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Sorption enhanced methanation of biomass

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Sorption enhanced methanation of biomass

Disclosed embodiments provide a system and method for producing hydrocarbons from biomass. Certain embodiments of the method are particularly useful for producing substitute natural gas from forestry residues. Certain disclosed embodiments of the method convert a biomass feedstock into a product hydrocarbon by hydropyrolysis. Catalytic conversion of the resulting pyrolysis gas to the product hydrocarbon and carbon dioxide occurs in the presence of hydrogen and steam over a CO2 sorbent with simultaneous generation of the required hydrogen by reaction with steam. A gas separator purifies product methane, while forcing recycle of internally generated hydrogen to obtain high conversion of the biomass feedstock to the desired hydrocarbon product. While methane is a preferred hydrocarbon product, liquid hydrocarbon products also can be delivered.
Related Terms: Carbon Dioxide Hydrocarbon Hydrogen Ethane Biomass

USPTO Applicaton #: #20130017460 - Class: 429419 (USPTO) -
Inventors: Bowie G. Keefer, Matthew L. Babicki, Brian G. Sellars, Edson Ng

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The Patent Description & Claims data below is from USPTO Patent Application 20130017460, Sorption enhanced methanation of biomass.

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This is a continuation application under 35 U.S.C. §120 of International Patent Application No. PCT/CA2010/001859, filed Nov. 18, 2010, which claims the benefit of the earlier filing date of U.S. Provisional Application No. 61/262,485, filed Nov. 18, 2009. Each of these prior applications is incorporated herein by reference.


The process of the invention applies to hydropyrolysis of carbonaceous feedstocks, and particularly of forestry residues, to generate higher value synthetic fuels, in particular methane and optionally liquid hydrocarbons.


Thermochemical conversion of biomass such as sawmill wood wastes, forestry residues and agricultural wastes into synthetic fuels is an important emerging avenue for advancement of renewable energy sources to supplement or replace fossils fuels. While air blown gasification is used for generation of lower heating value fuel gas, several variants of oxygen or steam gasification can be used for production of syngas containing minimal nitrogen. Syngas is a gas mixture containing mostly hydrogen and carbon monoxide, and is a versatile feedstock for further chemical processing into a wide range of useful fuels and chemical compounds. Syngas can be catalytically converted into methane, Fischer-Tropsch liquid fuels, methanol, dimethyl ether, or hydrogen. The methanation reaction of syngas to generate methane and byproduct water vapour is typically conducted over nickel catalysts at temperatures in the range of about 300° C. to about 400° C., and preferably at elevated pressure.

Methane is readily marketed and delivered through existing natural gas distribution infrastructure as substitute natural gas (SNG) for numerous end uses including space heating and electrical power generation. Methane has considerably higher energy density than hydrogen, and can be converted into syngas or hydrogen by catalytic steam reforming. Modern combined cycle power plants are conveniently fueled by natural gas. Methane is also a particularly advantageous fuel for future high temperature fuel cell power plants using highly endothermic internal steam reforming of natural gas to recover high grade heat generated by the fuel cell stack.

The reaction of steam with biomass to generate syngas is highly endothermic, hence conducted with direct or indirect heating by partial oxidation with air or oxygen; and is typically conducted at much higher temperature than the subsequent exothermic methanation reaction. The thermal mismatch between gasification and methanation reactions is detrimental to process efficiency.

Hydrogasification has previously been investigated for gasification of biomass. The key reaction is hydrogenation of carbon to form methane, whose exothermicity is a great advantage compared to other gasification approaches. As hydrogen is a premium fuel, its consumption in large amounts has presented the appearance of a major economic barrier.

The endothermic nature of the syngas formation reaction from the reaction of biomass pyrolysis gas and steam requires enthalpy heat to be added (typically by partial combustion with added oxygen). Temperatures well in excess of 650° C. are typically required to reduce tars to reasonable levels.

The gas composition produced in biomass gasification approaches a complex equilibrium established between CO, CO2, H2, H2O and CH4 which is a function of temperature, pressure and overall gas composition. Reforming reactions producing syngas increasingly dominate the equilibrium at temperatures above 650° C. at the expense of hydrocarbons, CO2 and water.

The use of catalysts, such as the use of olivine, dolomite or nickel coated media in fluidized beds, to enhance the rate of syngas formation is well known. These catalysts allow a faster reaction towards syngas equilibrium favoured under the process conditions. Catalysts have also been used in a secondary bed in series with the gasifier for the reduction of tars contained in the syngas or producer gas.

An oxygen blown entrained flow gasifier may typically operate at about 1300° C. to 1500° C., at which temperatures methane and higher hydrocarbons are all nearly entirely converted to syngas. This has the important advantage of almost completely eliminating tar constituents, but the disadvantage for SNG production that all of the product methane must be generated by the exothermic methanation of syngas at much lower temperature than the gasification temperature.

Indirect steam gasifiers (such as the US Battelle/FERCO “Silvagas” system, the Austrian fast internally circulating fluidized bed (FICFB) system, and the Dutch ECN “Milena” system) operate at about 850° C. These systems use twin bed configurations, in which fluidized granular heat transfer media is circulated between a gasification zone in which steam reacts with the biomass to produce syngas and char, and an air-blown regeneration zone in which the char is combusted to reheat the media. The product syngas contains a significant admixture of methane generated within the gasifier. While downstream processing is required to convert or remove tar constituents, an important advantage for SNG production is that only about 55% to 60% of the final product methane must be generated by methanation of syngas, since a useful fraction of the methane was already produced with the syngas.

Some recent improvements to the twin bed gasification approach have been based on adsorption enhanced reforming (“AER”) in which a CO2 acceptor such as lime or calcined dolomite is included in the granular media to remove carbon dioxide by carbonation from the gasification zone operating typically at about 600° C., and to release the carbon dioxide by calcining in the regeneration zone operating typically at about 800° C. The AER process has been disclosed by Specht et al. (European patent publications EP 1,218,290 B1 and EP 1,637,574 A1). The principle of the AER process is to generate hydrogen-rich syngas by shifting the reaction equilibria of the steam reforming and water gas shift reactions by CO2 removal. The AER process has been tested in the FICFB twin bed system, and is being developed for SNG production by using a molten salt methanation reactor to convert the syngas into methane.

Twin bed indirect steam biomass gasifiers, and experimental AER systems derived from twin bed gasifiers, have been operated at atmospheric pressure. Air blown combustion regeneration of pressurized fluidized beds would present challenges. ECN have considered operation of the Milena twin bed gasification system pressurized to about 7 bara.

There is a need to provide more efficient internally self-sustaining generation of the hydrogen needed for hydrogasification, which otherwise is an extremely attractive approach for conversion of biomass and other carbonaceous feedstocks into methane and other high value synthetic fuels.


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While the “sorption enhanced reforming” (SER) process [known in Europe as “absorption enhanced reforming” or AER] concerns generating hydrogen-rich syngas, which may be converted downstream in a separate methanation reactor into SNG, disclosed embodiments of the present invention concern the new principle of absorption enhanced methanation (“SEM”). Whereas carbon is nearly entirely removed from the feed syngas by carbonation of the sorbent in AER, only about half of the carbon is similarly removed in SEM.

Methanation as described in this disclosure is hydroconversion of a pyrolysis gas to produce methane, including but not confined to the conversion of syngas to methane.

It has been found unexpectedly that maintenance of a high hydrogen back-pressure in SEM will inhibit decomposition of methane by steam methane reforming, while carbon oxides are preferentially removed. Because only about half of the carbon contained in the initial syngas is removed by carbonation in SEM, the CO2 sorbent has much lighter duty in SEM as compared with SER.

Thermodynamic modeling indicates that slightly more than half of the carbon not rejected as char or coke deposits can be converted to methane under conditions of hydrogen self-sufficiency. Approximately 20% of the carbon originally in the biomass will typically be rejected as char or coke to be combusted or gasified in the regeneration reactor. If a supplemental source of hydrogen is available, the conversion of feed carbon to methane can be increased within the scope of the present invention, while even less of the carbon will be removed by carbonation of the sorbent.

SEM may be advantageously operated at moderately elevated working pressures in a range of just over 1 bara to about 50 bara, or in a preferred range of from about 5 bara to about 30 bara. While SEM can be conducted at atmospheric pressure, the methane concentration will be lower than at higher operating pressures, thus making the gas separation of hydrogen and methane more difficult. Conventional methanation requires much higher working pressures to achieve satisfactory conversion.

A preferred CO2 sorbent for SEM is CaO, which can be used in any suitable form, or combinations thereof, such as calcined limestone or dolomite, or CaO on a suitable support such as alumina. CaO is readily carbonated at working temperature around 600° C. and moderate pressures from atmospheric upward. Such temperature and pressure conditions have been found to be favourable for the hydrogasification of biomass pyrolysis gas to methane, and for steam reforming of methane to generate hydrogen.

Various CO2 sorbents or “acceptors” will work in the temperature range of from about 500° C. to about 650° C. of interest for SEM. These include calcined dolomite, calcium oxide, calcium hydroxide, lithium zirconate, lithium orthosilicate, and other metal oxides or hydroxides that can react with carbon dioxide to form a carbonate phase.

While hydroconversion of biomass pyrolysis gas to methane works favourably at temperatures in the range of from about 500° C. to about 650° C., productive hydroconversion of pyrolysis gas to liquid hydrocarbons requires lower temperatures in the range of from about 300° C. to about 400° C. CO and CO2 are extracted from the oxygenated pyrolysis gas by decarbonylation and decarboxylation respectively, in parallel with extraction of H2O by hydrodeoxygenation. As CO and H2O can be consumed to generate H2 and CO2 by the water gas shift reaction, it may be advantageous to remove CO2 by a carbonation reaction in order to maximize the generation of hydrogen by water gas shift. Suitable CO2 sorbents for the temperature range of from about 300° C. to about 400° include potassium-promoted hydrotalcites, magnesia supported on alumina, or dolomite in combination with alkali (and particularly potassium) promoters.

Certain disclosed embodiments provide a method for converting a biomass feedstock into a product hydrocarbon comprising: a. subjecting the feedstock to fast pyrolysis with rapid pyrolytic heating in the substantial absence of oxygen, or hydropyrolysis as fast pyrolysis in the presence of hydrogen, in order to generate fractions of pyrolysis gas and char; b. catalytically converting at least a portion of the pyrolysis gas to a product hydrocarbon and carbon dioxide in the presence of hydrogen and steam, while removing carbon dioxide by carbonation of a sorbent; c. generating at least a portion of the hydrogen by reaction between steam and a portion of the pyrolysis gas or a product hydrocarbon; d. separating hydrogen from the hydrocarbon product, and recycling the hydrogen so as to force the conversion of biomass into the hydrocarbon product; and e. regenerating the sorbent by heating through combustion of the char to release the carbon dioxide.

The fast pyrolysis step may be performed with externally heated media, e.g. circulating through a pressurized auger reactor, and preferably as hydropyrolysis in a hydrogen atmosphere. The heat transfer media may include circulating magnetite pellets, which are readily separable from char according to density and magnetic properties. Some impurities such as alkalis, other metals, sulphur, and chloride will be partially entrained by the char. While very fast pyrolysis will minimize char production, slower pyrolysis may also be considered for coproduction of charcoal or biochar with lower yield of methane and any other desirable hydrocarbon products.

The catalytic conversion step includes catalytic hydrogasification, such as steam hydrogasification. Hydroconversion, hydrodeoxygenation, and hydrocracking reactions will take place. The net reaction will be exothermic. This step may be conducted alternatively in any suitable reactor architecture, such as the following reactor architectures: a) bubbling or circulating fluidized bed; b) fixed bed with granular packing or monolithic catalyst, and rotary or directional valve logic for cyclically switching beds between reaction and regeneration steps; c) moving bed with granular catalyst.

The hydrogasification process requires a source of hydrogen, either externally supplied or internally generated. According to certain disclosed embodiments of the present invention, steam addition, plus moisture contained in feed biomass, provides sufficient steam for internal, self-sustaining generation of hydrogen required for the hydrogasification reaction to convert biomass feedstock into methane.

Certain disclosed embodiments of the invention may be realized by any of the following operating modes: 1. Self-sustaining recycle of H2 generated within catalytic stage with sufficient H2 excess to overcome incomplete recovery in downstream gas separation of recycle H2. Methane yield is approximately 50% of carbon after char production, balance primarily to CO2 with preferred use of water gas shift reaction to consume most CO. 2. Supplemental hydrogen may provided from any combination of (a) an external source of hydrogen rich gas, or (b) oxygen or steam gasification of char offgas, or (c) steam methane reforming of a portion of the methane product. 3. The process in preferred embodiments includes methanation, regeneration and reforming steps. Higher temperature, high steam concentration and low hydrogen concentration drive the reforming reaction forward. Lower temperature, low steam concentration and high hydrogen concentration drive the methanation reaction forward. Reforming and methanation may take place in each of the reforming and methanation steps, with the equilibrium balance reflecting not only bed temperature but also the steam/hydrogen ratio over the catalyst. The catalyst beds are cooled by reforming, heated by methanation and strongly heated to the maximum process temperature by regeneration. The reforming step follows the regeneration step to take advantage of sensible heat in the bed, then the methanation step follows after the catalyst bed has been cooled by the reforming step, and then the next regeneration step takes place to finish reheating the bed up to its cyclic maximum temperature. Such embodiments are an inventive extension of the known principle of cyclic reforming in which sensible heat for repeated reforming steps is provided by alternatingly repeated regeneration steps, with certain embodiments of the present inventive process also including methanation steps following reforming steps and preceding regeneration steps.

With larger steam supply, higher temperature and/or lower operating pressure, the process may generate excess syngas or hydrogen so that coproduction of methane and hydrogen/syngas may be contemplated. Coproduction of methane and higher hydrocarbon fuel commodities is also attractive.

The process also may include cleaning steps to remove catalyst poisons (alkalis, other metals, phosphorus, sulfur, chloride, etc.) and tars. Hot or cold clean-up process alternatives are well known.

Hot clean-up steps include sorbents (e.g. ZnO to remove sulphur), and catalytic tar cracking followed by cool-down in cyclic thermal regenerator loaded with layers of fine filtration metal matrix, porous ceramic, catalyst and adsorbent. Regeneration can be achieved by burning off tar and coke deposits, then air flush to cool the filtration matrix and provide hot air for front end feed dryer.

Cold clean-up can be achieved by higher temperature oil quench and wash, followed by lower temperature water quench and wash.

The process may also include gas separation steps for removing CO2, for recovering a hydrogen-enriched recycle stream for the hydrogasification step, and/or for purifying the product methane. Preferred gas separation alternatives include carbonation of CaO or pressure swing adsorption (PSA) for CO2 removal, and PSA or polymeric membranes for separation of H2 from CH4.

One disclosed apparatus includes a hydropyrolysis reactor. Alternative embodiments include a single stage reactor, or a two-stage system including a pyrolysis or hydropyrolysis reactor as the first stage, and a methanation or hydroconversion reactor as the second stage. The process achieves catalytic steam hydrogasification, with catalytic hydrocracking of tars favoured by relatively high hydrogen partial pressure.

The process includes sequential steps for (1) the working reaction by hydrogasification or hydroconversion combined with sorbent carbonation, and (2) regeneration of sorbent and catalysts. Combined regeneration of the sorbent (carbon dioxide acceptor) and catalyst is a very attractive operating mode.

Alternative reactor configurations include fixed beds with granular or monolithic catalyst with directional or rotary valves for cyclic switching of beds between the process steps of working reaction and regeneration, or fluidized beds with circulation to achieve the process steps. Twin fluidized beds are a suitable architecture for indirect steam gasifiers, achieving the working reaction in one bed, and regeneration by combustion of char in the other bed.

An important aspect of the invention is heat management. Combined exothermicity of sorption carbonation and methanation reactions provide abundant heat for preheating feedstock and steam generation, with reduced need for feedstock drying. Heat for sorbent and catalyst regeneration can be generated by combustion of relatively low value fuels, such as byproduct char or raw biomass feedstock.

Introduction of fibrous biomass with inconsistent properties into pressurized pyrolysis or gasification plants is a difficult challenge. Water slurry feed is mechanically attractive, but is incompatible with the normal requirement that the feed biomass be substantially dry. The present process is tolerant of relatively wet feed, because of the strong combined exothermicity of the methanation and sorbent carbonation reactions. Another novel approach for slurry feed within the present invention is to provide a pusher centrifuge dewatering system within the high pressure containment volume of the plant.

Catalyst and sorbent regeneration can be achieved in a regeneration reactor zone integrated with the pressurized combustor of gas turbine, or supplied with superheated steam with optional addition of enriched oxygen.

High methane yield can be achieved in hydrogasification, however in absence of a supplemental source of imported hydrogen up to half of that methane may be consumed downstream to generate recycle hydrogen and CO2. A preferred operating mode is defined by self-sustaining recycle of H2 generated within a catalytic stage, with just enough H2 excess to compensate for incomplete recovery in downstream gas separation of recycle H2. Methane yield is approximately 50% of carbon after char production, with the remaining carbon being converted to CO2.

Supplemental hydrogen may provided from any combination of (a) an external source of hydrogen-rich gas such as stranded hydrogen offgas from a chlor-alkali or ethylene plant, or (b) oxygen or steam gasification of char, or (c) steam methane reforming of a portion of the methane product. The process may be operated with any amount of hydrogen recycle, including the limiting case of zero hydrogen recycle, in which case the methane rich product gas will contain relatively less hydrogen but significantly larger amounts of carbon dioxide and carbon monoxide. In the opposite limiting case, zero methane is delivered so that maximum hydrogen may be generated; and hydrogen-rich syngas may then be delivered as a desired product. Coproduction of methane and hydrogen, or hydrogen-rich syngas, is an option within the scope of the invention.

Separation of hydrogen and methane can be achieved by pressure swing adsorption, membrane permeation, refrigerated hydrate formation or cryogenics. While sorption-enhanced reactors for SMR and/or methanation have integrated bulk CO2 removal, further purification of product streams will generally be needed to remove slip of CO or CO2 as required.

The invention provides a wide spectrum of cogeneration opportunities. The process can generate a range of hydrocarbon products (methane, LPG, and liquid hydrocarbons). Syngas and hydrogen are generated within the process, either consumed entirely within the hydrocarbon producing hydroconversion processes, or alternatively a portion of syngas or hydrogen may be exported as a useful product at some penalty of reducing the conversion of biomass carbon to hydrocarbons. Syngas is an intermediate for synthesis of a wide range of useful fuel and chemical products.

The hydropyrolysis reaction delivers a product stream of methane plus hydrogen, and minor amounts of CO and CO2. Syngas may also be generated by oxygen/steam gasification of char. The syngas generated by char gasification will typically have a low ratio of H2 to CO, which can be upgraded by admixture with H2 generated by the hydropyrolyser. A ratio of H2:CO˜2 is desirable for synthesis of methanol, dimethyl ether, or Fischer-Tropsch hydrocarbons.

Other cogeneration opportunities provided by the invention include the production of energy as heat or electricity. Heat recovery within the process can readily generate steam at different temperatures. Product or byproduct fuels can be used to power electrical generators through gas turbines, internal combustion engines or steam turbines. Some of the most attractive future applications of the present invention will be obtained by integration of high temperature fuel cells with the hydrogasfication of biomass.

As first suggested in copending U.S. patent application Ser. No. 11/869,555, biomass hydrogasification may be directly integrated with SOFC power plants having enriched H2 recycle for the anode of an internal reforming SOFC. The present invention develops practicable implementations of that opportunity. Without the relatively low operating pressures enabled by the inventive sorption enhanced methanation process, it would be very difficult to integrate the usually relatively low pressure SOFC system with the relatively high pressure hydrogasification processes.

When the oxidant for catalyst and sorbent regeneration by combustion of char and coke is enriched oxygen, a concentrated product stream of CO2 can be delivered for useful applications including enhanced oil recovery, or for disposal by underground sequestration.

The foregoing and other objects, features, and advantages of the invention will become more apparent from the following detailed description, which proceeds with reference to the accompanying figures.


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FIG. 1 is a schematic diagram of one embodiment of an apparatus according to the present invention.

FIG. 2 shows an embodiment with integration to a gas turbine power plant.

FIGS. 3 and 4 show an embodiment with a rotary reactor including cyclically switched hydrogasification and regeneration zones.

FIG. 5 shows a fluidized twin bed embodiment of the invention.

FIG. 6 shows a two stage double twin bed fluidized embodiment.

FIG. 7 shows a two stage embodiment, with the first stage a fluidized bed hydropyrolysis reactor and the second stage a methanation or hydroconversion reactor with a cyclic rotary switching mechanism.

FIG. 8 shows an embodiment for coproduction of methane and liquid hydrocarbons.

FIG. 9 shows an embodiment with a hydrogasification system coupled to a solid oxide fuel cell (SOFC) for generation of electricity.

FIG. 10 is a graph of methane conversion, methane concentration, hydrogen concentration, and the ratio of hydrogen output to hydrogen input from the hydrogasification reactor of the invention, versus the ratio of carbon carbonated on the sorbent to carbon content of the biomass feed to the process.


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US 20130017460 A1
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585254, 585251, 585242, 422187, 429423, 60781
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