rotation forestry products, such as energy crops, include alder, ash, southern beech, birch, eucalyptus, poplar, willow, paper mulberry, Australian Blackwood, sycamore, and varieties of paulownia elongate. Other examples of suitable biomass include vegetable oils, carbohydrates (e.g., sugars), organic waste materials, such as waste paper, construction, demolition wastes, digester sludge, and biosludge. Representative carbonaceous feeds therefore include, or comprise, any of these types of biomass. Particular carbonaceous feeds comprising biomass include municipal solid waste (MSW) or products derived from MSW, such as refuse derived fuel (RDF). Carbonaceous feeds may comprise a combination of fossil-derived and renewable substances, including those described above. A preferred carbonaceous feed is wood (e.g., in the form of wood chips).

[0027] In a gasifier (or, more particularly, a gasification reactor of this gasifier), or in any other vessel used to house a reaction of another oxidative conversion technology, such as ATR or POX, the carbonaceous feed is subjected to partial oxidation in the presence of an oxygen-containing gasifier feed or oxidant-containing feed generally, added in an amount generally limited to supply only 20-70% of the oxygen that would be necessary for complete combustion. The oxygen-containing gasifier feed or oxidant-containing feed will, alternatively to or in combination with oxygen, generally comprise other oxygenated gaseous components including H.sub.2O and/or CO.sub.2 that may likewise serve as oxidants of the carbonaceous feed. The oxygen-containing gasifier feed or oxidant-containing feed can refer to all gases being fed or added to the gasifier, or otherwise can refer to gas that is separate from other gases being fed or added, whether subsequently combined upstream of, or within, the gasifier or other vessel used to house a reaction of another oxidative conversion technology (or simply another oxidative process). For example, the oxygen-containing gasifier feed or oxidant-containing feed may be introduced to the gasifier or other vessel, along with steam, or a portion of steam, generated elsewhere in the process (e.g., RSC-generated steam or CSC-generated steam from a radiant syngas cooler or convective syngas cooler) and used as a separate feed. Contacting of the carbonaceous feed with the oxygen-containing gasifier feed, or oxidant-containing feed, in the gasifier or other vessel provides a gasifier effluent or other effluent or effluent of another oxidative process, and more particularly a raw gasifier effluent or raw effluent of another oxidative process (i.e., raw syngas), as the product directly exiting the gasifier or other vessel, or otherwise exiting a zone of such gasifier or other vessel, as described herein. One or more reactors (e.g., in series or parallel) of the gasifier or other oxidative process may operate under conditions present in such reactor(s), with these conditions including a temperature of generally from about 500? C. (932? F.) to about 1500? C. (2732? F.), and typically from about 816? C. (1500? F.) to about 1000? C. (1832? F.). Other gasification conditions, or conditions of another oxidative process, may include atmospheric pressure or elevated pressure, for example an absolute pressure generally from about 0.1 megapascals (MPa) (14.5 psi) to about 10 MPa (1450 psi), and typically from about 1 MPa (145 psi) to about 3 MPa (435 psi), or from about 0.5 MPa (72 psi) to about 2 MPa (290 psi).

[0028] The raw gasifier effluent, or raw effluent of another oxidative process (i.e., raw syngas), may comprise synthesis gas, i.e., may comprise both H.sub.2 and CO, with these components being present in various amounts (concentrations), and preferably in a combined amount of greater than about 25 mol-% (e.g., from about 25 mol-% to about 95 mol-%), greater than about 50 mol-% (e.g., from about 50 mol-% to about 90 mol-%), or greater than about 65 mol-% (e.g., from about 65 mol-% to about 85 mol-%). With respect to any such combined amounts (concentrations), the H.sub.2:CO molar ratio of the gasifier effluent, or raw effluent of another oxidative process (i.e., raw syngas), may be suitable, or may be adjusted to be suitable, for use in downstream syngas conversion operations (reactions or separations), such as (i) the conversion to a renewable syngas conversion product comprising higher molecular weight hydrocarbons and/or alcohols of varying carbon numbers via Fischer-Tropsch conversion or (ii) the conversion to a renewable syngas conversion product comprising methanol via a catalytic methanol synthesis reaction, or (iii) the conversion to a renewable syngas conversion product comprising renewable natural gas (RNG) via catalytic methanation that increases the methane content in a resulting RNG stream, or (iv) the separation of a renewable syngas separation product comprising purified hydrogen. Typically, the H.sub.2:CO molar ratio desired for downstream conversion may be from about 0.5:1 to about 5:1, such as from about 1:1 to about 4:1 or from about 1:1 to about 3:1. According to preferred embodiments, a CO.sub.2-consuming reaction described herein and/or other reaction(s) (e.g., a water-gas shift reaction) may be performed downstream of a base technology (e.g., gasification), either in-situ or ex-situ, and thereby adjust the H.sub.2:CO molar ratio of the raw syngas to achieve a suitable H.sub.2:CO molar ratio within these ranges.

[0029] For example, according to some embodiments, a CO.sub.2-consuming reaction, such as RWGS or dry reforming, performed in a CO.sub.2 reduction zone, may increase or decrease the H.sub.2:CO molar ratio of the raw syngas and thereby provide a CO.sub.2-depleted syngas with a higher or lower H.sub.2:CO molar ratio, as desired for a downstream syngas conversion reaction. The adjustment may be an increase or decrease in this molar ratio, for example, generally from about 0.1 to about 2.5, typically from about 0.5 to about 2.0, and often from about 0.5 to about 1.5. Alternatively or optionally in combination with such adjustment of the H.sub.2:CO molar ratio, the CO.sub.2-consuming reaction may advantageously increase the concentration of one or both of H.sub.2 and CO of the raw syngas and thereby provide a CO.sub.2-depleted syngas with a higher concentration of these components, while decreasing the concentration of CO.sub.2 relative to the raw syngas. For example, the concentration of one or both of H.sub.2 and CO may be increased by at least about 1 mol-% (e.g., from about 1 mol-% to about 25 mol-%), at least about 2 mol-% (e.g., from about 2 mol-% to about 20 mol-%), or at least about 5 mol-% (e.g., from about 5 mol-% to about 15 mol-%), such that the overall yield of syngas is increased as a result of incorporating a CO.sub.2 reduction zone.

[0030] Independently of, or in combination with, the representative amounts (concentrations) of H.sub.2 and CO above, the gasifier effluent or effluent of another oxidative process (i.e., raw syngas) may comprise CO.sub.2, for example in an amount of at least about 2 mol-% (e.g., from about 2 mol-% to about 30 mol-%), at least about 5 mol-% (e.g., from about 5 mol-% to about 25 mol-%), or at least about 10 mol-% (e.g., from about 10 mol-% to about 20 mol-%). Independently of, or in combination with, the representative amounts (concentrations) of H.sub.2, CO, and CO.sub.2 above, the gasifier effluent or effluent of another oxidative process (i.e., raw syngas) may comprise CH.sub.4, for example in an amount of at least about 0.5 mol-% (e.g., from about 0.5 mol-% to about 15 mol-%), at least about 1 mol-% (e.g., from about 1 mol-% to about 10 mol-%), or at least about 2 mol-% (e.g., from about 2 mol-% to about 8 mol-%). Together with any water vapor (H.sub.2O), these non-condensable gases H.sub.2, CO, CO.sub.2, and CH.sub.4 may account for substantially all of the composition of the gasifier effluent or effluent of another oxidative process (i.e., raw syngas). That is, these non-condensable gases and any water may be present in the gasifier effluent, or effluent of another oxidative process (i.e., raw syngas), in a combined amount of at least about 90 mol-%, at least about 95 mol-%, or even at least about 99 mol-%.

[0031] Concentration ranges given above for individual components or combinations of components, to the extent that they are described with respect to raw syngas, are likewise applicable, in certain embodiments, to the CO.sub.2-depleted syngas following a CO.sub.2-consuming reaction performed in a CO.sub.2 reduction zone.

[0032] In general, tar removal, and more particularly tar conversion reactions, may be performed downstream of, and under higher temperatures compared to those used in, the gasifier or other oxidative process, such that the tar-depleted gasifier effluent, obtained directly from the tar removal operation, may have a temperature of greater than about 1000? C. (e.g., from about 1000? C. (1832? F.) to about 1500? C. (2732? F.), such as from about 1204? C. (2200? F.) to about 1427? C. (2600? F.)). As described above, tar removal may be performed by adding a fuel source for conversion of tars and oils by oxidation, cracking, and/or reforming, to additional H.sub.2 and CO. Tar removal may be distinguishable from adding makeup hydrocarbons to a CO.sub.2 reduction zone, for example on the basis of that latter, CO.sub.2-consuming reaction resulting in more significant changes to the H.sub.2:CO molar ratio, H.sub.2 concentration, and/or CO concentration of the CO.sub.2-depleted syngas relative to the raw syngas, as described above.

[0033] In view of certain advantages that may be gained from performing a CO.sub.2-consuming reaction (e.g., RWGS by reaction with H.sub.2 and/or dry reforming by reaction with one or more hydrocarbons) under conditions and/or with the raw syngas quality characteristics representative of oxidative conversion technologies such as gasification, it can be appreciated that, according to certain embodiments, gasification conditions, or conditions of another oxidative process, as described herein, may be representative of CO.sub.2-consuming reaction conditions. These conditions include temperatures of effluents (e.g., raw syngas) described herein and obtained from gasification or other oxidative processes, as well as temperatures of effluents described herein and obtained from a tar removal operation. Likewise, any features pertaining to compositions of effluents obtained from gasification or other oxidative processes may be representative of CO.sub.2-depleted syngas obtained from CO.sub.2-consuming reactions, cooled effluents obtained from syngas cooling (e.g., in a syngas cooling zone), or filtered effluents obtained from filtration (e.g., in a filtration zone).

[0034] FIG. 1 depicts an overall process through which the CO.sub.2 content in a gasification syngas effluent, i.e., raw syngas 6, may be reduced via an ex-situ catalytic RWGS process. Oxidant-containing feed 2 and carbonaceous feed 4 are introduced to oxidative conversion zone 100, such as a gasification zone, for example via pneumatic and/or mechanical methods. Components of carbonaceous feed become devolatilized due to the heat in oxidative conversion zone 100, then become partially combusted oxidant(s) such as oxygen in oxidant-containing feed 2, and thereafter become gasified in a reducing environment. The devolatilization, oxidation and reduction reactions in oxidative conversion zone 100, such as a gasification zone, lead to the feedstock conversion to syngas that primarily includes CO, H.sub.2, CO.sub.2, and H.sub.2O, for example in the case of an oxygen-blown gasifier, and CO, H.sub.2, CO.sub.2, H.sub.2O, and nitrogen (N.sub.2) in the case of an air-blown or enriched-air-blown gasifier. The syngas effluent from the oxidative conversion zone 100 then enters syngas cooling zone 200 where it is cooled via direct and/or indirect quench methods that brings the gasification syngas effluent, or raw syngas 6, temperature to drop to an acceptable level for the physical integrity and safety of the downstream equipment and hardware. Thereafter, raw syngas 6 may undergo downstream syngas purification operation(s) 300, such as filtration and/or scrubbing to ensure the removal of undesirable particulates and trace contaminants (e.g., water-soluble contaminants such as HCl, NH.sub.3, and HCN), to accommodate further downstream processing of the resulting, clean syngas 8.

[0035] For example, according to FIG. 1A, clean syngas 8 from downstream syngas purification operation(s) 300 (e.g., filtration and/or scrubbing) may be subjected to catalytic CO.sub.2-consuming reaction 501, which may include a catalytic RWGS reactor for reaction of clean syngas 8 with externally supplied, or generated H.sub.2 41 from hydrogen production process 401, to reduce the CO.sub.2 content in clean syngas 8 while producing additional CO and H.sub.2O that may be recovered in CO.sub.2-depleted syngas 151, which may have an enhanced CO yield/concentration. External heat 101 may be required for catalytic RWGS reactor 501. According to FIG. 1B, clean syngas 8 from downstream syngas purification operation(s) 300 (e.g., filtration and/or scrubbing) may be subjected to catalytic CO.sub.2-consuming reaction 502, which may include a catalytic dry reforming reactor for reaction of clean syngas 8 with externally supplied, or makeup hydrocarbons (C.sub.xH.sub.y) 42 from hydrocarbon source 402, to reduce the CO.sub.2 content in clean syngas 8 while producing additional CO and H.sub.2 that may be recovered in CO.sub.2-depleted syngas 152, which may have enhanced yields/concentrations of both H.sub.2 and CO. External heat 102 may be required for catalytic dry reforming reactor 502.

[0036] As best shown in FIG. 2, according to one embodiment of the invention, the CO.sub.2 content of raw syngas 6 from oxidative conversion zone (e.g., gasification zone) 100 may be innovatively reduced via an in-situ CO.sub.2-reduction zone 50, in which a CO.sub.2-consuming reaction such as RWGS is carried out, for example non-catalytically. Oxidant-containing feed 2 and carbonaceous feed 4 are introduced to oxidative conversion zone 100, such as a gasification zone, for example via pneumatic and/or mechanical methods. Components of carbonaceous feed become devolatilized due to the heat in oxidative conversion zone 100, then become partially oxidized and/or combusted by oxidant(s) such as oxygen in oxidant-containing feed 2, and thereafter become gasified in a reducing environment. The devolatilization, oxidation and reduction reactions in oxidative conversion zone 100, such as a gasification zone, lead to the feedstock conversion to syngas that primarily includes CO, H.sub.2, CO.sub.2, and H.sub.2O, for example in the case of an oxygen-blown gasifier, and CO, H.sub.2, CO.sub.2, H.sub.2O, and nitrogen (N.sub.2) in the case of an air-blown or enriched-air-blown gasifier.

[0037] The syngas effluent from oxidative conversion zone 100, as raw syngas 6, then enters CO.sub.2 reduction zone 50 to undergo an in-situ RWGS reaction where it is reacted, for example non-catalytically, with externally supplied, generated H.sub.2 41, provided from hydrogen production process 401, in this case an RWGS process, optionally after being heated via hydrogen preheater 451. This reduces the CO.sub.2 content in both (i) CO.sub.2-depleted gasifier effluent 7 (or CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent, depending on the oxidative conversion process used) exiting CO.sub.2 reduction zone 50 and (ii) CO.sub.2-depleted syngas 151 exiting syngas cooling zone, relative to that in raw syngas 6, while producing additional CO and H.sub.2O. CO.sub.2-depleted syngas 151 has a cooler temperature relative to raw syngas 6 and CO.sub.2-depleted gasifier effluent 7 (or CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent, depending on the oxidative conversion process used), but may have substantially the same composition as CO.sub.2-depleted gasifier effluent 7. In this regard, according to such particular embodiments, CO.sub.2-depleted syngas 151, may be referred to as a cooled, CO.sub.2-depleted gasifier effluent (cooled gasifier effluent, cooled ATR effluent, or cooled POX effluent).

[0038] The generated H.sub.2 41 may be imported into CO.sub.2 reduction zone 50 in a very controlled and safe manner that effectively reduces the syngas stream CO.sub.2 concentration while maintaining a temperature in this zone that is sufficiently high for the RWGS reaction to proceed at kinetic rates, even in the absence of catalyst, in view of the syngas stream residence time in CO.sub.2 reduction zone 50. As such, an external heat source, such as hydrogen preheater 451 can be utilized if required to heat up generated H.sub.2 41 to a target temperature before it is imported into CO.sub.2 reduction zone 50. The syngas effluent from the CO.sub.2 reduction zone 50 then enters syngas cooling zone 200 where it is cooled via direct and/or indirect quench methods that bring the gasification syngas effluent temperature to drop to an acceptable level for the physical integrity and safety of the downstream equipment and hardware. A second portion 41a of externally supplied, generated H.sub.2 can be further imported into syngas cooling zone 200 to directly quench the syngas effluent from CO.sub.2 reduction zone 50 and to simultaneously supplement the H.sub.2 content in this syngas effluent. By the RWGS reaction, generated H.sub.2 41, optionally in combination with quenching, section portion 41a, can achieve a target or optimized H.sub.2:CO molar ratio in the CO.sub.2-depleted syngas 151, for example within a range as described above. In some embodiments, however, second portion 41a may be avoided, such that all H.sub.2 from hydrogen production process 401, optionally following heating in hydrogen preheater, may be input to CO.sub.2 reduction zone 50. As can be appreciated from FIG. 2, raw syngas 6 may be internal to a single vessel that contains both oxidative conversion zone 100 and CO.sub.2 reduction zone 50, and also optionally syngas cooling zone 200. However, it is also possible for at least one, and possibly all of these zones 100, 50, 200 to constitute separate vessels that are maintained under separate operating conditions.

[0039] As best shown in FIG. 3, according to one embodiment of the invention, the CO.sub.2 content of raw syngas 6 from oxidative conversion zone (e.g., gasification zone) 100 may be innovatively reduced via an in-situ CO.sub.2-reduction zone 50, in which a CO.sub.2-consuming reaction such as RWGS is carried out, for example non-catalytically and integrated with water splitting technologies such as electrolyzers to yield the needed hydrogen. Oxidant-containing feed 2 and carbonaceous feed 4 are introduced to oxidative conversion zone 100, such as a gasification zone, for example via pneumatic and/or mechanical methods. Components of carbonaceous feed become devolatilized due to the heat in oxidative conversion zone 100, then become partially oxidized and/or combusted by oxidant(s) such as oxygen in oxidant-containing feed 2, and thereafter become gasified in a reducing environment. The devolatilization, oxidation and reduction reactions in oxidative conversion zone 100, such as a gasification zone, lead to the feedstock conversion to syngas that primarily includes CO, H.sub.2, CO.sub.2, and H.sub.2O, for example in the case of an oxygen-blown gasifier, and CO, H.sub.2, CO.sub.2, H.sub.2O, and nitrogen (N.sub.2) in the case of an air-blown or enriched-air-blown gasifier.

[0040] The syngas effluent from oxidative conversion zone 100, as raw syngas 6, then enters CO.sub.2 reduction zone 50 to undergo an in-situ RWGS reaction where it is reacted, for example non-catalytically, with externally supplied, generated H.sub.2 41, provided from hydrogen production process 401, which is namely a water-splitting process, optionally after being heated via hydrogen preheater 451. This reduces the CO.sub.2 content in both (i) CO.sub.2-depleted gasifier effluent 7 (or CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent, depending on the oxidative conversion process used) exiting CO.sub.2 reduction zone 50 and (ii) CO.sub.2-depleted syngas 151 exiting syngas cooling zone, relative to that in raw syngas 6, while producing additional CO and H.sub.2O. CO.sub.2-depleted syngas 151 has a cooler temperature relative to raw syngas 6 and CO.sub.2-depleted gasifier effluent 7 (or CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent, depending on the oxidative conversion process used), but may have substantially the same composition as CO.sub.2-depleted gasifier effluent 7. In this regard, according to such particular embodiments, CO.sub.2-depleted syngas 151, may be referred to as a cooled, CO.sub.2-depleted gasifier effluent (cooled gasifier effluent, cooled ATR effluent, or cooled POX effluent).

[0041] The externally supplied, water splitting process generated H.sub.2 41 may be imported into CO.sub.2 reduction zone 50 in a very controlled manner that effectively reduces the syngas stream CO.sub.2 concentration while maintaining a temperature in this zone that is sufficiently high for the RWGS reaction to proceed at kinetic rates, even in the absence of catalyst, in view of the syngas stream residence time in CO.sub.2 reduction zone 50. As such, an external heat source such as hydrogen preheater 451 can be utilized if required to heat-up the externally supplied water splitting process generated H.sub.2 41 to a target temperature before it is imported into CO.sub.2 reduction zone 50. The syngas effluent from the CO.sub.2 reduction zone 50 then enters the syngas cooling zone 200 where it is cooled via direct and/or indirect quench methods that bring the gasification syngas effluent temperature to drop to an acceptable level for the physical integrity and safety of the downstream equipment and hardware. A second portion 41a of the externally supplied water splitting process generated H.sub.2 can be further imported into syngas cooling zone 200 to directly quench the syngas effluent from CO.sub.2 reduction zone 50 and to simultaneously supplement the H.sub.2 content in this syngas effluent. By the RWGS reaction, generated H.sub.2 41, optionally in combination with quenching, section portion 41a, can achieve a target or optimized H.sub.2:CO molar ratio in the CO.sub.2-depleted syngas 151, for example within a range as described above. In cases where the water splitting process requires heat as an input, indirectly recovered heat, such as process heat 103a from oxidative conversion zone 100 and/or syngas cooling zone 200 can be transferred as needed to hydrogen production process 401, which is namely a water-splitting process, in order to facilitate the water splitting process. If further necessary, external heat 103b can also be transferred to this process. In addition, further process integration can be realized if oxygen generated from water-splitting process is used to provide part or all of oxidant-containing feed 2. As can be appreciated from FIG. 3, raw syngas 6 may be internal to a single vessel that contains both oxidative conversion zone 100 and CO.sub.2 reduction zone 50, and also optionally syngas cooling zone 200. However, it is also possible for at least one, and possibly all of these zones 100, 50, 200 to constitute separate vessels that are maintained under separate operating conditions.

[0042] As best shown in FIG. 4, according to one embodiment of the invention, the CO.sub.2 content of raw syngas 6 from oxidative conversion zone (e.g., gasification zone) 100 may be innovatively reduced via an in-situ CO.sub.2-reduction zone 50, in which a CO.sub.2-consuming reaction such as dry reforming is carried out, for example non-catalytically. Oxidant-containing feed 2 and carbonaceous feed 4 are introduced to oxidative conversion zone 100, such as a gasification zone, for example via pneumatic and/or mechanical methods. Components of carbonaceous feed become devolatilized due to the heat in oxidative conversion zone 100, then become partially oxidized and/or combusted by oxidant(s) such as oxygen in oxidant-containing feed 2, and thereafter become gasified in a reducing environment. The devolatilization, oxidation and reduction reactions in oxidative conversion zone 100, such as a gasification zone, lead to the feedstock conversion to syngas that primarily includes CO, H.sub.2, CO.sub.2, and H.sub.2O, for example in the case of an oxygen-blown gasifier, and CO, H.sub.2, CO.sub.2, H.sub.2O, and nitrogen (N.sub.2) in the case of an air-blown or enriched-air-blown gasifier.

[0043] The syngas effluent from oxidative conversion zone 100, as raw syngas 6, then enters CO.sub.2 reduction zone 50 to undergo an in-situ dry reforming reaction where it is reacted, for example non-catalytically, with externally supplied, makeup hydrocarbons 42, provided from hydrogen production process 402, in this case a dry reforming process, optionally after being heated via hydrocarbon preheater 452. This reduces the CO.sub.2 content in both (i) CO.sub.2-depleted gasifier effluent 7 (or CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent, depending on the oxidative conversion process used) exiting CO.sub.2 reduction zone 50 and (ii) CO.sub.2-depleted syngas 152 exiting syngas cooling zone, relative to that in raw syngas 6, while producing additional H.sub.2 and CO. CO.sub.2-depleted syngas 152 has a cooler temperature relative to raw syngas 6 and CO.sub.2-depleted gasifier effluent 7 (or CO.sub.2-depleted ATR effluent, or CO.sub.2-depleted POX effluent, depending on the oxidative conversion process used), but may have substantially the same composition as CO.sub.2-depleted gasifier effluent 7. In this regard, according to such particular embodiments, CO.sub.2-depleted syngas 152, may be referred to as a cooled, CO.sub.2-depleted gasifier effluent (cooled gasifier effluent, cooled ATR effluent, or cooled POX effluent).

[0044] The makeup hydrocarbons 42 may be imported into CO.sub.2 reduction zone 50 in a very controlled and safe manner that effectively reduces the syngas stream CO.sub.2 concentration while maintaining a temperature in this zone that is sufficiently high for the dry reforming reaction to proceed at kinetic rates, even in the absence of catalyst, in view of the syngas stream residence time in CO.sub.2 reduction zone 50. As such, an external heat source, such as hydrocarbon preheater 452 can be utilized if required to heat up makeup hydrocarbons 42 to a target temperature before it is imported into CO.sub.2 reduction zone 50. The syngas effluent from the CO.sub.2 reduction zone 50 then enters syngas cooling zone 200 where it is cooled via direct and/or indirect quench methods that bring the gasification syngas effluent temperature to drop to an acceptable level for the physical integrity and safety of the downstream equipment and hardware. By the dry reforming reaction, makeup hydrocarbons 42 (e.g., methane, ethane, and/or propane) can achieve a target or optimized H.sub.2:CO molar ratio in the CO.sub.2-depleted syngas 152, for example within a range as described above. As can be appreciated from FIG. 4, raw syngas 6 may be internal to a single vessel that contains both oxidative conversion zone 100 and CO.sub.2 reduction zone 50, and also optionally syngas cooling zone 200. However, it is also possible for at least one, and possibly all of these zones 100, 50, 200 to constitute separate vessels that are maintained under separate operating conditions.

[0045] Particular representative embodiments include the following: An integrated gasification and RWGS process to produce a syngas effluent, or CO.sub.2-depleted syngas, from a gasifier vessel with reduced CO.sub.2 content, wherein the gasifier includes at least three zones: a gasification zone for a carbonaceous feed (where drying, devolatilization, oxidation reactions, and gasification reactions take place), a CO.sub.2 reduction zone, and a syngas cooling zone. H.sub.2 may be added to the CO.sub.2 reduction zone downstream of the gasification zone to reduce the CO.sub.2 content in raw syngas from the gasification zone via RWGS reactions, optionally performed non-catalytically, to produce additional CO and H.sub.2O. The syngas may be quenched in the syngas cooling zone via direct quench or indirect quench methods. According to any embodiment recited herein, the carbonaceous feed may be lignocellulosic feedstocks, agriculture waste, algae, organic wet waste, municipal solid waste (MSW), food waste, grain starch, oilseed crops, manure waste, coal, lignite, anthracite, and petcoke. The carbonaceous feed may be any gaseous or liquid matter such as natural gas, liquefied petroleum gas, flare gases, petroleum oil, tars, bio-oils, and biogas.

[0046] According to any embodiment recited herein, the gasification process and gasification zone may be substituted by another oxidative conversion process and associated oxidative conversion zone, such as POX process having a POX zone or an ATR process having an ATR zone.

[0047] According to any embodiment recited herein, externally sourced H.sub.2 may be fed or imported into the syngas cooling zone to directly quench the syngas effluent from the oxidative conversion zone (gasification/POX/ATR zone) and simultaneously augment the H.sub.2 content in the CO.sub.2-depleted syngas from the syngas cooling zone in order to achieve a target or optimized H.sub.2:CO molar ratio for downstream processes. This H.sub.2 fed or imported into the CO.sub.2 reduction zone, and/or into the syngas cooling zone, may be produced via a water splitting process such as electrolysis and the water splitting process oxygen byproduct may be fully or partially used to react with the carbonaceous feed in the gasifier, POX, or ATR process. The H.sub.2 may be preheated to a target temperature, sufficient for gasification/POX/ATR, before being fed or imported into the CO.sub.2 reduction zone. Oxygen needed in the gasification/POX/ATR zone may be fully or partially sourced from a source other than electrolysis such an air separation unit (ASU), a pressure swing adsorber (PSA), a vacuum pressure swing adsorber (VPSA), or an air separation membrane. The H.sub.2 needed in the CO.sub.2 reduction zone may otherwise be fully or partially sourced from one or more processes other than electrolysis such as a steam methane reforming, autothermal reforming, partial oxidation, gasification, and methane pyrolysis. Likewise, the H.sub.2 fed or imported to the syngas cooling zone may be fully or partially sourced from one or more processes other than electrolysis such as a steam methane reforming, autothermal reforming, partial oxidation, gasification, and methane pyrolysis.

[0048] According to any embodiment recited herein, additional CO.sub.2, not originating from the carbonaceous feed in the gasification/POX/ATR zone, may be fed or imported in the gasification/POX/ATR zone and/or the CO.sub.2 reduction zone. Such additional CO.sub.2 may originate from external point-source CO.sub.2 capture facilities and/or direct air capture facilities, for feeding or importing into the gasification/POX/ATR zone and/or the CO.sub.2 reduction zone. According to any embodiment recited herein, additional carbonaceous materials, not originating from the carbonaceous feed to the gasification/POX/ATR zone, may be fed to the gasification/POX/ATR zone and/or the CO.sub.2 reduction zone. According to any embodiment recited herein, H.sub.2O produced from the RWGS reaction in the CO.sub.2 reduction zone may gasify and reform unconverted materials from the carbonaceous feedstocks fed to the gasification zone. Alternatively, or in combination, H.sub.2O produced from the RWGS reaction in the CO.sub.2 reduction zone may gasify and reform any external carbonaceous materials that are fed or imported into the gasification zone and/or the CO.sub.2 reduction zone.

[0049] Other particular representative embodiments include the following: An integrated gasification and dry reforming process to produce a syngas effluent, or CO.sub.2-depleted syngas, from a gasifier vessel with reduced CO.sub.2 content, wherein the gasifier includes at least three zones: a gasification zone for a carbonaceous feed (where drying, devolatilization, oxidation reactions, and gasification reactions take place), a CO.sub.2 reduction zone, and a syngas cooling zone. One or more hydrocarbons (e.g., methane, ethane, and/or propane) may be added to the CO.sub.2 reduction zone downstream of the gasification zone to reduce the CO.sub.2 content in the raw syngas from the gasification zone via dry reforming reactions, optionally performed non-catalytically, to produce more CO and H.sub.2. The syngas may be quenched in the syngas cooling zone via direct quench or indirect quench methods. According to any embodiment recited herein, the carbonaceous feed may be lignocellulosic feedstocks, agriculture waste, algae, organic wet waste, municipal solid waste (MSW), food waste, grain starch, oilseed crops, manure waste, coal, lignite, anthracite, and petcoke. The carbonaceous feed may be any gaseous or liquid matter such as natural gas, liquefied petroleum gas, flare gases, petroleum oil, tars, bio-oils, and biogas.

[0050] According to any embodiment recited herein, the one or more hydrocarbons may be preheated to a target temperature, sufficient for gasification/POX/ATR, before being fed or imported into the CO.sub.2 reduction zone. Externally supplied CO.sub.2 may be pre-mixed and co-injected with the one or more hydrocarbons into the CO.sub.2 reduction zone. Additional carbonaceous materials, not originating from the carbonaceous feed to the gasification/POX/ATR zone, may be fed to the gasification/POX/ATR zone and/or the CO.sub.2 reduction zone.

[0051] Other particular representative embodiments include the following: an integrated gasification, in-situ RWGS process, and in-situ dry reforming process to produce a syngas effluent, or CO.sub.2-depleted syngas, from a gasifier vessel with reduced CO.sub.2 content, wherein the gasifier includes at least three zones: a gasification zone for a carbonaceous feed (where drying, devolatilization, oxidation reactions, and gasification reactions take place), a CO.sub.2 reduction zone, and a syngas cooling zone. Hydrogen may be added to the CO.sub.2 reduction zone downstream of the gasification zone to reduce the CO.sub.2 content in the raw syngas from the gasification zone via RWGS reactions, optionally performed non-catalytically, to produce more CO and H.sub.2O. One or more hydrocarbons (e.g., methane, ethane, and/or propane) may be added to the CO.sub.2 reduction zone downstream of the gasification zone to reduce the CO.sub.2 content in the syngas effluent from the gasification zone via dry reforming reactions, optionally performed non-catalytically, to produce additional CO and H.sub.2. The syngas exiting the CO.sub.2 reduction zone may be quenched in the syngas cooling zone via direct quench or indirect quench methods. The hydrogen and/or one or more hydrocarbons, which are optionally imported or supplied from on-site external processes, may be pre-heated to respective target temperatures, sufficient for gasification/POX/ATR, before being fed to the CO.sub.2 reduction zone. Externally supplied CO.sub.2 may be pre-mixed and co-injected with the hydrogen and/or one or more hydrocarbons into the CO.sub.2 reduction zone.

[0052] According to any embodiment recited herein, the hydrogen, which is optionally imported or supplied from an on-site external process, may be fed to the syngas cooling zone to directly quench the syngas effluent from the gasification/POX/ATR zone and simultaneously augment the H.sub.2 content in the syngas effluent from the syngas cooling zone in order to achieve a target or optimized H.sub.2:CO molar ratio for downstream processes. The hydrogen added to the CO.sub.2 reduction zone may be produced via a water splitting process such as electrolysis and the water splitting process oxygen by-product may be fully or partially used to react with the carbonaceous feed to the gasifier/POX/ATR. Hydrogen fed to the syngas cooling zone may be produced via a water splitting process such as electrolysis and the water splitting process oxygen byproduct may be fully or partially used to react with a carbonaceous feed to the gasifier/POX/ATR.

[0053] According to any embodiment recited herein, oxygen needed in the gasification/POX/ATR zone may be fully or partially sourced from a source other than electrolysis, such an air separation unit (ASU), a pressure swing adsorber (PSA), a vacuum pressure swing adsorber (VPSA), or an air separation membrane. Hydrogen fed to the CO.sub.2 reduction zone and/or hydrogen fed to the syngas cooling zone, may be fully or partially sourced from processes other than electrolysis such as a steam methane reforming, autothermal reforming, partial oxidation, gasification, and methane pyrolysis.

[0054] Embodiments disclosed herein may be suitably practiced without further collaboration of additional elements, parts, steps, components, or ingredients of which those skilled in the art, having knowledge of the present disclosure, would be aware and would be capable of implementation. To the extent that associated equipment such as certain vessels, heat exchangers, valves, instrumentation, and utilities, are not shown, their specific description is not essential to the implementation or understanding of the various aspects of the invention. Such equipment would be readily apparent to those skilled in the art, having knowledge of the present disclosure.

[0055] Whereas in the foregoing detailed description this invention has been described in relation to certain preferred embodiments thereof, and many details have been set forth for purposes of illustration, it will be apparent to those skilled in the art that the invention is susceptible to additional embodiments and that certain of the details described herein can be varied considerably without departing from the basic principles or science of the invention.