Process and system for reforming methane and light hydrocarbon into liquid hydrocarbon fuel

Abstract

To provide a reforming catalyst and a process for reforming methane and / or other hydrocarbons to produce a synthesis gas product comprising H2 and CO, with further downstream conversion to liquid hydrocarbons.SOLUTION: A process for producing C4+ hydrocarbons comprises the steps of: (a) bringing a gaseous mixture comprising methane and an oxidant into contact with a reforming catalyst in a reforming stage to produce a synthesis gas product; (b) converting H2 and CO in the synthesis gas product into hydrocarbons containing the C4+ hydrocarbons, which are supplied as Fischer-Tropsch (FT) products to a Fischer-Tropsch (FT) reactor; and (c) supplying the FT product containing the C4+ hydrocarbons to a finishing reactor to convert at least about 75% of the wax fraction's normal C20+ hydrocarbons into C4-C19 hydrocarbons.SELECTED DRAWING: Figure 3

Description

[Technical Field]

[0001] STATEMENT OF FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT This invention was made with government support under U.S. Department of Energy Grant DE-EE-0007009. The government has certain rights in this invention.

[0002] Aspects of the present invention relate to reforming catalysts and processes for reforming methane and / or other hydrocarbons to produce a synthesis gas product comprising H2 and CO, with further downstream conversion to liquid hydrocarbons. [Background technology]

[0003] 2. Description of Related Art The search for alternatives to crude oil for the production of hydrocarbon fuels is increasingly driven by a number of factors, including declining oil reserves, projected increases in energy demand, and growing concerns about greenhouse gas (GHG) emissions from nonrenewable carbon sources. Given the abundance of natural gas reserves and biogas streams obtained from biological sources, methane has become the focus of numerous potential routes to provide liquid hydrocarbons. Key commercial processes for converting methane to fuel involve a first conversion step to produce synthesis gas (syngas), followed by a second downstream Fischer-Tropsch (FT) conversion step. In this second step, the synthesis gas, containing a mixture of hydrogen (H2) and carbon monoxide (CO), undergoes sequential cleavage of C-O bonds and formation of C-C bonds incorporating hydrogen. This mechanism provides for the formation of hydrocarbons, particularly linear alkanes, with a molecular weight distribution that can be controlled to some extent by modifying the FT reaction conditions and catalyst properties. Such properties include pore size and other characteristics of the support material. Catalyst selection can affect FT product yields in other ways. For example, iron-based FT catalysts tend to produce more oxygenates, while ruthenium as the active metal tends to produce exclusively paraffins.

[0004] Regarding the first conversion step, well-known processes for producing syngas from methane upstream of the FT include partial oxidation reforming and autothermal reforming (ATR), which are based on the exothermic oxidation of methane with oxygen. On the other hand, steam methane reforming (SMR) uses steam as the oxidant, resulting in significantly different thermodynamics, not only because the generation of steam itself can require energy investment, but also because the reaction involving methane and water is endothermic. Recently, the use of carbon dioxide (CO2) as an oxidant for methane has also been proposed, so that the desired syngas is formed by the reaction of the most oxidized and most reduced forms of carbon according to the following equation:

number

[0005] This reaction, known as "dry reforming" of methane, is highly endothermic, making the thermodynamics of dry reforming of methane unfavorable compared to ATR, or even SMR. However, the stoichiometric consumption of one mole of carbon dioxide per mole of methane potentially reduces the overall carbon footprint of liquid fuel production, providing a more environmentally friendly consumption of methane. This CO2 consumption rate per mole of feed increases when reforming higher hydrocarbons (e.g., C2-C6 paraffins), which is desirable, for example, for hydrogen production (e.g., for refinery processes). In either case, the thermodynamic barrier is nevertheless a significant challenge, related to the fact that CO2 is fully oxidized and highly stable, requiring significant energy to activate it as an oxidant. In view of this, numerous catalytic systems have been investigated to overcome the activation energy barrier for the dry reforming of methane, as summarized, for example, in the literature [review by Lavoie (Frontiers in Chemistry (Nov. 2014), Vol. 2 (81): 1-17)], which confirms that heterogeneous catalytic systems are the most popular catalytic approaches to carry out this reaction.

[0006] On the other hand, nickel-based catalysts have shown effectiveness in reducing the activation energy for the aforementioned dry reforming reaction, but Lavoie also reported high rates of carbon deposition (coking) on ​​these catalysts. The undesirable conversion of methane to elemental carbon can proceed through methane decomposition (CH → C + 2H) or the Boudouard reaction (2CO → C + CO) at the reaction temperatures typically required for dry reforming of methane. Therefore, this reaction has been investigated as a promising route for syngas production, but commercialization of this technology, unlike other reforming technologies such as ATR and SMR, has yet to be realized. This is largely due to the high carbon formation rate and accompanying catalyst deactivation through coking, as observed with dry reforming catalyst systems operating under previously proposed conditions. Finally, while other conventional reforming technologies have proven economically viable, such processes, and SMR in particular, are well known to require significant upstream capital and operating costs to remove sulfur and other poisons from the catalysts used. Otherwise, commercially acceptable run lengths from a given catalyst loading cannot be realized. Satisfactory solutions to these and other problems with conventional hydrocarbon reforming to produce syngas and / or hydrogen have been sought but have not yet been realized. Summary of the Invention [Means for solving the problem]

[0007] Aspects of the present invention relate to the discovery of reforming catalysts and processes for converting methane and / or other hydrocarbons to synthesis gas (i.e., a gaseous mixture comprising H and CO) by reacting at least a portion of the hydrocarbon(s) with CO. Preferably, according to the CO-steam reforming reaction, at least a second portion of the hydrocarbon(s) (e.g., comprising the same hydrocarbon(s) as the first portion) reacts with HO (steam), thereby improving the overall thermodynamics of the process in terms of reducing endothermicity (ΔH) and required energy input compared to "pure" dry reforming in the absence of HO. Exemplary reforming catalysts beneficially possess high activity, thereby enabling significant levels of hydrocarbon (e.g., methane) conversion at temperatures below those traditionally used for dry reforming. Such high activity levels, optionally in conjunction with the use of HO to provide at least a portion of the oxidant, contribute to an overall operating environment, which can reduce coke formation and significantly extend the useful reforming catalyst life.

[0008] A further important benefit is the sulfur-tolerant nature of the reforming catalysts described herein, such that pretreatment of methane-containing feedstocks (e.g., natural gas) or other hydrocarbon-containing feedstocks to reduce the concentration of HS and other sulfur-containing contaminants is not required, or at least is less rigorous than in conventional reforming technologies, according to preferred embodiments. Also, considering that all or at least a significant portion of sulfur-containing contaminants such as mercaptans, except for HS, can be oxidized to SO in the dry reforming or CO-steam reforming reactions described herein, thereby making standard acid gas treatment (e.g., scrubbing) a preferred and relatively simple option for downstream sulfur removal, if such downstream sulfur removal may be desired, such as prior to a FT synthesis step, this can significantly simplify pretreatment.

[0009] Overall, the process and related reforming catalyst improvements described herein are commercially significant in that they make dry reforming, or otherwise CO and steam reforming (i.e., CO-steam reforming), processes an economically viable alternative to conventional technologies such as autothermal reforming (ATR) and steam methane reforming (STR). Furthermore, the synthesis gas from this process can be produced at a favorable H:CO molar ratio (e.g., about 2:1) for downstream processing via the Fischer-Tropsch (FT) reaction, or at least at a molar ratio that can be easily adjusted to achieve such a favorable value.

[0010] The demonstrated ability of the CO2-steam reforming process described herein to consistently produce a synthesis gas product with a favorable H2:CO molar ratio and tolerance to sulfur-containing contaminants often present in methane sources (e.g., natural gas) and other light hydrocarbon sources provides benefits when using such a process in addition to producing liquid hydrocarbons, such as gasoline and diesel boiling range hydrocarbon fractions. Such benefits include the overall liquid hydrocarbon production process being significantly simpler, requiring fewer addition, separation, and / or recycling steps compared to conventional processes, for example. This not only results in cost savings, but also allows the overall process to be provided in an easily transportable (e.g., skid-mounted) configuration that can be delivered to a natural gas source or to sources of other components of the gaseous mixture as described herein, from which transporting such components to conventional, conventional (brick and mortar) production facilities may otherwise be problematic. The benefits also include increased flexibility with respect to integration opportunities with a variety of processes that produce gas streams containing CO2 and / or light hydrocarbons, including biomass conversion processes, fermentation processes, and industrial processes that produce CO2-containing waste gases.

[0011] These and other embodiments, aspects, and advantages of the present invention will be apparent from the following detailed description. [Brief explanation of the drawings]

[0012] A more complete understanding of exemplary embodiments of the present invention, and its advantages, may be obtained by reference to the following description in consideration of the accompanying drawings, in which like reference numerals are used to identify the same or similar features. [Figure 1A] 1 shows a flow scheme illustrating a representative dry reforming and CO2-steam reforming process as described herein. [Figure 1B] 1 shows a flow scheme illustrating a representative dry reforming and CO2-steam reforming process as described herein. [Figure 2] Figure 1 illustrates the relationship between pressure in a Fischer-Tropsch (FT) reactor and the CO conversion level obtained when other operating conditions are constant. [Figure 3] FIG. 1 shows a flow scheme in which a dry reforming process CO 2 -steam reforming process such as that shown in FIG. 1A or FIG. 1B is integrated with downstream processing steps to produce liquid hydrocarbons. [Figure 4] 1A or 1B is used in conjunction with a process for producing renewable hydrocarbon fuels from the hydropyrolysis of biomass. [Figure 5] Figure 3 shows a flow scheme in which dry reforming or CO2-steam reforming is integrated into an overall liquid hydrocarbon production process, such as that shown in Figure 3, which is used in conjunction with a process for producing renewable hydrocarbon fuels from biomass hydropyrolysis. [Figure 6] 1 shows a flow scheme for a process to produce renewable hydrocarbon fuels from hydropyrolysis of biomass, where dry reforming or CO2-steam reforming processes can be used together as shown in FIG. 4, or where the entire liquid hydrocarbon production process can be integrated as shown in FIG. 5. [Figure 7]

[0033] Figure 3 shows a flow scheme in which dry reforming or CO2-steam reforming is integrated into the overall liquid hydrocarbon production process as shown in Figure 3, which is used in the hydrogen production process. [Figure 8] The high activity for methane conversion is illustrated for the reforming catalyst as described herein. [Figure 9] FIG. 1 illustrates the relationship between the H:CO molar ratio of the synthesis gas product and the H0 / CO molar ratio of the gaseous mixture in the CO-steam reforming reactor (as combined feed) at different reaction temperatures for a representative CO-steam reforming process. [Figure 10] 1 illustrates the long-term operational stability of the reforming catalyst as described herein in a CO2-steam reforming process over an extended operating period. [Figure 11] 1 illustrates the long-term operational stability of the reforming catalyst as described herein in a CO2-steam reforming process over an extended operating period.

[0013] It should be understood that the drawings provide illustrations of processes and associated specific results and parameters, and / or associated principles. It is understood that Figures 1A, 1B, 3-7, 10, and 11 provide simplified overviews for ease of explanation and understanding, and that such drawings and elements are not necessarily drawn to scale. Valves, instruments, and other equipment and systems not essential to the understanding of various aspects of the present invention are not shown. As will be readily apparent to one of ordinary skill in the art with knowledge of this disclosure, processes for converting hydrocarbons such as methane by dry reforming or CO2-steam reforming will have components and elements that are determined in part by their particular application. DETAILED DESCRIPTION OF THE INVENTION

[0014] The expressions "wt%" and "mol%" are used herein to refer to weight percent and mole percent, respectively. The expressions "wt-ppm" and "mol-ppm" refer to parts per million by weight and parts per million by mole, respectively. For an ideal gas, "mol%" and "mol-ppm" are equal to volume percent and parts per million by volume, respectively.

[0015] As used in this disclosure, "C4 + hydrocarbons," "C 20 + Hydrocarbons, C4-C 19 Terms such as "hydrocarbon" refer to hydrocarbons with more than 4 carbon atoms, hydrocarbons with more than 20 carbon atoms, hydrocarbons with 4 to 19 carbon atoms, etc., respectively. Unless otherwise specified, such terms do not imply that hydrocarbons with all carbon numbers in a specified range must be present. For example, "normal C 20 + In the designation "hydrocarbons," the term includes all types of hydrocarbons (e.g., normal, branched, aromatic, naphthenic, olefinic, etc.).

[0016] The term "gaseous mixture" refers to a mixture comprising at least a hydrocarbon, such as methane, and also comprising CO as an oxidant, that undergoes dry reforming or CO-steam reforming (when water is also present in the gaseous mixture) by contact with a reforming catalyst as described herein. The term "gaseous mixture" generally refers to such a mixture that is entirely or at least predominantly in the gas phase under conditions used for dry reforming or CO-steam reforming ("reforming conditions"), including temperatures and pressures suitable for such reactions as described herein. The term "gaseous mixture" does not exclude the presence of compounds in the mixture (e.g., water) that are liquid under ambient temperature and pressure conditions. Such compounds include hydrocarbons, e.g., C6-C6, such as those found in liquid fuels, including naphtha and jet fuel. 16 It may contain hydrocarbons.

[0017] The terms "naphtha boiling range hydrocarbons" and "gasoline boiling range hydrocarbons" refer to hydrocarbon fractions comprising hydrocarbons having boiling points characteristic of C5 hydrocarbons between an initial ("front-end") distillation temperature of 35°C (95°F) and a final distillation temperature of 204°C (399°F). The term "jet fuel boiling range hydrocarbons" refers to hydrocarbon fractions comprising hydrocarbons having boiling points between a front-end distillation temperature of 204°C (399°F) and a final distillation temperature of 271°C (520°F). The term "diesel boiling range hydrocarbons" refers to hydrocarbon fractions comprising hydrocarbons having boiling points between a front-end distillation temperature of 204°C (399°F) and a final distillation temperature of 344°C (651°F). Thus, "diesel boiling range hydrocarbons" encompass not only "jet fuel boiling range hydrocarbons" but also "heavy diesel boiling range hydrocarbons" having boiling points between a front distillation temperature of 271°C (520°F) and a tail distillation temperature of 344°C (651°F). The term "VGO boiling range hydrocarbons" refers to a hydrocarbon fraction comprising hydrocarbons having boiling points between a front distillation temperature of 344°C (651°F) and a tail distillation temperature of 538°C (1000°F). Such front and tail distillation temperatures of hydrocarbon fractions such as naphtha boiling range hydrocarbons, gasoline boiling range hydrocarbons, jet fuel boiling range hydrocarbons, and diesel boiling range hydrocarbons (which are also characteristic of petroleum-derived naphtha, gasoline, jet fuel, and diesel boiling range fractions, respectively) are determined according to ASTM D86 with a 95% tail recovery.

[0018] The term "substantially," as used in the phrases "substantially the same" or "substantially the same," in reference to a given parameter, is meant to encompass values ​​for that parameter that deviate by less than 5% when measured in absolute terms (e.g., absolute temperature or absolute pressure). The terms "substantially all" or "substantially all of" mean "at least 95% of." The term "substantially complete" means "at least 95% substantially complete."

[0019] Embodiments of the invention relate to a process for producing a synthesis gas product (syngas), the process comprising: (i) a process for producing methane and / or other hydrocarbon(s) (e.g., CH4, C2H6, C2H4, C3H8, C3H6, C4H 10 , C4H8, C5H 12 , C5H 10 , any of the high molecular weight hydrocarbons, and mixtures thereof), and (ii) CO with a reforming catalyst comprising at least one (e.g., two or more) noble metal on a solid support comprising cerium oxide. It is possible that CO alone can serve as an oxidant for methane and / or other hydrocarbon(s) to CO and H by dry reforming of such hydrocarbons, which can be generalized, for example, in the case of alkanes, as follows:

number

[0020] In preferred embodiments, i.e., embodiments in which the gaseous mixture further comprises HO, the combination of CO and HO can serve as the oxidant. The reaction in this case is the "CO-steam reforming" reaction, which also includes steam reforming as a route to producing syngas from methane and / or other hydrocarbons, which can be generalized, for example, for alkanes, as follows:

number

number

[0021] From this, C4-C, which are desirable as fuels or fuel components, 12 C4 hydrocarbons + It can be observed that hydrocarbons are ideally formed at H:CO molar ratios close to 2. Importantly, the use of steam (H2O) as an oxidant in combination with CO2 provides a useful "handle" or control parameter for adjusting the H2:CO molar ratio of the syngas product over a wide range of CO2-steam reforming conditions. Indeed, for any given set of such conditions (e.g., conditions within the CO2-steam reforming reactor, such as temperature, pressure, weight hourly space velocity, and reforming catalyst loading) under which the CO2-steam reforming and steam reforming reactions are carried out in combination, a relationship can be established between the H2O:CO2 molar ratio of the gaseous mixture (e.g., the combined CO2-steam reforming reactor feed) and the H2:CO molar ratio of the syngas product (e.g., the CO2-steam reforming reactor effluent). While dry and steam reforming of hydrocarbons other than methane produce H and CO in other molar ratios, the same directionally shifts or adjustments in product yields can be achieved by relatively varying the amounts of oxidants H O and CO in the gaseous mixture undergoing CO-steam reforming. Accordingly, embodiments of the present invention relate to a CO-steam reforming process comprising determining a synthesis gas product H:CO molar ratio and adjusting the H O:CO molar ratio of the gaseous mixture based on the H:CO molar ratio toward a target synthesis gas product H:CO molar ratio, e.g., toward a target H:CO molar ratio of 2:1, or otherwise generally in the range of about 1.5:1 to about 2.5:1, typically in the range of about 1.5:1 to about 2.3:1, and often in the range of about 1.8:1 to about 2.2:1.

[0022] More specifically, the HO:CO molar ratio of the gaseous mixture may be increased to increase the observed H:CO molar ratio of a syngas product below target, toward the target H:CO molar ratio. Conversely, the HO:CO molar ratio of the gaseous mixture may be decreased to decrease the observed H:CO molar ratio of a syngas product above target, toward the target H:CO molar ratio. Any such adjustment to the HO:CO molar ratio of the gaseous mixture may be made, for example, by adjusting the flow rate(s) of one or more components of the gaseous mixture (e.g., the combined feed), such as the methane-containing feedstock (or hydrocarbon-containing feedstock generally), the CO-containing oxidant, and the HO-containing oxidant, relative to the flow rate(s) of one or more other such components. According to a particular embodiment, the HO:CO molar ratio of the combined feed to the CO-steam reforming reactor may be increased or decreased by increasing or decreasing, respectively, the flow rate of steam (as the HO-containing oxidant), which may result in an increased or decreased HO:CO molar ratio of the gaseous mixture.

[0023] In addition to providing the ability to control the H:CO molar ratio of the synthesis gas product to a value within a preferred range, the use of steam (HO) as an oxidant in combination with CO further surprisingly reduces the carbon (coke) formation rate compared to pure dry reforming, thereby extending catalyst life as described herein. Accordingly, a further embodiment of the present invention relates to a CO-steam reforming process in which the carbon formation rate (e.g., using a suitable ratio or concentration / partial pressure of CO and HO oxidant in combination with a reforming catalyst as described herein) is less than that of a baseline process (i.e., a baseline dry reforming process), all parameters being kept the same, except for replacing HO in the gaseous mixture (e.g., the combined CO-steam reforming reactor feed) with an equimolar amount of oxygen for CO (i.e., replacing 1 mole of HO with ½ mole of CO). Coupled with this relatively low carbon formation relative to the baseline process, the synthesis gas product can have a H2 / CO molar ratio as described herein (e.g., from about 1.5:1 to about 2.3:1).

[0024] CO-steam reforming as described herein can be carried out to produce a synthesis gas product having the aforementioned preferred H:CO molar ratios, such as in the range of about 1.5:1 to about 2.5:1, the range of about 1.5:1 to about 2.3:1, and the range of about 1.8:1 to about 2.2:1. Such ranges, including 2:1, are particularly beneficial for downstream processing of the synthesis gas product in a FT synthesis stage to produce liquid hydrocarbons as described herein. In particular, the H and CO in the synthesis gas product can be converted to C4 + The step of converting hydrocarbons (including hydrocarbons that are liquid at ambient temperature and pressure) to hydrocarbons containing hydrocarbons may be carried out using a FT feed produced by upstream CO2-steam reforming, having substantially the same H2:CO molar ratio as the syngas product. That is, the FT feed may preferably be obtained without adjusting the H2:CO molar ratio of the syngas product (e.g., without adding H2 to increase the molar ratio and / or without using a separate water-gas shift reaction or reverse water-gas shift reaction), such as by adding or removing H2 and / or CO or otherwise converting or producing such components. According to some embodiments, the FT feed may be obtained with substantially the same H2:CO molar ratio as the syngas product by condensing water from this product prior to converting H2 and CO to hydrocarbons in the FT synthesis stage. According to some embodiments, the FT feed may be obtained without any change to the composition of the syngas product. For example, some or all of the syngas product may be used directly in the FT synthesis stage without any intervening operations that would affect its composition (e.g., by adding, removing, or converting components that would change its composition).

[0025] The aforementioned range of H:CO molar ratios of the synthesis gas product, including 2:1, is similarly beneficial for downstream processing of the synthesis gas product in a methanol production stage that produces methanol according to the following reaction: 2H + CO → CHOH. In particular, the step of converting H and CO in the synthesis gas product to methanol, which is provided as the methanol product, can be carried out using a methanol synthesis feed produced by upstream CO-steam reforming and having substantially the same H:CO molar ratio as the synthesis gas product. That is, the methanol synthesis feed can be preferably obtained without adjusting the H:CO molar ratio of the synthesis gas product (e.g., without adding H to increase the molar ratio and / or without using a separate water-gas shift reaction or reverse water-gas shift reaction), such as by adding or removing H and / or CO or otherwise converting or producing such components. According to some embodiments, the methanol synthesis feed can be obtained with substantially the same H:CO molar ratio as the synthesis gas product by condensing water from this product. According to some embodiments, the methanol synthesis feed can be obtained without any modification of the composition of the synthesis gas product. For example, some or all of the synthesis gas product may be used directly in a methanol production stage without any intervening operations that would affect its composition (e.g., by the addition, removal, or conversion of components that would alter its composition). Methanol production from the synthesis gas product may be carried out at temperatures of about 204°C (400°F) to about 316°C (600°F) and pressures of about 4.5 MPa (650 psig) to about 11.7 MPa (1700 psig). Methanol synthesis catalysts typically comprise Cu and ZnO supported on a metal oxide such as alumina (Al2O3).

[0026] When producing methanol from the synthesis gas product, the methanol may be further reacted in a dehydration stage to produce dimethyl ether (DME) according to the following reaction: 2CHOH → CHOCH + H. Catalysts and conditions for carrying out this reaction stage are described, for example, in U.S. Patent No. 5,037,511; U.S. Patent No. 2004 / 0034255; and U.S. Patent No. 8,451,630. Alternatively, DME may be produced directly from the synthesis gas product in a direct DME production stage, without an intervening methanol production stage. In this regard, dry reforming as described herein may be carried out to produce a synthesis gas product having a preferred H:CO molar ratio in the range including 1:1, suitable for carrying out the following reaction: 3H + 3CO → CHOCH + CO, as described, for example, in Takeishi et al. (Recent Advances in Energy & Environment). A suitable H:CO molar ratio is about 0.5:1 to about 1.5:1, about 0.5:1 to about 1.3:1, or about 0.8:1 to about 1.2:1. In particular, the step of converting H and CO in the syngas product to DME, which is provided as the DME product, can be carried out using a DME synthetic feed produced by upstream dry reforming, having substantially the same H:CO molar ratio as the syngas product. That is, the DME synthetic feed can be preferably obtained without adjusting the H:CO molar ratio of the syngas product (e.g., without adding H to increase the molar ratio and / or without using a separate water-gas shift reaction or reverse water-gas shift reaction), such as by adding or removing H and / or CO or otherwise converting or producing such components. According to some embodiments, the DME synthetic feed can be obtained at substantially the same H:CO molar ratio as the syngas product by condensing water from this product. According to some embodiments, the DME synthetic feed can be obtained without any modification of the composition of the syngas product. For example, some or all of the synthesis gas product may be used directly in the DME production stage without any intervening operations that would affect its composition (e.g., by adding, removing, or converting components that would change its composition).

[0027] In addition to producing a synthesis gas product with a desirable H:CO molar ratio, which can be tailored to specific downstream reaction steps as described above, the reforming catalysts described herein also exhibit surprising sulfur tolerance, which is particularly beneficial, for example, in the case of methane-containing feedstocks comprising or derived from natural gas, which, depending on its source, may contain significant concentrations of HS (e.g., several weight percent or more by volume). In this regard, conventional steam methane reforming (SMR) processes typically require pretreatment to reduce the total feed sulfur content to less than 1 mol-ppm to protect the reforming catalyst from sulfur poisoning. In contrast, according to exemplary embodiments of the present invention, the gaseous mixture or any of its components, particularly the hydrocarbon-containing feedstock, is not subjected to or has otherwise undergone a sulfur removal pretreatment step. Such embodiments offer substantial economic benefits over known processes with stringent desulfurization requirements and associated costs, as needed to achieve favorable reforming catalyst life. In contrast to such known processes, the gaseous mixture in a dry reforming or CO2-steam reforming process as described herein not only generally has not undergone pretreatment for sulfur removal, but may also comprise any concentration of sulfur typical of a source of hydrocarbon feedstock, such as natural gas, that, when combined with other components of the gaseous mixture (e.g., CO2) having low concentrations of sulfur, results in sulfur dilution. For example, the gaseous mixture may generally comprise at least about 1 molar ppm (e.g., from about 1 mol-ppm to about 10 mol%) total sulfur (e.g., as H2S and / or other sulfur-containing contaminants). The gaseous mixture may generally comprise at least about 10 mol-ppm (e.g., from about 10 mol-ppm to about 1 mol%) and often at least about 100 mol-ppm (e.g., from about 10 mol-ppm to about 1 mol%) total sulfur. For example, about 500 mol-ppm to about 1000 mol-ppm total sulfur, according to certain embodiments, generally causes no adverse, or at least negligible, adverse effect on the stability of reforming catalysts as described herein.

[0028] Regarding the sulfur tolerance of the reforming catalysts described herein, a further aspect of the present invention relates to the discovery that high levels (concentrations) of sulfur in a gaseous mixture can be compensated for by increasing the reaction temperature, i.e., the temperature of the reforming catalyst bed described herein, contained in a reforming reactor (which can be either a dry reforming reactor or a CO2-steam reforming reactor, the latter being applicable to gaseous mixtures in reactors with both CO2 and HO). That is, it has been found that increasing the sulfur concentration affects the activity of the reforming catalyst, as measured by the reduced conversion of methane and / or other hydrocarbon(s) in the gaseous mixture, when all other operating parameters remain unchanged. However, the desired conversion level can be restored by increasing the reaction temperature. For example, under some operating conditions, an increase of 28°C (50°F) can be sufficient to restore the lost activity of a reforming catalyst with an 800 mol-ppm HS concentration in the gaseous mixture, compared to the activity of the reforming catalyst without any sulfur in the gaseous mixture. Accordingly, an embodiment of the present invention relates to a dry reforming process or a CO2-steam reforming process as described herein, comprising determining the conversion of methane and / or other hydrocarbon(s) (e.g., the conversion of combined C1-C4 hydrocarbons or combined C1-C3 hydrocarbons) or otherwise determining the sulfur level (e.g., the H2S level) in the gaseous mixture or synthesis gas product, and adjusting the reaction temperature based on the conversion or sulfur level toward a conversion target of methane and / or other hydrocarbon(s), e.g., a conversion target of at least about 75% (e.g., any particular conversion value in the range of about 75% to about 100%), e.g., at least about 85% (e.g., any particular conversion value in the range of about 85% to about 99%).

[0029] Importantly, however, such a decrease in the activity of the reforming catalysts described herein with increasing sulfur concentrations in the gaseous mixture is not accompanied by any appreciable loss in the stability of the reforming catalyst. That is, increasing the compensatory reforming reactor temperature to offset high sulfur levels, as described herein, does not significantly affect the ability of the reforming catalyst to achieve stable operational performance for dry reforming or CO₂-steam reforming over extended periods of time. This finding is contrary to expectations based on conventional reforming technology, which predict that the presence of even small amounts of sulfur (e.g., mol-ppm levels) in the feed must be avoided to prevent catalyst deactivation and costly premature replacement. The unique sulfur tolerance, or activity stability in the presence of sulfur-containing contaminants, of the reforming catalysts described herein can be determined according to a standard test in which a small catalyst sample of 5 to 100 grams is loaded into a fixed-bed reforming reactor and contacted with a feed blend of 30 mol% methane, 30 mol% CO₂, and 30 mol% HO spiked with 800 mol-ppm HS. In this standard test, -1 With WHSV flow conditions, a catalyst bed temperature of 788°C (1450°F), and a CO2-steam reforming reactor pressure of 138 kPa (20 psig), at least 85% and preferably 95% methane conversion is maintained at a constant catalyst bed temperature for at least 50 hours of operation, and more typically for 100 hours of operation, or even for at least 400 hours of operation.

[0030] The resistance or "robustness" of the reforming catalysts described herein is further manifested in their high stability against deactivation in the presence of other compounds in the gaseous mixture, including high molecular weight hydrocarbons, such as reactive aromatic and / or olefinic hydrocarbons, which are typically considered prone to deactivating the reforming catalyst through coking. For example, the gaseous mixture may generally comprise aromatic and olefinic hydrocarbons in a combined amount of at least about 1 mol % (e.g., from about 1 mol % to about 25 mol %), e.g., at least about 3 mol % (e.g., from about 3 mol % to about 20 mol %), or more specifically, at least about 5 mol % (e.g., from about 5 mol % to about 15 mol %). At such levels of aromatic and / or olefinic hydrocarbons, the stability of the reforming catalyst may be demonstrated according to the same activity stability test defined above for sulfur tolerance, except that the feed blend contains aromatic and / or olefinic hydrocarbons in concentrations distinct from HS. This tolerance of the reforming catalyst with respect to both sulfur and reactive hydrocarbons as described herein enables the reforming of a wide range of hydrocarbon-containing feedstocks, including various fractions obtained from crude oil refining (e.g., naphtha and jet fuel), as described in detail below.

[0031] More generally, the gaseous mixture, and in particular the hydrocarbon-containing feedstock component, may comprise, in addition to methane, other hydrocarbons such as C2, C3, and / or C4 hydrocarbons (e.g., ethane, propane, propylene, butane, and / or butene) that may be present in natural gas and / or other methane sources. Alternatively, the reforming catalyst as described herein may be configured to predominantly or solely comprise C4 hydrocarbons, C5 hydrocarbons, C6 hydrocarbons, C7 hydrocarbons, C8 hydrocarbons, C9 hydrocarbons, C10 hydrocarbons, C11 hydrocarbons, C12 hydrocarbons, C13 hydrocarbons, C14 hydrocarbons, C15 hydrocarbons, C16 hydrocarbons, C17 hydrocarbons, C18 hydrocarbons, C19 hydrocarbons, C20 hydrocarbons, C210 hydrocarbons, C22 hydrocarbons, C23 hydrocarbons, C24 hydrocarbons, C25 hydrocarbons, C26 hydrocarbons, C27 hydrocarbons, C28 hydrocarbons, C29 hydrocarbons, C30 hydrocarbons, C31 hydrocarbons, C32 hydrocarbons, C33 hydrocarbons, C34 hydrocarbons, C35 hydrocarbons, C36 hydrocarbons, C37 hydrocarbons, C38 hydrocarbons, C39 hydrocarbons, C40 hydrocarbons, C41 hydrocarbons, C42 hydrocarbons, C43 hydrocarbons, C44 hydrocarbons, C45 hydrocarbons, C46 hydrocarbons, C47 hydrocarbons, C48 hydrocarbons, C49 hydrocarbons, C50 hydrocarbons, C51 hydrocarbons, C52 hydrocarbons, C53 hydrocarbons, C54 hydrocarbons, C55 hydrocarbons, C56 hydrocarbons, C57 hydrocarbons, C58 hydrocarbons, C59 hydrocarbons, C60 hydrocarbons, C61 hydrocarbons, C62 hydrocarbons, C63 hydrocarbons, C64 hydrocarbons, C65 hydrocarbons, C66 hydrocarbons, C77 hydrocarbons, C88 hydrocarbons, C99 hydrocarbons, C18 hydrocarbons, C19 hydrocarbons, C19 hydrocarbon 10 Hydrocarbons, C 11 Hydrocarbons, C 12 Hydrocarbons, C 13 Hydrocarbons, C 14 Hydrocarbons, C 15 Hydrocarbons, C 16 Hydrocarbons, C 17 Hydrocarbons, C 18The gaseous mixture may be used for dry reforming or CO2-steam reforming of high molecular weight hydrocarbons, such as in the case of hydrocarbons in a gaseous mixture, comprising, or optionally consisting of, any one or more compounds selected from the group consisting of hydrocarbons, C4-C8 hydrocarbons, C4-C6 hydrocarbons, and combinations thereof. For example, the hydrocarbons in the gaseous mixture may comprise or consist of C4-C8 hydrocarbons or C4-C6 hydrocarbons in the case of dry reforming or CO2-steam reforming of naphtha boiling range hydrocarbons (naphtha reforming). As another example, the hydrocarbons in the gaseous mixture may comprise or consist of C8-C8 hydrocarbons or C4-C6 hydrocarbons in the case of dry reforming or CO2-steam reforming of jet fuel boiling range hydrocarbons (jet fuel reforming). 18 Hydrocarbons or C8-C 14 The gaseous mixture may comprise or consist of hydrocarbons. Such naphtha boiling range hydrocarbons and jet fuel boiling range fractions are typically obtained as products from crude oil refining and, as such, may be a source of sulfur-containing contaminants in the gaseous mixture. In exemplary embodiments, the gaseous mixture may comprise methane and / or any of the hydrocarbons described herein in a total amount generally between about 5 mol% and about 85 mol%, typically between about 10 mol% and about 65 mol%, and often between about 20 mol% and about 45 mol%. The gaseous mixture may further comprise CO in an amount generally between about 8 mol% and about 90 mol%, typically between about 15 mol% and about 75 mol%, and often between about 20 mol% and about 50 mol%. In the case of CO-steam reforming, the gaseous mixture may comprise HO in an amount generally between about 15 mol% and about 70 mol%, typically between about 20 mol% and about 60 mol%, and often between about 25 mol% and about 55 mol%. The remainder of the gaseous mixture may contain contaminants such as H2S and / or other sulfur-containing contaminants as previously described.

[0032] For gaseous mixtures comprising methane and / or light hydrocarbons (e.g., C2-C3 or C2-C4 hydrocarbons), the synthesis gas product of dry reforming or CO2-steam reforming can be beneficially used in downstream production of liquid hydrocarbon fuels via Fischer-Tropsch synthesis at a favorable H2:CO molar ratio, as previously described. Alternatively, the synthesis gas can be used for other downstream applications involving conventional steam methane reforming (SMR). For example, Tarun (International Journal of Greenhouse Gas Control I (2007): 55-61) describes a conventional hydrogen production process involving SMR. When dry reforming or CO2-steam reforming is applied in accordance with embodiments of the present invention for hydrogen production as described herein, an exemplary process may further comprise (i) subjecting the synthesis gas product to one or more water-gas shift (WGS) reaction stages to increase the hydrogen content, and / or (ii) optionally separating the effluent of the WGS stage(s) (e.g., by pressure swing adsorption (PSA) or membrane separation), or otherwise separating the synthesis gas product without an intervening WGS stage(s), to provide a hydrogen-enriched product stream and a hydrogen-depleted PSA tail gas stream (or simply, "PSA tail gas"). The hydrogen-enriched product stream may then be used in conventional refinery processes, such as hydrotreating processes (e.g., hydrodesulfurization, hydrocracking, hydroisomerization, etc.). The hydrogen-depleted PSA tail gas stream may then be separated to recover hydrogen and / or used as combustion fuel to meet at least a portion of the heating requirements of the dry reforming or CO2-steam reforming. In yet a further embodiment, the CO and H2-containing PSA tail gas can be passed to a biological fermentation stage to produce a fermentation product such as alcohol (e.g., ethanol). The gaseous effluent from the fermentation stage can then be separated as described above to recover hydrogen and / or used as combustion fuel. Further integration of a biological fermentation stage with conventional hydrogen production is described, for example, in U.S. Patent 9,605,286; U.S. Patent 9,145,300; U.S. Patent 2013 / 0210096; and U.S. Patent 2014 / 0028598.As an alternative to integration in a hydrogen production process, dry reforming or CO2-steam reforming as described herein can be used to provide a synthesis gas product that is used directly in the downstream production of a fermentation product using suitable carboxydotrophic bacteria (e.g., Clostridium autoethanogenum or Clostridium ljungdahlii species). In either case, with or without such integration, the microorganisms used in the fermentation can be sulfur-tolerant or may even require sulfur in the cell culture medium, and as a result, the sulfur-tolerance of the reforming catalyst as described herein can be particularly beneficial in terms of compatibility and cost savings with respect to eliminating, or at least reducing, upstream sulfur removal requirements relative to conventional reforming catalysts.

[0033] Thus, aspects of the present invention relate to dry reforming and CO-steam reforming processes for producing a synthesis gas product (e.g., comprising both H and CO, and optionally unconverted CO, HO, and / or other gases such as hydrocarbons). In exemplary embodiments, a gaseous mixture comprising methane and / or other hydrocarbon(s) may be provided to a reactor for a dry reforming process (i.e., a dry reforming reactor for a feed or gaseous mixture further comprising CO but no water) or a CO-steam reforming process (i.e., a CO-steam reforming reactor for a feed or gaseous mixture further comprising both CO and water) in a batchwise manner, but preferably as a continuous flow, although the general term "reforming reactor" encompasses either case. The synthesis gas product may then be removed from the dry reforming reactor or the CO-steam reforming reactor, as the case may be, in a batchwise manner (if the gaseous mixture is provided in a batchwise manner), but preferably as a continuous flow (if the gaseous mixture is provided in a continuous flow).

[0034] In addition to H2 and CO, and optionally other gases, water (H2O) may also be present in the syngas product, although at least a portion of the water present in vapor form can be easily separated by cooling / condensation, for example, upstream of the Fischer-Tropsch synthesis reactor (FT reactor) used to convert the syngas product to liquid hydrocarbons. Neither water nor CO2 in the syngas product affects the H2:CO molar ratio, and as previously mentioned, this ratio is an important parameter in determining the suitability of the syngas product as a direct feed stream to the FT reactor.

[0035] In a representative process, a gaseous mixture comprising methane and / or other light hydrocarbon(s) (e.g., ethane, ethylene, propane, and / or propylene) and CO, as well as optionally HO, is contacted with a reforming catalyst active to effect reforming of the hydrocarbon(s). In particular, such hydrocarbon(s), e.g., a majority of such hydrocarbons, may be reformed (i) through oxidation with only some or all of the CO according to a dry reforming process, or (ii) through oxidation with both some or all of the CO and some or all of the HO (if present) according to a CO-steam reforming process.

[0036] As previously mentioned, aspects of the present invention relate to the discovery of reforming catalysts for such dry reforming and CO2-steam reforming processes that exhibit significant advantages over conventional reforming catalysts, particularly with respect to sulfur tolerance and / or reduced carbon formation (coking) rates. These characteristics, in turn, reduce the catalyst's deactivation rate through poisoning and / or coking mechanisms that chemically and / or physically block active catalytic sites. Further improvements in the stability of the reforming catalyst result, at least in part, from the high activity of the reforming catalysts described herein, when combined with the necessary reduction of the substantial activation energy barrier associated with the use of CO2 as an oxidant for methane and / or other hydrocarbon(s), as previously described. This high activity manifests itself at lower operating (dry reforming reactor, CO2-steam reforming reactor, dry reforming catalyst bed, or CO2-steam reforming catalyst bed) temperatures, which further contributes to reduced carbon deposition (coking) rates on the reforming catalyst surface and long-term stable operation. According to certain embodiments, processes utilizing the reforming catalysts described herein may maintain stable operating parameters as described herein with respect to hydrocarbon conversion (e.g., at least about 85% conversion of methane and / or other hydrocarbon(s)) and / or H / CO molar ratio in the syngas product (e.g., from about 1.5:1 to about 2.3:1), for at least about 100 hours, at least about 300 hours, or even at least about 500 hours of continuous or, optionally, non-continuous operation. This may be a period of operation during which (i) the reforming catalyst does not undergo regeneration, for example, according to a reforming process utilizing the catalyst as a fixed bed in the reforming reactor, and / or (ii) the temperature of the reforming reactor, or each dry reforming catalyst bed, or CO2-steam reforming catalyst bed, does not increase beyond a threshold temperature difference between the start and end, for example, 100°C (180°F), 50°C (90°F), 25°C (45°F), 10°C (18°F), or even 5°C (9°F).

[0037] Representative reforming catalysts suitable for catalyzing the reaction of methane and / or other hydrocarbon(s) with CO and, optionally, HO may comprise one precious metal on a solid support, and may optionally comprise two or more precious metals. The solid support preferably comprises a metal oxide, including, of particular interest, cerium oxide. The cerium oxide may be present in an amount of at least about 80 wt %, and preferably at least about 90 wt %, based on the weight of the solid support (e.g., relative to the total weight(s) of the metal oxide(s) in the solid support). The solid support may comprise only or substantially only (e.g., greater than about 95 wt %) cerium oxide. Other metal oxides, such as aluminum oxide, silicon oxide, titanium oxide, zirconium oxide, magnesium oxide, strontium oxide, and the like, may also be present in the solid support, the total amount representing a minor amount, such as less than about 50 wt %, less than about 30 wt %, or less than about 10 wt % of the solid support. In other embodiments, the solid support may comprise such other metal oxides alone or in combination with minor amounts (eg, less than about 50 wt % or less than about 30 wt %) of cerium oxide.

[0038] Noble metals are understood to refer to a class of oxidation-resistant metallic elements. In exemplary embodiments, the noble metals, e.g., at least two noble metals, of the reforming catalyst can be selected from the group consisting of platinum (Pt), rhodium (Rh), ruthenium (Ru), palladium (Pd), silver (Ag), osmium (Os), iridium (Ir), and gold (Au), where the term "consisting of" is used merely to describe the group members from which the noble metal(s) are selected according to a particular embodiment, but is not generally used to exclude the addition of other noble metals and / or other metals. Thus, a reforming catalyst comprising noble metals encompasses not only catalysts comprising at least two noble metals but also catalysts comprising at least three noble metals, as well as catalysts comprising two noble metals and a third non-noble metal, such as a promoter metal (e.g., a transition metal). According to preferred embodiments, the precious metal is present in an amount of about 0.05 wt% to about 5 wt%, about 0.3 wt% to about 3 wt%, or about 0.5 wt% to about 2 wt%, based on the weight of the catalyst, or alternatively, at least two precious metals are each present in independent amounts. For example, an exemplary reforming catalyst may comprise two precious metals, Pt and Rh, which may be present independently in any amount within such range (e.g., about 0.05 wt% to about 5 wt%). That is, either Pt may be present in that amount, or Rh may be present in that amount, or both Pt and Rh may be present in that amount.

[0039] In exemplary embodiments, the at least two precious metals (e.g., Pt and Rh) can be substantially the only precious metals present in the reforming catalyst, such that, for example, any other precious metal(s) are present in an amount or combined amount of less than about 0.1 wt% or less than about 0.05 wt% based on the weight of the reforming catalyst. In further exemplary embodiments, the at least two precious metals (e.g., Pt and Rh) are substantially the only metals present in the reforming catalyst, except for metals present in the solid support (e.g., cerium present as cerium oxide in the solid support). For example, the at least two precious metals and any other metal(s) other than the metal(s) on the solid support can be present in an amount or combined amount of less than about 0.1 wt% or less than about 0.05 wt% based on the weight of the reforming catalyst. Any metal present in the catalyst, including the precious metal(s), may generally have a metal particle size in the range of about 0.3 nanometers (nm) to about 20 nm, commonly in the range of about 0.5 nm to about 10 nm, and often in the range of about 1 nm to about 5 nm.

[0040] The precious metal(s) can be incorporated into the solid support according to well-known techniques for catalyst preparation, including sublimation, impregnation, or dry mixing. In the case of impregnation, which is a preferred technique, an impregnation solution of soluble compounds of one or more of the precious metals in a polar (aqueous) or non-polar (e.g., organic) solvent can be contacted with the solid support, preferably under an inert atmosphere. For example, this contacting can be carried out in an ambient atmosphere of nitrogen, argon, and / or helium, or otherwise in a non-inert atmosphere such as air, preferably with stirring. The solvent can then be evaporated from the solid support, for example, using conditions of heat, flowing gas, and / or vacuum, to form a dry precious metal-impregnated support. The precious metal(s) can be impregnated into the solid support; for example, if two precious metals are being simultaneously impregnated, both can be dissolved in the same impregnation solution, or can be impregnated separately using different impregnation solutions and contacting steps. In either case, the precious metal impregnated support may undergo further preparation steps such as washing with a solvent to remove excess precious metal(s) and impurities, further drying, calcination, etc. to provide the reforming catalyst.

[0041] The solid support itself can be prepared according to well-known methods, such as extrusion to form cylindrical particles (extrudates), oil dripping, or spray drying to form spherical particles. Regardless of the particular shape of the solid support and the resulting catalyst particles, the amount of precious metal(s) present in the reforming catalyst, as described above, refers to the average weight of such precious metal(s) in a given catalyst particle (of any shape, e.g., cylindrical or spherical), regardless of the particular distribution of the precious metal(s) within the particle. In this regard, it can be understood that different preparation methods can provide different distributions, such as depositing the precious metal(s) primarily on or near the surface of the solid support, or distributing the precious metal(s) uniformly throughout the solid support. Generally, weight percents described herein can refer to weight percents for a single catalyst particle, based on the weight of the solid support or otherwise based on the weight of the reforming catalyst, but generally refer to the average weight percents for a number of catalyst particles, such as the number in a reforming reactor that form the catalyst bed used in the processes described herein.

[0042] Simplified illustrations of a dry reforming process and, optionally, a CO2-steam reforming process 10 are shown in FIGS. 1A and 1B. In either such embodiment, a gaseous mixture 4 comprising one or more hydrocarbons (e.g., methane) and CO2 may be present in a reforming reactor 5 in the form of a vessel used to contain a bed of reforming catalyst 6, as described above, under reforming conditions in which the gaseous mixture 4 and the reforming catalyst 6 are contacted. According to the embodiment illustrated in FIG. 1A, the gaseous mixture 4 may be provided in the reforming reactor 5 solely from a hydrocarbon-containing feedstock 1. For example, a typical hydrocarbon-containing feedstock is a methane-containing feedstock obtained from gasification or pyrolysis of biomass, including hydrogasification or hydropyrolysis, and may further comprise CO2 and HO. Such a hydrocarbon-containing feedstock thereby provides the gaseous mixture 4 for the CO2-steam reforming process, in which both CO2 and HO react as oxidants for methane. In other embodiments, the gaseous mixture 4 may be obtained from combining the hydrocarbon-containing feedstock 1 with an optional CO2-containing oxidant 2 when the liquid hydrocarbons include naphtha boiling range hydrocarbons and / or jet fuel boiling range hydrocarbons, or when the hydrocarbon-containing feedstock 1 otherwise contains little CO2, such as in the case of certain types of natural gas.

[0043] As another option, an HO-containing oxidant 3 (e.g., as steam) can also be combined to form a gaseous mixture 4 comprising both CO and HO oxidants for the CO-steam reforming process, and methane. However, again, HO may also be present in sufficient amounts in the hydrocarbon-containing feedstock 1 and / or the CO-containing oxidant 2, such that a separate HO-containing oxidant 3 may not be necessary. It should be apparent that any of the hydrocarbon-containing feedstock 1, CO-containing oxidant 2, and HO-containing oxidant 3 can be combined prior to (e.g., upstream of) the reforming reactor 5, as indicated by the dashed double-arrowed line between them. According to certain embodiments, FIG. 1B illustrates a hydrocarbon-containing feedstock 1 being mixed with optional CO-containing oxidant 2 and optional HO-containing oxidant 3 to provide a gaseous mixture 4 prior to (e.g., upstream of) and within the reforming reactor 5.

[0044] As mentioned above, in embodiments in which gaseous mixture 4 comprises one or more hydrocarbons, such as methane and CO, but no HO, the process may be considered a "dry reforming" process, whereas in embodiments in which gaseous mixture 4 comprises hydrocarbon(s) and CO, and further comprises active HO in combination with CO as an oxidant for the hydrocarbon(s) (so that, e.g., at least a respective oxidant portion of CO and HO oxidizes a respective reactant portion of the hydrocarbon(s)), the process may be considered a "CO-steam reforming" process. The reforming catalysts described herein provide beneficial results in both dry reforming and CO-steam reforming, as discussed above, with respect to both activity and stability. Under the reforming conditions provided in the reforming reactor 5, the gaseous mixture 4 is converted into a synthesis gas product 7 which may be enriched (i.e., have an increased concentration) in hydrogen and CO compared to the gaseous mixture 4 and / or may be depleted (i.e., have a decreased concentration) in CO, HO, methane and / or other hydrocarbon(s) originally present in the gaseous mixture 4.

[0045] An important methane-containing feedstock is natural gas, particularly stranded natural gas, which is not readily converted to synthesis gas products in an economical manner using known processes. In contrast to conventional steam reforming, natural gas with relatively high concentrations of CO, e.g., at least about 10 mol%, or even at least about 25 mol%, represents an attractive methane-containing feedstock because the processes described herein do not require CO removal (e.g., scrubbing with an amine solution) and, in fact, utilize CO as a reactant. Other methane-containing feedstocks may include methane obtained from coal or biomass (e.g., lignocellulose or char) gasification, or obtained from biomass digesters, or as an effluent from renewable hydrocarbon fuel (biofuel) production processes (e.g., pyrolysis processes such as hydropyrolysis processes or fatty acid / triglyceride hydroconversion processes). Additional methane-containing feedstocks may include methane obtained from wellheads or industrial process effluents, including petroleum refining process effluents (as refinery off-gas), power generation process effluents, steel manufacturing process effluents, or non-ferrous metal manufacturing process effluents, chemical (e.g., methanol) production process effluents, or coke manufacturing process effluents. Generally, any process gas known to contain hydrocarbons (e.g., C1-C3 hydrocarbons) and CO2 may provide all or part of the gaseous mixture as described herein, or at least all or part of the methane-containing feedstock as a component of this mixture. When the methane-containing feedstock comprises methane obtained from renewable resources (e.g., biomass), including, for example, methane from a process stream obtained by hydropyrolysis as described in U.S. Patent No. 8,915,981 assigned to Gas Technology Institute, the processes described herein may be used to produce a renewable synthesis gas product (i.e., comprising renewable CO2), which may then be further processed to provide renewable hydrocarbon-containing fuels, fuel blending components, and / or chemicals.Thus, the methane-containing feedstock may comprise methane derived from a non-renewable source (e.g., natural gas) and / or methane derived from a renewable source (e.g., biomass), the latter source reducing the carbon footprint associated with the syngas product and downstream products overall. As described herein, natural gas and / or other methane-containing feedstocks may, but need not, be pretreated to remove H2S and other sulfur-containing contaminants prior to dry reforming or CO2-steam reforming.

[0046] Similar to the methane-containing feedstock (or hydrocarbon-containing feedstock generally), and particularly considering the sulfur tolerance of the reforming catalyst as described herein, the other components of the gaseous mixture, including the CO-containing oxidant and / or the HO-containing oxidant, can be obtained from a variety of sources. Beneficially, such sources include waste gases, which are considered to have little or no economic value and may further contribute to atmospheric CO levels. For example, the CO-containing oxidant can comprise industrial process waste gases obtained from steelmaking or non-ferrous product manufacturing processes. Other processes from which all or a portion of the CO-containing oxidant can be obtained include petroleum refining processes, renewable hydrocarbon fuel (biofuel) production processes (e.g., pyrolysis processes such as hydropyrolysis processes or fatty acid / triglyceride hydroconversion processes), coal and biomass gasification processes, power production processes, carbon black production processes, ammonia production processes, methanol production processes, and coke production processes.

[0047] As previously mentioned, a methane-containing feedstock (or hydrocarbon-containing feedstock in general) may itself provide a gaseous mixture for a dry reforming process or a CO-steam reforming process; i.e., if sufficient CO and / or HO are already present in the mixture, there is no need to add a separate CO-containing oxidant and / or a separate HO-containing oxidant. Alternatively, a methane-containing feedstock (or hydrocarbon-containing feedstock in general) may be combined with only one of a CO-containing oxidant or an HO-containing oxidant to provide a suitable gaseous mixture. For example, steam (as an HO-containing oxidant) may be combined with a methane-containing feedstock further comprising CO to provide a gaseous mixture suitable for a CO-steam reforming process.

[0048] A representative methane-containing feedstock further comprising a particularly suitable amount of CO to provide a gaseous mixture for the CO-steam reforming processes described herein is a hydropyrolysis gaseous mixture obtained from biomass hydropyrolysis and having (i) a methane concentration generally between about 3 mol% and about 45 mol% (e.g., between about 5 mol% and about 25 mol%, or between about 7 mol% and about 15 mol%), (ii) an ethane and propane concentration generally between about 1 mol% and about 35 mol% each (e.g., between about 2 mol% and about 25 mol%, or between about 3 mol% and about 15 mol%), and (iii) a CO concentration generally between about 10 mol% and about 75 mol% (e.g., between about 12 mol% and about 55 mol%, or between about 15 mol% and about 35 mol%). A substantial remainder of the hydropyrolysis gaseous mixture can be steam. However, depending on the actual amount of water vapor, the HO-containing oxidant may optionally be combined with the hydropyrolysis gaseous mixture to provide a gaseous mixture at a desired HO:CO molar ratio to the CO-steam reforming reactor. In this case, the HO-containing oxidant may be readily available as a condensed aqueous phase that is separated from the substantially completely deoxygenated hydrocarbon liquid (e.g., hydrocarbon-containing liquid having a total oxygen content of less than about 2% by weight or less than about 1% by weight) produced from the hydropyrolysis of biomass.

[0049] Another example of a representative methane-containing feedstock further comprising a particularly suitable amount of CO to provide a gaseous mixture for the CO-steam reforming process described herein is natural gas, which generally comprises a CO concentration of about 3 mol% to about 35 mol% (e.g., about 5 mol% to about 30 mol%, or about 10 mol% to about 25 mol%) and a methane concentration of about 65 mol% to about 98 mol% (e.g., about 70 mol% to about 95 mol%, or about 75 mol% to about 90 mol%). Other hydrocarbons (e.g., ethane and propane) and nitrogen may be present in small amounts. An HO-containing oxidant may optionally be combined with this methane-containing feedstock to provide a gaseous mixture with a desired HO:CO molar ratio to the CO-steam reforming reactor.

[0050] Another example of a representative methane-containing feedstock further comprising a particularly suitable amount of CO to provide a gaseous mixture for the CO2-steam reforming process described herein is biogas obtained from bacterial digestion of organic waste, such as anaerobic digestion processes, and from landfills. Biogas generally contains methane at a concentration of about 35 mol% to about 90 mol% (e.g., about 40 mol% to about 80 mol%, or about 50 mol% to about 75 mol%) and CO2 at a concentration of about 10 mol% to about 60 mol% (e.g., about 15 mol% to about 55 mol%, or about 25 mol% to about 50 mol%). The gases N2, H2, H2S, and O2 may be present in minor amounts (e.g., less than 20 mol% or less than 10 mol% combined). An HO-containing oxidant may optionally be combined with this methane-containing feedstock to provide a gaseous mixture with a desired HO:CO2 molar ratio to the CO2-steam reforming reactor.

[0051] Another example of a representative methane-containing feedstock further comprising a particularly suitable amount of CO to provide a gaseous mixture for the CO-steam reforming process described herein is a hydrogen-depleted PSA tail gas obtained from a hydrogen production process, such as one involving SMR, as described above. This stream may have (i) a methane concentration generally between about 5 mol% and about 45 mol% (e.g., between about 10 mol% and about 35 mol%, or between about 15 mol% and about 25 mol%), (ii) a CO concentration generally between about 20 mol% and about 75 mol% (e.g., between about 25 mol% and about 70 mol%, or between about 35 mol% and about 60 mol%), and (iii) an H concentration generally between about 10 mol% and about 45 mol% (e.g., between about 15 mol% and about 40 mol%, or between about 20 mol% and about 35 mol%). The remainder of this stream may comprise mostly water vapor and / or CO. An H2O-containing oxidant may optionally be combined with this methane-containing feedstock to provide a gaseous mixture to the CO2-steam reforming reactor at a desired H2O:CO2 molar ratio.

[0052] Another example of a representative methane-containing feedstock further comprising a particularly suitable amount of CO to provide a gaseous mixture for the CO-steam reforming process described herein is a gaseous effluent derived from bacterial fermentation integrated with a hydrogen production process, as described above. This stream may have (i) a methane concentration generally between about 5 mol% and about 55 mol% (e.g., between about 5 mol% and about 45 mol%, or between about 10 mol% and about 40 mol%), (ii) a CO concentration generally between about 5 mol% and about 75 mol% (e.g., between about 5 mol% and about 60 mol%, or between about 10 mol% and about 50 mol%), and (iii) an H concentration generally between about 5 mol% and about 40 mol% (e.g., between about 5 mol% and about 30 mol%, or between about 10 mol% and about 25 mol%). The remainder of this stream may comprise mostly water vapor and / or CO. An H2O-containing oxidant may optionally be combined with this methane-containing feedstock to provide a gaseous mixture to the CO2-steam reforming reactor at a desired H2O:CO2 molar ratio.

[0053] 1A and 1B, the gaseous mixture 4 comprising hydrocarbons and CO2 can be contacted with the reforming catalyst 6 in a batch or discontinuous operation; however, preferably, the dry reforming or CO2-steam reforming process is carried out continuously using a flowing stream of the gaseous mixture 4 or its components (e.g., hydrocarbon-containing feedstock 1, CO2-containing oxidant 2, and / or HO-containing oxidant 3, as described herein) to improve process efficiency. For example, contacting can be carried out by continuously flowing the gaseous mixture 4 (e.g., any of such components combined as a combined reforming reactor feed stream) through the reforming reactor 5 with the reforming catalyst 6 under reforming conditions (e.g., conditions within the reforming reactor vessel and conditions within a reforming catalyst bed contained within the vessel), including suitable flow rates. In certain embodiments, the reforming conditions are generally for a period of about 0.05 hr -1 ~approx. 10 hours -1 , generally about 0.1 hours -1 ~approx. 4.0 hours -1 , and often about 0.3hr -1 ~approx. 2.5 hours -1 The reforming catalyst 6 may include a weight hourly space velocity (WHSV) per unit time. As understood in the art, WHSV is the weight flow rate of the total feed (e.g., gaseous mixture) entering the reactor divided by the weight of catalyst in the reactor, and corresponds to the equivalent catalyst bed weight of the feed stream processed per hour. WHSV is related to the inverse of the reactor residence time. The reforming catalyst 6 may be contained within the reforming reactor 5 in the form of a fixed bed, although other catalyst systems are possible, such as moving bed and fluidized bed systems, which may be beneficial for processes utilizing continuous catalyst regeneration.

[0054] Other convenient reforming conditions for dry reforming or CO2-steam reforming generally include temperatures between about 649°C (1200°F) and about 816°C (1500°F). The processes described herein can effectively oxidize methane and / or other hydrocarbons at temperatures significantly lower than the typical 950°C (1742°F) temperature used in dry reforming or steam reforming due to the high activity of the reforming catalyst with respect to the reduced activation energy barrier required for the use of CO2 as an oxidant. For example, in exemplary embodiments, reforming conditions can include temperatures in the range of about 677°C (1250°F) to about 788°C (1450°F), or in the range of about 704°C (1300°F) to about 760°C (1400°F). As previously mentioned, the presence of significant amounts (e.g., 100-1000 mol-ppm) of HS and / or other sulfur-containing contaminants may warrant a temperature increase, for example, in the range of about 732°C (1350°F) to about 843°C (1550°F), or about 760°C (1400°F) to about 816°C (1500°F), to maintain a desired conversion level (e.g., greater than about 85%). Still other reforming conditions may include pressures above ambient pressure, i.e., pressures above 0 kPa (0 psig) gauge pressure, corresponding to an absolute pressure of 101 kPa (14.7 psig). Because the reforming reaction favors a higher number of moles of product relative to moles of reactant, equilibrium conditions at relatively low pressures are favored. Thus, reforming conditions may generally include gauge pressures of from about 0 kPa (0 psig) to about 517 kPa (75 psig), commonly from about 0 kPa (0 psig) to about 345 kPa (50 psig), and often from about 103 kPa (15 psig) to about 207 kPa (30 psig).

[0055] Beneficially, the high activity of the reforming catalyst may achieve at least about 80% (e.g., about 80% to about 99%), at least about 85% (e.g., about 85% to about 97%), or at least about 90% (e.g., about 90% to about 99%) methane and / or other hydrocarbon(s) conversion (e.g., methane conversion, combined C1-C3 hydrocarbon conversion, combined C1-C4 hydrocarbon conversion, naphtha boiling range hydrocarbon conversion, jet fuel boiling range hydrocarbon conversion, etc.) within any of the aforementioned temperature ranges, for example, by adjusting the particular reforming reactor temperature or reforming catalyst bed temperature and / or other reforming conditions (e.g., WHSY and / or pressure) as will be recognized by one of ordinary skill in the art with the knowledge gained from this disclosure. Beneficially, the reforming catalyst as described herein is sufficiently active to achieve significant hydrocarbon (e.g., methane) conversion, such as at least about 85%, stably at temperatures up to about 732°C (1350°F), or even up to about 704°C (1300°F). For oxidation reactants, typical conversions of CO are at least about 50% (e.g., about 50% to about 75%), and typical conversions of HO are at least about 70% (e.g., about 70% to about 90%), with conversion levels described herein for the hydrocarbon(s). As understood in the art, the conversion of any particular compound (e.g., methane) or combination of compounds (e.g., C-C hydrocarbons or C-C hydrocarbons) can be calculated based on the following formula:

number

[0056] As previously mentioned, additional benefits associated with reforming processes, and CO2-steam reforming processes in particular, include the ability to achieve a favorable H2 / CO molar ratio in the syngas product as well as the ability to adjust this ratio, as described herein. This has particularly important implications for downstream Fischer-Tropsch processing for the production of liquid hydrocarbons. The exact composition of the syngas product depends on the composition of the feed (e.g., combined reforming reactor feed) or gaseous mixture, the reforming catalyst, and the reforming conditions.

[0057] In exemplary embodiments, the synthesis gas product has a molar H:CO ratio that is beneficially close to 2:1, particularly for CO-steam reforming processes, e.g., generally in the range of about 1.5:1 to about 2.3:1, and typically in the range of about 1.8:1 to about 2.2:1. The combined concentration of H and CO in the product is generally at least about 35 mol% (or vol%) (e.g., about 35 mol% to about 85 mol%), typically at least about 50 mol% (about 50 mol% to about 80 mol%), and often at least about 60 mol% (about 60 mol% to about 75 mol%). As noted above, the balance of the synthesis gas product may be substantially or entirely CO and water, depending on the particular dry reforming or CO-steam reforming process, including the conditions of such process (e.g., conditions within the reforming reactor, such as temperature, pressure, weight hourly space velocity, and reforming catalyst loading) and the feed or gaseous mixture in which the reaction was carried out. In exemplary embodiments, CO2 is present in the synthesis gas product at a concentration generally less than about 45 mol% (e.g., from about 5 mol% to about 45 mol%), and typically less than about 35 mol% (e.g., from about 10 mol% to about 35 mol%). Water is generally present at a concentration of less than about 20 mol% (e.g., from about 1 mol% to about 25 mol%), and typically less than about 15 mol% (e.g., from about 5 mol% to about 15 mol%). Small amounts of unconverted hydrocarbons may also be present in the synthesis gas product. For example, the total amount of C1-C4 hydrocarbons (e.g., the total amount of methane, ethane, propane, and butane), which may optionally include only C1-C3 hydrocarbons, may be present at a concentration of less than about 5 mol%, and typically less than about 2 mol%.

[0058] Integrated process including a conversion step to produce liquid hydrocarbons Further exemplary processes include dry reforming or CO2-steam reforming as described herein to remove C4 CO2 from liquid fuels, such as gasoline, jet fuel, and / or diesel fuel. +Additional process steps are added, such as converting H2 and CO in the synthesis gas product in the FT synthesis stage to provide a hydrocarbon-containing Fischer-Tropsch product (e.g., the effluent from the FT reactor, as described above). For example, C4 + A particular integrated process for producing hydrocarbons may comprise converting methane and CO in a gaseous mixture, such as any of the gaseous mixtures described herein, including gaseous mixtures comprising any methane-containing feedstock or other components of such gaseous mixtures, in a reforming reactor of a reforming stage to produce a synthesis gas product, as described above. This converting step may more specifically comprise contacting the gaseous mixture with a reforming catalyst, such as any of the reforming catalysts described herein, in a reforming reactor of the reforming stage to produce the synthesis gas product. The integrated process may comprise converting H and CO in the synthesis gas product to C4 as the synthesis gas product, provided as the synthesis gas product, in a FT reactor of a FT synthesis stage downstream of the reforming stage. + The method may further comprise converting the hydrocarbons into hydrocarbons, including hydrocarbons (i.e., at least some hydrocarbons having 4 or more carbon atoms). 20 + C4 in the FT product, which contains a waxy fraction comprising hydrocarbons (i.e., at least some normal or straight chain hydrocarbons having 20 or more carbon atoms and therefore solid at room temperature). + For hydrocarbons, the integrated process involves the production of normal C in a finishing reactor in a finishing stage downstream of the FT synthesis stage. 20 + At least a portion of the hydrocarbons are normal or branched C4-C 19 The method may further comprise converting the hydrocarbons to hydrocarbons (i.e., normal or branched hydrocarbons, at least some of which have from 4 to 19 carbon atoms), which hydrocarbons are provided as hydroisomerization / hydrocracking products.

[0059] The term "stage," as used in "reforming stage," "FT synthesis stage," and "finishing stage," refers not only to the reactor(s) used to carry out the reaction associated with that stage as described herein, but also to the catalyst(s) associated with the reactor(s), and conventional auxiliary equipment (e.g., sensors, valves, gauges, control systems, etc.). In some embodiments, and preferably, only a single reactor is required for a given stage, i.e., a single reforming reactor, a single FT reactor, and / or a single finishing reactor. However, the reaction associated with a given stage may also be carried out in more than one reactor, e.g., two reactors operating in parallel or sequentially.

[0060] Additional details and benefits of the reforming stage, FT synthesis stage, and optional finishing stage in an exemplary integrated process are provided below, and integrated processes according to the present disclosure are understood to include any of the additional details and / or benefits, or otherwise have any combination of such details and / or benefits.

[0061] Modification Stage The reforming stage includes at least one, and typically only one, reforming reactor as described above, which may be a dry reforming reactor or a CO2-steam reforming reactor, the latter term indicating the presence of steam in the gaseous mixture. The gaseous mixture converted in this stage, as well as representative reforming catalysts and their properties (e.g., activity, stability, tolerance to sulfur, and high molecular weight hydrocarbons), suitable reforming conditions for use in the at least one reforming reactor, and performance criteria (conversion level and product yield) are as described above.

[0062] As mentioned above, the gaseous mixture may be pre-treated upstream of the reforming reactor(s) to reduce the concentration of HS and / or other sulfur-containing contaminants, for example by contacting the gaseous mixture or any of its components (e.g., hydrocarbon-containing feedstock) with a suitable bed of adsorbent or wash liquid. Alternatively, post-treatment (downstream of the reforming stage) of the synthesis gas product or possibly the FT feed (e.g., after condensing water from the cooled synthesis gas product to provide the FT feed) may be carried out in this manner, for example, to reduce the concentration of HS and / or other sulfur-containing contaminants. The option of carrying out a step of removing sulfur-containing contaminants either upstream or downstream of the reforming reactor(s) arises from the sulfur tolerance of the reforming catalyst, as mentioned above, so that, although protection of the FT catalyst may be necessary, it may not be necessary to protect the reforming catalyst from sulfur poisoning. Beneficially, if the concentration of HS and / or other sulfur-containing contaminants is reduced upstream of the reforming reactor(s) (e.g., if HS removal pretreatment is performed on the gaseous mixture), such pretreatment may be less stringent and / or involve less gas removal than conventional acid gas removal (e.g., using amine scrubbing), in which CO is also normally removed. The ability of the reforming catalysts described herein to tolerate CO and actually utilize this gas as a reactant may therefore enable the reduction or even elimination of conventional pretreatment steps. For example, a gaseous mixture comprising natural gas and having a high concentration of CO (e.g., greater than 25 mol% or greater than 30 mol%) may originate from a particular source of natural gas, and the gaseous mixture may be provided to the reforming reactor(s) without any pretreatment, or possibly only with pretreatment to remove dust particles, such as filtration.

[0063] As previously mentioned, the reforming stage generates a synthesis gas product comprising H and CO by reacting hydrocarbons via dry reforming or CO-steam reforming. Furthermore, as previously mentioned, given the preferred range of H:CO molar ratios in the synthesis gas product that can be obtained (including, for example, 2:1 in the case of CO-steam reforming), some or all of the synthesis gas product can be beneficially used directly in the FT synthesis stage without any intervening operations that would affect the H:CO molar ratio (e.g., by adding, removing, or converting components that would alter this ratio, e.g., by using a separate water-gas shift reaction or a reverse water-gas shift reaction). Further benefits related to the composition of the synthesis gas product are described in accordance with the embodiments presented herein and with respect to downstream processing of this product.

[0064] FT Synthesis Stage In the FT reactor(s) or the entire FT synthesis stage, at least a portion of the H and CO in the syngas product are converted to hydrocarbons according to the aforementioned Fischer-Tropsch (FT) synthesis reaction. In particular, the FT feed comprising some or all of the syngas product is provided to the FT reactor(s) of the FT synthesis stage, optionally after one or more intervening operations such as cooling, heating, pressurizing, depressurizing, separation of one or more components (e.g., removal of condensed water), addition of one or more components (e.g., addition of H and / or CO to adjust the H:CO molar ratio of the FT feed relative to the H:CO molar ratio of the syngas product), and / or reaction of one or more components (e.g., reaction of HCO using a separate water-gas shift reaction or a reverse water-gas shift reaction). The syngas product may be cooled, separated from the condensed water, and pressurized, taking into account the temperatures and pressures typically used in the FT reactor(s) of the FT synthesis stage relative to the temperatures and pressures typically used in the reforming reactor(s) of the reforming stage. In some embodiments, these may be the only intervening operations the syngas product undergoes to provide the FT feed. In other embodiments, cooling and pressurization may be the only intervening operations. In still other embodiments, intervening operations that may be omitted include drying the syngas product to remove vapor-phase HO (which may therefore involve using a water vapor-selective adsorbent, such as a 5A molecular sieve, as opposed to condensing liquid-phase HO), and / or CO removal via a conventional acid gas treatment step (e.g., amine scrubbing). However, according to some embodiments, CO removal may be performed upstream of the FT synthesis stage (e.g., intervening operation) but downstream of the reforming stage, instead of performing this CO removal directly upstream of the reforming stage as is customarily done. Preferably, water produced in the reforming reactor(s) is condensed from the syngas product prior to the FT reactor(s), and / or the H:CO molar ratio of the syngas product is preferably not adjusted either. The absence, limited intervening operations, and / or omission or specific intervening operations between the reforming stage and the FT synthesis stage result in benefits related to the overall simplification of the integrated process.

[0065] The conditions in the FT reactor(s) are such that H2 and CO are converted into C4 + The FT synthesis stage is suitable for converting hydrocarbons, including methyl methyl ether, into hydrocarbons, including methyl methyl ether. In exemplary embodiments, FT reaction conditions (suitable for use in at least one FT reactor) may include temperatures ranging from about 250°F (121°C) to about 550°F (288°C), or from about 380°F (193°C) to about 500°F (260°C). Other FT reaction conditions may include gauge pressures ranging from about 100 psig (689 kPa) to about 500 psig (3.44 MPa), or from about 200 psig (1.38 MPa) to about 400 psig (2.76 MPa). As discussed above, one benefit of using an FT synthesis stage downstream of a reforming stage, compared to downstream production of methanol and / or DME, is the significantly reduced pressure (e.g., generally less than 500 psig, or typically less than 450 psig) compared to such downstream processing options.

[0066] In the FT reactor(s), the FT feed may be contacted with a suitable FT catalyst (e.g., a bed of FT catalyst particles disposed within the FT reactor) under FT reaction conditions, which may include the temperatures and / or pressures described above. Exemplary FT catalysts comprise one or more transition metals selected from cobalt (Co), iron (Fe), ruthenium (Ru), and nickel (Ni). Preferred FT catalysts comprise at least about 10 wt. % of the transition metal(s) on a solid support, and typically at least about 15 wt. % of the transition metal(s). The phrase "on a solid support" is intended to encompass catalysts in which the active metal(s) are on the support surface and / or within the porous interior structure of the support. Exemplary solid supports comprise one or more metal oxides selected from the group consisting of aluminum oxide, silicon oxide, titanium oxide, zirconium oxide, magnesium oxide, strontium oxide, and the like. The solid support may comprise only or substantially only (e.g., greater than about 95 wt%) one or more such metal oxides. Preferred FT catalysts comprise the aforementioned amounts (e.g., at least about 10 wt%) of the transition metal cobalt (Co) on a support comprising aluminum oxide (alumina).

[0067] The FT catalysts and FT reaction conditions described herein are generally suitable for achieving at least about 20% (e.g., about 20% to about 99% or about 20% to about 75%), at least about 30% (e.g., about 30% to about 95% or about 30% to about 65%), or at least about 50% (e.g., about 50% to about 90% or about 50% to about 85%) H and / or CO conversion (H conversion or CO conversion). Such FT conversion levels may be based on H conversion or CO conversion, depending on which reactant is stoichiometrically limited by the FT feed, given the FT synthesis reaction, and such FT conversion levels may be calculated as described above. Where preferred, such FT conversion levels are based on CO conversion. Such FT conversion levels may be based on the "per pass" conversion achieved in a single pass through the FT synthesis stage (e.g., the FT reactor of this stage), or alternatively, may be based on the overall conversion achieved by returning a recycled portion of the FT product to the FT synthesis stage (e.g., the FT reactor of this stage), as described in more detail below.

[0068] The desired H2 conversion and / or CO conversion in the FT reactor(s) can be achieved by adjusting the aforementioned FT reaction conditions (e.g., FT reaction temperature and / or pressure) and / or by adjusting the weight hourly space velocity (WHSV) as defined above. FT reaction conditions are generally about 0.01 hr -1 ~approx. 10 hours -1 , generally about 0.05 hours -1 ~approx. 5 hours -1 , and often about 0.3hr -1 ~approx. 2.5 hours -1The conversion level (e.g., CO conversion) can be increased by, for example, increasing the pressure and decreasing the WHSV, both of which have the effect of increasing reactant concentration and reactor residence time. An example of the effect of pressure on CO conversion levels achieved in a Fischer-Tropsch (FT) reactor containing an FT catalyst as described herein and operating within the aforementioned ranges, with other FT reaction conditions held constant, is shown in Figure 2. The FT reaction conditions can optionally include returning a recycle portion of the FT product exiting the FT reactor to the FT feed for combination with the FT feed or otherwise returning it to the FT reactor. Recycle operation allows the FT reactor to operate at a relatively low "per pass" conversion while achieving a high overall conversion due to the recycle. In some embodiments, this low per pass conversion is achieved by reducing the amount of high molecular weight hydrocarbons (e.g., normal C 20 + The present invention may beneficially limit the amount of hydrocarbons (hydrocarbons) that may be produced as part of the hydrocarbon product distribution obtained from the FT synthesis reaction.

[0069] Preferably, however, the FT reaction conditions involve little or even no FT product recycle. For example, the FT reaction conditions may include a weight ratio of recycled FT product to FT feed (i.e., a "recycle ratio"), with both the recycled FT product and the FT feed generally providing a combined feed to the FT reactor at less than about 1:1, typically less than about 0.5:1, and often less than about 0.1:1. For example, the recycle ratio may be 0, i.e., no FT product recycle is used, resulting in a per-pass conversion equal to the total conversion. With such low recycle ratios, a relatively high per-pass rate of H2 conversion or CO conversion, such as at least about 50% (e.g., about 50% to about 95%), at least about 70% (e.g., about 70% to about 92%), or at least about 80% (e.g., about 80% to about 90%), is desirable from the perspective of process efficiency and economics. As the per-pass conversion level increases, the hydrocarbon distribution in the FT product shifts toward a distribution with an increased number of carbon atoms. This allows for the desired C4 +This is a benefit in view of the reduced yield of light C1-C3 hydrocarbons, which are less valuable than liquid hydrocarbons. In some embodiments, the C1-C3 hydrocarbon yield ("gaseous hydrocarbon yield"), or the fraction of total carbon in the CO of the FT feed provided to the FT reactor that is converted to C1-C3 hydrocarbons in the FT product removed from the reactor, is less than about 30% (e.g., about 1% to about 30%), or even less than about 20% (e.g., about 3% to about 20%). As discussed above for conversion, the amounts provided to and removed from the reactor may be expressed in terms of flow rates.

[0070] Therefore, embodiments of the present invention provide a method for producing C4 from a synthesis gas, e.g., a synthesis gas product, or FT feed, comprising H2 and CO, as described above. + This invention relates to a process for producing hydrocarbons. The synthesis gas product or FT feed can generally be produced by reforming (conventional reforming, dry reforming, or CO2-steam reforming). The process comprises contacting the synthesis gas with an FT catalyst comprising at least about 10 wt% Co and / or optionally other transition metal(s) as described above on a solid support, e.g., a refractory metal oxide such as alumina. The process converts H2 and CO in the synthesis gas into C4 + The method includes converting the hydrocarbons into hydrocarbons, including hydrocarbons.

[0071] Advantageously, the absence of FT product recycle saves compression costs and simplifies the overall design of the integrated process. This results in increased conversion per pass and an associated hydrocarbon distribution in the FT product that is less desirable. 20 + In cases where a shift towards a distribution of increasing numbers of carbon atoms containing hydrocarbons is required, embodiments of the present invention provide such normal C 20 + Hydrocarbons normal and / or branched C4-C 19It should be appreciated that this involves the discovery of important further downstream processing strategies for converting the raw materials to hydrocarbons that contribute to the yield of desired naphtha boiling range hydrocarbons, jet fuel boiling range hydrocarbons, and / or diesel boiling range hydrocarbons. Further optional downstream processing stages, i.e., finishing stages, that effect this conversion are described below.

[0072] Finishing Stage The optional finishing stage may be used to remove C4 + Hydrocarbons are normal C 20 + This may be desirable in embodiments containing hydrocarbons, particularly C4 + The waxy fraction of hydrocarbons may comprise those high carbon number hydrocarbons that are solid at room temperature and represent a yield loss of hydrocarbons that have great utility as liquid fuels, as well as causing deleterious wax buildup in process piping and creating significant problems in terms of transportation and blending difficulties.

[0073] In the finishing reactor(s) of the finishing stage, normal C in the FT product is purified by hydroisomerization and hydrocracking reactions in the reactor(s). 20 + At least a portion of the hydrocarbons are normal and / or branched C4-C 19 In particular, the finishing feed optionally comprises some or all of the FT product after one or more intervening operations such as cooling, heating, pressurizing, depressurizing, separating one or more components, adding one or more components, and / or reacting one or more components. Considering the temperatures and pressures typically used in the finishing reactor(s) of the finishing stage relative to the temperatures and pressures used in the FT reactor(s) of the FT synthesis stage, the FT product may be converted into normal C hydrocarbons in the FT product at the finishing stage. 20 +Prior to hydrocarbon conversion, the FT product may be heated to a temperature suitable for the finishing reactor used in this stage as described herein. In some embodiments, such heating may be the only intervening operation the FT product undergoes to provide the finishing feed. Alternatively, for greater operational simplicity and efficiency, this heating may even be omitted, given that the FT reaction conditions may include temperatures that are the same as or substantially the same (e.g., within about 10°C (18°F)) as those used in downstream finishing stages, e.g., temperatures within the temperature ranges set forth below for the finishing reaction conditions. In other embodiments, intervening operations that may be omitted include pressurization and depressurization, since it has been discovered that the finishing reaction conditions may beneficially include pressures that are the same as or substantially the same as those set forth above for the FT reaction conditions. For example, the pressure in the finishing reactor may be the same as in the upstream FT reactor, reduced by the nominal pressure drops associated with the piping between such reactors and, optionally, other process equipment. Thus, the expense of pressurizing (compressing) or depressurizing (expanding) the FT product upstream of the finishing reactor may be beneficially avoided. Similar to the intervening operation between the reforming stage and the FT synthesis stage, the use of no intervening operation, limited intervening operation, and / or the omission of certain intervening operations between the FT synthesis stage and the finishing stage provides benefits related to the overall simplification of the integrated process. For example, certain benefits arise when all or substantially all of the synthesis gas product is used in the FT feed and / or all or substantially all of the FT product is used in the finishing feed. In other embodiments, all or substantially all of the synthesis gas product, except for the condensed water-containing portion, is used in the FT feed and / or all or substantially all of the FT product is used in the finishing feed.

[0074] The conditions in the finishing reactor(s) are such that normal C 125° C. isocratic acid is produced according to finishing reactions which include or optionally consist of hydroisomerization and / or hydrocracking reactions. 20 + Hydrocarbons C4-C 19The finishing reactor is suitable for converting hydrocarbons into FT reactors. A finishing reactor can be incorporated into a FT reactor, for example, by using a finishing catalyst bed directly connected to an FT catalyst bed in a single vessel, or by otherwise interspersing the two types of catalyst within a single vessel. However, the use of at least one separate finishing reactor (e.g., in a separate finishing reactor vessel) is generally preferred so that the finishing reaction conditions can be maintained independently from the FT reaction conditions, as described above. A separate finishing reactor can be beneficial, for example, when (i) maintaining the finishing catalyst in a different type of reactor compared to the FT reactor, typically in a fixed-bed reactor of simpler design compared to the FT reactor because fixed-bed reactors typically do not suffer from the same design limitations, e.g., with respect to the ability to remove heat of reaction; (ii) removing and / or replacing the finishing catalyst at times (e.g., different intervals) that do not necessarily coincide with when the FT catalyst is removed and / or replaced; and / or (iii) operating the finishing reactor at a different temperature (e.g., higher) compared to the FT reactor. With respect to the use of a separate finishing reactor, the FT product (or at least any portion of this product used in the finishing reactor) may be maintained at an elevated temperature from the outlet (effluent) of the FT reactor to the inlet of the finishing reactor to achieve any normal C 20 + It can be important to prevent the deposition of hydrocarbons and other hydrocarbons with high melting temperatures similar to solid waxes. Otherwise, such deposition can result in the loss of desired products produced from conversion during the finishing stage, as well as plugging and / or fouling of process equipment, leading to operational failures. The use of a finishing reactor also prevents the formation of any normal C 20 +This can be simplified if condensation of hydrocarbons is prevented, i.e., all or substantially all of the FT product is maintained in the vapor phase from the FT reactor outlet to the finishing reactor inlet. For example, to prevent deposition and / or condensation, from the FT reactor effluent to the finishing reactor inlet, the FT product can be maintained at a temperature of at least about 66°C (150°F), at least about 121°C (250°F), at least about 216°C (420°F), or even at least about 327°C (620°F), such as by heating the FT product from the temperature below to a temperature suitable for the finishing reactor as described herein.

[0075] In exemplary embodiments, finishing reaction conditions (suitable for use in at least one finishing reactor) may include temperatures ranging from about 232° C. (450° F.) to about 399° C. (750° F.), or from about 304° C. (580° F.) to about 371° C. (700° F.). Other finishing reaction conditions may include gauge pressures of from about 621 kPa (90 psig) to about 3.38 MPa (490 psig), or from about 2.00 MPa (290 psig) to about 3.10 MPa (450 psig).

[0076] In the finishing reactor(s), the finishing feed may be contacted with a suitable finishing catalyst (e.g., a bed of finishing catalyst particles disposed within the finishing reactor) under finishing reaction conditions, which may include the temperatures and / or pressures described above. Also as described above, the finishing catalyst preferably is a catalyst that is capable of reducing the normal C4 present in the FT product. 20 + The characteristics of such hydrocarbons, i.e., solid waxes, are more desirable as liquid fuel components as described herein, and have activity for hydrocracking and / or hydroisomerization of hydrocarbons. 19In relation to hydrocarbons, it is derived from the carbon number distribution of normal hydrocarbons obtained by Fischer-Tropsch reaction chemistry. As understood in the art, hydroisomerization refers to the reaction of normal hydrocarbons in the presence of hydrogen to produce branched hydrocarbons. Hydrocracking refers to the reaction of hydrocarbons with hydrogen to produce hydrocarbons with lower carbon number and therefore lower molecular weight. Hydroisomerization produces hydrocarbons with lower carbon number and useful as components of liquid fuels (e.g., C4-C6). 19 Hydrocracking is beneficial for improving the characteristics of naphtha boiling range hydrocarbons, which may be present in the finishing feed and / or FT product or may be produced by hydrocracking in the finishing reactor(s). Such characteristics include higher octane numbers (e.g., research octane number and / or motor octane number) of naphtha boiling range hydrocarbons present in the finishing product compared to the finishing feed and / or FT product. Such characteristics also include lower pour points of diesel boiling range hydrocarbons present in the finishing product compared to the finishing feed and / or FT product. Hydrocracking is beneficial for its overall impact on the carbon number distribution of the finishing feed, which may correspond to that of the FT product, and in particular, for normal C hydrocarbons present in the finishing feed and / or FT product. 20 + It is useful to reduce, and in some cases eliminate, the weight percentage of hydrocarbons that are solid at room temperature, which interferes with the ability of products containing such hydrocarbons to be transported through conventional pipelines.

[0077] Because both the hydroisomerization and hydrocracking reactions require hydrogen, in preferred embodiments, this hydrogen is present in the finishing feed and / or FT product going to the finishing reactor. For example, hydrogen in the unconverted syngas product in a downstream FT reactor may enable operation of the finishing reactor without the need to add a supplemental hydrogen source to the finishing reactor or downstream of the FT reactor. According to some embodiments, hydrogen is present in the finishing feed and / or FT product at a concentration of at least about 20 mol% (e.g., about 20 mol% to about 75 mol%), at least about 30 mol% (e.g., about 30 mol% to about 65 mol%), or at least about 40 mol% (e.g., about 40 mol% to about 60 mol%) in excess of the hydrogen produced in the reforming stage and / or the syngas product without the introduction of a supplemental hydrogen source. According to other embodiments, a supplemental hydrogen source added to the finishing reactor or upstream of the finishing reactor in the finishing stage (e.g., downstream of the FT reactor in the FT synthesis stage) may be used to achieve such hydrogen concentrations. Typical supplemental hydrogen sources are purified (eg, by PSA or membrane separation) or impure hydrogen (eg, syngas).

[0078] As mentioned above, the typical finishing catalyst is normal C 20 +If the catalyst has activity for converting wax to hydrocarbons, i.e., hydroisomerization and hydrocracking activity, it may also be referred to as a dewaxing catalyst. An example of a finishing or dewaxing catalyst comprises at least one dewaxing-active (e.g., hydroisomerization and / or hydrocracking-active) metal on a solid support. The phrase "on a solid support" is intended to encompass catalysts in which the active metal(s) are on the support surface and / or within the porous interior structure of the support. Exemplary dewaxing-active metals may be selected from Groups 12-14 of the Periodic Table, such as Groups 13 or 14 of the Periodic Table. A particular dewaxing-active metal is gallium. The at least one dewaxing-active metal may be present in an amount of, for example, about 0.1 wt. % to about 3 wt. %, or about 0.5 wt. % to about 2 wt. %, based on the weight of the dewaxing catalyst. When a combination of dewaxing-active metals is used, such as a combination of metals selected from Groups 12-14 of the Periodic Table, then such metals may be present in a total amount within such ranges. Generally, the dewaxing catalyst may not comprise any metal(s) on the support in an amount or total amount greater than about 1 wt. %, or greater than about 0.5 wt. %, based on the weight of the dewaxing catalyst, other than the aforementioned dewaxing active metal(s) (e.g., no metals other than metals in Groups 12-14 of the Periodic Table, no metals other than metals in Groups 13 or 14 of the Periodic Table, or no metals other than gallium). Preferably, the dewaxing catalyst may not comprise any metal(s) on the support other than the aforementioned dewaxing active metal(s) (e.g., no metals other than metals in Groups 12-14 of the Periodic Table, no metals other than metals in Groups 13 or 14 of the Periodic Table, or no metals other than gallium).

[0079] To promote hydrocracking activity, the solid support of the finishing or dewaxing catalyst may more specifically be a solid acidic support. The acidity of the support may be determined, for example, by temperature-programmed desorption (TPD) of the amount of ammonia (ammonia TPD) from an ammonia-saturated sample of the support over a temperature range of 275°C (527°F) to 500°C (932°F), above the temperature at which ammonia is physisorbed. The amount of acid sites in millimoles of acid sites per gram of support (mmol / g) therefore corresponds to the number of millimoles of ammonia desorbed per gram of support over this temperature range. Exemplary solid supports comprise zeolites or non-zeolitic molecular sieves and have at least about 15 mmol / g (e.g., from about 15 mmol / g to about 75 mmol / g) of acid sites, or at least about 25 mmol / g (e.g., from about 25 mmol / g to about 65 mmol / g) of acid sites, as measured by ammonia TPD. For zeolite molecular sieves, acidity is a function of the silica-to-alumina (SiO2 / Al2O3) molar framework ratio. In embodiments where the solid support comprises a zeolite molecular sieve (zeolite), the silica-to-alumina molar framework ratio may be less than about 60 (e.g., 1-60) or less than about 40 (e.g., 5-40). Particular solid supports may comprise one or more zeolite molecular sieves (zeolites) having a structure type selected from the group consisting of FAU, FER, MEL, MTW, MWW, MOR, BEA, LTL, MFI, LTA, EMT, ERI, MAZ, MEI, and TON, preferably one or more of FAU, FER, MWW, MOR, BEA, LTL, and MFI. [Meier, W.M., et al., Atlas of Zeolite Structure Types, 4 th Ed., Elsevier: Boston (1996)] describes the structures of zeolites having these and other structure types and provides further references. Specific examples include zeolite Y (FAU structure), zeolite X (FAU structure), MCM-22 (MWW structure), and ZSM-5 (MFI structure), with ZSM-5 being exemplary.

[0080] Solid supports other than zeolites and non-zeolites include metal oxides such as any one or more of silica, alumina, titania, zirconia, magnesium oxide, calcium oxide, strontium oxide, etc. In exemplary embodiments, the solid support may comprise (i) a single type of zeolitic molecular sieve, (ii) a single type of non-zeolitic molecular sieve, or (iii) a single type of metal oxide, with (i), (ii), or (iii) present in an amount greater than about 75 wt. % (e.g., from about 75 wt. % to about 99.9 wt. %), or greater than about 90 wt. % (e.g., from about 90 wt. % to about 99 wt. %) based on the weight of the dewaxing catalyst. Other components of the support, such as binders and other additives, may be present in minor amounts, such as less than about 10 wt. % (e.g., from about 1 wt. % to about 10 wt. %) or in total, based on the weight of the dewaxing catalyst.

[0081] Exemplary dewaxing catalysts comprise ZSM-5 in an amount as described above (e.g., from about 0.5 wt. % to about 2 wt. %, e.g., about 1 wt. %, based on the weight of the dewaxing catalyst), or optionally gallium as the dewaxing active metal present on a support consisting essentially of ZSM-5. Representative silica-to-alumina molar framework ratios for ZSM-5 are described above.

[0082] The finishing or dewaxing catalysts and finishing reaction conditions described herein generally produce a normal C catalyst of at least about 80% (e.g., from about 80% to about 100%), at least about 85% (e.g., from about 85% to about 98%), or at least about 90% (e.g., from about 90% to about 95%). 20 + Hydrocarbons (e.g., normal C 20 -C 60 Such high conversion levels are important for improving the quality of the FT product, particularly with regard to its ability to be transported (e.g., by pipeline) as a liquid fuel without the need for solid wax separation or conversion. 20 + Low molecular weight C4-C hydrocarbons 19Conversion to hydrocarbons also improves the overall yield of such hydrocarbons compared to operation of the FT synthesis stage alone. Preferably, in the finishing stage (e.g., the finishing reactor of this stage), at least about 75% (e.g., about 75% to about 100%), at least about 85% (e.g., about 85% to about 98%), or at least about 90% (e.g., about 90% to about 97%) of normal C in the FT product is achieved. 20 + The hydrocarbon is C4-C 19 converted to hydrocarbons, i.e., normal C 20 + C4-C from hydrocarbon conversion 19 The yield of hydrocarbons is within this range. Preferably, the finished product (or the hydroisomerization / hydrocracking product of the finishing reactor) contains less than about 2 wt. % or even less than about 1 wt. % hydrocarbons that are solid at room temperature (e.g., normal C 20 + In an exemplary embodiment, normal C 20 + The hydrocarbons are converted in the finishing stage (e.g., in at least one finishing reactor of this stage) to a yield (e.g., full or substantially full conversion, and / or within the aforementioned conversion ranges) of (i) about 25% to about 70%, or about 40% to about 60% isoparaffinic (branched) hydrocarbons, (ii) about 10% to about 35%, or about 15% to about 25% aromatic hydrocarbons, (iii) about 50% to about 95%, or about 70% to about 90% gasoline boiling range hydrocarbons, (iv) about 5% to about 45%, or about 10% to about 30% diesel boiling range hydrocarbons, and / or (v) less than about 1% or less than about 0.5% VGO boiling range hydrocarbons, such yield being indicative of a conversion of normal C hydrocarbons in the finishing feed provided to the finishing reactor(s) to such components in the finished product. 20 +It indicates the percentage of total carbon in the hydrocarbons. Beneficially, isoparaffinic hydrocarbons improve the quality of diesel boiling range hydrocarbons by lowering both the pour point and cloud point of such fractions. Both isoparaffinic and aromatic hydrocarbons improve the quality of gasoline boiling range hydrocarbons by increasing the octane number (e.g., research octane number and / or motor octane number) of such fractions. In an exemplary embodiment, normal C 20 + The gasoline boiling range hydrocarbons obtained from the conversion of hydrocarbons have a research octane number of at least about 75 (eg, from about 75 to about 85).

[0083] Normal C in the finishing stage (e.g., in at least one finishing reactor in this stage) as described above. 20 + The hydrocarbon conversion level may be less than 100%, and therefore this normal C 20 + A portion of the hydrocarbons may remain unconverted. C4-C 19 Hydrocarbon and / or branched C 20 + Normal C, such as complete conversion to hydrocarbons 20 + To achieve complete conversion of hydrocarbons, the finishing reaction conditions can be made more stringent by increasing the temperature, increasing the pressure, decreasing the WHSV, etc. However, normal C 20 + It should be understood that complete conversion of hydrocarbons is not a requirement to achieve complete "dewaxing" of the FT product and / or finishing feed in the sense of providing a finished product that is free of solid phase hydrocarbons and therefore easily transportable as a liquid fuel in accordance with preferred embodiments. Nevertheless, normal C 20 + Incomplete conversion of hydrocarbons (such as achieving a conversion level within the specified ranges described above) can provide a finished product, wherein normal C 20 +Sufficient products obtained from the conversion of hydrocarbons, i.e., (i) sufficient non-normal C with a melting point below room temperature (20°C) 20 + Hydrocarbons (e.g., branched C 20 + hydrocarbons) and / or (ii) sufficient C4-C 19 The hydrocarbon is any unconverted normal C hydrocarbon in the finished product comprising (i) and (ii). 20 + If the hydrocarbon is soluble at room temperature, it will be present in the finished product.

[0084] Thus, embodiments of the present invention relate to the use of a finishing stage following an FT synthesis stage to improve the overall selectivity and yield to desired products and / or reduce the overall selectivity and yield to undesired products (particularly waxes) compared to an FT synthesis stage without the finishing stage (i.e., compared to a baseline FT synthesis stage or FT synthesis reaction). For example, the finishing stage may be used to remove some or all of the wax (e.g., normal C as described above) produced by the FT synthesis reaction. 20 + At the hydrocarbon conversion level, the wax selectivity (and / or yield) in the combined FT synthesis and finishing stage may be beneficially converted, thereby reducing the wax selectivity (and / or yield) in the combined FT synthesis and finishing stage compared to a baseline FT synthesis stage. In an exemplary embodiment, the wax selectivity (and / or yield) is reduced from a value of about 10% to about 50%, e.g., about 20% to about 45%, in the baseline FT synthesis stage to a value of about 0% to about 10%, e.g., about 0.5% to about 5%, in the combined FT synthesis and finishing stage. Preferably, the wax selectivity (and / or yield) is reduced to less than about 0.5%. As previously mentioned, the small amount of wax in the finishing product is due to the presence of any unconverted normal C 20 + Hydrocarbons, and / or any hydrocarbons that melt generally above room temperature, may be acceptable if present in the finished product in amounts below their solubility (i.e., amounts that can be completely dissolved in the product). In other exemplary embodiments, C4-C19 The selectivity (and / or yield) to liquid hydrocarbons increases from about 15% to about 45%, e.g., about 20% to about 35%, for the baseline FT synthesis stage to about 40% to about 75%, e.g., about 50% to about 70%, for the combined FT synthesis and finishing stage. For the baseline FT synthesis stage and the combined FT synthesis and finishing stage, the selectivity to liquid hydrocarbons (and / or yield) increases from about 15% to about 45%, e.g., about 20% to about 35%, for the baseline FT synthesis stage to about 75%, e.g., about 50% to about 70%, for the combined FT synthesis and finishing stage. 19 Selectivity to hydrocarbons is based on the percentage of carbon in CO that is converted by FT, which can be wax or C4-C, respectively. 19 For the baseline FT synthesis stage and the combination of the FT synthesis stage and the finishing stage, wax or C4-C 19 Hydrocarbon yields are based on the percentage of carbon in the CO input to the FT synthesis stage (e.g., FT feed and input CO, whether converted or not), which carbon is either wax or C4-C6, respectively. 19 The incorporation of a finishing stage (e.g., a finishing reactor) results in (i) a decrease in selectivity to (and / or yield of) wax, and / or (ii) a decrease in C4-C 19 The increase in selectivity to (and / or yield of) liquid hydrocarbons can be achieved without a significant difference between the CO conversion obtained in a baseline FT synthesis stage and the CO conversion obtained in a combined FT synthesis stage and finishing stage. For example, the CO conversion values ​​obtained in both the baseline FT synthesis stage and the combined FT synthesis stage and finishing stage can be within the ranges as described above with respect to the performance criteria for the FT synthesis stage. That is, the finishing stage generally does not significantly affect the CO conversion obtained in the FT synthesis stage alone, such that the CO conversions achieved in both the baseline FT synthesis stage and the combined FT synthesis stage and finishing stage can be the same or substantially the same.

[0085] As previously mentioned, the conversion level in the finishing stage may be based on the "per pass" conversion achieved in a single pass through the finishing stage (e.g., the finishing reactor of this stage), or alternatively, may be based on the overall conversion achieved by returning a recycled portion of the finishing product to the finishing stage (e.g., the finishing reactor of this stage), as previously described with respect to the FT synthesis stage. 20 + The desired conversion of hydrocarbons can be achieved by adjusting the aforementioned finishing reaction conditions (e.g., finishing reaction temperature and / or pressure) and / or by adjusting the weight hourly space velocity (WHSV) as defined above. Finishing reaction conditions are generally about 0.05 hr -1 ~about 35hr -1 , generally about 0.1 hours -1 ~approx. 20 hours -1 , and often about 0.5hr -1 ~approx. 10 hours -1 The finishing reaction conditions may include a weight hourly space velocity (WHSV) per unit time of 0.01 MPa. The finishing reaction conditions may optionally include returning a recycled portion of the finishing product from the finishing reactor to the finishing feed for combination with the finishing feed or otherwise returning it back to the finishing reactor. Recycle operation allows the finishing reactor to operate at a relatively low "per pass" conversion while achieving a high overall conversion due to the recycle. Preferably, however, the finishing reaction conditions include little or even no finishing product recycle. For example, the finishing reaction conditions may include a weight ratio of recycled finishing product to finishing feed (e.g., a "recycle ratio"), with this recycled finishing product and finishing feed together providing a combined feed to the FT reactor(s) in the aforementioned FT synthesis stage. Preferably, the recycle ratio may be 0, i.e., no finishing product recycle is used, resulting in a per pass conversion equal to the total conversion. Advantageously, the absence of finishing product recycle saves energy costs and simplifies the overall design of the integrated process.

[0086] Embodiments of the present invention therefore provide a method for producing C4+ C in the feed comprising hydrocarbons 20 + Hydrocarbons (e.g., normal C 20 + For processes converting C4 hydrocarbons, this feed may comprise all or a portion of the FT product as described above. + The hydrocarbon-containing feed may contain, for example, C in an amount of at least about 5 wt % (e.g., about 5 wt % to about 30 wt %), or at least about 10 wt % (e.g., about 10 wt % to about 25 wt %) based on the weight of the total hydrocarbons or based on the weight of the feed. 20 + The feed may comprise a finishing or dewaxing catalyst as described above, comprising, for example, an active metal selected from Groups 12-14 of the Periodic Table (e.g., gallium) on a zeolite molecular sieve support (ZSM-5), to produce a C2 hydrocarbon feed at conversion levels, and yields and selectivities to lower carbon number hydrocarbons and hydrocarbon fractions, and other performance criteria, as described herein. 20 + The method comprises the step of achieving conversion of hydrocarbons.

[0087] Overall Performance Criteria, Benefits, and Exemplary Implementations As discussed above, an integrated process, and in particular the combined use of (i) a dry reforming or CO2-steam reforming process as discussed above, combined with (ii) Fischer-Tropsch synthesis, and (iii) optional finishing (dewaxing), may be referred to as an "integrated CSR-FT process," which may be used to directly convert hydrocarbons, such as methane, in natural gas to one or more liquid fuels. Such liquid fuel(s), along with lower carbon number hydrocarbons, such as C1-C3 hydrocarbons, may be provided as a finished product from a finishing stage (e.g., the reactor of this stage) as discussed above. Such lower carbon number hydrocarbons, along with unconverted residual gas (e.g., H2, CO, and / or CO2), may be further separated into liquid fuel(s) (C4-C4) using a flash separator providing a vapor-liquid equilibrium separation stage. 19Hydrocarbon and optionally branched C 20 + Alternatively, as in the case of separation using distillation, multiple vapor-liquid equilibrium separation stages may be used to separate the lower carbon number hydrocarbons and to separate the liquid fuels, for example, by separating a fraction comprising most, substantially all, or all gasoline boiling range hydrocarbons from a fraction comprising most, substantially all, or all diesel boiling range hydrocarbons. In yet other embodiments, a flash separation vessel may be used to initially separate the lower carbon number hydrocarbons and residual gases from the finished product, followed by separation of the liquid fuels in the finished product using distillation.

[0088] The integrated CSR-FT process described herein accrues numerous benefits, including those associated with operating the FT synthesis stage at high per-pass conversions, as discussed above. Such benefits include the option of operating the FT synthesis stage without recycle, shifting the hydrocarbon distribution in the FT product toward hydrocarbons with higher carbon numbers and present in liquid fuels, thereby reducing the yield of undesirable C1-C3 hydrocarbons. In exemplary embodiments, the integrated CSR-FT process, as discussed above, can convert hydrocarbons (e.g., methane) present in the gaseous mixture and / or hydrocarbon-containing feedstock fed to the process, such that at least about 70% (e.g., about 70% to about 95%), or at least about 85% (e.g., about 85% to about 95%) of the carbon originally present in the hydrocarbons converted in the process, is converted to C4-C4 in the finished product. 19The carbon content of the C1-C3 hydrocarbons in the finished product is typically present in the liquid hydrocarbons. This means that the selectivity of the integrated CSR-FT process as a whole to liquid fuel(s) comprising such hydrocarbons (e.g., naphtha boiling range hydrocarbons and diesel boiling range hydrocarbons) can be within this range. Furthermore, up to about 25% (about 5% to about 25%), or up to about 15% (about 10% to about 15%) of the carbon present in the hydrocarbons originally converted in the process can be present in the C1-C3 hydrocarbons of the finished product. This means that the selectivity of the integrated CSR-FT process as a whole to such low carbon number hydrocarbons can be within this range. Additionally, if such low carbon number hydrocarbons can be separated as a vapor fraction of the finished product, this vapor fraction can be combusted to provide heat energy elsewhere in the integrated CSR-FT process, particularly to the furnace or hot box of the reforming reactor in the reforming stage, due to its heating value (fuel value). This would allow for the generation of at least a portion, and possibly all, of the heat required to sustain the endothermic dry reforming and / or CO-steam reforming reactions of the reforming stage, especially considering the fact that the vapor fraction generally comprises not only C1-C3 hydrocarbons but also residual H2 and / or CO, which are also combustible.

[0089] A further optional finishing stage may be used to remove all or substantially all of the wax (e.g., normal C 20 + hydrocarbons) with low carbon numbers (e.g., C4-C 19 The optional finishing stage can also convert a portion of the wax into isoparaffins C4 with melting points below room temperature. 20 + If any hydrocarbons with melting points above room temperature are present in the finished product, the amount of such hydrocarbons may be small enough to be completely soluble in the product, thereby advantageously making the liquid fraction of the finished product suitable for transportation by pipeline. Additionally, the finishing stage may also be used to convert other hydrocarbons (e.g., C4-C6) present in the FT product and / or finishing feed. 19The FT product may be used to isomerize the octane number of gasoline boiling range hydrocarbons and / or to lower the pour point and / or cloud point of diesel boiling range hydrocarbons present in the finished product compared to the respective values ​​in the FT product and / or the finished feed.

[0090] FIG. 3 shows a flow scheme of a representative integrated CSR-FT process 100 in which a dry reforming or CO2-steam reforming process 10, as previously described and shown in FIG. 1A or FIG. 1B, is integrated with downstream processing steps to produce liquid hydrocarbons, as previously described, using an FT reactor 20 and a finishing reactor 30. According to the integrated CSR-FT process 100, a gaseous mixture 4 may be provided, as previously described, by a connection such as from a system input 15 to a source of the gaseous mixture or a source of one or more components of the gaseous mixture (e.g., a hydrocarbon-containing feedstock such as natural gas). From the system input 15, the gaseous mixture 4 may be passed to a reforming reactor 5, which may operate under reforming conditions as previously described and may optionally include a reforming catalyst 6, such as a catalyst as previously described. The syngas product 7 received from the reforming reactor 5 may be passed to a syngas product cooler 17, where it may be cooled, for example, from a temperature of the representative reforming conditions as previously described to a temperature of the representative downstream FT reaction conditions as previously described. A cooled syngas product 19 may be received from the syngas product cooler 17 and sent to an optional condenser 21 for removing condensed water 22 from the cooled syngas product 19. In this case, the condensed water 22 is provided as the system water (or aqueous product) output.

[0091] Regardless of whether optional condenser 21 is included or excluded from integrated CSR-FT process 100, cooled syngas product 19 may be sent to compressor 23 to increase the pressure of cooled syngas product 19 to a pressure of typical FT reaction conditions, as described above. FT feed 27 may be received from compressor 23 and sent to FT reactor 20, which may operate under FT reaction conditions, as described above, and may optionally include an FT catalyst, as described above. As such, all or a portion of syngas product 7 may be sent to FT reactor 20 to form all or a portion of FT feed 27 (e.g., the portion of syngas product 7 obtained after condensing water may form all or substantially all of FT feed 27). FT product 29 may be received from FT reactor 20 and sent to optional FT product heater 31, which may be used to heat FT product 29 to a temperature of typical finishing reaction conditions, as described above. Alternatively, both the FT reactor 20 and the downstream finishing reactor 30 can be operated at the same or substantially the same temperature, such that the optional FT product heater 31 can be removed from the integrated CSR-FT process 100. All or a portion of the FT product 29 can be sent to the finishing reactor 30 to form all or a portion of the finishing feed 32 (e.g., all of the FT product 29 can form all or substantially all of the finishing feed 32). The finishing reactor 30 can be operated under finishing reaction conditions as described above and can optionally include a finishing catalyst as described above. The finishing product 33 can be received from the finishing reactor 30 and sent to a finishing product separator 50, which provides separated fractions of the finishing product 33, such as a vapor fraction 37 and a liquid fraction 39, into a system vapor output 40 and a system liquid output 45, respectively.

[0092] According to an alternative embodiment, the vapor fraction 37 received from the finished product separator 50 may be maintained within the integrated CSR-FT process 100 and sent to the furnace or hot box of the reforming reactor 5 as a fuel source for maintaining the reforming catalyst 6 at temperatures representative of reforming conditions, as described above. In such an embodiment, the flue gas effluent (not shown) may be provided as a system vapor output instead of the vapor fraction 37. According to another alternative embodiment, in addition to the vapor fraction 37 (which may alternatively be used as a fuel source to heat the reforming reactor 5, as described above), the separator 50, unlike a single-stage (vapor / liquid) flash separator, may provide more limited liquid fractions of the finished product as a system liquid output, such as a gasoline boiling range hydrocarbon-containing fraction 41 and a diesel boiling range hydrocarbon-containing fraction 43, for example, when the separator 50 operates as a distillation column to crack such fractions. In this case, the liquid fraction 39 may more specifically be a high carbon number hydrocarbon-containing fraction, such as a VGO boiling range hydrocarbon-containing fraction. According to a further embodiment, separator 50 may provide all or substantially all of liquid fraction 39 of finished product 33 to second separator 55 to provide more limited liquid fractions 41, 43, as described above with respect to separator 50. In this case, as shown in FIG. 3 , second separator 55 may be external to integrated CSR-FT process 100 (e.g., may be used at a remote location to crack the liquid fraction), or may be otherwise included within the process.

[0093] In addition to the integrated CSR-FT process, aspects of the present invention therefore also relate to systems or apparatus for carrying out such processes, including the integrated CSR-FT process 100 as shown in Figure 3. Accordingly, certain embodiments of the present invention provide for the production of C4 hydrocarbons useful as liquid fuels from methane and / or other light hydrocarbons. +The present invention relates to a system or apparatus for producing hydrocarbons, which may include one or more of the following: (i) a reforming reactor 5 configured to be coupled to a source of gaseous mixture 4, e.g., a source of natural gas comprising methane and CO, via a system inlet 15. The reforming reactor 5 may contain a reforming catalyst 4 as described above and / or may be further configured to generate or provide a syngas product 7 comprising H and CO from the gaseous mixture 4 under reforming conditions, e.g., as described above; (ii) a syngas product cooler 17 configured to receive (and / or cool) the syngas product 7 from the reforming reactor 5. The syngas product cooler 17 may be coupled to the reforming reactor 5 or may otherwise have an inlet configured to be coupled to an outlet of the reforming reactor 5; and (iii) a compressor 23 configured to receive (and / or compress) the cooled syngas product 19 from the syngas product cooler 17. The compressor 23 may be coupled to the syngas product chiller 17 or may have an inlet configured to be coupled to an outlet of the syngas product chiller 17; (iv) a FT reactor 20 configured to receive the FT feed 27 (e.g., as a compressed output) from the compressor 23. The FT reactor 20 may contain a FT catalyst as described above and / or may convert H and CO in the syngas product 7 to C4 + The FT reactor 20 may be further configured to produce or provide a FT product 29 comprising hydrocarbons containing hydrocarbons. The FT reactor 20 may be coupled to the compressor 23 or may have an inlet otherwise configured to be coupled to an outlet of the compressor 23; (v) a finishing reactor 30 configured to receive a finishing feed 32 as a heated output from an optional FT product heater 31 or otherwise directly as the FT product 29. The finishing reactor 30 may contain a finishing catalyst as described above and / or may be configured to reduce normal C in the FT product 29 under finishing reaction conditions, e.g., as described above. 20 + Conversion of hydrocarbons to normal and branched C4-C 19The finishing reactor 30 may be further configured to produce or provide a hydrocarbon-containing finishing product 33. The finishing reactor 30 may be coupled to the FT reactor 20 or the optional FT product heater 31, or the finishing reactor 30 may have an inlet configured to be coupled to an outlet of the FT reactor 20 or the optional FT product heater 31; and (vi) a finishing product separator 50 configured to receive the finishing product 33 from the finishing reactor 30 and further configured to provide or separate a vapor fraction 37 and a liquid fraction 39 of the finishing product 33, respectively, via a system vapor output 40 and a system liquid output 45. The finishing product separator 50 may be coupled to the finishing reactor 33 or may have an inlet configured to be coupled to an outlet of the finishing reactor 33. Otherwise, the separator 50 may be configured to provide the more restricted liquid fractions 41, 43 of the finishing product 33 as the system liquid output, as described above. Alternatively, separator 50 may be coupled to or configured to be coupled to a second separator 55 to provide more specific supra-specified liquid fractions 41, 43, as previously described.

[0094] The integrated CSR-FT process 100, or related system or apparatus, may optionally further include a condenser 21 configured to condense liquid water from the cooled syngas product 19. In this case, a compressor 23 is configured to receive the cooled syngas product 19 from the condenser 21 and subsequently remove condensed water 22, which may be provided as a system water (or aqueous product) output. The compressor 23 may be coupled to the condenser 21 or may have an inlet configured to be otherwise coupled to an outlet of the condenser 21.

[0095] In view of the foregoing, it can be seen that the integrated CSR-FT process, and associated systems and apparatus, can provide a highly economical method for converting hydrocarbon-containing gases, such as methane, into liquid fuels. Each process step or system element can be seamlessly integrated with the next step or element. Such integration is beneficially possible without the need for certain conventional steps and associated elements (equipment) and expenses (both capital and operating costs), such as by omitting one or more of the following steps: (i) removing CO from a CO-rich natural gas source (e.g., using amine scrubbing); (ii) adjusting the H:CO molar ratio of the synthesis gas product upstream of the FT reactor; (iii) removing solid wax or condensed liquid wax (e.g., normal C) upstream of a finishing reactor (e.g., for processing the solid wax in a separate hydrotreating reactor); 20 + and separation of the FT product (comprising hydrocarbons). Indeed, the CSR-FT process, and associated systems and apparatus, may beneficially operate as described herein such that no materials are added and / or removed during the reforming, FT synthesis, and finishing stages, except for the addition of gaseous mixture 4 and removal of a fraction of finished product 33, and possibly removal of condensed water 22 (or aqueous product). In this manner, the integrated CSR-FT process, and associated systems and apparatus, may be streamlined and simplified, enabling economically favorable operation and implementation associated with liquid fuel production.

[0096] Moreover, this simplicity allows such integrated CSR-FT processes and associated systems and apparatus to be operable on a small scale and, in some embodiments, transportable, for example, by truck, ship, train, or plane. For example, integrated CSR-FT process 100, or associated systems or apparatus, as described above, may be skid-mounted for easy transport to a source of natural gas, other suitable hydrocarbon-containing feedstocks, and / or even a source of CO2-containing industrial waste gas. For example, integrated CSR-FT process 100 may be beneficially used to convert flared natural gas into liquid fuels and reduce greenhouse gas (GHG) emissions at a well site. If such a process is transportable, a single process or its associated systems or apparatus may be used for both of these purposes and / or with a variety of other different gaseous mixtures and components thereof (e.g., hydrocarbon-containing feedstocks), as described above, even if their source locations differ.

[0097] Integration with biomass hydropyrolysis As previously discussed, processes for producing renewable hydrocarbon fuels from biomass hydropyrolysis can provide a gaseous mixture comprising methane and / or other light hydrocarbons in combination with CO. Such a gaseous mixture thus represents a potential feed to a CO-steam reforming process or, as otherwise described above, to an integrated CSR-FT process, which can be converted (i) to a hydrogen-containing syngas in the case of a CO-steam reforming process, or (ii) to a liquid fuel in the case of an integrated CSR-FT process. Regarding embodiment (i), the hydrogen-containing syngas can be used as a hydrogen source to sustain the hydropyrolysis process, optionally followed by purification to obtain an H-enriched portion thereof. Regarding embodiment (ii), the liquid fuel produced from the integrated CSR-FT process can beneficially increase the overall yield of biogenic (renewable) liquid fuels compared to yields that could otherwise be obtained from biomass hydropyrolysis. This increase can be relative to a baseline yield without using any reaction stages of the integrated CSR-FT process, and this increase also corresponds to a baseline yield obtained using a reforming stage to produce a syngas product, but without using an FT synthesis stage to convert H and CO in the syngas product to hydrocarbons, as described above. According to some embodiments, the increase in yield of biogenic liquid fuels can be at least about 25% (e.g., from about 25% to about 60%), or at least about 35% (e.g., from about 35% to about 50%).

[0098] FIG. 4 shows a flow scheme in which the hydropyrolysis process 200 produces a gaseous mixture 4 comprising methane and CO as a feed to the CO-steam reforming process 10, as shown in FIG. 1A or 1B. Thus, according to this embodiment, the CO-steam reforming process 10 is integrated into a process for producing renewable hydrocarbon fuels from the hydropyrolysis of biomass. The gaseous mixture 4 may comprise methane and CO and other species in concentrations as described above for the "hydropyrolysis gaseous mixture." In addition to the gaseous mixture 4, the hydropyrolysis process 200 also produces a substantially completely deoxygenated hydrocarbon liquid 61 (e.g., having a total oxygen content of less than about 2 wt. % or less than about 1 wt. %), which comprises hydrocarbons that can be separated into a gasoline boiling range hydrocarbon-containing fraction 41 and a diesel boiling range hydrocarbon-containing fraction 43. The hydropyrolysis process 200 may further produce an aqueous liquid 63, for example, obtained by phase separation from the substantially completely deoxygenated hydrocarbon liquid 61. As can be seen, all or a portion of aqueous liquid 63 may optionally be combined with gaseous mixture 4, for example to adjust the H2O:CO2 molar ratio of gaseous mixture 4 to a molar ratio as described above for CO2-steam reforming process 10. Hydropyrolysis process 200 may further produce solid char 65. Such products of hydropyrolysis process 200, including gaseous mixture 4, substantially completely deoxygenated hydrocarbon liquid 61, and aqueous liquid 63, are produced from a feed to hydropyrolysis process 200, including a biomass-containing or biomass-derived feedstock 67 and a hydrogen-containing feed gas stream 69.

[0099] With respect to biomass-containing or biomass-derived feedstocks 67, the term "biomass" refers to material derived from living organisms on the Earth's surface or in the Earth's oceans, rivers, and / or lakes. Exemplary biomass can include any plant material, or mixture of plant materials, such as hardwood (e.g., white wood), softwood, hardwood or softwood bark, lignin, algae, and / or lemna (seaweed). Energy crops, or alternatively, agricultural residues (e.g., logging residues), or other types of plant or plant-derived waste, can also be used as plant material. Specific exemplary plant materials include corn fiber, corn stover, and sugarcane bagasse fiber, as well as energy "use" crops such as switchgrass, miscanthus, and algae. Short rotation forestry products include energy crops such as alder, ash, southern beech, birch, eucalyptus, poplar, willow, paper mulberry, Australian blackwood, sycamore, and varieties of marshmallow. Other examples of suitable biomass include vegetable oils, carbohydrates (e.g., sugars), organic waste materials such as waste paper, construction and demolition waste, biological sludge, etc.

[0100] A "biomass-containing" feedstock may comprise all or substantially all biomass, but may also contain non-living materials (e.g., petroleum-derived materials such as plastics, or mineral-derived materials extracted from the earth's surface, such as metals and metal oxides, including glass). One example of a "biomass-containing" feedstock that may contain one or more non-living materials is municipal solid waste (MSW).

[0101] For example, "biomass-derived" when used in the phrase "biomass-derived feedstock" refers to products resulting from or obtained from thermal and / or chemical transformation of biomass, as defined above, or to biomass-containing feedstocks (e.g., MSW). Thus, exemplary biomass-derived feedstocks include, but are not limited to, products of pyrolysis (e.g., bio-oil), torrefaction (e.g., torrefaction and optional densification of wood), hydrothermal carbonization (e.g., pretreatment and densification of biomass by acid hydrolysis in pressurized hot water), and polymerization (e.g., organic polymers derived from plant monomers). Specific examples of other biomass-derived products (e.g., for use as feedstocks) include black liquor, pure lignin, and lignosulfonic acid. Biomass-derived feedstock also extends to pretreated feedstocks resulting from or obtained from thermal and / or chemical transformation prior to or upstream of their use as feedstock for a given conversion step (e.g., hydropyrolysis). Certain types of pretreatment steps that result in biomass-derived products include those involving devolatilization and / or at least some hydropyrolysis of a biomass-containing feedstock. Therefore, certain pretreated feedstocks are also "biomass-derived" feedstocks, while other pretreated feedstocks, for example, resulting from or obtained from sorting without thermal or chemical transformation, are "biomass-containing" but not "biomass-derived" feedstocks.

[0102] Therefore, instead of all or a portion of the biomass-containing feedstock, a biomass-derived feedstock, such as a pretreated feedstock, can be fed to the hydropyrolysis process 200, the pretreated feedstock being obtained from the biomass-containing feedstock after devolatilization and / or partial hydropyrolysis in a pretreatment reactor (pre-reactor) upstream of the hydropyrolysis reactor vessel. Such thermal and / or chemical transformation of the biomass in the pre-reactor can be accompanied by other supplemental transformations, for example, to reduce the content of corrosive species and / or reduce the content of hydropyrolysis catalyst poisons (sodium reduction) and / or reduce the content of hydroconversion catalyst poisons. Devolatilization and / or partial hydropyrolysis of the biomass or biomass-containing feedstock in the pre-reactor can be carried out in the presence of suitable solid bed materials, such as pretreatment catalysts, adsorbents, heat transfer media, and mixtures thereof, to help effect the supplemental transformations and thereby improve the quality of the pretreated feedstock. Suitable solid bed materials include materials with dual or multiple functions. In the case of pretreatment catalysts, the following catalysts having activity for hydroprocessing biomass-containing feedstocks are representative.

[0103] It is also possible to provide a biomass-containing feedstock that is a pretreated feedstock obtained after a pretreatment step, e.g., physical classification, to improve at least one characteristic such as reduced non-living material content (e.g., glass, metal, and metal oxide content, including all mineral forms), reduced average particle size, reduced average aerodynamic particle size, increased average particle surface area to mass ratio, or particle size uniformity.

[0104] As shown in FIG. 4, the CO2-steam reforming process 10 may include a reforming reactor 5 containing a reforming catalyst 6, as shown in FIGS. 1A and 1B, having a composition as described above. The reforming reactor 5 may operate under reforming conditions as described above to produce a syngas product 7 comprising H2 and CO. An optional hydrogen purification module 75, utilizing, for example, pressure swing adsorption (PSA) or membrane separation, may be used to obtain an H2-enriched portion 71 of the syngas product 7, having a high hydrogen concentration relative to the product (e.g., having a hydrogen concentration of at least about 80 mol%, such as from about 80 mol% to about 99 mol%, or at least about 85 mol%, such as from about 85 mol% to about 98 mol%). As shown in FIG. 4, the H2-enriched portion 71 may be returned to the hydropyrolysis process 200 to provide at least a portion, and possibly all, of the hydrogen-containing feed gas stream 69. An H-depleted portion (not shown) of the synthesis gas product may also be obtained from hydrogen purification module 75 and possibly combusted to provide thermal energy for CO-steam reforming process 10 or hydropyrolysis process 200. Hydrogen purification module 75 may be used to preferentially separate any of CO, CO, light (C1-C3) hydrocarbons, and / or H2S into an H2-depleted portion.

[0105] FIG. 5 illustrates a flow scheme in which hydropyrolysis process 200 produces a gaseous mixture 4 comprising methane and CO, as in FIG. 4. However, according to the embodiment of FIG. 5, gaseous mixture 4 is a feed to integrated CSR-FT process 100, as shown in FIG. 3. Thus, in this case, integrated CSR-FT process 100 is further integrated with a process for producing renewable hydrocarbon fuels from the hydropyrolysis of biomass. Products produced from hydropyrolysis process 200 are described above with respect to the embodiment of FIG. 4. Such products include (i) gaseous mixture 4, (ii) substantially fully deoxygenated hydrocarbon liquid 61 comprising hydrocarbons that can be separated into a gasoline boiling range hydrocarbon-containing fraction 41 and a diesel boiling range hydrocarbon-containing fraction 43, (iii) aqueous liquid 63, and (iv) solid char 65. Also, as described above with respect to the embodiment of FIG. 4, all or a portion of aqueous liquid 63 can optionally be combined with gaseous mixture 4, for example, to adjust the HO:CO molar ratio of gaseous mixture 4. Because the integrated CSR-FT process 100 to which the gaseous mixture is sent in the embodiment of FIG. 5 includes an FT synthesis stage and, optionally, the use of an FT catalyst that is susceptible to sulfur poisoning, according to some embodiments, it may be desirable to treat the gaseous mixture 4 to remove HS and / or other sulfur-containing contaminants prior to (upstream of) the integrated CSR-FT process 100.

[0106] In the embodiment of Figure 5, the integrated CSR-FT process 100 provides a liquid fraction 39 of the finished product 33, as described above with respect to Figure 3. The liquid fraction 39 beneficially comprises a gasoline boiling range hydrocarbon-containing fraction and / or a diesel boiling range hydrocarbon-containing fraction, one or both of which may be enhanced, for example, in accordance with the yield enhancements described herein, to enhance the yield of such fractions 41, 43 compared to the yield obtained from the hydropyrolysis process 200 alone (the baseline yield obtained in the absence of the integrated CSR-FT process 100). Also according to the embodiment of Figure 5, the vapor fraction 37 of the finished product 33 (Figure 3), comprising methane and / or other light hydrocarbons (e.g., C2-C3 hydrocarbons), as well as other combustible species such as residual H2 and / or CO, may optionally be combusted as a fuel source. As shown in Figure 5, a hydrogen production process 300, as described above, is used to produce a purified hydrogen product 79 by steam methane reforming (SMR) of natural gas 77 fed to the process. 5, the vapor fraction 37 can be used to generate heat for the SMR, and all or a portion of the aqueous liquid 63 from the hydropyrolysis process 200 can be used to generate steam for the SMR used in the hydrogen production process 300. The purified hydrogen product 79 can be used to provide all or a portion of the hydrogen-containing feed gas stream 69 to the hydropyrolysis process 200.

[0107] 6 provides additional details of a hydropyrolysis process 200, such as that shown in FIGS. 4 and 5, used to convert a biomass-containing or biomass-derived feedstock 67 and a hydrogen-containing feed gas stream 69 to provide (i) a gaseous mixture 4 comprising methane and CO, (ii) a substantially fully deoxygenated hydrocarbon liquid 61 comprising a liquid hydrocarbon-containing fraction, (iii) an aqueous liquid 63, and (iv) a solid char 65. As shown in FIG. 6, the hydropyrolysis process 200 may include two reaction stages carried out in a first-stage hydropyrolysis reactor 81 and a second-stage hydroconversion reactor 83. The hydropyrolysis reactor 81 may operate as a catalytic fluidized bed reactor to devolatilize the feedstock 67 in the presence of stabilized hydrogen, producing a hydropyrolysis reactor effluent 85. After removing the solid char 65 from the hydropyrolysis reactor effluent 85 and cooling in the first stage effluent cooler 84, hydropyrolysis vapors 87 containing the partially deoxygenated hydropyrolysis product, light hydrocarbons, H, CO, CO, and HO are sent to the hydroconversion reactor 83. This reactor may operate as a fixed bed for further catalytic hydrodeoxygenation of the partially deoxygenated hydropyrolysis product. The hydroconversion reactor effluent 89 is then sent to the second stage effluent cooler 86, which condenses the substantially completely deoxygenated hydrocarbon liquid 61 and aqueous liquid 63 from the hydroconversion reactor effluent 89. In the separator 82, these liquid products 61, 63 of the hydropyrolysis process 200 may be separated into a denser phase, i.e., the aqueous liquid 63, and a less dense phase, i.e., the substantially completely deoxygenated hydrocarbon liquid 61, which settles thereon, by organic / aqueous phase separation.

[0108] Also in separator 82, a product vapor fraction 88 comprising light hydrocarbons, H, CO, CO, and HO may be separated by vapor / liquid phase separation. Product vapor fraction 88 may be sent to hydrogen purification module 75, for example, using pressure swing adsorption (PSA) or membrane separation, to separate recycle hydrogen 97 from gaseous mixture 4, the recycle hydrogen 97 being enriched in hydrogen relative to product vapor fraction 88. Gaseous mixture 4 may therefore be enriched in hydrogen relative to product vapor fraction 88 and may have other compositional characteristics, as discussed above, with respect to representative gaseous mixtures generally and / or with respect to "hydropyrolysis gaseous mixtures" in particular. Hydrogen purification module 75 may be used to preferentially separate any or all of the light (C1-C3) hydrocarbons, CO, CO, HO, and / or HS from gaseous mixture 4. The recycle hydrogen 97 may have a hydrogen concentration of at least about 80 mol%, such as from about 80 mol% to about 99 mol%, or at least about 85 mol%, such as from about 85 mol% to about 98 mol%. The recycle hydrogen 97 may be used to provide at least a portion, and possibly all, of the hydrogen-containing feed gas stream 69. Optionally, external make-up hydrogen or fresh hydrogen 64 may be combined with the recycle hydrogen 97 to provide the hydrogen-containing feed gas stream 69.

[0109] 7 shows additional details of a hydrogen production process 300, such as that shown in FIG. 5. As previously described, the hydrogen production process may convert natural gas 77 to a purified hydrogen product 79 using steam methane reforming (SMR) 92, water-gas shift (WGS) reaction 94, and pressure swing adsorption (PSA) 96 stages. In this case, the SMR may be used to produce an SMR syngas 98, and the hydrogen content may be increased by the WGS reaction 94 to provide the WGS product 99. The PSA 96 is then used to recover the purified hydrogen product 79 and reject non-hydrogen impurities (e.g., substantially all non-hydrogen impurities) in a hydrogen-depleted PSA tail gas 91. The hydrogen-depleted PSA tail gas 91 generally comprises (i) unconverted methane (resulting from methane “breakthrough” from the SMR 92), (ii) hydrogen not recovered in the purified hydrogen product 79 using the PSA 96, and (iii) CO, as well as generally CO and HO. The hydrogen-depleted PSA exhaust gas 91 may have other compositional characteristics generally with respect to the gaseous mixture as described above and / or with respect to the "hydrogen-depleted PSA exhaust gas."

[0110] Typically, the hydrogen-depleted PSA tail gas 91 obtained as a by-product from the hydrogen production process is combusted to recover its fuel value. This combustion energy can serve as a significant heat source for the furnace or hot box of the SMR 92 because this step of the hydrogen production process 300 operates endothermically and at high temperatures (e.g., above 950°C (1742°F)). However, according to the process shown in FIG. 7 , the hydrogen-depleted PSA tail gas 91 is first sent to the integrated CSR-FT process 100, e.g., as shown in FIG. 3 and described above. Depending on the composition of the hydrogen-depleted PSA tail gas 91, a supplemental hydrocarbon source 95 (e.g., natural gas) and / or a supplemental steam source 93 can optionally be combined with the hydrogen-depleted PSA tail gas 91 to provide a gaseous mixture 4 having a suitable composition, as described above. In this manner, methane and CO from the hydrogen-depleted PSA tail gas 91 can be converted in the integrated CSR-FT process 100 to produce a liquid fraction 39 of the finished product 33 (FIG. 3), comprising liquid hydrocarbons useful as fuel. While the consumption of methane thereby reduces the heating value of combustion of the hydrogen-depleted PSA tail gas 91, the value of the produced liquid fraction 39 exceeds this loss in heating value, which can be replaced, for example, by using low-cost natural gas. For example, this natural gas can be combined with the vapor fraction 37 of the finished product 33 (FIG. 3) as a supplemental fuel gas (not shown) for the furnace or hot box of the SMR 92, since the vapor fraction 37 itself can provide some of the heat required to maintain the SMR 92.

[0111] The following examples are offered as representative of the invention, and such examples should not be construed as limiting the scope of the invention, as other equivalent embodiments will be apparent in light of the present disclosure and claims. [Example]

[0112] Research on CO2-steam reforming Pilot plant scale experiments were carried out in which a gaseous mixture was continuously fed to a CO2-steam reforming reactor containing catalyst particles with a composition of 1 wt% Pt and 1 wt% Rh on a cerium oxide support. The CO2-steam reforming performance of the system was measured over a 0.7 hr -1 Testing was performed at WHSV, 760°C (1400°F), and a gauge pressure range of 124 kPa (18 psig) to 172 kPa (25 psig). Two gaseous mixtures were tested: (1) a composition containing methane, ethane, propane, and CO2, plus HO, simulating that obtained from the combination of biomass hydropyrolysis and hydroconversion ("renewable type"); and (2) a typical natural gas composition with high levels of CO2 ("natural gas type"). The renewable type composition provided an example of a methane-containing feedstock that was also a "hydropyrolysis gaseous mixture" as described above. The natural gas type composition provided an example of a methane-containing feedstock that was also a "natural gas with CO2" with the addition of steam as an oxidant containing HO as described above. These gaseous mixtures (combined feeds) and the synthesis gas product obtained from such feeds are summarized in Table 1 below. [Table 1]

[0113] These results demonstrate that the CO2-steam reforming catalyst and process can produce a syngas product with a molar ratio of H2:CO of approximately 2:1, and therefore suitable for subsequent direct processing via a Fischer-Tropsch reaction, or at least without prior (upstream) adjustment of this ratio. While these favorable results were obtained only at a reaction temperature of 760°C (1400°F), lower temperatures such as 704°C (1300°F) are also possible given the high activity of the catalyst. Lower operating temperatures tend to reduce the rate of coke-forming side reactions, which deactivate the catalyst. Figure 8 illustrates the relationship between temperature and methane conversion for the type of feed and reforming catalyst tested in Example 1. In particular, this figure illustrates the ability to achieve greater than 85% methane conversion at 704°C (1300°F) and greater than 95% methane conversion at 760°C (1400°F). 9 illustrates how the HO:CO molar ratio of the gaseous mixture affects the H:CO molar ratio of the syngas product at temperatures of both 704° C. (1300° F.) and 760° C. (1400° F.) for the type of feed and reforming catalyst tested in Example 1. Given the possibility of establishing a relationship between such parameters for a given feed, reforming catalyst, and set of operating conditions, the gaseous mixture composition can serve as a convenient control for achieving a desired syngas product composition. [Example]

[0114] Sulfur tolerance of CO2-steam reforming catalyst Additional experiments were conducted in which the typical natural gas composition described in Example 1 was subjected to CO2-steam reforming, also described in this example. However, in this case, the gaseous mixture or combined feed was spiked with HS at a concentration of 800 mol-ppm. Despite the high levels of sulfur contamination, the offset in methane conversion was found to be easily restored by increasing the reforming catalyst bed temperature from 760°C (1400°F) to approximately 788°C (1450°F). Furthermore, the reforming catalyst surprisingly exhibited long-term stability over 400 hours of operation (hours on-stream) at this temperature, WHSV, and pressure, as described above for Example 1. This stability, achieved despite substantial sulfur concentrations, was surprising given the sulfur sensitivity of conventional catalysts used in steam methane reforming. [Example]

[0115] Long-term CO2-steam reforming test The gaseous mixture described as "renewable type" in Example 1 and having the composition given in Table 1 was tested using the catalyst and conditions described in Example 1 to evaluate system performance for CO2-steam reforming over a long-term operating period. The "renewable type" feed or gaseous mixture also provides an example of a representative "hydropyrolysis gaseous mixture," as described above. Long-term stability testing revealed that the composition of the obtained synthesis gas product was stable over 500 hours of operation under these constant conditions, demonstrating essentially no deactivation of the reforming catalyst over the long-term operating period. Figure 10 illustrates the stable synthesis gas product composition with high methane conversion obtained over this operating period. Figure 11 illustrates the stable H2 / CO molar ratio of the obtained synthesis gas product, which was approximately 2 and therefore optimal for use in downstream FT synthesis reactions to produce liquid hydrocarbons. [Example]

[0116] Evaluation of hydroisomerization and hydrocracking of wax produced from FT synthesis The FT synthesis reaction generally produces hydrocarbons with a wide range of molecular weights (and carbon numbers), but does not produce normal C hydrocarbons, which are solid at room temperature and are generally considered undesirable wax products. 20 + The use of hydrocracking to remove this wax by separating it from the FT product and converting it to lower carbon number hydrocarbons generally adds one-third of the capital cost and a significant amount of complexity to the FT synthesis complex. Being a solid, wax is not easily transported through pipelines and cannot be blended with crude oil. The goal was to develop a simple, integrated gas-to-liquids (GTL) process in which the wax produced in the FT synthesis reaction could be converted to (i) lower carbon number hydrocarbons with liquid fuel value and / or (ii) isoparaffinic hydrocarbons with melting points below room temperature, thereby adding to its yield. To this end, a simple hydroisomerization / hydrocracking reaction combination was investigated. The use of hydroisomerization was considered a potentially attractive option because this reaction requires only a small amount of hydrogen. Therefore, incorporating a hydroisomerization step immediately after the FT synthesis stage with all or substantially all of the FT product (e.g., without wax separation) was proposed as a low-cost solution to the wax production problem of this stage. Normal C 20 + This step, which involves both hydroisomerization and hydrocracking of hydrocarbons, was called the "finishing stage," which utilized at least one "finishing reactor."

[0117] To investigate possible catalysts for use in wax hydroisomerization / hydrocracking, C 23 -C 60Normal paraffins were obtained from a commercial supplier of FT wax (Sasol). Batch experiments were conducted by adding 200 grams of wax to a stirred Parr bomb reactor. After the wax addition, the reactor temperature was increased under flowing hydrogen or flowing syngas (a mixture of hydrogen and CO). The reactor (loaded with 25 grams of finishing catalyst (or hydroisomerization / hydrocracking catalyst)) absolute pressure was maintained at 2.76 MPa (400 psia). A catalyst blend of 1 wt% gallium on a ZSM-5 zeolite support (G-ZSM-5 catalyst) was found to be efficient for converting wax through hydroisomerization combined with hydrocracking. Such combined reactions resulted in the formation of branched hydrocarbons and low molecular weight hydrocarbons, respectively, thereby improving the quality of diesel boiling range hydrocarbons in terms of lower pour point and cloud point, and gasoline boiling range hydrocarbons in terms of increased octane number. The results of batch tests carried out using this catalyst are summarized in Table 2 below, which includes the composition of the products recovered following conversion of the wax. [Table 2]

[0118] These tests clearly demonstrated that Ga-ZSM-5 catalysts can produce significant hydroisomerization and hydrocracking of wax, so that the product can be blended with crude oil and transported following this finishing step performed after the FT synthesis reaction. The use of a separate finishing reactor to convert wax is superior to other options previously proposed, including the use of a wax conversion catalyst within the FT reactor. [Example]

[0119] Improving FT product quality through a finishing stage A material-balanced "baseline FT" process was evaluated against the same process, but with the addition of a finishing step to hydroisomerize and hydrocrack the wax produced in the FT process according to information obtained from Example 4 above. The baseline FT process utilized a catalyst containing 20 wt. % cobalt on an alumina support, and the process was run for a sufficient period of time to establish an operating equilibrium, particularly with respect to wax formation rate. A finishing reactor containing a Ga-ZSM-5 finishing catalyst, as described in Example 4, was added downstream of the baseline FT process to evaluate its ability to convert the FT wax produced in the baseline FT process and thereby improve overall product quality compared to using the baseline FT process alone. This improvement is illustrated in Table 3 below. [Table 3]

[0120] Considering these results, it can be seen that the combination of the FT synthesis stage and the finishing stage does not produce wax, i.e., hydrocarbons with melting points above room temperature. Furthermore, the addition of a finishing stage using a Ga-ZSM-5 catalyst can produce hydrocarbons (C4-C) that are useful for liquid fuels. 19 Selectivity to C1-C3 gaseous hydrocarbons (e.g., liquid hydrocarbons, i.e., the percentage of carbon in the CO converted by FT synthesis that resulted in such hydrocarbons) increased. Selectivity to C1-C3 gaseous hydrocarbons also increased slightly as a result of the cracking reactions that produced these products. Although these tests were not optimized to minimize the yield of C1-C3 gaseous hydrocarbons and maximize the yield of liquid hydrocarbon fuels, they nevertheless demonstrated that the use of finishing (hydroisomerization and hydrocracking) reactions can convert essentially all of the wax into condensed liquid hydrocarbons useful as fuels without producing excessive gaseous hydrocarbons. Gas chromatography-mass spectrometry (GC-MS) of the finishing product obtained after the finishing reaction confirmed complete conversion of the wax. [Example]

[0121] Integration of biomass hydropyrolysis to improve the yield of biogenic liquid fuels To increase the yield of biogenic liquid fuels from biomass-containing feedstocks (wood), a comparison was made between the cost and performance of the hydropyrolysis process shown in Figure 6 and a process to which an integrated CSR-FT process, as shown in Figure 5, has been added. The evaluation of each case was based on a production rate of 500 tonnes per day (t / d) of liquid fuel for computational convenience. This comparison is given in Table 4 below. [Table 4]

[0122] This comparison shows that the addition of an integrated CSR-FT process to produce additional hydrocarbons from the hydropyrolysis gaseous mixture 4, as shown in Figure 5, provides a substantial improvement in the yield of such hydrocarbons (38 wt% vs. approximately 26 wt% based on biomass). The carbon in such additional hydrocarbons is derived from biomass, and as a result, all liquid fuel obtained from each of the aforementioned cases is biogenic. It is estimated that the addition of the CSR-FT process could increase the production rate of gasoline and diesel boiling range hydrocarbons from 86 to 120 gallons per ton of wood biomass.

[0123] In general, aspects of the present invention relate to the use of dry reforming or CO2-steam reforming to achieve high conversion of methane and / or other hydrocarbon(s) and to produce a synthesis gas product with desired characteristics, including H2:CO molar ratio, as described herein. Further aspects relate to such reforming processes using active reforming catalysts capable of converting methane and / or other hydrocarbon(s) in the presence of CO2 or both CO2 and H2O with little coke deposition and high catalyst stability, even in the case of feeds comprising sulfur-containing contaminants and / or reactive compounds, such as aromatic and / or olefinic hydrocarbons, which are associated with rapid deactivation in conventional catalyst systems. Still further aspects relate to such reforming processes using liquid (C4 + ) Reforming processes also provide a straightforward approach for direct use in further processing stages, such as Fischer-Tropsch synthesis for the production of hydrocarbons and / or alcohols, fermentative alcohol synthesis, or hydrogen production. Beneficially, the process may utilize conventional CO2 present in both renewable and non-renewable methane sources, preferably without removing this CO2, and / or may utilize lower levels of water compared to conventional methane steam reforming. In addition, the sulfur tolerance of the reforming catalyst is further evidenced by its activity in converting sulfur-containing contaminants to SO2 and HS, which are easily managed downstream, optionally using a single acid gas removal step. Still further aspects relate to the integration of CO2-steam reforming with Fischer-Tropsch synthesis, as described above, optionally with a finishing stage. Those skilled in the art, armed with the knowledge of this disclosure, will recognize that various modifications may be made to such processes to realize these and other benefits without departing from the scope of the present disclosure. In this context, it should be understood that features of the disclosure are susceptible to variation and / or substitution without departing from the scope of the present disclosure. The particular embodiments shown and described in this disclosure are set forth solely for purposes of illustration and not as limitations on the invention, as set forth in the appended claims.

Claims

1. A process for producing C4+ hydrocarbons, comprising: converting H2 and CO in the synthesis gas product to hydrocarbons, including said C4+ hydrocarbons, provided in a Fischer-Tropsch (FT) reactor FT product; feeding a finishing feed comprising at least a portion of said FT product to a finishing stage comprising at least one finishing reactor containing a finishing catalyst to convert normal C20+ hydrocarbons present in said finishing feed by hydroisomerization and / or hydrocracking reactions to C4-C19 hydrocarbons provided in a finishing product of said finishing stage; Including, The process wherein the finishing feed comprises at least a portion of the unconverted CO present in the FT product.

2. The process of claim 1, wherein the finishing feed comprises substantially all of the unconverted CO present in the FT product.

3. The process of claim 1, wherein the finishing feed is supplied to the finishing stage without an intervening operation to separate all or substantially all of the unconverted CO present in the FT product.

4. A process for producing C4+ hydrocarbons, comprising: converting H2 and CO in the synthesis gas product into hydrocarbons, including said C4+ hydrocarbons, provided in a Fischer-Tropsch (FT) reactor FT product; feeding a finishing feed comprising at least a portion of said FT product to a finishing stage comprising at least one finishing reactor containing a finishing catalyst to convert normal C20+ hydrocarbons present in said finishing feed by hydroisomerization and / or hydrocracking reactions to C4-C19 hydrocarbons provided in a finishing product of said finishing stage; Including, A process wherein the finishing feed comprises at least a portion of the unconverted H2 present in the FT product.

5. The process of claim 4, wherein the finishing feed comprises substantially all of the unconverted H2 present in the FT product.

6. The process of claim 4 or 5, wherein the finishing feed is supplied to the finishing stage without an intervening operation to separate all or substantially all of the unconverted H2 present in the FT product.

7. The process of claim 1, wherein the finishing feed comprises H 2 at a concentration of at least about 20 mol%.

8. The process of claim 1, wherein the synthesis gas product is produced in a reforming stage by contacting a gaseous mixture comprising methane and an oxidant with a reforming catalyst.

9. The process of claim 8, wherein the gaseous mixture further comprises naphtha boiling range hydrocarbons.

10. The process of claim 8 or 9, wherein the gaseous mixture further comprises jet fuel boiling range hydrocarbons.

11. The process of any one of claims 8 to 10, wherein the oxidant comprises CO2 and / or H2O.

12. The process of claim 11, wherein the oxidant comprises both CO2 and H2O.

13. The process of claim 11, wherein the oxidant comprises CO 2 and the conversion of the CO 2 in the reforming stage is at least about 50%.

14. The process of claim 8, wherein the conversion of methane in the reforming stage is at least about 75%.

15. The process of any one of claims 8 to 14, wherein the hydrocarbons present in the gaseous mixture are converted with a selectivity of up to about 25% C1-C3 hydrocarbons provided in the finished product.

16. A process described in any one of claims 8 to 12, wherein at least one of (i) a CO2 conversion in the reforming stage of at least about 50%, (ii) a methane conversion in the reforming stage of at least about 75%, and (iii) a H2:CO molar ratio of at least about 1.5:1 in the synthesis gas product is maintained over an operating period of at least about 500 hours, either continuously or discontinuously, without replacement or regeneration of the reforming catalyst.

17. The process of any one of claims 8 to 16, wherein the reforming catalyst comprises a precious metal present in an amount of at least about 0.05 wt. % based on the weight of the reforming catalyst.

18. The process of claim 17, wherein the precious metal is present in an amount of at least about 0.3 weight percent based on the weight of the reforming catalyst.

19. The process of claim 17, wherein the precious metal is present in an amount of about 0.05% to about 5% by weight based on the weight of the reforming catalyst.

20. The process of any one of claims 17 to 19, wherein the precious metal is selected from the group consisting of platinum (Pt), rhodium (Rh), ruthenium (Ru), palladium (Pd), silver (Ag), osmium (Os), iridium (Ir), and gold (Au).

21. The process of claim 20, wherein the noble metal is selected from the group consisting of Pt, Ru, Pd, Ag, and Os.

22. The process of any one of claims 8 to 21, wherein the reforming catalyst comprises a solid support comprising cerium oxide and one or more other metal oxides.

23. The process of claim 22, wherein the one or more other metal oxides are selected from the group consisting of aluminum oxide, silicon oxide, titanium oxide, zirconium oxide, magnesium oxide, and strontium oxide.

24. A process described in any one of claims 8 to 23, wherein at least a portion of the methane is derived from a renewable source.

25. The process of claim 24, wherein the renewable source is the effluent of (a) a biomass gasification process, (b) a biomass digestion process, (c) a biomass pyrolysis process, or (d) a biomass hydropyrolysis process.

26. A process described in any one of claims 8 to 23, wherein at least a portion of the methane is derived from an industrial process effluent.

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