RU2777599C2 - Catalysts based on noble metals and methods for reforming methane and other hydrocarbons - Google Patents

Abstract

FIELD: chemistry.

SUBSTANCE: present invention can be used at the first stage of conversion of methane into fuel, followed by the second stage of conversion, Fischer-Tropsch product synthesis. Options of a method for the production of products of synthesis gas containing H₂ and CO are claimed. One of options of the method for the production of synthesis gas consists in the supply of a gaseous mixture to a steam reforming reactor with CO₂, which contains a catalyst on a solid carrier. The gaseous mixture contains methane, CO₂ and H₂O. The catalyst contains at least 2 noble metals selected from a group of Pt, Rh, Ru, Pd, Ag, Os, Ir, Au and contains less than 0.05% of metals different from the specified two noble metals and metals of the solid carrier. The solid carrier contains at least 80% of cerium oxide. In the reactor, at least 80% of methane is converted by the reaction with CO₂ and H₂O as oxidizers.

EFFECT: reduction in rates of carbon formation and catalyst deactivation because of coking, reduction in significant capital and operational costs for the removal of sulfur and other poisons from used catalysts.

25 cl, 5 dwg, 1 tbl, 3 ex

Description

STATEMENT REGARDING RESEARCH OR DEVELOPMENT FINANCED FROM THE FEDERAL BUDGET

This invention was carried out with government support under the decision of the US Department of Energy DE-EE-0007009. The government has certain rights to this invention.

FIELD OF TECHNOLOGY TO WHICH THE INVENTION RELATES

Aspects of the invention relate to catalysts and processes for the conversion of methane and/or other hydrocarbons, in particular to the reaction of such hydrocarbon(s) with CO ₂ as an oxidant, or with CO ₂ and H ₂ O as a combination of oxidants, in the presence of a catalyst containing noble metal, to produce synthesis gas containing H ₂ and CO.

DESCRIPTION OF THE PRIOR ART

The continuous search for alternatives to crude oil for the production of hydrocarbon fuels is increasingly driven by a number of factors. These include dwindling oil inventories, higher projected energy demand, and increased concerns about greenhouse gas (GHG) emissions from non-renewable carbon sources. Methane has become the focus of attention among the ways to obtain liquid hydrocarbons, given its abundance in natural gas reserves, as well as in gas streams obtained from biological sources (biogas). The main commercial process for converting methane to fuel includes: a first conversion stage to produce synthesis gas (syngas) followed by a second conversion stage, Fischer-Tropsch (FT) product synthesis, downstream. In this second step, the synthesis gas containing a mixture of hydrogen (H ₂ ) and carbon monoxide (CO) undergoes sequential splitting of CO bonds and formation of CC bonds to include hydrogen. This mechanism provides for the formation of hydrocarbons, in particular straight chain alkanes, having a molecular weight distribution that can be controlled to some extent by changing the FT reaction modes and catalyst properties. Such properties include pore size and other characteristics of the carrier material. In other aspects, the choice of catalyst can influence the yield of the FT product. For example, iron-based FT catalysts tend to produce more oxidized compounds, while ruthenium, as the active metal, tends to produce paraffins exclusively.

With respect to the first conversion stage, upstream of the FT, known methods for producing synthesis gas from methane include: reforming with partial oxidation; and autothermal reforming (ATR), based on the exothermic oxidation of methane with oxygen. Steam methane reforming (SMR), in contrast, uses steam as the oxidant, so the thermodynamics are quite different, not only because the production of steam itself requires energy, but also because the reactions involving methane and water are endothermic. More recently it has been proposed to use carbon dioxide (CO ₂ ) as the oxidizer for methane, so that the required synthesis gas is produced by the reaction of carbon in its most oxidized form with carbon in its most reduced form according to:

CH ₄ +CO ₂ → 2CO + 2H ₂ .

This reaction has been called "dry reforming" of methane, and because it is highly endothermic, the thermodynamics of dry methane reforming is less efficient than ATR or even SMR. However, a stoichiometric consumption of one mole of carbon dioxide per mole of methane can reduce the overall carbon footprint of liquid fuel production, resulting in a greener consumption of methane. This CO ₂ consumption rate per mole of feed increases in the case of reforming higher hydrocarbons ( eg C ₂ -C ₆ paraffins), which is desirable, for example, if the goal is to produce hydrogen ( eg for refineries). In any case, the thermodynamic barrier, however, remains a major problem and is due to the fact that CO ₂ is fully oxidizable and very stable, so that significant energy is required to activate it as an oxidizing agent. In view of this, a number of catalytic systems have been studied to overcome the activation energy barrier in dry methane reforming, and the results have been summarized, for example, in a review by Lavoie (Frontiers in Chemistry (Nov. 2014), Vol. 2 (81): 1-17), in in which heterogeneous catalytic systems are noted as the most popular in terms of catalytic approaches for carrying out this reaction.

Since nickel-based catalysts have been shown to be effective in reducing activation energy for the above dry reforming reaction, the high rate of carbon deposition (coking) with these catalysts was also noted in the Lavoie review. The undesired conversion of methane to elemental carbon can take place during methane cracking (CH ₄ → C+2H ₂ ) or the Boudouis reaction (2CO → C+CO ₂ ) at reaction temperatures commonly used for dry methane reforming. Although this reaction has been studied as a promising way to produce synthesis gas, however, the commercial implementation of this technology, unlike other reforming technologies such as ATR and SMR, remains unrealized. This is largely due to the high rates of carbon formation and the corresponding deactivation of the catalysts due to coking that occurs with dry reforming catalyst systems that operate under the modes proposed to date. In conclusion, while other conventional reforming technologies have proven to be economically viable, it is well known that these processes, and SMR in particular, require significant capital and operating costs to remove sulfur and other poisons from the catalysts used. Otherwise, commercially acceptable operating times cannot be achieved for a given catalyst loading. Satisfactory solutions to these and other problems associated with conventional reforming of hydrocarbons to produce synthesis gas and/or hydrogen have been found but not implemented.

SUMMARY OF THE INVENTION

Aspects of the invention relate to the discovery of catalysts and methods for converting methane and/or other hydrocarbons to synthesis gas ( ie, a gaseous mixture containing H ₂ and CO) by reacting at least a portion of such hydrocarbons with CO ₂ . Preferably, according to the CO ₂ steam reforming reaction, at least a second portion of the hydrocarbon(s) ( e.g. containing the same hydrocarbon(s) as in the first portion) is reacted with H ₂ O (steam), thereby improving overall thermodynamics of the process, in terms of reduced endothermicity (ΔH) and required energy input, compared to "clean" dry reforming, which does not have H ₂ O. Typical catalysts are generally high activity and thus can achieve significant conversion levels hydrocarbons ( eg methane) at temperatures below those normally used for dry reforming. These high levels of activity, optionally combined with the use of H ₂ O to provide at least a portion of the oxidizer, contribute to an overall operating environment that reduces coke formation and significantly increases catalyst life.

Other important advantages are the sulfur tolerance of the catalysts described herein, whereby, according to preferred embodiments, no pretreatment of methane-containing feedstock ( e.g., natural gas) or other hydrocarbon-containing feedstock is required to reduce the concentration of H ₂ S and other sulfur-containing pollutants, or at least not as stringent as in traditional reforming technologies. Also, to the extent that downstream sulfur removal is necessary, for example prior to the FT conversion step, it can be greatly simplified given that all or at least a substantial portion of the sulfur-containing contaminants other than H ₂ S , such as mercaptans, can be oxidized to SO ₂ in a dry reforming or steam reforming reaction with CO ₂ as described here, making standard acid gas treatment ( e.g. scrubbing) a suitable and relatively simple option for such sulfur removal downstream.

In general, the improvements associated with the processes and catalysts described herein are of commercial importance in terms of performing dry reforming or other CO ₂ processes and steam reforming ( i.e., “CO ₂ steam reforming”) as a cost-effective alternative. compared to traditional technologies such as autothermal reforming (ATR) and steam reforming (SMR) of methane. Moreover, synthesis gas according to these processes can be produced in a suitable H ₂ :CO molar ratio ( e.g., about 2:1) for further downstream treatment in a Fischer-Tropsch (FT) reaction or at least at least with a molar ratio that can be easily adjusted to obtain such suitable values.

These and other embodiments, aspects and advantages related to the present invention will be apparent from the following detailed description.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the embodiments of the present invention and its advantages can be obtained by referring to the following description, taking into account the accompanying drawings, in which the same reference numbers are used to identify the same features.

On FIG. 1A and 1B are block diagrams illustrating typical CO ₂ dry and steam reforming processes as described herein.

On FIG. 2 is a graph of the high activity of the catalysts, in terms of methane conversion, as described here.

On FIG. 3 is a graph of the H ₂ :CO molar ratio of synthesis gas and the H ₂ O/CO ₂ molar ratio of the gaseous mixture in the (combined) reactor feed at various reaction temperatures in typical CO ₂ steam reforming processes.

On FIG. 4 and 5 show the long term operational stability of the catalysts as described herein in a CO ₂ steam reforming process over a long period of operation.

The drawings should be read in such a way as to represent the methods and certain related results, parameters and/or principles. For a better understanding, in FIG. 1A and 1B are simplified perspective views, noting that the drawings and their elements are not necessarily drawn to scale. Valves, instrumentation, and other equipment and assemblies not essential to an understanding of the various aspects of the invention are not shown. For those skilled in the art to which this invention pertains, and having knowledge of the present disclosure, processes for converting hydrocarbons such as methane by dry reforming or steam reforming with CO ₂ will be obvious, which will have a configuration and elements determined in part by their particular use.

DETAILED DESCRIPTION OF THE INVENTION

The expressions "wt. %" and "mol %" are used here to refer to mass percent and mole percent, respectively. Expressions "wt-ppm" and "mol-ppm" denote mass and molar parts per million, respectively. For ideal gases "mol%" and "mol-h / ppm" equal to percent by volume and parts per million by volume, respectively.

The term "gaseous mixture" refers to a mixture containing at least a hydrocarbon, such as methane, and also containing CO ₂ as an oxidant, which is dry reformed or steam reformed with CO ₂ (if water is also present in the gaseous mixture) in during the reaction with the catalyst, as described here. The term "gaseous mixture" generally refers to such a mixture that is wholly or at least predominantly in the gas phase under the conditions used for dry reforming or CO ₂ steam reforming, including the temperatures and pressures described herein as being appropriate. for these reactions. The term "gaseous mixture" does not exclude the presence in this mixture of compounds which, like water, are liquid at ambient temperature and pressure. Such compounds may include hydrocarbons found in liquid fuels, including naphtha and jet fuel, such as C ₆ -C ₁₆ hydrocarbons.

Embodiments of the invention describe a process for producing synthesis gas (syngas), a process comprising reacting a gaseous mixture containing (i) methane and/or other hydrocarbon(s) ( e.g., any of 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 H ₁₀ , higher molecular weight hydrocarbons and mixtures thereof) and (ii) with CO ₂ with a catalyst containing at least one ( eg, two or more than two) noble metal on a solid support containing cerium oxide. It is possible that CO ₂ alone can serve as an oxidizer for methane and/or other hydrocarbons to CO and H ₂ in accordance with the dry reforming reaction of such hydrocarbons, which, for example, in the case of alkanes, can be expressed as:

C _n H _2n+2 + nCO ₂ → 2nCO + (n+1)H ₂ .

In preferred embodiments, the combination of CO ₂ and H ₂ O may serve as the oxidizing agent, i.e., in embodiments in which the gaseous mixture additionally contains H ₂ O. The reaction in this case is a “CO ₂ steam reforming” reaction, which also includes steam reforming as a process for producing syngas from methane and/or other hydrocarbons, which, for example, in the case of alkanes, can be expressed as:

C _n H _2n+2 + nH ₂ O → nCO + (2n+1)H ₂ .

Considering that the theoretical H ₂ :CO molar ratio of synthesis gas produced from dry methane reforming is 1, adding steam reforming to CO ₂ steam reforming makes it possible to increase this molar ratio to values more suitable for Fischer synthesis -Tropsch downstream and production of liquid hydrocarbons, according to:

(2n+1) H ₂ +n CO → C _n H _2n+2 +n H ₂ O.

From this, it can be observed that C ₄ ⁺ hydrocarbons, for example C ₄ -C ₁₂ hydrocarbons, which are required as liquid fuels or components of liquid fuels, are ideally formed at H ₂ :CO molar ratios approaching 2. It is important to note that that the use of steam (H ₂ O) as an oxidizer in combination with CO ₂ provides a convenient "control lever" or control variable for adjusting the H ₂ :CO molar ratio of synthesis gas over a wide range of CO ₂ steam reforming regimes. In fact, for any given set of such regimes ( e.g., regimes within the reactor, in particular temperature, pressure, hourly space velocity of the feedstock, and reforming catalyst composition) under which combined reactions with CO ₂ and steam reforming are carried out, a relationship can be established between the molar the H ₂ O:CO ₂ ratio of the gaseous mixture ( eg combined feedstock in the reactor) and the H ₂ :CO molar ratio of the synthesis gas ( eg effluent). Given that dry reforming and steam reforming of hydrocarbons other than methane produce H ₂ and CO at different molar ratios, the same shifts or adjustments in product yield can be achieved by varying the relative amounts of H ₂ O and CO ₂ oxidizing agents. in a gaseous mixture which is steam reformed with CO ₂ . Accordingly, embodiments of the invention describe a CO ₂ steam reforming process comprising determining the H ₂ :CO molar ratio of the synthesis gas and, based on the H ₂ :CO molar ratio, adjusting the H ₂ O:CO ₂ molar ratio of the gaseous mixture relative to a given molar ratio H ₂ :CO synthesis gas, for example, a given H ₂ :CO molar ratio of 2:1, or otherwise a given H ₂ :CO molar ratio, typically from about 1.5:1 to about 2.5:1, typically about 1.5:1 to about 2.3:1, and often about 1.8:1 to about 2.2:1.

In particular, the H ₂ O:CO ₂ molar ratio of the gaseous mixture can be increased to achieve a given H ₂ :CO molar ratio, an observed synthesis gas H ₂ :CO molar ratio that is below a given value. Conversely, the H ₂ O:CO ₂ molar ratio in the gaseous mixture can be reduced to achieve a given H ₂ :CO molar ratio of the observed synthesis gas H ₂ :CO molar ratio that is above a given value. Any such adjustments to the H ₂ O:CO ₂ molar ratio of the gaseous mixture can be made, for example, by adjusting the flow rate of one or more components of the gaseous mixture ( e.g. combined feed), in particular one or more methane-containing feeds (or hydrocarbon-containing feeds in general) , an oxidizer containing CO ₂ and an oxidizer containing H ₂ O, relative to the consumption of one or more other such components. In accordance with a specific example, the molar ratio of H ₂ O:CO _{2 of} the combined feed in the reactor can be increased or decreased by increasing or decreasing, respectively, the flow rate of steam (as an oxidant containing H ₂ O), thereby resulting in a corresponding increase or decrease molar ratio of H ₂ O:CO ₂ in the gaseous mixture.

In addition to making it possible to control the H ₂ :CO molar ratio of the synthesis gas within the desired range, the use of steam (H ₂ O) as an oxidant in combination with CO ₂ also reduces the rate of carbon (coke) formation compared to pure dry reforming. thereby extending the life of the catalysts as described here. Accordingly, further embodiments of the invention describe a CO ₂ steam reforming process in which the rate of carbon formation ( e.g., using appropriate ratios or concentrations/partial pressures of oxidants containing CO ₂ and H ₂ O in combination with a catalyst as described herein) less than the carbon generation rate of the base process ( i.e. the base dry reforming process) in which all parameters are kept the same except for the replacement of H ₂ O in the gaseous mixture ( e.g. combined feed in the reactor) by an equimolar amount of oxygen in the form of CO ₂ ( i.e., replacing moles of H ₂ O with ½ moles of CO ₂ ). In combination with this comparatively lower carbon production compared to the base process, the synthesis gas can have an H ₂ /CO molar ratio as described herein ( e.g., about 1.5:1 to about 2.3:1 ).

Catalysts as described herein further exhibit a high degree of sulfur tolerance, which is particularly advantageous, for example, in the case of using methane-containing feedstock contained or derived from natural gas, which, depending on its source, may contain a significant concentration of H ₂ S ( eg, a few weight percent by volume or more). As such, conventional methane steam reforming (SMR) processes require pretreatment to reduce the total sulfur content of the feedstock, typically to less than 1 mol ppm, to protect the catalyst from sulfur poisoning. In contrast, in accordance with exemplary embodiments of the present invention, the gaseous mixture or any of its components, in particular the hydrocarbonaceous feedstock, is not or otherwise not subjected to a pre-treatment step to remove sulfur. Such embodiments provide significant economic benefits over known methods with stringent desulfurization requirements and associated costs to achieve acceptable catalyst life. In contrast to such prior art processes, the gaseous mixture in a CO ₂ dry reforming or steam reforming process as described herein may contain sulfur, generally at any concentration, depending on the source of the hydrocarbon feedstock, such as natural gas, not pre-treated to remove sulfur, and also taking into account the potential dilution of sulfur when combined with other components of the gaseous mixture ( eg CO ₂ ) having a lower sulfur concentration. For example, the gaseous mixture may typically contain at least about 1 mol ppm ( eg, from about 1 mol-ppm to about 10 mol-%) of the total sulfur content ( eg, as H ₂ S and/or other sulfur-containing pollutants). The gaseous mixture may typically contain at least about 10 mole ppm. ( e.g., from about 10 mol-hours/million to about 1 mol-%) and often at least about 100 mol-hours/million. ( eg, from about 100 mol-hours/million to about 1000 mol-hours/million) of the total sulfur content. For example, in accordance with specific embodiments, the range is from about 500 mol-hours/million. up to about 1000 mol-h/million. from the total sulfur content, as a rule, has no adverse effect, or at least has a negligible effect on the stability of the reforming catalysts, as described here.

With regard to the sulfur tolerance of the catalysts described here, further aspects of the invention relate to the discovery that higher levels (concentrations) of sulfur in the gaseous mixture can be compensated by increasing the reaction temperature, i.e., the temperature of the catalyst bed located in the reactor, as described here . It has been found that elevated sulfur concentrations affect the activity of the catalyst, which is determined by the decrease in the conversion of methane and/or other hydrocarbons in the gaseous mixture, with all other operating parameters unchanged. However, the desired conversion level can be restored by increasing the reaction temperature. For example, under certain operating conditions, a temperature increase of 28 °C (50 °F) may be sufficient to restore the activity of the catalyst, which corresponds to an H ₂ S concentration of 800 mol-ppm, in the gaseous mixture relative to the activity in the absence sulfur in a gaseous mixture. Accordingly, embodiments of the invention describe a dry reforming process or a CO ₂ steam reforming process as described herein, including determining the conversion level of methane and/or other hydrocarbon(s) ( e.g., the conversion level of combined C ₁ -C ₄ hydrocarbons or combined C ₁ -C ₃ hydrocarbons) or otherwise determines the level of sulfur content (for example, the level of H ₂ S) in the gaseous mixture or synthesis gas and, based on the level of conversion or level of sulfur content, the reaction temperature is adjusted relative to the desired level of methane conversion and/ or other hydrocarbons, e.g., a conversion target of at least about 75% ( e.g., any particular conversion rate of from about 75% to about 100%), e.g., a conversion target of at least at least about 85% ( eg, any specific conversion rate between about 85% and about 99%).

However, it is important that such a decrease in the activity of the catalysts described herein, accompanying an increase in the sulfur content in the gaseous mixture, is not further accompanied by any noticeable loss in catalyst stability. That is, raising the reactor temperature as described herein to lower high sulfur levels does not significantly affect the ability of the catalyst to have stable performance over a long period of operation. This finding is contrary to expectations based on conventional reforming technologies, in which the presence of even small amounts ( eg, at mol-ppm levels) of sulfur in the feed must be excluded to avoid deactivation and costly premature replacement of the catalyst. The characteristic sulfur resistance or stable activity in the presence of sulfur containing impurities of the catalysts as described herein can be determined according to a standard test in which a small sample of catalyst weighing 5-100 grams is loaded into a fixed bed reactor and reacted with a mixture of feedstock, containing 30 mol% methane, 30 mol% CO ₂ and 30 mol% H ₂ O, to which H ₂ S is added in an amount of 800 mol-h / million. In this standard test, at a feedstock hourly space velocity (WHSV) of 0.7 h ^-1 , a catalyst bed temperature of 788 °C (1450 °F) and a reactor pressure of 138 kPa (20 psi) inch) methane conversion is maintained at least 85%, preferably at least 95% at constant catalyst bed temperature for at least 50 hours of operation and more typically for at least 100 hours work or even for at least 400 hours of work.

The stability or "resistance" of the catalysts described herein is further manifested by a high resistance to deactivation in the presence of other compounds in a gaseous mixture comprising higher molecular weight hydrocarbons, for example, reactive aromatic hydrocarbons and/or olefinic hydrocarbons, which are generally considered capable of carry out deactivation of the catalyst by coking. For example, the gaseous mixture may contain aromatic and olefinic hydrocarbons in a total amount of at least about 1 mol% ( e.g., from about 1 mol% to about 25 mol%), in particular at least about 3 mol % ( eg, from about 3 mol% to about 20 mol%) or, more specifically, at least about 5 mol% ( eg, from about 5 mol% to about 15 mol%). At these levels of aromatics and/or olefins, the stability of the catalyst will be in accordance with the same reactivity stability test as defined above for sulfur tolerance, except for a feed mixture containing these concentrations of aromatics and/or olefins compared to H ₂ S. This stability of the catalysts, as described herein, with respect to sulfur and reactive hydrocarbons, allows for the reforming of widespread hydrocarbon feedstocks, including various fractions ( eg, naphtha and jet fuel) obtained from the processing of crude oil, as described in more detail. below.

More generally, the gaseous mixture, and in particular the hydrocarbon-containing feed component of this mixture, may contain, in addition to methane, other hydrocarbons, in particular C ₂ , C ₃ hydrocarbons and/or C ₄ hydrocarbons ( e.g. ethane, propane, propylene, butane and/or butenes) that may be present in natural gas and/or other sources of methane). In addition, the catalysts as described herein can be used for dry reforming or steam reforming with CO ₂ predominantly or only higher molecular weight hydrocarbons, such as hydrocarbons in a gaseous mixture containing or optionally consisting of one or more compounds selected from the group consisting of C ₄ hydrocarbon, C ₅ hydrocarbon, C ₆ hydrocarbon, C ₇ hydrocarbon, C ₈ hydrocarbon, C ₉ hydrocarbon, C ₁₀ hydrocarbon, C ₁₁ hydrocarbon, C ₁₂ hydrocarbon, C ₁₃ hydrocarbon, C ₁₄ hydrocarbon, C ₁₅ hydrocarbon, C ₁₆ hydrocarbon, C ₁₇ hydrocarbon, C ₁₈ hydrocarbon and mixtures thereof. For example, the hydrocarbons in the gaseous mixture may contain or consist of C ₄ -C ₈ or C ₄ -C ₆ hydrocarbons in the case of dry reforming or CO ₂ steam reforming of naphtha boiling range hydrocarbons (naphtha reforming). As another example, the hydrocarbons in the gaseous mixture may contain or consist of C ₈ -C ₁₈ or C ₈ -C ₁₄ hydrocarbons in the case of dry reforming or CO ₂ steam reforming of hydrocarbons with a jet fuel boiling range (jet fuel reforming). Such naphtha boiling range hydrocarbons and jet fuel boiling range fractions are typically produced as crude oil refineries and, as such, can be a source of sulfur contaminants in the gaseous mixture. In typical embodiments, the gaseous mixture may contain methane and/or any of the hydrocarbons described herein in a total amount of from about 5 mol% to about 85 mol%, typically from about 10 mol% to about 65 mol%, and often from about 20 mol% to about 45 mol%. The gaseous mixture may further contain CO ₂ in an amount typically from about 8 mol% to about 90 mol%, typically from about 15 mol% to about 75 mol%, and often from about 20 mol% to about 50 mol%. In the case of a steam reforming reaction with CO ₂ , the gaseous mixture may contain H ₂ O in an amount typically from about 15 mol% to about 70 mol%, typically from about 20 mol% to about 60 mol%, and often from about 25 mol% up to about 55 mol%. The composition of the gaseous mixture may include pollutants, for example, H ₂ S and/or other sulfur-containing pollutants, as described above.

In the case of using gaseous mixtures containing methane and/or light hydrocarbons ( e.g. C ₂ -C ₃ or C ₂ -C ₄ hydrocarbons), dry reformed or steam reformed synthesis gas with CO ₂ can be used with a suitable molar ratio of H ₂ :CO in downstream production of liquid hydrocarbon fuels via Fischer-Tropsch synthesis as described above. The synthesis gas may alternatively be used for other downstream applications associated with conventional methane steam reforming (SMR). For example, Tarun (International Journal of Greenhouse Gas Control I (2007): 55-61) describes a conventional hydrogen production process involving SMR. If dry reforming or CO ₂ steam reforming, as described herein, is used in hydrogen production, in accordance with embodiments of the invention, then typical methods may further include the steps of (i) using synthesis gas in one or more water gas shift steps. (WGS) to increase its hydrogen content and/or (ii) separate the effluent from the WGS stage(s), or otherwise separate the synthesis gas product without the intermediate WGS stage(s), as appropriate ( e.g. by adsorption pressure swing (PSA) or membrane separation) to produce a hydrogen-rich product stream and a hydrogen-depleted tail gas stream PSA. The hydrogen-enriched product stream can then be used in a conventional processing process, for example a hydrotreatment process ( eg hydrodesulfurization, hydrocracking, hydroisomerization, etc.). The hydrogen-depleted tail gas stream PSA can then be separated to recover hydrogen and/or used as a combustion fuel to meet at least some of the heating requirements of the CO ₂ dry reforming or steam reforming reaction. In other embodiments, the PSA tail gas containing CO and H ₂ may be passed to the biological fermentation stage to produce fermentation products, eg alcohols ( eg, ethanol). The gaseous effluent from the fermentation step may then be separated to recover hydrogen and/or used as a combustion fuel as described above. With respect to conventional hydrogen production, the further integration of the biological fermentation step is described in, for example, US Pat. No. 9,605,286, US Pat. No. 9,145,300, US Pat. As an alternative to integration into a hydrogen production process, dry reforming or steam reforming with CO ₂ as described here can be used to produce synthesis gas that is used directly in the production of downstream fermentation products using suitable carboxydotrophic bacteria ( e.g. species Clostridium autoethanogenum or Clostridium ljungdahlii ). In any of these cases, i.e. with or without such integration, the microorganisms used for fermentation may be sulfur tolerant or even require sulfur in the cell culture medium, so that sulfur tolerance for catalysts such as described herein can be particularly advantageous over conventional reforming catalysts in terms of compatibility and cost savings associated with eliminating or at least reducing sulfur removal requirements in upstream devices.

Thus, aspects of the invention relate to CO ₂ dry reforming and steam reforming processes to produce synthesis gas ( i.e., containing both H ₂ and CO, and optionally other gases such as unreacted CO ₂ , H ₂ O and/or hydrocarbons). In representative embodiments, the gaseous mixture containing methane and/or other hydrocarbons may be fed intermittently, but is preferably fed as a continuous stream to the dry reformer ( i.e., in the case of a feed or gaseous mixture that additionally includes CO ₂ but not water) or a CO ₂ steam reformer ( i.e. in the case of a feedstock or a gaseous mixture additionally containing both CO ₂ and water). Synthesis gas, in turn, can be taken off intermittently (if the gaseous mixture is fed intermittently), but is preferably taken as a continuous stream (if the gaseous mixture is fed as a continuous stream) from the reactor.

In addition to H ₂ , CO, and optionally other gases, water (H ₂ O) may also be present in the synthesis gas, although at least some of the water that is present as vapor can be easily separated by cooling/ condensation, for example, in devices upstream of the Fischer-Tropsch synthesis reactor (FT reactor) used to convert synthesis gas to liquid hydrocarbons. Neither the water nor the CO ₂ in the synthesis gas affects its H ₂ :CO molar ratio, which, as described above, is an important parameter in determining the suitability of the synthesis gas as a direct feed stream to the FT reactor.

In typical processes, a gaseous mixture containing methane and/or other light hydrocarbons ( eg ethane, ethylene, propane and/or propylene) and CO ₂ and optionally H ₂ O is reacted with a catalyst having activity to effect reforming such hydrocarbons. In particular, such hydrocarbons, for example most of such hydrocarbons, may be reformed (i) by oxidizing them with only some or all of CO ₂ , in accordance with the dry reforming process, or (ii) by oxidizing them with some, and all of the CO ₂ and some of the H ₂ O (if any), according to the CO ₂ steam reforming process.

As described above, aspects of the invention relate to the discovery of reforming catalysts for such CO ₂ dry reforming and steam reforming processes, showing important advantages, especially in terms of sulfur tolerance and/or reduced carbon formation rate (coking), compared to conventional catalysts. reforming. These properties, in turn, reduce the rate of catalyst deactivation through poisoning and/or coking mechanisms that chemically and/or physically block the active sites of the catalyst. Further improvement in catalyst stability is a result, at least in part, of the high activity of the catalysts described here, which is necessary to reduce the activation energy, as a significant limiting factor associated with the use of CO ₂ as an oxidant of methane and/or other hydrocarbon(s), as described above. This high activity is exhibited at lower operating temperatures (in the reactor or in the catalyst bed), which additionally help to reduce the rate of carbon deposition (coking) on the catalyst surface and increase the period of stable operation. According to specific embodiments, processes using the catalysts described herein can maintain stable operating parameters as described herein, for example, in terms of: hydrocarbon conversion ( e.g., conversion of methane and/or other hydrocarbon(s), at least about 85%); and/or a molar ratio of H ₂ /CO ( eg, from about 1.5:1 to about 2.3:1) of synthesis gas; for at least about 100, at least about 300, or even at least about 500 hours of continuous or possibly intermittent operation. This may be a period of operation during which (i) the catalyst is not subject to regeneration, for example, in accordance with the reforming process using the catalyst as a fixed bed in the reactor and/or; (ii) the temperature of the reactor or catalyst bed does not rise above a threshold temperature difference from the start of the time period to the end of the time period, which 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).

Typical reforming catalysts useful for promoting the reaction of methane and/or other hydrocarbons with CO ₂ and optionally H ₂ O contain a noble metal and optionally two or more noble metals on a solid support. The phrase "on a solid support" is intended to describe catalysts in which the active metal(s) is on the surface of the support and/or in the porous internal structure of the support. The solid support preferably contains a metal oxide, with cerium oxide being of particular interest. Cerium oxide may be present in an amount of at least about 80 wt. %, preferably at least about 90 wt. %, based on the weight of the solid support ( eg , relative to the total amount of metal oxide(s) in the solid support). The solid support may contain all or substantially all of the cerium oxide ( eg, greater than about 95% by weight). Other metal oxides, such as alumina, silicon oxide, titanium oxide, zirconium oxide, magnesium oxide, strontium oxide , etc. , may also be present in the solid support in minor amounts, such as less than about 50 wt. , less than about 30 wt. % or less than about 10 wt. % of solid support. In other embodiments, the solid support may contain other metal oxides alone or in combination with a minor portion ( eg, less than about 50% by weight or less than about 30% by weight) of cerium oxide.

By noble metals is meant a class of metallic elements that are resistant to oxidation. In typical embodiments, the noble metal, such as at least two noble metals, of the catalyst may be selected from the group consisting of platinum (Pt), rhodium (Rh), ruthenium (Ru), palladium (Pd), silver (Ag ), osmium (Os), iridium (Ir), and gold (Au), with the term "consisting of" being used simply to refer to the members of the group according to the particular embodiment from which the noble metal(s) are selected, but not to preclude the addition of other noble metals and/or other metals in general. Accordingly, the noble metal catalyst includes a catalyst containing at least two noble metals, as well as a catalyst containing at least three noble metals, and likewise a catalyst containing two noble metals and a third non-noble metal, in particular a metal promoter ( eg transition metal). In accordance with preferred embodiments, the noble metal is present in an amount or, in accordance with another option, each of at least two of these noble metals is independently present in an amount of from about 0.05 wt. % to about 5 wt. %, from about 0.3 wt. % to about 3 wt.% or from about 0.5 wt. % to about 2 wt. % based on the weight of the catalyst. For example, a typical catalyst contains the two noble metals Pt and Rh, and Pt and Rh may independently be present in any of these ranges ( eg, from about 0.05 wt.% to about 5 wt.%). That is, either Pt may be present in such an amount, Rh may be present in such an amount, or both Pt and Rh may be present in such amounts.

In typical embodiments, at least two noble metals ( e.g., Pt and Rh) may be essentially the only noble metals present in the catalyst, such that, for example, any other noble metal(s) is/are present in an amount or a combined amount of less than about 0.1 wt. % or less than about 0.05 wt.% based on the weight of the catalyst. In other exemplary embodiments of the invention, at least two noble metals ( e.g. , Pt and Rh) are essentially the only metals present in the catalyst, with the exception of metals present in the solid support ( e.g., such as cerium present in solid support in the form of cerium oxide). For example, any other metal(s), in addition to at least two noble metals and metals of the solid support, may be present in an amount or in a total 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 noble metal(s), may have a metal particle size typically from about 0.3 nanometers (nm) to about 20 nm, typically from about 0.5 nm to about 10 nm and often from about 1 nm to about 5 nm.

The noble metal(s) may be incorporated into the solid support according to known catalyst preparation methods including sublimation, impregnation or dry blending. In the case of impregnation, which is the preferred method, an impregnating solution of a soluble compound of one or more noble metals in a polar (aqueous) or non-polar ( eg, organic) solvent may be reacted with a solid carrier, preferably under an inert gas atmosphere. For example, this reaction can be carried out, preferably with stirring, in an atmosphere of nitrogen, argon and/or helium, or otherwise in a non-inert atmosphere, such as air. The solvent may then be evaporated from the solid carrier, for example by heating, gas flow and/or the use of vacuum, leaving a dried noble metal-impregnated carrier. The noble metal(s) may be impregnated into a solid support, for example, where two noble metals are impregnated simultaneously and both are dissolved in the same impregnation solution, or otherwise impregnated separately using different impregnation solutions and reaction steps. In any case, the noble metal-impregnated support may be subjected to additional preparation steps, such as washing with a solvent to remove excess noble metal(s) and impurities, further drying, calcining , etc. to obtain a catalyst.

The solid support itself can be prepared according to known methods, for example, extrusion to form cylindrical particles (extrudates), or oil dripping, or spray drying to form spherical particles. Regardless of the specific form 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 mass of such noble metal(s) in a given catalyst particle (e.g., any shape, such as cylindrical or spherical), regardless of the particular distribution of precious metals within the particle. In this regard, it should be understood that different methods of preparation may give different types of distribution, for example, deposition of the noble metal (s) mainly on or near the surface of the solid support, or even distribution of the noble metal (s) throughout the solid support. In general, the weight percentages described herein, based on the weight of the solid support, or otherwise based on the weight of the catalyst, may refer to the weight percent in a single catalyst particle, but generally refer to the average weight percent of a large number of catalyst particles, in particular the number of particles in the reactor. , which form the catalyst layer used in the methods described here.

Simplified diagrams of dry reforming processes and optional CO ₂ steam reforming processes 10 are shown in FIG. 1A and 1B. In any of these embodiments, a gaseous mixture 4 containing one or more hydrocarbons ( e.g. methane) and CO ₂ may be inside a reactor 5 made in the form of a tank, which is used to contain the catalyst bed 6, as described above, in reforming modes in which the gaseous mixture 4 and catalyst 6 react. According to the embodiment shown in FIG. 1A, gaseous mixture 4 may be supplied to reactor 5 only from hydrocarbon feedstock 1. For example, a typical hydrocarbon feedstock is a methane feed that is produced by gasification or pyrolysis of biomass, including hydrogasification or hydropyrolysis, and may additionally contain CO ₂ and H ₂ O. Thus, such a hydrocarbon-containing feedstock can itself produce a CO ₂ steam reforming gas mixture 4 in which both CO ₂ and H ₂ O react as methane oxidizers. In other embodiments, gaseous mixture 4 can be obtained by combining hydrocarbon containing feed 1, optionally with an oxidizing agent 2 containing CO ₂ if, for example, hydrocarbon containing feed 1 contains little CO ₂ , for example, in the case of using liquid hydrocarbons, including hydrocarbons with an interval boiling range of naphtha and/or hydrocarbons with a jet fuel boiling range, or in the case of some natural gas.

Alternatively, an oxidant 3 containing H ₂ O ( eg, as steam) can also be combined to form a gaseous mixture 4 containing methane and oxidizers CO ₂ and H ₂ O for steam reforming with CO ₂ . However, H ₂ O may also be present in sufficient quantities in the hydrocarbon feed 1 and/or the CO ₂ containing oxidizer 2 such that a separate H ₂ O oxidizer 3 may not be required. oxidizer 2 containing CO ₂ and oxidizer 3 containing H ₂ O, it becomes apparent that any of these streams can be combined before ( eg, upstream) reactor 5. In accordance with a specific embodiment, in FIG. 1B shows a hydrocarbon feed stream 1 combined optionally with an oxidizer 2 containing CO ₂ and optionally with an oxidizer 3 containing H ₂ O to produce a gaseous mixture 4 both upstream ( e.g. upstream) of reactor 5 and inside this reactor.

As described above, in embodiments in which the gaseous mixture 4 contains one or more hydrocarbons, in particular methane and CO ₂ , but does not contain H ₂ O, this method can be considered a "dry reforming" method, while in the embodiments, in which the gaseous mixture 4 contains hydrocarbon(s)) and CO ₂ , and additionally contains H ₂ O, acting in combination with CO ₂ as oxidizers of the hydrocarbon(s) ( e.g., so that at least the corresponding parts of the oxidant CO ₂ and H ₂ O oxidized the respective portions of the reactant hydrocarbon(s)), the process can be considered a "CO ₂ steam reforming" process. Catalysts as described here provide good results in both dry reforming and CO ₂ steam reforming in terms of both activity and stability as described above. Under the conditions provided in the reactor 5, the gaseous mixture 4 undergoes conversion into the product 7 of synthesis gas, which, in comparison with the gaseous mixture 4, can be enriched ( i.e., have a higher concentration) in hydrogen and CO, and/or become depleted ( i.e. have a lower concentration) of CO ₂ , H ₂ O, methane and/or other hydrocarbons originally present in the gaseous mixture 4.

An important methane-containing feedstock is natural gas and, in particular, hard-to-recover natural gas, which is not easily converted into synthesis gas in an economically advantageous manner using known methods. Natural gas having a relatively high CO ₂ concentration of, for example, at least about 10 mole %, or even at least about 25 mole %, is an attractive methane feed because the processes described here do not require CO ₂ removal. ( eg by cleaning with an amine solution), as opposed to conventional steam reforming, and actually use CO ₂ as a reactant. Other methane-containing feedstocks may contain methane produced by: gasification of coal or biomass (eg, lignocellulose or coke residue); from a bioreactor for the production of biofuels; or an effluent from processes for the production of renewable hydrocarbon fuels (biofuels) ( eg pyrolysis processes, in particular hydropyrolysis processes or fatty acid/triglyceride hydroconversion processes). The additional methane-containing feedstock may contain methane derived from wellhead equipment or an effluent from an industrial process, including an oil refining process (as refinery off-gas), a power generation process, a steel production process or a non-ferrous metal production process, a chemical production process ( e.g. , methanol) or coke production process. Generally, any process gas known to contain a hydrocarbon (eg, C ₁ -C ₃ hydrocarbon) and CO ₂ may comprise all or part of the gaseous mixture as described herein, or at least all or part of the methane-containing feed as a component of this mixture. If the methane feed contains methane derived from a renewable resource ( e.g., biomass), such as methane from a hydropyrolysis process stream, as described in US Pat. renewable syngas products ( i.e. containing renewable CO), which in turn can be further processed to produce renewable hydrocarbon containing fuels, fuel blending components and/or chemicals. Accordingly, the methane feedstock may contain methane from a non-renewable source ( e.g. natural gas) and/or methane from a renewable source ( e.g. biomass), the latter source causing an overall reduction in the carbon footprint associated with synthesis gas and downstream products. . As further described herein, natural gas and/or other methane-containing feedstock may optionally be pretreated to remove H ₂ S and other sulfur-containing contaminants prior to dry reforming or steam reforming with CO ₂ .

In typical embodiments, gaseous mixture 4 containing hydrocarbon and CO ₂ may react with catalyst 6 in batch or discontinuous mode, but continuous dry reforming or steam CO ₂ is preferred with flowing streams of gaseous mixture 4 or their components ( e.g. ., hydrocarbon-containing feedstock 1, oxidant 2 containing CO ₂ and/or oxidizer 3 containing H ₂ O, as described here) to improve the efficiency of the process. For example, the reaction can be carried out by continuously feeding the gaseous mixture 4 ( e.g., as a combined feed stream to the reactor of any of these components in combination) through the reactor 5 and catalyst 6 under reforming modes ( e.g., in the modes inside the reactor vessel and inside the bed catalyst, which is contained in the tank) taking into account the flow rate. In particular embodiments, the reforming mode parameters may be a feed hourly space velocity (WHSV) typically from about 0.05 h ^-1 to about 10 h ^-1 , typically from about 0.1 h ^-1 to about 4 .0 hour ^-1 and often from about 0.3 hour ^-1 to about 2.5 hour ^-1 . It is accepted in the art to which this invention relates that the WHSV parameter is the mass flow of the gaseous mixture divided by the mass of the catalyst in the reactor and represents the equivalent masses of the catalyst bed of the feed stream treated each hour. The WHSV parameter has an inverse relationship with the residence time in the reactor. Catalyst 6 may be present in reactor 5 as a fixed bed, but other catalyst systems, such as moving bed and fluidized bed systems, may be useful in processes using continuous catalyst regeneration.

Other reforming conditions that are suitable for both dry reforming and steam reforming with CO ₂ are temperatures typically from about 649 °C (1200 °F) to about 816 °C (1500 °F) . The processes described herein, due to the high activity of the catalyst in terms of lowering the activation energy required to use CO ₂ as an oxidant, can effectively oxidize methane and/or other hydrocarbons at significantly lower temperatures compared to a typical temperature of 816°C. (1500°F), which is used for dry or steam reforming. For example, in exemplary embodiments, the reforming regimes may be carried out at temperatures ranging from about 677°C (1250°F) to about 788°C (1450°F) or from about 704°C (1300°F) to about 760° C (1400°F). As described above, the presence of H ₂ S and/or other sulfur-containing contaminants in significant amounts ( e.g. 100-1000 mol-h/ppm) can cause temperatures to rise, for example from about 732 °C (1350 °F ) to about 843°C (1550°F) or from about 760°C (1400°F) to about 816°C (1500°F) to maintain desired conversion levels ( e.g. greater than about 85%). Another reforming mode parameter is pressure above ambient pressure, i.e., pressure above a gauge pressure of 0 kPa (0 psi), which corresponds to an absolute pressure of 101 kPa (14.7 psi). Because the reforming reactions produce more moles of product than moles of reactant, equilibrium is preferred at relatively low pressures. Therefore, the parameters of the reforming modes can be a gauge pressure, typically from about 0 kPa (0 psi) to about 517 kPa (75 psi), typically from about 0 kPa (0 psi ) up to about 345 kPa (50 psi) and often from about 103 kPa (15 psi) to about 207 kPa (30 psi).

The advantage is that, in any of the above temperature ranges, high catalyst activity is able to effect the conversion of methane and/or other hydrocarbons ( e.g., methane conversion, conversion of combined C ₁ -C ₃ hydrocarbons, conversion of combined C ₁ -C ₄ hydrocarbons, naphtha boiling range hydrocarbon conversion, jet fuel boiling range hydrocarbon conversion, etc. ) of at least about 80% ( e.g. , from about 80% to about 99%), of at least about 85% ( e.g., about 85% to about 97%) or at least about 90% ( e.g., about 90% to about 99%), for example, by adjusting the reactor temperature or temperature catalyst bed and/or other reforming regime parameters ( e.g., WHSV and/or pressure), which will be determined by those skilled in the art to which this invention pertains, taking into account the knowledge gained from the present disclosure. tiya. It is also advantageous that catalysts as described herein are active enough to achieve significant hydrocarbon ( e.g. methane) conversion of at least about 85% while maintaining stability at a temperature of at most about 732°C (1350°F), or at most about 704°C (1300°F). With respect to oxidant reactants, typical CO ₂ conversion is at least about 50% ( e.g., about 50% to about 75%) and typical H ₂ O conversion is at least about 70% ( e.g. ., from about 70% to about 90%) at the conversion levels described herein with respect to hydrocarbons. It is accepted in the art to which this invention relates that the conversion of any particular compound ( eg, methane) or combination of compounds ( eg, C ₁ -C ₄ hydrocarbons or C ₁ -C ₃ hydrocarbons) can be calculated using the formula:

100 * (X _{raw material} -X _product ) / X _{raw material} ,

where X _feed is the total amount ( e.g. total mass or total moles) of compound(s) X in the gaseous mixture ( e.g. combined feed in a reactor) fed to the reactor and X _product is the total amount of compound(s) ) X in the synthesis gas taken from the reactor. In the case of continuous methods, these totals are conveniently expressed in units of flow or totals per unit of time ( eg, total mass/hour or total moles/hour). Other performance criteria that can be achieved using catalysts and reforming regimes as described herein are: high hydrogen yield; or the fraction of total hydrogen in methane and/or other hydrogen-containing compounds ( e.g. total hydrogen in hydrocarbons, e.g. C ₂ -C ₄ hydrocarbons or C ₂ -C ₃ hydrocarbons) in the gaseous mixture fed to the reactor which is converted to H ₂ in synthesis gas taken from the reactor. In typical embodiments, the hydrogen yield is at least about 70% ( eg, about 70% to about 85%). As described above with respect to conversion, the amounts of feedstock fed to and withdrawn from the reactor may be expressed in units of flow.

As described above, additional advantages associated with reforming processes, and in particular CO ₂ steam reforming processes as described herein, include suitable H ₂ /CO molar ratios as well as the ability to adjust these ratios in the synthesis gas. This is especially important for the Fischer-Tropsch reaction for the production of downstream liquid hydrocarbons. The exact composition of the synthesis gas depends on the composition of the feedstock ( eg combined feedstock in the reactor) or gaseous mixture, catalyst and reforming regimes.

In exemplary embodiments, the synthesis gas, especially in the case of CO ₂ steam reforming, advantageously has an H ₂ :CO molar ratio of about 2:1, for example, typically about 1.5:1 to about 2.3: 1 and is typically about 1.8:1 to about 2.2:1. The combined concentration of H ₂ and CO in this product is typically at least about 35 mol% (or vol%) ( e.g., about 35 mol% to about 85 mol%), typically at least about 50 mol% ( eg, from about 50 mol% to about 80 mol%) and is often at least up to about 60 mol% ( eg, from about 60 mol% to about 75 mol%). As described above, the composition of the synthesis gas may be essentially only CO ₂ and water, depending on the specific dry reforming or CO ₂ steam reforming process, including modes ( e.g. modes inside the reactor, in particular temperature, pressure , hourly space velocity of the feedstock and the composition of the catalyst) and the feedstock or gaseous mixture that enters the reaction. In exemplary embodiments, CO ₂ is present in the synthesis gas at a concentration typically less than about 45 mol% ( e.g., about 5 mol% to about 45 mol%) and typically less than about 35 mol% ( eg, from about 10 mol% to about 35 mol%). Water may be present at a concentration typically less than about 20 mole% ( e.g., about 1 mole% to about 25 mole%) and usually less than about 15 mole% ( e.g., about 5 mole% to about 15 mol %). Minor amounts of unconverted hydrocarbons may also be present in the synthesis gas. For example, the total amount of C ₁ -C ₄ hydrocarbons ( eg, the total amount of methane, ethane, propane and butane), which may include only C ₁ -C ₃ hydrocarbons, may be present in a concentration of less than about 5 mol% and typically less than about 2 mol%.

The following examples are given as representative of the present invention. These 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 the appended claims.

EXAMPLE 1

The experiments carried out on the pilot plant were carried out using gaseous mixtures continuously fed into the reactor containing catalyst particles having a composition of 1 wt. % Pt and 1 wt. % Ph on a support containing cerium oxide. The performance of the CO ₂ steam reformer set was tested at a 0.7 h ^-1 WHSV at 760 °C (1400 °F) and a gauge pressure of 124 kPa (18 psig). square inch) to 172 kPa (25 psi). Two types of gas mixtures were tested: (1) a composition containing methane, ethane, propane and CO ₂ , in addition to H ₂ O, and reproducing the composition obtained from combined hydropyrolysis and biomass hydroconversion (“Renewable Type”), and (2 ) typical composition of high CO ₂ natural gas (“Natural Gas”). These gaseous mixtures (combined feed) and the synthesis gas produced from this feed are shown in Table 1 below.

Table 1

Renewable
Type of Renewable
Type of Natural gas Natural gas Combined:
raw material synthesis gas Combined:
raw material synthesis gas methane, mol.% 11.7 0.3 21.7 .79 ethane, mol.% 5.8 0 5.8 0 propane, mol.% 5.8 0 1.4 0 CO ₂ mol.% 23.4 10.6 29.0 8.2 water, mol.% 53.3 12.7 42.1 8.6 H ₂ (mol%) 51.3 51.9 CO, mol.% 25.1 30.4 methane conversion rate % 96 93 ethane conversion rate % 100 100 propane conversion rate % 100 100 molar ratio of H ₂ :CO 2.05 1.71

It follows from these results that the CO ₂ steam reforming catalyst and process can produce synthesis gas with an H ₂ :CO molar ratio of nearly 2:1 and therefore suitable for direct post-treatment in a Fischer-Tropsch reaction. or at least without prior (upstream) adjustment of this ratio. Given that these suitable results were only obtained at a reaction temperature of 760 °C (1400 °F), lower temperatures, such as 704 °C (1300 °F), may also be used due to the high activity of the catalyst. The use of lower operating temperatures makes it possible to purposefully reduce the rate of side reactions that form coke, which deactivates the catalyst. On FIG. Figure 2 shows the relationship between temperature and methane conversion for the type of feedstock and catalysts tested in Example 1, and in particular, this figure illustrates the ability to achieve greater than 85% methane conversion at 704°C (1300°F) and greater than 95% conversion rate at 760°C (1400°F). On FIG. Figure 3 shows how the H ₂ O:CO ₂ molar ratio of the gaseous mixture for the type of feedstock and catalyst tested in Example 1 affects the H ₂ :CO molar ratio of synthesis gas at temperatures of 704 °C (1300 °F) and 760 °C (1400°F). Given the possibility of establishing relationships between these parameters for a given feedstock, catalyst, and set of operating conditions, the composition of the gaseous mixture can serve as a convenient means of controlling to achieve a given composition of the synthesis gas.

EXAMPLE 2

Additional experiments were carried out in which a typical natural gas composition as described in Example 1 was steam reformed with CO ₂ as also described in this example. However, in this case, H ₂ S was added to the gaseous mixture or combined feed at a concentration of 800 mol-ppm. Despite this high level of sulfur contamination, the methane conversion bias has been found to be easily recovered by raising the catalyst bed temperature from 760°C (1400°F) to 788°C (1450°F). In addition, the catalyst unexpectedly showed long-term stability for 400 operating hours (on-line hours) at this temperature, as well as at the same WHSV and pressure, as described above with respect to Example 1. This stability, achieved despite a significant concentration of sulfur, was unexpected in terms of sulfur sensitivity of conventional catalysts used for steam methane reforming.

EXAMPLE 3

The gas mixture described in Example 1 as "Renewable Type" and having the composition shown in Table 1 was tested using the catalyst and modes described in Example 1 to evaluate the performance of the CO ₂ steam reformer package over a long period of operation. Long-term stability tests showed that the composition of the produced synthesis gas remained stable over 500 hours of operation at these constant conditions, demonstrating essentially no deactivation of the reformer catalyst over a long period of operation. On FIG. 4 shows the compositional stability of the synthesis gas produced over a given period of operation with a high level of methane conversion. On FIG. 5 shows the stability of the H ₂ /CO molar ratio of the produced synthesis gas, which was nearly 2 and therefore ideally suited for use in the downstream FT synthesis reaction to produce liquid hydrocarbons.

In general, aspects of the invention relate to the use of dry reforming or steam reforming with CO ₂ to achieve high conversion of methane and/or other hydrocarbons and obtain synthesis gas having the desired characteristics, including H ₂ :CO molar ratios, as described here. Additional aspects relate to those reforming processes that use an active catalyst that is capable of converting methane and/or other hydrocarbons in the presence of CO ₂ or both CO ₂ and H ₂ O, while maintaining a low degree of coking and high catalyst stability, even when using feedstock with sulfur-containing contaminants and/or reactive compounds, for example, aromatic and/or olefinic hydrocarbons with such contaminants and compounds that are associated with the rapid deactivation of conventional catalyst systems. Other aspects relate to those reforming processes that can be used directly with additional processing steps, such as Fischer-Tropsch synthesis, to produce liquid (C ₄ ⁺ ) hydrocarbons and/or alcohols, alcohol synthesis via fermentation, or hydrogen production. These methods have the advantage of using existing CO ₂ present in both renewable and non-renewable methane sources, preferably without removing that CO ₂ , and/or using lower water levels than conventional steam methane reforming. In addition, the sulfur resistance of the catalyst is indicative of its activity in the conversion of SO ₂ and H ₂ S sulfur-containing contaminants, which, if necessary, can be easily treated downstream using a single acid gas removal step. Those skilled in the art to which this invention pertains, having knowledge derived from the present disclosure, will appreciate that various modifications can be made to these methods with respect to these and other advantages without departing from the scope of the present invention. As such, it should be understood that the features of the present invention may be subject to modifications and/or substitutions without departing from the scope of the present invention. The specific embodiments illustrated and described herein are for illustrative purposes only and do not limit the scope of the present invention as set forth in the appended claims.

Claims (33)

1. A method for producing a synthesis gas product, including the supply of a gaseous mixture containing methane, CO₂ and H₂O to steam reformer with CO₂, said CO steam reformer reactor₂contains a catalyst containing at least two noble metals selected from the group consisting of Pt, Rh, Ru, Pd, Ag, Os, Ir and Au, on a solid support containing cerium oxide in an amount of at least 80 wt. % solid media, the specified catalyst contains less than 0.05 wt. % of metals other than the two noble metals and solid support metals, wherein the CO ₂ steam reformer converts at least 80% of the methane by reaction with CO ₂ and H ₂ O as oxidizers. 2. The method according to claim 1, characterized in that at least two noble metals are Pt and Rh. 3. The method according to p. 2, characterized in that Pt is present in an amount ranging from 0.05 wt. % up to 5 wt. % catalyst. 4. The method according to p. 3, characterized in that Pt is present in an amount ranging from 0.5 wt. % up to 2 wt. % catalyst. 5. The method according to p. 2, characterized in that Rh is present in an amount ranging from 0.05 wt. % up to 5 wt. % catalyst. 6. The method according to p. 5, characterized in that Rh is present in an amount ranging from 0.05 wt. % up to 2 wt. % catalyst. 7. The method according to any one of paragraphs. 1-6, where H ₂ O is present in the gaseous mixture in an amount of from 15 mol.% to 70 mol.%. 8. The method according to any one of paragraphs. 1-7, additionally including before said supply of a gaseous mixture containing methane, CO₂ and H₂O to steam reformer with CO₂, by combining a methane-containing feedstock and an oxidizer containing CO₂ with the formation of gaseous mixes, where the source of H ₂ O in the gaseous mixture is a raw gaseous mixture containing methane and/or an oxidizer containing CO ₂ . 9. The method according to any one of paragraphs. 1-8, characterized in that the gaseous mixture additionally contains at least 100 mol-hours/million of the total sulfur content. 10. The method according to any one of paragraphs. 1-9, characterized in that the gaseous mixture contains aromatic and olefinic hydrocarbons in a total amount ranging from 1 mol.% to 25 mol.%. 11. The method of claim. 8, characterized in that the methane-containing feed contains natural gas and methane from a renewable source of methane. 12. The method according to any one of paragraphs. 1-11, further comprising, before said supply of a gaseous mixture containing methane, CO ₂ and H ₂ O, to the steam reforming reactor with CO ₂ , combining an oxidizer containing H ₂ O with a methane-containing feed and an oxidizer containing CO ₂ to obtain a gaseous mixture. 13. The method according to any one of paragraphs. 1-12, wherein the reaction conditions in the CO ₂ steam reformer include a feedstock hourly space velocity (WHSV) of 0.1 h ^-1 to 2.5 h ^-1 to produce synthesis gas as a product effluent from steam reforming reactor with CO ₂ . 14. The method according to any one of paragraphs. 1-13, characterized in that the reaction conditions in the CO ₂ steam reformer include a temperature value of 649 °C (1200 °F) to 816 °C (1500 °F). 15. The method of claim 14, wherein the modes further include a gauge pressure of 0 kPa to 517 kPa (75 psi). 16. The method according to any one of paragraphs. 1-15, characterized in that in the CO ₂ steam reformer the methane conversion level is at least 85% at a temperature not exceeding 704 °C (1300 °F). 17. The method according to any one of paragraphs. 1-16, characterized in that the synthesis gas contains H ₂ in an amount constituting at least 70% hydrogen in hydrogen-containing compounds, including methane and water, in a gaseous mixture. 18. The method according to any one of paragraphs. 1-17, where the synthesis gas product has an H ₂ :CO molar ratio of 1.5:1 to 2.3:1. 19. The method according to any one of paragraphs. 1-18, where the gaseous mixture further comprises ethane, ethylene, propane and propylene. 20. The method according to any one of paragraphs. 1-19 where the methane is derived from a renewable resource. 21. The method of claim 20 wherein the renewable resource is biomass. 22. A method for producing a synthesis gas product, including the supply of a gaseous mixture containing methane, CO₂ and H₂O to steam reformer with CO₂, said CO steam reformer reactor₂contains a catalyst containing Pt in an amount of 0.3 wt. % up to 3 wt. % catalyst, and Rh in an amount of 0.3 wt. % up to 3 wt. % catalyst, on a solid support containing cerium oxide in an amount of at least 80 wt. % solid support, where the reforming regimes in the steam reforming reactor with CO ₂ include a raw material hourly space velocity (WHSV) of 0.1 hour ^-1 to 4 hour ^-1 , a gauge pressure of 0 kPa to 517 kPa (75 psi, where the activity of the catalyst is sufficient to convert more than 95% of the methane in the CO _{2 steam reformer by reaction with CO 2 and} H ₂ O as oxidants at a temperature of 760 °C. 23. A method for producing a synthesis gas product, including the supply of a gaseous mixture containing methane, CO₂ and H₂O to steam reformer with CO₂, said CO steam reformer reactor₂contains a catalyst containing at least one noble metal on a solid support containing cerium oxide in an amount of at least 80 wt. % solid support, wherein in the CO ₂ steam reformer, at least 80% of the methane is converted by reaction with CO ₂ and H ₂ O as oxidizers, where in the case where the gaseous mixture contains sulfur in an amount of at least 10 mol-hours/million to 1 mol.%), the method further includes adjusting the reaction temperature of the steam reformer reactor with CO ₂ based on sulfur determination data. 24. The method of claim 23, wherein the gaseous mixture contains sulfur from 100 mol-hours/million to about 1000 mol-hours/million. 25. The method of claim 24, wherein the gaseous mixture contains sulfur from 500 mol-hours/million to about 1000 mol-hours/million.

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