Noble metal catalysts and processes for reforming methane and other hydrocarbons

Abstract

To provide processes for converting methane and / or other hydrocarbons to synthesis gas (i.e., a gaseous mixture comprising H2 and CO).SOLUTION: In the process, at least a portion of hydrocarbons reacts with CO2. At least a second portion of the methane reacts with H2O (steam), thereby improving overall thermodynamics of the process, in terms of reducing endothermicity and the required energy input, compared to dry reforming in which no H2O is present. Catalysts for such processes advantageously possess high activity and thereby can achieve significant levels of methane conversion at temperatures below those used conventionally under comparable conditions. These catalysts also exhibit high sulfur tolerance, in addition to reduced rates of carbon formation, even in the reforming of heavier (e.g., naphtha boiling-range or jet fuel boiling-range) hydrocarbons. The robustness of the catalyst translates to high operating stability. A representative catalyst comprises 1 wt% of Pt and 1 wt% of Rh as noble metals, on a cerium oxide support.SELECTED DRAWING: Figure 2

Description

Technical Field

[0001] Description of Research or Development Funded by the Federal Government 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 catalysts and processes for reforming methane and / or other hydrocarbons, and more specifically to reacting such hydrocarbons, in the presence of a noble metal-containing catalyst, with CO as an oxidant 2 or with a combination of oxidants including CO 2 and H 2 2O to produce a syngas product comprising H 2 2 and CO.

Background Art

[0003] Description of Related Art The search for alternatives to crude oil for the production of hydrocarbon fuels is being driven by a growing number of factors. These include the depletion of oil reserves, the predicted increase in energy demand, and the growing concern about greenhouse gas (GHG) emissions from non-renewable carbon sources. Given the abundance of natural gas reserves as well as gas streams obtained from biological sources (biogas), methane has emerged as a focus for many possible routes to provide liquid hydrocarbons. Key commercial processes for converting methane to fuel include a first conversion step to produce synthesis gas (syngas), followed by a second downstream Fischer-Tropsch (FT) synthesis step. In this second step, hydrogen (H 2) A synthesis gas containing a mixture of hydrogen and carbon monoxide (CO) undergoes successive cleavage of C-O bonds and formation of C-C bonds incorporating hydrogen. This mechanism provides for the formation of hydrocarbons, especially straight-chain alkanes, with a molecular weight distribution that can be controlled to some extent by varying the Fischer-Tropsch (FT) reaction conditions and catalyst properties. Such properties include pore size and other characteristics of the support material. The choice of catalyst can affect the FT product yields among other aspects. For example, iron-based FT catalysts tend to produce more oxygenates, while ruthenium as the active metal tends to produce only paraffins.

[0004] For the first conversion step, well-known processes for producing syngas from methane upstream of FT include partial oxidation reforming and autothermal reforming (ATR) 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 production of steam itself can require an energy investment, but also because the reaction involving methane and water is endothermic. Recently, the use of carbon dioxide (CO 2 ) as an oxidant for methane has also been proposed, and as a result the desired syngas is formed by the reaction of the most oxidized form of carbon and the most reduced form of carbon according to the following equation:

Equation

[0005] This reaction is called the "dry reforming" of methane and is highly endothermic, so the thermodynamics of the dry reforming of methane are less favorable compared to ATR or even more so compared to SMR. However, the stoichiometric consumption of 1 mole of carbon dioxide per mole of methane can potentially reduce the overall carbon footprint of liquid fuel production and provide a more environmentally friendly consumption of methane. The CO consumption rate per mole of this feed is for higher hydrocarbons (e.g., C 2 -C 2 -C 6rises when reforming paraffin), and this reforming is desirable, for example, when hydrogen production (e.g., for a purification process) is the goal. In any case, the thermodynamic barrier is still a major challenge, due to the fact that CO 2 is fully oxidized and very stable, so a large amount of energy is required to activate it as an oxidizing agent. In view of this, numerous catalyst systems have been studied to overcome the activation energy barrier for the dry reforming of methane, which is summarized, for example, in the review by Lavoie (Frontiers in Chemistry (Nov. 2014), Vol. 2(81):1-17), and it is confirmed that heterogeneous catalyst systems are the most popular regarding the catalytic approach 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 the high rate of carbon deposition (coking) of these catalysts has also been reported in the literature by Lavoie. The undesirable conversion of methane to elemental carbon generally occurs at the reaction temperature required for the dry reforming of methane, through methane decomposition (CH 4 →C + 2H 2 ) or the Boudouard reaction (2CO → C + CO 2) can proceed through. Therefore, this reaction has been studied as a promising route for syngas production, but the commercialization of this technology, unlike other reforming technologies such as ATR and SMR, has not yet been realized. This is largely due to the high carbon formation rate and the accompanying catalyst deactivation through coking, as seen 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, such processes, and especially SMR, are well-known to require significant upstream capital and operating costs to remove sulfur and other poisons from the catalysts used. Otherwise, a commercially acceptable operating period from a given catalyst loading cannot be achieved. Satisfactory solutions to such problems and other problems regarding conventional hydrocarbon reforming for producing syngas and / or hydrogen have been sought but not yet realized.

Summary of the Invention

Means for Solving the Problems

[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 2 and CO) by reacting at least a portion of the hydrocarbon(s) with CO 2 . Preferably, according to the CO 2 -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 H 2 O (steam), thereby improving the overall thermodynamics of the process in terms of reducing the endothermicity (ΔH) and the energy input required compared to "pure" dry reforming without the presence of H 2 O. Representative catalysts beneficially have high activity, thereby achieving significant levels of hydrocarbon (e.g., methane) conversion at temperatures below those customarily used for dry reforming. Such high activity levels can optionally be achieved in the presence of H 2Providing at least a portion of the oxidant in combination with the use of O contributes to the overall operating environment, thereby reducing coke formation and significantly extending the useful life of the beneficial catalyst.

[0008] As a further important benefit, the catalysts described herein have sulfur resistance, such that the pretreatment of a methane-containing feedstock (e.g., natural gas) or other hydrocarbon-containing feedstock is, according to a preferred embodiment, 2 not required, or at least not as stringent as in conventional reforming techniques, to reduce the concentration of H 2 S and other sulfur-containing contaminants. Also, all or at least a substantial portion of the sulfur-containing contaminants such as mercaptans other than H 2 S can be oxidized to SO 2 in the dry reforming reaction or the CO

[0009] In general, the improvements associated with the processes and catalysts described herein are commercially important in the sense of making the dry reforming process, or otherwise the CO 2 and steam reforming (i.e., CO 2 -steam reforming) processes economically viable alternatives to conventional techniques such as autothermal reforming (ATR) and steam methane reforming (STR). Further, the syngas produced by this process can be produced at an H 2 :CO molar ratio (e.g., about 2:1) that is favorable for downstream processing by the Fischer-Tropsch (FT) reaction, or at least at a molar ratio that can be easily adjusted to achieve such a favorable value.

[0010] Such and other embodiments, aspects, and benefits of the present invention will be apparent from the following detailed description.

Brief Description of the Drawings

[0011] A more complete understanding of exemplary embodiments of the present invention and the benefits thereof can be obtained by considering the accompanying drawings and referring to the following description, in which like reference numerals are used to identify the same characteristics in the figures.

Figure 1A

Figure 1B

Figure 2

Figure 3

Figure 4

Figure 5

[0012] The drawings are to be understood as presenting examples of the processes, and the specific results associated therewith, and parameters, and / or principles involved. Figures 1A and 1B provide simplified overviews for ease of explanation and understanding, and it is understood that such drawings and elements are not necessarily drawn to scale. Valves, appliances, and other equipment and systems not essential to the understanding of the various aspects of the present invention are not shown. As will be readily apparent to those skilled in the art having knowledge of the present disclosure, the hydrocarbon conversion process, such as methane, by dry reforming or CO 2 -steam reforming comprises configurations and elements that are partially determined by its particular use.

BEST MODE FOR CARRYING OUT THE INVENTION

[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 weight parts per million and mole parts per million, respectively. For an ideal gas, "mol%" and "mol-ppm" are equal to volume percent and volume parts per million, respectively.

[0014] The term "gaseous mixture" refers to a mixture comprising at least hydrocarbons such as methane and an oxidant including CO that undergoes dry reforming or CO 2 -steam reforming (when water is also present in the gaseous mixture) upon contact with a catalyst. The term "gaseous mixture" generally refers to such a mixture that is completely or at least mostly in the gas phase under the conditions of dry reforming or CO 2 -steam reforming as described herein, including the temperatures and pressures suitable for such reactions. The term "gaseous mixture" does not exclude the presence of compounds (e.g., water) in this mixture that are liquid under ambient temperature and pressure conditions. Such compounds can include hydrocarbons such as those found in liquid fuels including naphtha and jet fuel, e.g., C 2 -C 6 -C 16 hydrocarbons.

[0015] Embodiments of the invention relate to a process for producing a synthesis gas product (syngas), the process comprising: (i) methane and / or one or more other hydrocarbons (e.g., CH 4 、C 2 H 6 、C 2 H 4 、C 3 H 8 、C 3 H 6 、C 4 H 10 、C 4 H 8 、C 5 H 12 、C 5 H10 , any of the high molecular weight hydrocarbons, and mixtures thereof), and (ii) CO 2 , a gaseous mixture comprising, contacting with a catalyst comprising at least one (e.g., two or more) noble metals on a solid support comprising cerium oxide. CO 2 alone can serve as an oxidant for such hydrocarbons in dry reforming to CO and H 2 and can serve as an oxidant for methane and / or other hydrocarbons (s) to, which can be generalized as follows for example in the case of alkanes:

Number

[0016] Preferred embodiments, i.e., embodiments in which the gaseous mixture further comprises H 2 O, in the combination of CO 2 and H 2 O can serve as an oxidant. The reaction in this case is the "CO 2 -steam reforming reaction", which also includes steam reforming as a route to produce syngas from methane and / or other hydrocarbons, which can be generalized as follows for example in the case of alkanes:

Number

Number

[0017] From here, C 4 -C 12 hydrocarbons such as C hydrocarbons desirable as liquid fuels or components of liquid fuels4 + Hydrocarbons have an H close to 2 2 :CO molar ratio can be observed to be ideally formed. Importantly, CO 2 in combination with steam (H 2 O) as an oxidizing agent is used, which provides a useful "handle" or control parameter for adjusting the H 2 :CO molar ratio of the syngas product under a wide range of CO 2 -steam reforming conditions. In fact, for any given set of such conditions (e.g., temperature, pressure, weight hourly space velocity per unit time, and catalyst formulation, i.e., conditions inside the reactor) implemented by combining the CO 2 -steam reforming reaction and the steam reforming reaction, a relationship can be established between the H 2 O:CO 2 molar ratio of the gaseous mixture (e.g., combined reactor feed) and the H 2 :CO molar ratio of the syngas product (e.g., reactor effluent). The dry reforming and steam reforming of hydrocarbons other than methane produce H 2 and CO in other molar ratios, while by relatively changing the amounts of the oxidizing agent H 2 O and CO 2 in the gaseous mixture passing through the CO 2 -steam reforming, a directed same shift or adjustment can be achieved in the product yield. Therefore, embodiments of the present invention relate to a CO 2 -steam reforming process, which process comprises the steps of determining the H 2 :CO molar ratio of the syngas product, and based on the H 2 :CO molar ratio, adjusting the H 2 O:CO 2 molar ratio of the gaseous mixture in the direction of the target H 2 :CO molar ratio of the syngas product, for example, in the direction of a target H 2 :CO molar ratio of 2:1, or otherwise generally in the range of about 1.5:1 to about 2.5:1, generally 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 of the target H 2 :CO molar ratio.

[0018] More specifically, the H 2 O:CO 2 molar ratio of the gaseous mixture can be increased in a direction towards the target H 2 :CO molar ratio so as to increase the observed H 2 :CO molar ratio of the synthesis gas product below the target. Conversely, the H 2 O:CO 2 molar ratio of the gaseous mixture can be decreased in a direction towards the target H 2 :CO molar ratio so as to decrease the observed H 2 :CO molar ratio of the synthesis gas product above the target. Any such adjustment to the H 2 O:CO 2 molar ratio can be effected, for example, by adjusting the flow rate(s) of one or more of the components of the gaseous mixture (e.g., the combined feed), such as a methane-containing feedstock (or generally a hydrocarbon-containing feedstock), a CO 2 -containing oxidant, and an H 2 O-containing oxidant, relative to the flow rate(s) of one or more other of such components. According to a particular embodiment, the H 2 O:CO 2 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 H 2 O-containing oxidant), whereby the H 2 O:CO 2 molar ratio of the gaseous mixture can consequently be increased or decreased, respectively.

[0019] The ability to control the H 2 :CO molar ratio of the synthesis gas product to a value within a preferred range not only provides, but also, by using steam (H 2 O) as an oxidant in combination with CO 2 ), the carbon (coke) formation rate is further surprisingly reduced compared to pure dry reforming, thereby extending the life of the catalyst as described herein. Accordingly, a further embodiment of the present invention relates to a CO 2 -steam reforming process with respect to the carbon formation rate (e.g., in combination with a catalyst as described herein, CO2 and H 2 O oxidant at a suitable ratio or concentration / partial pressure) is less than the carbon formation rate of the baseline process (i.e., the baseline dry reforming process), and all parameters are maintained the same, but H in the gaseous mixture (e.g., the combined reactor feed) 2 O is replaced with an equimolar amount of CO 2 of oxygen (i.e., H 2 1 mole of O is replaced with 1 / 2 mole of CO 2 and replacement). Coupled with this relatively low carbon formation relative to the baseline process, the syngas product can have an H 2 / CO molar ratio (e.g., from about 1.5:1 to about 2.3:1) as described herein.

[0020] As described herein, the catalyst further exhibits surprisingly high sulfur tolerance, which is particularly beneficial, for example, in the case of natural gas that may contain significant concentrations (e.g., several weight percent or more by volume) of H 2 S, or a methane-containing feedstock derived from such natural gas. In this regard, conventional steam methane reforming (SMR) processes generally require a pretreatment to reduce the total feed sulfur content to less than 1 mol-ppm to protect the catalyst from sulfur poisoning. In contrast, according to representative embodiments of the present invention, the gaseous mixture or any of its components, particularly hydrocarbon-containing feedstocks, have either reduced or no sulfur removal pretreatment steps. Such embodiments provide a substantial economic benefit over well-known processes with stringent desulfurization requirements and associated costs, as needed to achieve a preferred catalyst life. In contrast to such well-known processes, the gaseous mixture during the dry reforming or CO 2 -steam reforming process as described herein generally not only has not undergone a sulfur removal pretreatment, but also other components of the gaseous mixture having a low concentration of sulfur (e.g., CO 2) may be provided with sulfur at any representative concentration of a hydrocarbon feedstock, such as natural gas, which causes dilution of sulfur when combined with 2 it. For example, the gaseous mixture may generally comprise at least about 1 mole-ppm (e.g., from about 1 mol-ppm to about 10 mol%) of total sulfur (e.g., as H

[0021] 2S 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 100 mol-ppm to about 1000 mol-ppm) of total sulfur. For example, from about 500 mol-ppm to about 1000 mol-ppm of total sulfur generally causes no side effects or only negligible side effects with respect to the stability of the reforming catalyst as described herein. 2 2

[0021] 1 4 With respect to the sulfur tolerance of the catalysts described herein, a further aspect of the invention relates to the discovery that a high level (concentration) 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 an increase in sulfur concentration affects the activity of the catalyst as measured by a decrease in the conversion of methane and / or other hydrocarbons (s) in the gaseous mixture when there is no change in all other operating parameters. 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) may be sufficient to restore the loss of activity of a catalyst with 800 mol-ppm of H 1 3determining the conversion of hydrocarbons), or otherwise determining the sulfur level (e.g., H 2 S level) in the gaseous mixture or syngas product, and adjusting the reaction temperature towards a conversion target of methane and / or other hydrocarbon(s), e.g., a conversion target of at least about 75% (e.g., any specific conversion value in the range of about 75% to about 100%), e.g., a conversion target of at least about 85% (e.g., any specific conversion value in the range of about 85% to about 99%), based on the conversion or sulfur level.

[0022] However, importantly, such a decrease in the activity of the catalysts described herein, accompanied by an increase in the sulfur concentration in the gaseous mixture, is not further accompanied by any significant loss in the stability of the catalyst. That is, as described herein, an increase in the compensating reaction temperature to offset the high sulfur level does not significantly affect the ability of the catalyst to achieve stable operating performance over a long period of time. This finding is contrary to what would be expected based on conventional reforming techniques, where even the presence of small amounts (e.g., mol-ppm levels) of sulfur in the feed has to be avoided to prevent catalyst deactivation and costly early replacement. The unique sulfur tolerance of the catalysts, or the stability of the activity in the presence of sulfur-containing contaminants, as 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 reactor and contacted with a feed blend of 800 mol-ppm H 2 S added, 30 mol% methane, 30 mol% CO 2 and 30 mol% H 2 O. In this standard test, a conversion of at least 85% and preferably 95% of methane is maintained at a constant catalyst bed temperature for at least 50 hours of operation, and more generally for 100 hours of operation, or even for at least 400 hours of operation, under a flow condition of 0.7 hr -1 WHSV, a catalyst bed temperature of 788 °C (1450 °F), and a reactor pressure of 138 kPa (20 psig).

[0023] The resistance of the catalysts described herein, i.e., "robustness", is further manifested in high stability against deactivation in the presence of other compounds in a gaseous mixture containing high molecular weight hydrocarbons such as reactive aromatic hydrocarbons and / or olefinic hydrocarbons, which are usually regarded as likely to cause deactivation of the catalyst through coking. For example, the gaseous mixture generally comprises aromatic hydrocarbons and olefinic hydrocarbons in a total amount of at least about 1 mol% (e.g., from about 1 mol% to about 25 mol%), such as 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 hydrocarbons and / or olefinic hydrocarbons, the stability of the catalyst can be shown according to the same activity stability test defined above with respect to sulfur resistance, except that the feed blend contains aromatic hydrocarbons and / or olefinic hydrocarbons at that concentration different from H 2 S. This resistance of the 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 will be described in detail below.

[0024] More generally, the gaseous mixture, and particularly this hydrocarbon-containing feedstock component, may comprise, in addition to methane, C 2 , C 3 , and / or C 4 hydrocarbons (e.g., ethane, propane, propylene, butane, and / or butene) and other hydrocarbons. Alternatively, as described herein, the catalyst may consist mostly or simply of C 4 hydrocarbons, C 5 hydrocarbons, C 6 hydrocarbons, C 7 hydrocarbons, C 8 hydrocarbons, C 9 hydrocarbons, C 10 hydrocarbons, C 11 hydrocarbons, C 12 hydrocarbons, C 13 hydrocarbons, C 14Hydrocarbon, C 15 Hydrocarbon, C 16 Hydrocarbon, C 17 Hydrocarbon, C 18 Comprising or optionally consisting of any one or more compounds selected from the group consisting of hydrocarbons and combinations thereof, for the dry reforming of high molecular weight hydrocarbons or CO as in the case of hydrocarbons in a gaseous mixture 2 -Steam reforming can be used. For example, the hydrocarbons in the gaseous mixture can be used for the dry reforming or CO 2 -Steam reforming (naphtha reforming), in the case of C 4 -C 8 Hydrocarbons or C 4 -C 6 Hydrocarbons may comprise or consist of. As another example, the hydrocarbons in the gaseous mixture can be used for the dry reforming or CO 2 -Steam reforming (jet fuel reforming), in the case of C 8 -C 18 Hydrocarbons or C 8 -C 14 Hydrocarbons may comprise or consist of. Such naphtha boiling range hydrocarbons and jet fuel boiling range fractions are usually obtained as products from crude oil refining, and from such situations can be a source of sulfur-containing contaminants in the gaseous mixture. In a representative embodiment, the gaseous mixture can generally comprise methane and / or any of the hydrocarbons described herein in a total amount of about 5 mol% to about 85 mol%, generally about 10 mol% to about 65 mol%, and often about 20 mol% to about 45 mol%. The gaseous mixture can generally further comprise CO in an amount of about 8 mol% to about 90 mol%, generally about 15 mol% to about 75 mol%, and often about 20 mol% to about 50 mol%. 2 For CO 2 -In the case of steam reforming, the gaseous mixture can generally comprise H 2 O in an amount of about 15 mol% to about 70 mol%, generally about 20 mol% to about 60 mol%, and often about 25 mol% to about 55 mol%. The balance of the gaseous mixture is H 2It may contain contaminants such as S and / or other sulfur-containing contaminants as described above.

[0025] In the case of a gaseous mixture comprising methane and / or light hydrocarbons (e.g., C 2 -C 3 or C 2 -C 4 hydrocarbons), the syngas products of dry reforming or CO 2 -steam reforming can be beneficially used in the downstream production of liquid hydrocarbon fuels through Fischer-Tropsch synthesis as described above. The syngas can alternatively be used in other downstream applications associated with conventional steam methane reforming (SMR). For example, the literature [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 CO 2 -steam reforming is applied in accordance with embodiments of the present invention in hydrogen production, representative processes may further comprise (i) a step of subjecting the syngas 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 syngas product without intervening the WGS stage(s), to provide a hydrogen-enriched product stream and a hydrogen-depleted PSA off-gas stream. The hydrogen-enriched product stream can then be used in conventional purification processes such as hydrotreating processes (e.g., hydrodesulfurization, hydrocracking, hydroisomerization, etc.). The hydrogen-depleted PSA off-gas stream can then be separated, hydrogen can be recovered therefrom, and / or it can be used as a combustion fuel to satisfy at least part of the heating requirements of dry reforming or CO 2 -steam reforming. In still further embodiments, CO and H 2 2The PSA-containing exhaust gas can be passed to a biological fermentation stage to produce fermentation products 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 a combustion fuel. With respect to conventional hydrogen production, further integration of the biological fermentation stage is described, for example, in U.S. Patent 9,605,286; U.S. Patent 9,145,300; U.S. Patent Application 2013 / 0210096; and U.S. Patent Application 2014 / 0028598. As an alternative to integration in the hydrogen production process, dry reforming or CO 2 -steam reforming, as described herein, can be used to provide a syngas product that is directly used in the downstream production of fermentation products using suitable carboxydotrophic bacteria (e.g., Clostridium autoethanogenum or Clostridium ljungdahlii species). In either case, i.e., with or without such integration, the microorganisms used in fermentation can be sulfur-tolerant or may further require sulfur in the cell culture medium, such that the sulfur tolerance of the catalyst, as described herein, can be particularly beneficial in terms of compatibility and cost savings with respect to the upstream discontinuation of sulfur removal or at least relaxation of the sulfur removal requirements for conventional reforming catalysts.

[0026] For this reason, aspects of the present invention relate to dry reforming processes and CO 2 -steam reforming processes for producing a syngas product (e.g., comprising both H 2 and CO, and optionally unconverted CO 2 , H 2 O, and / or other gases such as hydrocarbons). In representative embodiments, a gaseous mixture comprising methane and / or other hydrocarbon(s) is subjected to a dry reforming process (in the case of a feed or gaseous mixture that further comprises CO 2 but does not comprise water) or a CO 2 -steam reforming process (CO 2and water may be provided batchwise to the reactor (in the case of a feed or gaseous mixture further comprising both), although preferably it may be provided as a continuous stream. The syngas product may then be withdrawn batchwise from the reactor (if the gaseous mixture is provided batchwise), but preferably may be withdrawn as a continuous stream (if the gaseous mixture is provided as a continuous stream).

[0027] H 2 along with CO, and optionally in addition to other gases, water (H 2 O) may also be present in the syngas product, but at least a portion of the water present in vapor form can be readily separated, for example, by cooling / condensing upstream of a Fischer-Tropsch synthesis reactor (FT reactor) used to convert the syngas product to liquid hydrocarbons. Neither the water nor the CO 2 in the syngas product affects the H 2 :CO molar ratio, which as described above is an important parameter in determining the suitability of the syngas product as a direct feed stream to the 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 CO 2 as well as optionally H 2 O is contacted with a catalyst having activity for reforming the hydrocarbon(s). In particular, such hydrocarbon(s), e.g., most of such hydrocarbon, can be reformed through oxidation with (i) only a portion or all of the CO 2 according to a dry reforming process, or (ii) a portion or all of both a portion or all of the CO 2 and H 2 O (if present) according to a CO 2 -steam reforming process.

[0029] As described above, aspects of the present invention exhibit significant benefits, particularly with respect to sulfur resistance and / or reduction in the rate of carbon formation (coking), compared to conventional reforming catalysts, for such dry reforming and CO 2 - steam reforming processes related to the discovery of reforming catalysts. Such characteristics then reduce the catalyst deactivation rate through poisoning mechanisms and / or coking mechanisms that chemically and / or physically block active catalyst sites. Further improvements in catalyst stability result, at least in part, from the high activity of the catalysts described herein, when reducing, as needed, the substantial activation energy barrier associated with the use of CO 2 as an oxidant for methane and / or other hydrocarbons (plural possible). This high activity manifests when the operating (reactor or catalyst bed) temperature is low, which further contributes to the rate of carbon deposition (coke formation) on the catalyst surface and long-term stable operation. According to certain embodiments, a process utilizing the catalysts described herein can maintain stable operating parameters as described herein, for example, during continuous or optionally discontinuous operation for at least about 100 hours, at least about 300 hours, or even at least about 500 hours, for hydrocarbon conversion (e.g., conversion of at least about 85% of methane and / or other hydrocarbons (plural possible)) and / or the H 2 / CO molar ratio (e.g., from about 1.5:1 to about 2.3:1). This can be an operating period where (i) the catalyst does not experience regeneration, for example, according to a reforming process that utilizes the catalyst as a fixed bed within a reactor, and / or (ii) the temperature of the reactor or catalyst bed does not increase beyond a threshold temperature difference between the starting and ending times, where this threshold temperature difference is, for example, 100°C (180°F), 50°C (90°F), 25°C (45°F), 10°C (18°F), or even 5°C (9°F).

[0030] The reaction of methane and / or other hydrocarbons (plural possible) with CO 2 and optionally H 2Typical reforming catalysts suitable for catalyzing the reaction with O may comprise one noble metal on a solid support and, optionally, two or more noble metals. The phrase "on a solid support" is intended to encompass catalysts in which the active metal(s) is / are on the surface of the support and / or within the porous internal structure of the support. The solid support preferably comprises a metal oxide, particularly interestingly cerium oxide. 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., more than about 95 wt%). Other metal oxides such as aluminum oxide, silicon oxide, titanium oxide, zirconium oxide, magnesium oxide, strontium oxide, etc. may also be present in the solid support, and their total amount corresponds to a small 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 a small amount (e.g., less than about 50 wt% or less than about 30 wt%) of cerium oxide.

[0031] The noble metal is understood to refer to a class of metal elements with oxidation resistance. In a representative 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). The term "consisting of" is simply used to represent group members according to a specific embodiment, from which the noble metal(s) is selected, but is generally not used to exclude the addition of other noble metals and / or other metals. Thus, a catalyst comprising a noble metal includes not only a catalyst comprising at least two noble metals but also a catalyst comprising at least three noble metals. Similarly, it includes a catalyst comprising two noble metals and a third non-noble metal such as a promoter metal (e.g., a transition metal). According to a preferred embodiment, the noble 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 noble metals are each present in that amount independently. For example, a representative catalyst can comprise two noble metals Pt and Rh, and Pt and Rh can be present independently of each other in any amount within such a range (e.g., about 0.05 wt% to about 5 wt%). That is, Pt can be present in that amount, or Rh can be present in that amount, or both Pt and Rh can be present in that amount.

[0032] In representative embodiments, at least two noble metals (e.g., Pt and Rh) can be the substantially only noble metals present in the catalyst, such that any other optional noble metal(s) is / are present in an amount or total amount of less than about 0.1 wt% or less than about 0.05 wt% based on the weight of the catalyst. In further representative embodiments, at least two noble metals (e.g., Pt and Rh) are the substantially only metals present in the catalyst, excluding metals present in the solid support (e.g., cerium present as cerium oxide in the solid support). For example, any other optional metal(s) other than the at least two noble metals and the metals of the solid support can be present in an amount or total amount of less than about 0.1 wt% or less than about 0.05 wt% based on the weight of the catalyst. Any metal present in the catalyst, including the noble metal(s), can generally have a metal particle size in the range of about 0.3 nanometers (nm) to about 20 nm, generally 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 noble 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 noble metal in a polar (aqueous) solvent or a nonpolar (e.g., organic) solvent can preferably be contacted with the solid support under an inert atmosphere. For example, this contact can be carried out in a surrounding atmosphere of nitrogen, argon, and / or helium, or otherwise in a non-inert atmosphere such as air, preferably using agitation. The solvent can then be vaporized from the solid support, for example, using heating, flowing gas, and / or vacuum conditions, to form a dried noble metal-impregnated support. The noble metal(s) can be impregnated into the solid support. For example, if two noble metals are impregnated simultaneously, both can be dissolved in the same impregnation solution or, alternatively, separately impregnated using different impregnation solutions and contact steps. In any case, the noble metal-impregnated support can be subjected to further preparation steps such as washing with a solvent for removal of excess noble metal(s) and impurities, further drying, and calcination to provide the catalyst.

[0034] The solid support itself can be prepared according to well-known methods such as a method of extruding to form cylindrical particles (extrudates), an oil dropping method, or a spray drying method to form spherical particles. Regardless of the specific shape of the solid support and the resulting catalyst particles, the amount of noble metal(s) present in the catalyst, as described above, refers to the average value of the weight of such noble metal(s) in a predetermined catalyst particle (regardless of the specific distribution of the noble metal within the particle), for example, in any shape such as cylindrical or spherical. In this regard, it can be understood that different preparation methods can provide different distributions, such as noble metal(s) depositing mainly on or near the surface of the solid support or the noble metal(s) being uniformly distributed throughout the solid support. Generally, the weight percentages described herein can refer to the weight percentage in a single catalyst particle based on the weight of the solid support or, alternatively, based on the weight of the catalyst, but generally refer to the average value of the weight percentages of a large number of catalyst particles, such as the number in the reactor forming the catalyst bed used in the processes described herein.

[0035] Dry reforming process and optionally CO 2 - A simplified illustration of the steam reforming process 10 is shown in FIGS. 1A and 1B. In any such embodiment, a gaseous mixture 4 comprising one or more hydrocarbons (e.g., methane) and CO 2 can be present in the reactor 5 in the form of a vessel, which is used to accommodate the bed of the catalyst 6 under reforming conditions where the gaseous mixture 4 and the catalyst 6 are in contact, as described above. According to the embodiment illustrated in FIG. 1A, the gaseous mixture 4 can be provided into the reactor 5 from only the hydrocarbon-containing feedstock 1. For example, a typical hydrocarbon-containing feedstock is a methane-containing feedstock, which is obtained from the gasification or pyrolysis of biomass including hydrogasification or hydrogenolytic pyrolysis, and can further comprise CO 2 and H 2 O. Thereby, such a hydrocarbon-containing feedstock itself provides the gaseous mixture 4 for the CO 2 -steam reforming process, in which CO 2 and H 2Both of O react as an oxidizer for methane. In other embodiments, the gaseous mixture 4 is such that when the liquid hydrocarbon contains naphtha boiling range hydrocarbons and / or jet fuel boiling range hydrocarbons, or otherwise a certain type of natural gas, etc., the hydrocarbon-containing feedstock 1 contains little CO 2 and can be obtained by combining the hydrocarbon-containing feedstock 1 with an optional CO 2 -containing oxidizer 2.

[0036] As another option, H 2 O-containing oxidizer 3 (e.g., as steam) can also be combined to form a gaseous mixture 4 comprising both a CO 2 -steam reforming process CO 2 oxidizer and an H 2 O oxidizer, and methane. However, again, H 2 O can also be present in sufficient amounts in the hydrocarbon-containing feedstock 1 and / or the CO 2 -containing oxidizer 2, such that the H 2 O-containing oxidizer 3 may not be separately required. As indicated by the double-arrowed dashed lines between the hydrocarbon-containing feedstock 1, the CO 2 -containing oxidizer 2, and the H 2 O-containing oxidizer 3, it is clear that any of these can be combined prior to (e.g., upstream of) the reactor 5. According to a particular embodiment, FIG. 1B illustrates a hydrocarbon-containing feedstock 1 that is mixed with an optional CO 2 -containing oxidizer 2 and an optional H 2 O-containing oxidizer 3 to provide a gaseous mixture 4 prior to (e.g., upstream of) and within this reactor.

[0037] As described above, in embodiments where the gaseous mixture 4 comprises one or more hydrocarbons such as methane and CO 2 but does not contain H 2 O, the process can be considered a "dry reforming" process, whereas the gaseous mixture 4 comprises hydrocarbons (s) and CO 2 and CO 2In combination with, active H as an oxidizing agent for hydrocarbons (plural available) 2 O is further provided (as a result, for example, CO 2 and H 2 O, at least each oxidizing agent portion of which oxidizes each reactant portion of the hydrocarbon(s)) In embodiments, the process can be regarded as a "CO 2 -steam reforming" process. As described herein, the catalyst provides beneficial results with respect to both activity and stability as described above in both dry reforming and CO 2 -steam reforming. Under the reforming conditions provided in the reactor 5, the gaseous mixture 4 is converted into a syngas product 7, which can be enriched in hydrogen and CO (i.e., its concentration can be increased) compared to the gaseous mixture 4, and / or CO 2 present in the initial gaseous mixture 4, H 2 O, methane and / or other hydrocarbon(s) can be depleted (i.e., its concentration can be decreased).

[0038] An important methane-containing feedstock is natural gas, especially stranded natural gas, which cannot be easily converted into a syngas product in an economical way using well-known processes. In contrast to conventional steam reforming, since the process described herein does not require the removal of CO 2 (e.g., scrubbing with an amine solution) and actually utilizes CO 2 as a reactant, for example, a relatively high concentration of CO of at least about 10 mol%, or even at least about 25 mol% 2Natural gas comprising is emblematic of an attractive methane-containing feedstock. Other methane-containing feedstocks may be obtained from coal or biomass (e.g., lignocellulose or carbide) gasification, or from biomass pyrolysis, or as an effluent from a renewable hydrocarbon fuel (biofuel) production process (e.g., a pyrolysis process such as a hydrothermal cracking process or a fatty acid / triglyceride hydroconversion process), and may comprise methane. Further methane-containing feedstocks may include methane obtained from a well head, or an effluent (as refinery offgas) from an oil refining process, an effluent from an electricity production process, an effluent from a steel manufacturing process, or an effluent from a non-ferrous manufacturing process, an effluent from a chemical (e.g., methanol) production process, or an effluent from an industrial process including a coke manufacturing process. Generally, any process gas known to contain hydrocarbons (e.g., C 1 -C 3 hydrocarbons) and CO 2 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 a renewable resource (e.g., biomass), such as when it includes methane from a process stream obtained by hydrothermal cracking as described in U.S. Patent No. 8,915,981 assigned to the Gas Technology Institute, the processes described herein may be used to produce a renewable syngas product (i.e., comprising renewable CO), which can then be further processed to provide renewable hydrocarbon-containing fuels, fuel blend components, and / or chemicals. Therefore, the methane-containing feedstock may comprise methane derived from non-renewable sources (e.g., natural gas) and / or methane derived from renewable sources (e.g., biomass), and the latter source reduces the overall carbon footprint associated with the syngas product and downstream products. As described herein, natural gas and / or other methane-containing feedstocks may be pre-treated by dry reforming or CO 2 -steam reforming with H 2S and other sulfur-containing contaminants can be pretreated to remove them, but it is not necessarily required to be pretreated.

[0039] In an exemplary embodiment, the gaseous mixture 4 comprising hydrocarbons and CO 2 and can be contacted with the catalyst 6 in a batch or discontinuous operation, but preferably, the dry reforming or CO 2 -steam reforming process is continuously carried out using a flowing stream of the gaseous mixture 4 or its components (e.g., as described herein, the hydrocarbon-containing feedstock 1, CO 2 containing oxidant 2, and / or H 2 O-containing oxidant 3) to improve process efficiency. For example, the contacting can be carried out by continuously flowing the gaseous mixture 4 (e.g., as a combined reactor feed stream with any combination of such components) through the reactor 5 and the catalyst 6 under reforming conditions including a suitable flow rate (e.g., conditions within the reactor vessel and within the catalyst bed contained within the vessel). In certain embodiments, the reforming conditions can generally include a weight hourly space velocity (WHSV) of from about 0.05 hr -1 to about 10 hr -1 , generally from about 0.1 hr -1 to about 4.0 hr -1 , and often from about 0.3 hr -1 to about 2.5 hr -1 . As is understood in the art, the WHSV is the weight flow rate of the gaseous mixture divided by the weight of the catalyst within the reactor and corresponds to the weight of the equivalent catalyst bed of the feed stream processed per hour. The WHSV is related to the reciprocal of the reactor residence time. The catalyst 6 can be housed within the reactor 5 in the form of a fixed bed, but other catalyst systems such as moving bed and fluidized bed systems that can be beneficial in processes utilizing continuous catalyst regeneration are also possible.

[0040] Other reforming conditions convenient for dry reforming or CO 2 -steam reforming generally include a temperature of from about 649 °C (1200 °F) to about 816 °C (1500 °F). The processes described herein use CO as an oxidant 2Due to the high activity of the catalyst regarding the reduction of the activation energy barrier required for its use, methane and / or other hydrocarbons can be effectively oxidized at a temperature significantly lower than the typical conventional temperature of 816 °C (1500 °F) used in dry reforming or steam reforming. For example, in a representative embodiment, the reforming conditions can include a temperature 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 described above, H 2 The presence of a significant amount (e.g., 100 - 1000 mol-ppm) of H2S and / or other sulfur-containing contaminants can ensure a temperature increase in the range of, for example, about 732 °C (1350 °F) to about 843 °C (1550 °F), or in the range of about 760 °C (1400 °F) to about 816 °C (1500 °F), in order to maintain the desired conversion level (e.g., greater than about 85%). Other reforming conditions can include a pressure above ambient pressure, i.e., a pressure greater than the gauge pressure of 0 kPa (0 psig) corresponding to an absolute pressure of 101 kPa (14.7 psig). The reforming reaction preferably reaches an equilibrium state at a relatively low pressure because the number of moles of the product is greater than the number of moles of the reactant. Therefore, the reforming conditions can generally include a gauge pressure in the range of about 0 kPa (0 psig) to about 517 kPa (75 psig), typically about 0 kPa (0 psig) to about 345 kPa (50 psig), and often about 103 kPa (15 psig) to about 207 kPa (30 psig).

[0041] Advantageously, the high activity of the catalyst allows for at least about 80% (e.g., about 80% - about 99%), at least about 85% (e.g., about 85% - about 97%), or at least about 90% (e.g., about 90% - about 99%) conversion of methane and / or other hydrocarbons (e.g., methane conversion, combined C 1 -C 3 hydrocarbon conversion, combined C 1 -C 4Hydrocarbon conversion, conversion of naphtha boiling range hydrocarbons, conversion of jet fuel boiling range hydrocarbons, etc.) can be achieved. Advantageously, as described herein, the catalyst is stable at temperatures up to about 732 °C (1350 °F), or even up to about 704 °C (1300 °F), and has sufficient activity to achieve significant hydrocarbon (e.g., methane) conversion of at least about 85%. For the oxidation reactant, CO 2 Typical conversion is at least about 50% (e.g., about 50% to about 75%), and H 2 Typical conversion of O is at least about 70% (e.g., about 70% to about 90%), and the conversion levels are described herein for hydrocarbon(s). As is understood in the art, the conversion of any particular compound (e.g., methane) or combined compounds (e.g., C 1 -C 4 hydrocarbons or C 1 -C 3 hydrocarbons) can be calculated based on the following formula:

Equation

[0042] As described above, the reforming process and in particular CO 2 - Further benefits associated with the steam reforming process are, as described herein, the preferred molar ratio of H 2 / CO in the syngas product, as well as the ability to adjust this ratio. This has particular implications for downstream processing by Fischer - Tropsch for the production of liquid hydrocarbons. The exact composition of the syngas product depends on the composition of the feed (e.g., the combined reactor feed) or gaseous mixture, the catalyst, and the reforming conditions.

[0043] In a representative embodiment, the syngas product, particularly in the case of a CO 2 - steam reforming process, advantageously has an H 2 :CO molar ratio close to 2:1, e.g., generally in the range from about 1.5:1 to about 2.3:1, and typically in the range from about 1.8:1 to about 2.2:1. The total concentration of H 2 and CO in this product is generally at least about 35 mol% (or vol%) (e.g., from about 35 mol% to about 85 mol%), typically at least about 50 mol% (from about 50 mol% to about 80 mol%), and often at least about 60 mol% (from about 60 mol% to about 75 mol%). As described above, the remainder of the syngas product is a particular dry reforming or CO 2 - steam reforming process that includes the conditions of such a process (e.g., temperature, pressure, weight hourly space velocity per unit time, and in - reactor conditions such as catalyst formulation) and the feed or gaseous mixture on which the reaction was conducted, and can be substantially or all CO 2 and water. In a representative embodiment, CO 2 and water. 2is generally present in the syngas product at a concentration of less than about 45 mol% (e.g., from about 5 mol% to about 45 mol%), and generally 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 generally 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 syngas product. For example, in some cases C 1 -C 3 may contain only hydrocarbons C 1 -C 4 The total amount of hydrocarbons (e.g., the total amount of methane, ethane, propane, and butane) may be present at a concentration of less than about 5 mol%, and generally less than about 2 mol%.

[0044] The following examples are presented as representative of the invention. Such examples should not be construed as limiting the scope of the invention, and other equivalent embodiments will be apparent in view of the present disclosure and the claims.

Examples

[0045] Pilot plant scale experiments were conducted in which a gaseous mixture was continuously fed to a reactor containing catalyst particles having a composition of 1 wt% Pt and 1 wt% Rh on a cerium oxide support. The CO 2 -steam reforming performance of the system was tested at a WHSV of 0.7 hr -1 , conditions of 760 °C (1400 °F), and a gauge pressure range of 124 kPa (18 psig) to 172 kPa (25 psig). The two gaseous mixtures tested were (1) a composition that simulates a product obtained from a combination of biomass hydrothermal decomposition and hydroconversion, containing methane, ethane, propane, and CO 2 , and further H 2 O (a "renewable type"), and (2) a high level of CO 2was a common natural gas composition (a "natural gas type") having. Such a gaseous mixture (combined feed) and a syngas product obtained from such a feed are summarized in Table 1 below.

Table 1

[0046] From these results, it has a H 2 :CO molar ratio of approximately 2:1, and thus a syngas product suitable for subsequent direct processing can be provided by the Fischer-Tropsch reaction or at least without pre-adjusting (upstream) this ratio. It can be seen that a CO 2 -steam reforming catalyst and process can provide. Such favorable results were obtained only at a reaction temperature of 760 °C (1400 °F), but lower temperatures such as 704 °C (1300 °F) are also possible considering the high activity of the catalyst. The low operating temperature directionally reduces the rate of side reactions that form 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. In particular, this figure illustrates the ability to achieve a methane conversion greater than 85% at 704 °C (1300 °F) and a methane conversion greater than 95% at 760 °C (1400 °F). Figure 3 illustrates how the H 2 O:CO 2 molar ratio of the gaseous mixture affects the H 2 :CO molar ratio of the syngas product at both temperatures of 704 °C (1300 °F) and 760 °C (1400 °F). Considering the possibility of establishing the relationship between such parameters for a given feed, catalyst, and set of operating conditions, the gaseous mixture composition can serve as a convenient reference for achieving the desired syngas product composition.

Example

[0047] The general natural gas composition described in Example 1 was used with the CO also described in this example 2- Additional experiments were conducted on steam reforming. However, in this case, H was added to the gaseous mixture or combined feed at a concentration of 800 mol-ppm. 2 Despite the high level of sulfur contamination, it was found that the offset in methane conversion was easily recovered by raising the catalyst bed temperature from 760 °C (1400 °F) to approximately 788 °C (1450 °F). Furthermore, the catalyst unexpectedly showed long-term stability over 400 operating hours (on-stream hours (hr)) at this temperature, WHSV, and pressure as described above for Example 1. This stability achieved despite the significant sulfur concentration was unexpected considering the sulfur sensitivity of conventional catalysts used in steam methane reforming.

Example

[0048] A gaseous mixture described as a “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 the system performance for CO steam reforming. In the long-term stability test, it was revealed that the composition of the syngas product obtained was stable even during 500 hours of operation under such constant conditions, demonstrating that there was basically no deactivation of the reforming catalyst over the long-term operation period. Figure 4 illustrates the stable syngas product composition with high methane conversion obtained over this operation period. Figure 5 illustrates the stable H / CO molar ratio of the syngas product obtained, and this molar ratio was approximately 2, which was thus optimal for use in downstream FT synthesis reactions for producing liquid hydrocarbons. 2 - For evaluating the system performance for steam reforming, tests were conducted using the catalyst and conditions described in Example 1. In the long-term stability test, it became clear that the composition of the syngas product obtained was stable even during 500 hours of operation under such constant conditions, demonstrating that there was basically no deactivation of the reforming catalyst over the long-term operation period. Figure 4 illustrates the stable syngas product composition with high methane conversion obtained over this operation period. Figure 5 illustrates the stable H 2 / CO molar ratio of the syngas product obtained, and this molar ratio was approximately 2, which was thus optimal for use in downstream FT synthesis reactions for producing liquid hydrocarbons.

[0049] Overall, aspects of the present invention are for achieving high conversion of methane and / or other hydrocarbon(s) and for producing a syngas product having the desired characteristics including the H 2 :CO molar ratio as described herein, for dry reforming or CO 2-Regarding the use of steam reforming. A further aspect is in the case of feeds comprising sulfur-containing contaminants and / or reactive compounds such as aromatic hydrocarbons and / or olefinic hydrocarbons, even in the presence of both CO 2 or CO 2 and H 2 O, for such reforming processes using an active catalyst having the ability to convert methane and / or other hydrocarbons, with little coke deposition and high catalyst stability, such contaminants and compounds being associated with rapid deactivation in conventional catalyst systems. Still further aspects relate to reforming processes that also provide a direct approach for direct use in further processing stages such as Fischer-Tropsch synthesis for the production of liquid (C 4 + ) hydrocarbons and / or alcohols, synthesis of alcohols by fermentation, or hydrogen production. Advantageously, the process can utilize conventional CO 2 present in both renewable and non-renewable methane sources, preferably without removing this CO 2 and / or can reduce the level of water utilization compared to conventional steam reforming of methane. Additionally, the sulfur tolerance of the catalyst is further demonstrated by the activity to convert sulfur-containing contaminants, using a single acid gas removal step if necessary, to SO 2 and H 2 S, which are more easily managed downstream. Those skilled in the art having the knowledge obtained from this disclosure will recognize that various changes can be made to such processes without departing from the scope of this disclosure in realizing these and other benefits. From such circumstances, it should be understood that the features of the disclosure are subject to variation and / or substitution without departing from the scope of the disclosure. The specific embodiments illustrated and described in this disclosure are described solely for purposes of explanation and are not intended to limit the invention presented in the appended claims.

Claims

【Request 1】 A process for producing a synthesis gas product, comprising: ２ with a catalyst comprising a precious metal on a solid support comprising cerium oxide.

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