Noble metal catalysts and processes for reforming methane and other hydrocarbons - Patents.com

Abstract

A process is provided for converting methane and / or other hydrocarbons into synthesis gas (i.e., a gaseous mixture comprising H2 and CO). The process comprises contacting a catalyst comprising precious metals on a solid support comprising cerium oxide, an exemplary catalyst comprising 1 wt% Pt and 1 wt% Rh as precious metals on a cerium oxide support.

Description

[Technical field]

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

[0002] Aspects of the invention relate to catalysts and processes for reforming methane and / or other hydrocarbons, and more particularly to reacting such hydrocarbon(s) with CO as an oxidant, or with both CO and HO as a combination of oxidants, in the presence of a precious metal-containing catalyst to produce a synthesis gas product comprising H and CO. [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. These include dwindling oil reserves, projected increases in energy demand, and growing concerns over greenhouse gas (GHG) emissions derived from non-renewable carbon sources. Given the abundance of natural gas reserves as well as gas streams obtained from biological sources (biogas), methane has become the focus of a number of possible routes to provide liquid hydrocarbons. The key commercial process for converting methane to fuel involves a first conversion step that produces synthesis gas (syngas), followed by a second downstream Fischer-Tropsch (FT) synthesis step. In this second step, the synthesis gas, which contains a mixture of hydrogen (H2) and carbon monoxide (CO), undergoes successive cleavage of C-O bonds and the formation of C-C bonds that incorporate hydrogen. This mechanism provides for the formation of hydrocarbons, especially 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. The choice of catalyst can affect FT product yields in other respects. For example, iron-based FT catalysts tend to produce more oxygenates, whereas ruthenium as the active metal tends to produce exclusively paraffins.

[0004] Concerning 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, which results in significantly different thermodynamics, not only because the generation of steam itself may 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:

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[0005] This reaction is called "dry reforming" of methane, and since it is highly endothermic, the thermodynamics of dry reforming of methane are unfavorable compared to ATR, or even compared to SMR. However, the stoichiometric consumption of one mole of carbon dioxide per mole of methane may reduce the overall carbon footprint of liquid fuel production, providing a more environmentally friendly consumption of methane. The CO2 consumption rate per mole of feed increases when reforming higher hydrocarbons (e.g. C2-C6 paraffins), which is desirable for example for the purpose of hydrogen production (e.g. for refinery processes). In any case, the thermodynamic barrier is nevertheless a major challenge and relates to the fact that CO2 is fully oxidized and very stable, so a large amount of energy is required 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, which is summarized, for example, in the literature [reviewed by Lavoie (Frontiers in Chemistry (Nov. 2014), Vol. 2 (81): 1-17)], confirming that with regard to the catalytic approach to carry out this reaction, heterogeneous catalytic systems are the most popular.

[0006] On the other hand, nickel-based catalysts have shown efficacy in reducing the activation energy for the aforementioned dry reforming reactions, but high rates of carbon deposition (coking) of these catalysts have also been reported in Lavoie's literature. The undesirable conversion of methane to elemental carbon can proceed through methane decomposition (CH4 → C + 2H2) or the Boudouard reaction (2CO → C + CO2) 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 has yet to be realized, unlike other reforming technologies such as ATR and SMR. This is in large part due to the high carbon formation rates and the associated catalyst deactivation through coking, as observed when using dry reforming catalyst systems operating under the conditions proposed so far. Finally, while other conventional reforming technologies have been demonstrated to be economically viable, it is well known that such processes, and SMR in particular, 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 catalysts and processes for converting methane and / or other hydrocarbons into 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 H0 (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 H0. Exemplary catalysts beneficially have 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 H0 to provide at least a portion of the oxidant, contribute to the overall operating environment, which can reduce coke formation and significantly extend beneficial catalyst life.

[0008] A further important benefit is the sulfur tolerance of the catalysts described herein, whereby pretreatment of methane-containing feedstocks (e.g., natural gas) or other hydrocarbon-containing feedstocks is not required to reduce the concentration of H2S and other sulfur-containing contaminants according to preferred embodiments, or at least is not as rigorous as in conventional reforming techniques. Also, considering that all or at least a significant portion of sulfur-containing contaminants such as mercaptans, except for H2S, can be oxidized to SO2 in the dry reforming reaction or CO2-steam reforming reaction as described herein, thereby making standard acid gas treatment (e.g., scrub) a suitable and relatively simple option for downstream sulfur removal, if such downstream sulfur removal may be desired, such as before the FT conversion step, this pretreatment can be greatly simplified.

[0009] Overall, the process and catalyst related improvements described herein are commercially significant in that they make dry reforming, or otherwise CO2 and steam reforming (i.e., CO2-steam reforming), processes an economically viable alternative to conventional techniques such as autothermal reforming (ATR) and steam methane reforming (STR). Furthermore, the synthesis gas from this process can be produced at a H2:CO molar ratio (e.g., about 2:1) that is favorable for downstream processing via the Fischer-Tropsch (FT) reaction, or at least at a molar ratio that can be readily adjusted to achieve such a favorable value.

[0010] These and other embodiments, aspects, and advantages of the present invention will become apparent from the following detailed description. [Brief description of the drawings]

[0011] A more complete understanding of exemplary embodiments of the present invention, and advantages thereof, may be obtained by reference to the following description in consideration of the accompanying drawings, in which like reference numerals are used to identify like features, and in which: [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. [Diagram 2] The catalysts described herein demonstrate high activity for methane conversion. [Diagram 3] 1 illustrates the relationship between the H2:CO molar ratio of the synthesis gas product in the reactor (as combined feed) and the H2O / CO2 molar ratio of the gaseous mixture at different reaction temperatures for a representative CO2-steam reforming process. [Figure 4] 1 illustrates the long-term operational stability of a catalyst as described herein in a CO2-steam reforming process over an extended operating period. [Diagram 5]1 illustrates the long-term operational stability of a catalyst as described herein in a CO2-steam reforming process over an extended operating period.

[0012] It should be understood that the drawings provide an illustration of the process and the specific results and parameters associated and / or the principles associated. It is understood that Figures 1A and 1B provide a simplified overview 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 that are not essential to the understanding of the 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, the process of converting hydrocarbons such as methane by dry reforming or CO2-steam reforming comprises components and elements that are determined in part by its specific application. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0013] 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.

[0014] The term "gaseous mixture" refers to a mixture comprising at least a hydrocarbon, such as methane, and also comprising CO2 as an oxidant, that undergoes dry reforming or CO2-steam reforming (when water is also present in the gaseous mixture) by contact with a 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 CO2-steam reforming, 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, such as C6-C6, C8, C9, C10, C11, C12, C13, C14, C15, C16, C17, C18, C20, C22, C24, C25, C30, C35, C40, C45, C50, C60, C70, C85, C90, C95, C100, C120, C140, C150, C160, C180, C250, C160, C180, C250, C180, C260, C180, C270, C180, C280, C300, C400, C450, C500, C60, C70, C85, C90, C100, C120, C140, C160, C180, C25 ...16 It may contain hydrocarbons.

[0015] An embodiment of the invention relates to a process for producing a synthesis gas product (syngas), the process comprising: (i) oxidizing 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) CO2, with a catalyst comprising at least one (e.g., two or more) noble metal on a solid support comprising cerium oxide. It is possible that CO2 alone can act as an oxidant for methane and / or other hydrocarbon(s) to CO and H2 by dry reforming of such hydrocarbons, which can be generalized, for example, in the case of alkanes, as follows:

number

[0016] In preferred embodiments, i.e., where the gaseous mixture further comprises HO, a combination of CO and HO may serve as the oxidant. The reaction in this case is the "CO-steam reforming reaction", which also includes steam reforming as a route to produce syngas from methane and / or other hydrocarbons, which can be generalized, for example, for alkanes, as follows:

number

number

[0017] From this, C4-C, which are desirable as liquid fuels or components of liquid fuels, 12 Hydrocarbons and other C4 + It can be observed that hydrocarbons are ideally formed at H2: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 to tune the H2:CO molar ratio of the syngas product to a wide range of CO2-steam reforming conditions. Indeed, for any given set of such conditions (e.g., conditions within the reactor such as temperature, pressure, weight hourly space velocity, and catalyst loading) in which the combined CO2-steam reforming and steam reforming reactions are carried out, a relationship can be established between the H2O:CO2 molar ratio of the gaseous mixture (e.g., the combined reactor feed) and the H2:CO molar ratio of the syngas product (e.g., the reactor effluent). While dry and steam reforming of hydrocarbons other than methane produce other molar ratios of H2 and CO, the same directionally shifts or adjustments in product yields can be achieved by relatively altering the amounts of oxidants H2O and CO2 in the gaseous mixture undergoing CO2-steam reforming. Accordingly, an embodiment of the present invention relates to a CO2-steam reforming process comprising determining a H2:CO molar ratio of a synthesis gas product and adjusting the H2O:CO2 molar ratio of the gaseous mixture based on the H2:CO molar ratio toward a target H2:CO molar ratio of the synthesis gas product, e.g., toward a target H2: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.

[0018] More specifically, the H2O:CO2 molar ratio of the gaseous mixture may be increased to increase the observed H2:CO molar ratio of the synthesis gas product below the target toward the target H2:CO molar ratio. Conversely, the H2O:CO2 molar ratio of the gaseous mixture may be decreased to decrease the observed H2:CO molar ratio of the synthesis gas product above the target toward the target H2:CO molar ratio. Any such adjustment to the H2O:CO2 molar ratio of the gaseous mixture may be performed, 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 generally the hydrocarbon-containing feedstock), the CO2-containing oxidant, and the H2O-containing oxidant, relative to one or more other flow rates(s) of such components. According to a particular embodiment, the HO:CO molar ratio of the combined feed to the reactor can be increased or decreased by increasing or decreasing, respectively, the flow rate of steam (as the HO-containing oxidant), which can result in an increase or decrease, respectively, of the HO:CO molar ratio of the gaseous mixture.

[0019] In addition to providing the ability to control the H2:CO molar ratio of the synthesis gas product to a value within a preferred range, the use of steam (H2O) as an oxidant in combination with CO2 further surprisingly reduces the carbon (coke) formation rate compared to pure dry reforming, thereby extending the catalyst life as described herein. Thus, a further embodiment of the present invention relates to a CO2-steam reforming process in which the carbon formation rate (e.g., using a suitable ratio or concentration / partial pressure of CO2 and H2O oxidant in combination with a catalyst as described herein) is less than that of a baseline process (i.e., a baseline dry reforming process), with all parameters kept the same, except for replacing H2O in the gaseous mixture (e.g., combined reactor feed) with an equimolar amount of CO2 oxygen (i.e., replacing 1 mole of H2O with 1 / 2 mole of CO2). 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., about 1.5:1 to about 2.3:1).

[0020] The catalysts as described herein further exhibit surprising sulfur tolerance, which is particularly beneficial, for example, in the case of methane-containing feedstocks comprising or derived from natural gas, which may contain significant concentrations (e.g., several weight percent by volume or more) of H2S depending on the source. In this regard, conventional steam methane reforming (SMR) processes generally require pretreatment to reduce the total feed sulfur content to less than 1 mol-ppm to protect the catalyst from sulfur poisoning. On the other hand, according to exemplary embodiments of the present invention, the gaseous mixture or any of its components, particularly the hydrocarbon-containing feedstock, is not reduced or otherwise has not been subjected to a sulfur removal pretreatment step, as necessary to achieve favorable catalyst life. Such embodiments provide substantial economic benefits over known processes with stringent desulfurization requirements and associated costs. In contrast to such known processes, the gaseous mixture in a dry reforming or CO2-steam reforming process as described herein generally has not been subjected to pretreatment for sulfur removal, and may comprise sulfur at any concentration representative of a source of hydrocarbon feedstock, such as natural gas, that causes dilution of sulfur when combined with other components of the gaseous mixture (e.g., CO2) having low concentrations of sulfur. For example, the gaseous mixture generally may comprise at least about 1 mol-ppm (e.g., from about 1 mol-ppm to about 10 mol%) of total sulfur (e.g., as H2S and / or other sulfur-containing contaminants). The gaseous mixture generally may 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 100 mol-ppm to about 1000 mol-ppm) of total sulfur. For example, about 500 mol-ppm to about 1000 mol-ppm total sulfur, according to certain embodiments, generally causes no, or at least negligible, adverse effects on the stability of the reforming catalyst as described herein.

[0021] Regarding the sulfur tolerance of the catalysts described herein, a further aspect of the invention relates to the discovery that high levels (concentrations) of sulfur in the gaseous mixture can be compensated for by increasing the reaction temperature, i.e., the temperature of the catalyst bed described herein contained in the reactor. That is, it has been found that increasing the sulfur concentration affects the activity of the 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 loss of activity of a catalyst with a concentration of 800 mol-ppm H2S in the gaseous mixture, compared to the activity of a 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 a conversion of methane and / or other hydrocarbon(s) (e.g., conversion of combined C1-C4 hydrocarbons or combined C1-C3 hydrocarbons) or otherwise determining a sulfur level (e.g., 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), such as a conversion target of at least about 75% (e.g., any particular conversion value in the range of about 75% to about 100%), such as a conversion target of at least about 85% (e.g., any particular conversion value in the range of about 85% to about 99%).

[0022] Importantly, however, such a decrease in activity of the catalysts described herein with increasing sulfur concentration in the gaseous mixture is not accompanied by any appreciable loss in catalyst stability. That is, compensating reactor temperature increases to offset high sulfur levels, as described herein, do not significantly affect the catalyst's ability to achieve stable operating performance over extended periods of time. This finding is contrary to expectations based on conventional reforming technology, where 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 catalysts described herein can be determined according to a standard test in which a small catalyst sample of 5-100 grams is loaded into a fixed-bed reactor and contacted with a feed blend of 30 mol% methane, 30 mol% CO2, and 30 mol% H2O spiked with 800 mol-ppm H2S. In this standard test, the catalyst is heated for 0.7 hr. -1 With flow conditions of the WHSV, a catalyst bed temperature of 788°C (1450°F), and a reactor pressure of 138 kPa (20 psig), a methane conversion of at least 85% and preferably 95% 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.

[0023] The resistance or "robustness" of the catalysts described herein is further manifested in their high stability against deactivation in the presence of other compounds in the gaseous mixture, including higher molecular weight hydrocarbons such as reactive aromatic and / or olefinic hydrocarbons, which are typically considered to be prone to deactivating the 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., about 1 mol % to about 25 mol %), such as at least about 3 mol % (e.g., about 3 mol % to about 20 mol %), or more specifically at least about 5 mol % (e.g., about 5 mol % to about 15 mol %). At such levels of aromatic and / or olefinic hydrocarbons, the stability of the 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 that concentration different from H2S. This tolerance of the catalyst with respect to both sulfur and reactive hydrocarbons as described herein allows for 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 more detail below.

[0024] 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 catalyst as described herein may be capable of producing a large proportion or solely of C4 hydrocarbons, C5 hydrocarbons, C6 hydrocarbons, C7 hydrocarbons, C8 hydrocarbons, C9 hydrocarbons, C10 hydrocarbons, C12 hydrocarbons, C13 hydrocarbons, C14 hydrocarbons, C15 hydrocarbons, C16 hydrocarbons, C17 hydrocarbons, C18 hydrocarbons, C19 hydrocarbons, C20 hydrocarbons, C210 hydrocarbons, C220 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, C69 hydrocarbons, C60 hydrocarbons, C61 hydrocarbons, C62 hydrocarbons, C63 hydrocarbons, C64 hydrocarbons, C65 hydrocarbons, C66 hydrocarbons, C77 hydrocarbons, C78 hydrocarbons, C89 hydrocarbons, C90 hydrocarbons, C91 hydrocarbons, C92 hydrocarbons, C93 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, cyclohexane ... 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 an exemplary embodiment, 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 CO2 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 CO2-steam reforming, the gaseous mixture may comprise H2O 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 discussed above.

[0025] 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 through Fischer-Tropsch synthesis as described above, with a favorable H2:CO molar ratio. The synthesis gas can alternatively be used for other downstream applications associated with 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. As described herein, when dry reforming or CO2-steam reforming is applied according to embodiments of the present invention in hydrogen production, a representative 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. 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 further embodiments, the CO and H2-containing PSA tail gas may 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 may then be separated as described above to recover hydrogen and / or may be used as a combustion fuel. Further integration of a biological fermentation stage with conventional hydrogen production is described, for example, in US Patent 9,605,286; US Patent 9,145,300; US Patent 2013 / 0210096; and US Patent 2014 / 0028598.As an alternative to integration in the hydrogen production process, dry reforming or CO2-steam reforming as described herein can be used to provide a synthesis gas product, which is directly used 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 may be sulfur tolerant or may even require sulfur in the cell culture medium, so that the sulfur tolerance of the catalyst as described herein may be particularly beneficial in terms of compatibility and cost savings with respect to eliminating upstream sulfur removal or at least reducing the sulfur removal requirements, relative to conventional reforming catalysts.

[0026] Thus, aspects of the invention relate to dry reforming and CO2-steam reforming processes for producing a synthesis gas product (e.g., comprising both H2 and CO, and optionally unconverted CO2, HO, and / or other gases such as hydrocarbons). In an exemplary embodiment, a gaseous mixture comprising methane and / or other hydrocarbon(s) may be provided batchwise, but preferably as a continuous stream, to a reactor of a dry reforming process (for a feed or gaseous mixture further comprising CO2 but no water) or a CO2-steam reforming process (for a feed or gaseous mixture further comprising both CO2 and water). The synthesis gas product may then be removed batchwise (if the gaseous mixture is provided batchwise) or preferably as a continuous stream (if the gaseous mixture is provided as a continuous stream) from the reactor.

[0027] 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 may be easily separated, for example by cooling / condensation upstream of a 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, which, as mentioned above, is an important parameter in determining the suitability of the syngas product as a direct feed stream to a FT reactor.

[0028] In a representative process, a gaseous mixture comprising methane and / or other light hydrocarbon(s) (e.g., ethane, ethylene, propane, and / or propylene) and CO2, as well as optionally HO, is contacted with a catalyst having activity for effecting reforming of the hydrocarbon(s). In particular, such hydrocarbon(s), such as a majority of such hydrocarbons, may be reformed (i) through oxidation with only some or all of the CO2 according to a dry reforming process, or (ii) through oxidation with both some or all of the CO2 and some or all of the HO (if present) according to a CO2-steam reforming process.

[0029] As previously mentioned, aspects of the present invention relate to the discovery of such reforming catalysts for dry reforming and CO2-steam reforming processes that exhibit significant benefits compared to conventional reforming catalysts, particularly with respect to sulfur tolerance and / or reduced carbon formation (coking) rates. Such features then reduce the deactivation rate of the catalyst through poisoning and / or coking mechanisms that chemically and / or physically block active catalytic sites. Further improvements in catalyst stability result, at least in part, from the high activity of the catalysts described herein when the substantial activation energy barriers associated with the use of CO2 as an oxidant for methane and / or other hydrocarbon(s) are optionally lowered as previously mentioned. This high activity is manifested at low operating (reactor or catalyst bed) temperatures, which further contributes to the rate of carbon deposition (coking) on ​​the catalyst surface and long-term stable operation. According to certain embodiments, a process utilizing the catalyst 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 H2 / CO molar ratio of the synthesis gas product (e.g., 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 possibly non-continuous operation, which may be a period of operation during which (i) the catalyst does not undergo regeneration, e.g., according to a reforming process utilizing the catalyst as a fixed bed in a reactor, and / or (ii) the temperature of the reactor or catalyst bed does not increase beyond a threshold temperature difference between the start and end, e.g., 100° C. (180° F.), 50° C. (90° F.), 25° C. (45° F.), 10° C. (18° F.), or even 5° C. (9° F.).

[0030] Representative reforming catalysts suitable for catalyzing the reaction of methane and / or other hydrocarbon(s) with CO2 and optionally with H2O may comprise one precious metal on a solid support, and possibly more than one precious metal. 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. The solid support preferably comprises a metal oxide, including cerium oxide of particular interest. 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 cerium oxide, or substantially only cerium oxide (e.g., greater than about 95 wt%). 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 minor amounts, 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 (e.g., less than about 50 wt% or less than about 30 wt%) of cerium oxide.

[0031] Noble metals are understood to refer to a class of metal elements that are resistant to oxidation. In an exemplary embodiment, the noble metals of the catalyst, for example, at least two noble metals, 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), and the term "consisting of" is used merely to represent 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 catalyst comprising noble metals includes not only a catalyst comprising at least two noble metals, but also a catalyst comprising at least three noble metals, as well as a catalyst 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 that amount independently. For example, a representative catalyst may comprise two precious metals Pt and Rh, where Pt and Rh may be present independently of each other in any amount within such ranges (e.g., about 0.05 wt% to about 5 wt%). That is, 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.

[0032] In an exemplary embodiment, the at least two precious metals (e.g., Pt and Rh) may be substantially the only precious metals present in the catalyst, such as, 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 catalyst. In a further exemplary embodiment, the at least two precious metals (e.g., Pt and Rh) are substantially the only metals present in the 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 metals of the solid support may 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 catalyst. Any metals present in the catalyst, including the precious metal(s), may have a metal particle size generally in the range of about 0.3 nanometers (nm) to about 20 nm, typically 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.

[0033] The precious metal(s) can be incorporated into the solid support according to well-known techniques of catalyst preparation, including sublimation, impregnation, or dry mixing. In the case of impregnation, which is a preferred technique, an impregnation solution of one or more soluble compounds of the precious metal 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 contact 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 heating, 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, when two precious metals are simultaneously impregnated, both are dissolved in the same impregnation solution, or are otherwise impregnated separately using different impregnation solutions and contact 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 catalyst.

[0034] The solid support itself may be prepared according to 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 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 within the particle. In this regard, it may be understood that different preparation methods may 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, the weight percentages described herein may refer to the weight percentages of a single catalyst particle, based on the weight of the solid support or otherwise based on the weight of the catalyst, but may generally refer to the average weight percentages of a number of catalyst particles, such as the number in a reactor that forms the catalyst bed used in the processes described herein.

[0035] Simplified illustrations of a dry reforming process and optionally a CO2-steam reforming process 10 are shown in Figures 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 reactor 5 in the form of a vessel, which vessel is used to contain a bed of catalyst 6 as described above under reforming conditions in which the gaseous mixture 4 and the catalyst 6 are contacted. According to the embodiment illustrated in Figure 1A, the gaseous mixture 4 may be provided in the reactor 5 only from a hydrocarbon-containing feedstock 1. For example, a representative hydrocarbon-containing feedstock is a methane-containing feedstock, which may be obtained from gasification or pyrolysis of biomass, including hydrogasification or hydropyrolysis, and further comprise CO2 and H2O. Such a hydrocarbon-containing feedstock thereby provides itself with a gaseous mixture 4 for the CO2-steam reforming process, in which both CO2 and H2O 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.

[0036] As another option, the H2O-containing oxidant 3 (e.g., as steam) may also be combined to form a gaseous mixture 4 comprising both CO2- and H2O-oxidants for the CO2-steam reforming process, and methane. However, H2O may also be present in sufficient amounts in the hydrocarbon-containing feedstock 1 and / or the CO2-containing oxidant 2, such that a separate H2O-containing oxidant 3 may not be necessary. It is clear that any of these may be combined prior to (e.g., upstream of) the reactor 5, as indicated by the dashed double-arrowed line between the hydrocarbon-containing feedstock 1, the CO2-containing oxidant 2, and the H2O-containing oxidant 3. According to certain embodiments, FIG. 1B illustrates a hydrocarbon-containing feedstock 1 mixed with an optional CO2-containing oxidant 2 and an optional H2O-containing oxidant 3 to provide a gaseous mixture 4 prior to (e.g., upstream of) and within the reactor 5.

[0037] As mentioned above, in embodiments where the gaseous mixture 4 comprises one or more hydrocarbons such as methane and CO2 but no H2O, the process may be considered a "dry reforming" process, whereas in embodiments where the gaseous mixture 4 comprises a hydrocarbon(s) and CO2, and further comprises active H2O as an oxidant for the hydrocarbon(s) in combination with the CO2 (so that, for example, at least the respective oxidant portions of CO2 and H2O oxidize the respective reactant portions of the hydrocarbon(s)), the process may be considered a "CO2-steam reforming" process. The catalyst as described herein provides beneficial results in both dry reforming and CO2-steam reforming, as mentioned above, in terms of both activity and stability. Under reforming conditions provided in the reactor 5, the gaseous mixture 4 is converted to a synthesis gas product 7, which may be enriched (i.e., may have an increased concentration) of hydrogen and CO compared to the gaseous mixture 4, and / or may be depleted (i.e., may have a decreased concentration) of CO2, H2O, methane and / or other hydrocarbon(s) originally present in the gaseous mixture 4.

[0038] An important methane-containing feedstock is natural gas, particularly stranded natural gas, which is not easily 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, for example at least about 10 mol%, or even at least about 25 mol%, represents an attractive methane-containing feedstock, since the process described herein does not require the removal of CO (e.g., scrubbing with an amine solution) and in fact utilizes CO as a reactant. Other methane-containing feedstocks may comprise methane obtained from coal or biomass (e.g., lignocellulose or char) gasification, or obtained from biomass digesters, or obtained as an effluent from renewable hydrocarbon fuel (biofuel) production processes (e.g., pyrolysis processes such as hydropyrolysis processes or fatty acid / triglyceride hydroconversion processes). Further methane-containing feedstocks may comprise methane obtained from a well head or an industrial process effluent, including an oil refining process (as refinery off-gas), an electric power production process, an iron and steel manufacturing process, or a non-ferrous manufacturing process, a chemical (e.g., methanol) production process, or a coke manufacturing process. In general, any process gas known to contain hydrocarbons (e.g., C1-C3 hydrocarbons) and CO2 may provide all or a portion of the gaseous mixture as described herein, or at least all or a portion of the methane-containing feedstock as a component of the mixture. When the methane-containing feedstock comprises methane obtained from a renewable resource (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 generate a renewable synthesis gas product (i.e., comprising renewable CO), 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 do not necessarily need to, be pretreated to remove H2S and other sulfur-containing contaminants prior to dry reforming or CO2-steam reforming.

[0039] In an exemplary embodiment, the gaseous mixture 4 comprising the hydrocarbon and CO2 can be contacted with the catalyst 6 in a batch or non-continuous operation, but 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., the hydrocarbon-containing feedstock 1, the CO2-containing oxidant 2, and / or the H2O-containing oxidant 3, as described herein) to improve process efficiency. For example, the contacting can be carried out by continuously flowing the gaseous mixture 4 (e.g., any of such components combined as a combined reactor feed stream) through the reactor 5 and the catalyst 6 under reforming conditions (e.g., conditions within the reactor vessel and conditions within the 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 ~About 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 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 gaseous mixture divided by the weight of catalyst in the reactor, which corresponds to the weight of the equivalent catalyst bed of the feed stream processed per hour. WHSV is related to the inverse of the reactor residence time. The catalyst 6 may be contained within the 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 that utilize continuous catalyst regeneration.

[0040] 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 may effectively oxidize methane and / or other hydrocarbons at temperatures significantly lower than the typical conventional temperature of 816°C (1500°F) used for dry reforming or steam reforming due to the high activity of the catalyst with respect to the reduction of the activation energy barrier required for the use of CO2 as an oxidant. For example, in exemplary embodiments, reforming conditions may 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 discussed, the presence of significant amounts (e.g., 100-1000 mol-ppm) of H2S and / or other sulfur-containing contaminants may warrant an increase in temperature, 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 the 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, which corresponds to an absolute pressure of 101 kPa (14.7 psig). Since the reforming reaction produces a high number of moles of product per mole of reactant, equilibrium conditions at relatively low pressures are favored. Thus, reforming conditions may generally include gauge pressures from about 0 kPa (0 psig) to about 517 kPa (75 psig), typically 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).

[0041] Beneficially, the high activity of the 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 reactor or catalyst bed temperature and / or other reforming conditions (e.g., WHSY and / or pressure) as will be appreciated by one of ordinary skill in the art with the knowledge gained from this disclosure. Beneficially, the 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 CO2 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 as described herein for the hydrocarbon(s). As is understood in the art, the conversion of any particular compound (e.g., methane) or combination of compounds (e.g., C1-C4 or C1-C3 hydrocarbons) can be calculated based on the following formula:

number

[0042] As previously mentioned, additional benefits associated with reforming processes, and in particular CO2-steam reforming processes, as described herein, include the preferred molar ratio of H2 / CO in the syngas product, as well as the ability to adjust this ratio. 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 reactor feed) or gaseous mixture, the catalyst, and the reforming conditions.

[0043] In representative embodiments, the synthesis gas product has a H2:CO molar ratio that is beneficially close to 2:1, particularly in the case of CO2-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 H2 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 previously mentioned, the balance of the synthesis gas product may be substantially or entirely CO2 and water, depending on the particular dry reforming or CO2-steam reforming process, including the conditions of such process (e.g., conditions within the reactor such as temperature, pressure, weight hourly space velocity, and catalyst loading) and the feed or gaseous mixture in which the reaction was carried out. In an exemplary embodiment, CO2 is present in the synthesis gas product at a concentration generally less than about 45 mol% (e.g., about 5 mol% to about 45 mol%), and typically less than about 35 mol% (e.g., about 10 mol% to about 35 mol%). Water is generally present at a concentration of less than about 20 mol% (e.g., about 1 mol% to about 25 mol%), and typically less than about 15 mol% (e.g., 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%.

[0044] The following examples are presented 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 view of the present disclosure and claims. EXAMPLES

[0045] A pilot plant scale experiment was carried out in which a gaseous mixture was continuously fed to a 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 Conditions of WHSV, 760°C (1400°F), and gauge pressures ranging from 124 kPa (18 psig) to 172 kPa (25 psig) were tested. The two gaseous mixtures tested were (1) a composition containing methane, ethane, propane, and CO2, plus H2O, simulating that obtained from a combination of biomass hydropyrolysis and hydroconversion ("renewable type"), and (2) a typical natural gas composition with elevated levels of CO2 ("natural gas type"). Such gaseous mixtures (combined feeds) and the synthesis gas products obtained from such feeds are summarized in Table 1 below. [Table 1]

[0046] From these results it can be seen that the CO2-steam reforming catalyst and process can provide a synthesis gas product with a molar ratio of H2:CO of approximately 2:1 and therefore suitable for subsequent direct processing by a Fischer-Tropsch reaction, or at least without prior (upstream) adjustment of this ratio. Although such 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. The lower operating temperature will decrease the rate of the side reaction that forms coke, which deactivates the catalyst. Figure 2 illustrates the relationship between temperature and methane conversion for the type of feed and catalyst tested in Example 1, and in particular, the 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). 3 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 types of feeds and catalysts tested in Example 1. Given the possibility of establishing relationships between such parameters for a given feed, catalyst, and set of operating conditions, the gaseous mixture composition can serve as a convenient control for achieving a desired syngas product composition. EXAMPLES

[0047] Additional experiments were conducted in which the typical natural gas composition described in Example 1 was subjected to CO2-steam reforming, also as described in this Example, except that in this case the gaseous mixture or combined feed was spiked with H2S at a concentration of 800 mol-ppm. Despite the high levels of sulfur contamination, it was found that the offset in methane conversion was easily restored by increasing the catalyst bed temperature from 760°C (1400°F) to about 788°C (1450°F). Moreover, the catalyst surprisingly demonstrated long-term stability over 400 operating hours (hours on-stream (hr)) at this temperature and WHSV and pressure as described above with respect to Example 1. This stability, achieved despite substantial sulfur concentrations, was unexpected in view of the sulfur sensitivity of conventional catalysts used in steam methane reforming. EXAMPLES

[0048] The gaseous mixture described in Example 1 as "renewable type" and having the composition given in Table 1 was tested using the catalyst and conditions described in Example 1 to evaluate the system performance for CO2-steam reforming over a long-term operating period. The long-term stability test revealed that the composition of the obtained synthesis gas product was stable even over 500 hours of operation under such constant conditions, demonstrating essentially no deactivation of the reforming catalyst over the long-term operating period. Figure 4 illustrates the stable synthesis gas product composition obtained over this operating period, with high methane conversion. Figure 5 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.

[0049] In general, aspects of the 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 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 with 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 + ) relates to such reforming processes that also provide a direct approach for direct use in further processing stages, such as Fischer-Tropsch synthesis for the production of hydrocarbons and / or alcohols, synthesis of alcohols by fermentation, or hydrogen production. Advantageously, the process may utilize conventional CO2 present in both renewable and non-renewable methane sources, preferably without removing said CO2, and / or may utilize lower levels of water compared to conventional steam reforming of methane. In addition, the sulfur tolerance of the catalyst is further evidenced by its activity in converting sulfur-containing pollutants to SO2 and H2S, which are easily managed downstream, using a single acid gas removal step if desired. Those skilled in the art, armed with the knowledge gained from this disclosure, will recognize that various modifications may be made to such processes in realizing these and other benefits without departing from the scope of the disclosure. In this context, it should be understood that the features of the disclosure are susceptible to modification and / or substitution without departing from the scope of the disclosure. The specific embodiments shown and described in this disclosure are set forth solely for purposes of illustration and are not intended to limit the invention as set forth in the appended claims.

Claims

1. CO as an oxidant ２ and H ２ contacting a gaseous mixture comprising methane, together with O, with a catalyst to produce a synthesis gas product. ２ - a steam reforming process, the catalyst comprises Pt in an amount of 0.05% to 5% by weight of the catalyst on a solid support comprising cerium oxide present in an amount of at least 80% by weight of the solid support; The contacting may include using CO as the oxidant. ２ and H ２ conducted under reforming conditions in which the conversion of said methane by reaction with O is at least 80%; CO ２ - Steam reforming process.

2. 10. The process of claim 1, wherein the catalyst further comprises Rh in an amount of 0.05% to 5% by weight of the catalyst.

3. H of 1.5:1 to 2.3:1 ２ 2. The process of claim 1, wherein the methane:CO molar ratio and the methane conversion of at least 85% are maintained for at least 500 hours of operation.

4. 2. The process of claim 1, wherein the gaseous mixture comprises from 100 mol-ppm to 1000 mol-ppm total sulfur.

5. 10. The process of claim 1, wherein the gaseous mixture comprises aromatic and olefinic hydrocarbons in a combined amount of from 1 mol % to 25 mol %.

6. 2. The process of claim 1, wherein the methane is obtained from a renewable methane source.

7. The contact lasts for 0.1 hr. －１ ~2.5hr －１ 2. The process of claim 1, wherein the process is carried out by flowing the gaseous mixture through a reactor containing the catalyst at a weight hourly space velocity (WHSV) of 0.1 to 0.5 wt. % and providing the synthesis gas product as an effluent from the reactor.

8. The synthesis gas product H ２ determining a molar ratio of H:CO; ２ Based on the H:CO molar ratio of the gaseous mixture, ２ O:CO ２ The molar ratio of the synthesis gas product to the target H ２ : CO molar ratio; The process of claim 1 further comprising:

9. 9. The process of claim 8, wherein said contacting is carried out under said reforming conditions comprising a temperature of from 649°C (1200°F) to 816°C (1500°F).

10. The process of claim 1 , wherein the catalyst comprises the Pt in an amount of 0.3 wt % to 3 wt %.

11. 2. The process of claim 1, wherein the cerium oxide is present in an amount of at least 95% by weight of the solid support.

12. The process of claim 10, wherein the catalyst comprises the Pt in an amount of 0.5 wt% to 2 wt%.

13. 2. The process of claim 1, wherein the solid support comprises the cerium oxide and one or more other metal oxides.

14. 14. The process of claim 13, wherein the one or more other metal oxides are aluminum oxide, silicon oxide, titanium oxide, zirconium oxide, magnesium oxide or strontium oxide.

15. 15. The process of claim 14, wherein the one or more other metal oxides is aluminum oxide.

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