US20090320368A1

US20090320368A1 - Methods and Systems for Gasifying a Process Stream

Info

Publication number: US20090320368A1
Application number: US12/295,099
Authority: US
Inventors: Marco J. Castaldi; John P. Dooher; Klaus S. Lackner
Original assignee: Individual
Current assignee: John P Dooher Trust; Columbia University in the City of New York
Priority date: 2006-03-31
Filing date: 2007-03-30
Publication date: 2009-12-31
Also published as: WO2007123776A2; EP2007674A2; AU2007240969B2; AU2007240969A1; EP2007674A4; WO2007123776A3

Abstract

Methods and systems for gasifying process streams are described. In some embodiments, a method for gasifying a process stream includes gasifying the process stream in a first chamber to generate one or more product gases, transporting at least a portion of the one or more product gases to a second chamber, combusting at least a portion of the one or more product gases in the presence of one or more catalysts in the second chamber to generate a heat energy, and indirectly providing the heat energy from the second chamber to the first chamber as a primary heat source to drive gasification of the process stream.

Description

CROSS REFERENCE TO RELATED APPLICATION(S)

This application claims the benefit of U.S. Provisional Application Nos. 60/788,238, filed Mar. 31, 2006, and 60/846,063, filed Sep. 20, 2006, each of which is incorporated by reference as if disclosed herein in its entirety.

BACKGROUND

Various types of gasifiers are known in industry. A variety of fixed bed, fluidized bed, and entrained flow gasifiers have been in use for decades. In fixed bed gasifiers, a gasification agent such as steam, oxygen, and/or air flows through a fixed bed of fuel source, e.g., coal or biomass, thereby gasifying the fuel source. In fluidized bed gasifiers, the fuel source is fluidized in oxygen/air and steam. The gas throughput of fluid bed gasifiers is higher than for fixed bed gasifiers, but not as high as for entrained flow gasifiers. In entrained flow gasifiers, a slurry of particulates and fluids is gasified with oxygen.
In the majority of gasifiers used, the heat required for the endothermic gasification reactions is supplied by partial oxidation of the feedstock, which usually occurs in the same reaction chamber where the gasification takes place. This is typically the case for the state of the art entrained flow gasifiers, which tend to have the highest throughput/size ratio of any conventional gasification scheme. However, this approach is feedstock dependant and requires detailed analysis to optimize the product gas composition.
Fixed bed and fluidized bed gasifiers, typically have lower outlet temperatures, e.g., below the ash slagging temperatures, than single stage entrained gasifiers. At lower gasifier outlet temperatures, more methane from coal devolatization survives, which results in a loss in hydrogen output and is typically 10-15 percent of the coal's carbon content at 400-500 psig.
Some gasifier designs use two stages to improve gasifier cold gas efficiency, to reduce the sensible heat in the product gas, and to lower the oxygen requirements. In a two stage entrained gasifier, however, the coal fed to the second stage reduces the outlet temperature and there is some methane survival in the syngas. Hence, a conventional gasifier will generally not have the performance ability and versatility of a modular catalytic combustion system having a separate gasification section.

SUMMARY

Methods for gasifying a process stream are disclosed. In some embodiments, the method includes the following: providing a process stream including a fuel source; applying a primary heat source to a first chamber containing the process stream; gasifying the process stream in the first chamber so as to produce a gasified process stream including one or more product gases; conducting at least a portion of the one or more product gases to a second chamber; combusting the at least a portion of the one or more product gases in the presence of one or more catalysts in the second chamber to generate a heat energy; and conducting the heat energy from the second chamber to the first chamber so as to provide the primary heat source.
A system for gasifying a process stream is disclosed. In some embodiments, the system includes the following: a first chamber for gasifying the process stream to produce a gasified process stream including at least one of one or more product gases, water, and particulates, the gasification chamber including sidewalls; a primary heat source for heating the first chamber; and a second chamber for combusting the process stream, said second chamber in fluid communication with the first chamber and at least a portion of the process stream, the second chamber including one or more portions that are in thermal communication with respective ones of the sidewalls of the gasification chamber, the second chamber including interior surfaces having a coating formed from one or more catalysts, the second chamber being configured to combust at least a portion of the process stream to generate a heat energy that serves as the primary heat source and is provided to the first chamber via the one or more portions that thermally communicate with the first chamber.
A catalytic reaction gasifier for gasifying a process stream is disclosed. In some embodiments, the gasifier includes the following: a housing including one or more inlets and one or more outlets; a combustion chamber defined within the housing, the combustion chamber including a plurality of interior surfaces; one or more catalysts positioned within the combustion chamber; and a gasification chamber separate from but positioned so as to be in thermal communication with the combustion chamber, the gasification chamber including a first end and a second end, the first end being operably connected with the one or more inlets for receiving the process stream and the second end being operably connected with the one or more outlets.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings show embodiments of the disclosed subject matter for the purpose of illustrating the invention. However, it should be understood that the present application is not limited to the precise arrangements and instrumentalities shown in the drawings, wherein:

FIG. 1 is a schematic diagram of a system according to some embodiments of the disclosed subject matter;

FIG. 2 is a cross-sectional view of a gasifier device according to some embodiments of the disclosed subject matter;

FIG. 3 is a diagram of a process according to some embodiments of the disclosed subject matter;

FIG. 4 is a graph of the simulation results for hydrogen production and energy required versus the percentage of carbon dioxide recycled to the catalytic combustion chamber for systems and methods device according to some embodiments of the disclosed subject matter;

FIG. 5 is a graph of the simulation results for hydrogen production and energy required versus the percentage of carbon dioxide recycled to the catalytic combustion chamber for systems and methods device according to some embodiments of the disclosed subject matter;

FIG. 6 is a graph of the simulation results for hydrogen production and energy required versus the percentage of carbon dioxide recycled to the catalytic combustion chamber for systems and methods device according to some embodiments of the disclosed subject matter;

FIG. 7 is a graph of the simulation results for water and methane versus the percentage of carbon dioxide recycled to the catalytic combustion chamber for systems and methods according to some embodiments of the disclosed subject matter;

FIG. 8 is a graph of the simulation results for hydrogen production and energy required versus the percentage of carbon dioxide recycled to the catalytic combustion chamber for systems and methods device according to some embodiments of the disclosed subject matter;

FIG. 9 is a schematic diagram showing how heat is generated in a catalytic combustion chamber designed in accordance some embodiments of the disclosed subject matter; and

FIG. 10 is a schematic diagram showing how heat is generated in a prior art combustion chamber.

DETAILED DESCRIPTION

The disclosed subject matter of the present application relates to systems, methods, and devices that can be used to gasify a process stream containing a fuel source. Gasification is a process that converts a fuel source, such as coal, petroleum, petroleum coke, and biomass, into carbon monoxide and hydrogen.
The systems, methods, and devices according to the disclosed subject matter utilize heat energy produced from combusting gases produced during the gasification of the fuel source to drive the gasification process. Gasification of the fuel source is generally conducted in the presence of one or more catalysts. A supplemental heat energy source is typically used to initiate the gasification process. However, the heat energy produced during combustion of the gases produced during the gasification is used as the primary energy source for driving gasification after it has commenced. The use of catalytic combustion, which can provides reaction and heat transfer rates that are significantly greater than those generated by bulk combustion used in conventional indirectly heated gasification schemes, allows the efficient use of indirect heating for entrained flow configurations, e.g., coal/biosolids+steam and/or CO₂, for a wide range of scales and applications.
Carbon monoxide and hydrogen can be separated from the gases generated in the gasification process to generate electricity. Carbon dioxide generated during the combustion of the gasification gases can be recycled for gasification with the fuel source or contained as a sequestration-ready source of carbon dioxide. Alternately, hydrogen can be recycled and catalytically combusted with air to provide the required heat without carbon dioxide generation.
Referring now to the drawings and in particular to FIG. 1, one embodiment of the disclosed subject matter is a system 20 for gasifying a fuel source 22. System 20 includes a gasification chamber 24 in fluid and thermal communication with a combustion chamber 26.
Fuel source 22, which is typically coal or a biomass, but can alternatively be other combustible materials, is gasified in a first chamber, e.g., gasification chamber 24, to produce a process stream 28. Process stream 28 includes at least one of one or more product gases, water, and particulates, e.g., ash. As used herein, process stream 28 is used in reference to a dynamic process stream that is altered as it travels through system 20. One or more product gases (not shown) can include at least one of hydrogen, carbon monoxide, and combinations thereof. A primary heat source 30 is indirectly applied to gasification chamber 24 to heat the gasification chamber and drive the gasification of process stream 28. The components illustrated in FIG. 1 are not drawn to scale and may be sized according to the requirements of a particular application or as determined by one skilled in the art.
A second chamber, e.g., combustion chamber 26, which is separate from but in fluid communication with gasification chamber 24 to receive a portion of process stream 28, includes one or more portions 32 that thermally communicate with the gasification chamber. Combustion chamber 26 is configured to combust at least a portion of process stream 28 to generate a heat energy 34. After the gasification process has commenced, heat energy 34 indirectly serves as primary heat source 30 and thermally communicates with gasification chamber 24 via one or more portions 32 that are common to or coextensive with respective ones of sidewalls 35 of the gasification chamber. An auxiliary heat source (not shown) can be used to begin the gasification of fuel source 22.
Combustion chamber 26 also includes interior surfaces 40 having a coating (not shown) disposed thereon and formed from one or more catalysts (not shown). Examples of suitable catalysts include the following: one or more precious group metal formulation catalysts such as rhuthenium, rhodium, palladium, osmium, iridium, platinum, and the like; one or more hexaaluminates such as AxB_(1-x)Al₁₁O₁₈, where A can be Rh or Ni, and B can be La, Mn, or Sr, barium hexaaluminate, manganese hexaaluminate, platinum-barium hexxaaluminate, and the like; one or more spinel catalysts such as CuCr₂O₄, MnFe_1.95Ru_0.05O₄, MnCO₂O₄, and the like; one or more zeolite catalysts such as lovdarite and those sold under the trademarks YZSM-5, LINDE ZEOLITE-A, PENTASILS, and the like; and one or more base metal formulation catalysts such as Cu, Co, Fe, Ni, and the like.
System 20 can also include a hydrogen separator 42 for separating hydrogen from process stream 28. Separated hydrogen can be stored in a hydrogen storage tank 44 and/or utilized as an energy source in other processes, such as a proton exchange membrane fuel cell (not shown in FIG. 1).
System 20 can also include a particle separator 46 such as a cyclone or the like for separating particulate matter such as ash from process stream 28. The separated particulate matter can be disposed of using conventional means. In certain embodiments, particle separator 46 can also remove some water in addition to removing particulates from the process stream 28.
System 20 can also include a water separator 48 for separating water 50 from process stream 28. Separated water 50 can be recycled in system 20 by mixing it with fuel source 22 before introduction to gasification chamber 24. An additional source of water, a make-up water supply 52, can also be included in system 20 to supplement separated water 50 as necessary.
System 20 can also include a divider 54 for dividing process stream 28 after water is separated from the process stream. Divider 54 can be used to adjustably divide the process stream into first and second process streams, a process stream 28′ and a process stream 28″, respectively, both of which are primarily made-up of carbon monoxide after process stream 28 has passed through hydrogen, particle, and water separators 42, 46, and 48, respectively. In some of the embodiments, divider 54 merely divides process stream 28 in to various portions. However, in other embodiments, divider 54 may serve as a carbon monoxide filter to remove only carbon monoxide from process stream 28. Process stream 28′ can be utilized in one or more power generating systems such as, but not limited to a gas turbine engine, an internal combustion engine, a solid oxide fuel cell (SOFC) 56, and/or other similar power generating systems known by those of ordinary skill in the art. SOFC 56 typically produces electricity and sequestration-ready carbon dioxide. Process stream 28″ can be recycled directly to combustion chamber 26 for catalytic combustion or mixed with an oxygen supply 58 at a mixer 60 and then recycled to the combustion chamber. Combustion chamber 26 generally produces sequestration-ready carbon dioxide, which can be stored in a carbon dioxide holding tank 62 and either disposed of using conventional means or recycled back to gasification chamber 24.
In some embodiments, system 20 is designed to be modular. As a modular system, the specific components of system 20 can vary from those illustrated and FIG. 1 but generally include some or all of gasification chamber 24, combustion chamber 26, hydrogen separator 42, particle separator 46, water separator 48, and divider 54. In addition, the components that make-up system 20 can be individually skid-mounted, individually self-contained, and generally designed to be connected in the field.
Referring now to FIG. 2, a modular catalytic reaction gasifier 70 for gasifying a fuel source, such as, but not limited to, coal, a biomass, and/or other combustible materials selected by those skilled in the art, is disclosed. Gasifier 70 includes a housing 72, which includes wall partitions 73 that define a combustion chamber 74, and one or more tubes 75 that define a separate gasification chamber 76 that is positioned in thermal communication with the combustion chamber. Combustion chamber 74 and gasification chamber 76 are configured so that a portion of heat energy (not shown) generated in the combustion chamber indirectly heats the gasification chamber thereby gasifying the fuel source into a process stream containing hydrogen. Housing 72 includes a first inlet 78 for allowing the fuel source to enter gasification chamber 76 and a second inlet 80 for allowing carbon monoxide, oxygen, or a combination thereof to enter combustion chamber 74. Housing 72 also includes a one or more outlets including a first outlet 82 for exhausting gases from combustion chamber 74, a second outlet 84 for exhausting solid wastes from gasification chamber 76, a third outlet 86 for exhausting gaseous wastes from the gasification chambers, and a fourth outlet 88 for exhausting hydrogen from the gasification chambers.
As discussed above with respect to system 20 and combustion chamber 26, combustion chamber 74 generally includes a plurality of exterior surfaces 89 and interior surfaces 90. Interior surfaces 90 typically include a coating deposited thereon that is substantially made-up of one or more catalysts. Similar to system 20 and combustion chamber 26, examples of acceptable catalysts include precious group metals, hexaaluminates, spinels, zeolites, base metal formulations, and combinations thereof.
As discussed above, in some embodiments, gasification chamber 76 is typically made-up of one or more tubes 75 that extend through combustion chamber 74. Each of one or more tubes 75 includes a first end 94 that is generally operably connected with first inlet 78 and a second end 96 that is generally operably connected with one or more of the outlets of housing 72. Each of one or more tubes 75 includes a sidewall 97 that is common to and in thermal communication with interior surfaces 90 of combustion chamber 74. In some embodiments, second end 96 can be flared, which would serve to increase the space between the ash particles and tube walls, while resulting in a “jet” of particles down the center of the flared section. Each of one or more tubes 75 generally includes an exterior surface 98 having a coating deposited thereon that is substantially made-up of one or more catalysts similar of the same as those coating interior surfaces 90 of combustion chamber 26.
Energy transfer to the reactants can be accomplished by indirect radiation in systems and methods according to the disclosed subject matter. Using coal as the fuel source, if the walls of one or more tubes 75 operate at 1200K and the coal particles are about 20 micron and remain cold due to endothermic reactions, e.g., particle surface temperature is approximately 500K, the energy transfer to the particle via radiation can be about 100 kW/m2. The transfer of this energy can result in a 20 micron spherical coal particle completely reacting on the order 0.5-1.0 seconds. Therefore, it is possible to transfer enough energy to sustain the gasification reaction, which was assumed to need about 150 kJ/mol with reasonable particle residence times. These residence times are roughly the same as that observed in conventional coal gasifiers.
When operating with coal, slagging issues can be at least partially addressed orienting gasification chamber 76 in a particular manner. For example, if the ash fusion temperature is below 1000 degrees Celsius, gasification chamber 76 can be designed in a vertical configuration to allow slag to run down the walls. However, most coals can have ash fusion temperatures well above 1000 degrees Celsius. If this is the case, although ash deposition on surfaces (not shown) of gasification chamber 76 can cause problems, there are certain effects that will limit the amount of ash that is deposited to the surfaces of one or more tubes 75. First, since the walls are hot and the core gas is cold, a driving force will push the particles (ash) toward the center (also known as the Soret effect). Second, evaporation of volatiles off the coal particle surface facing the hot wall of one or more tubes 75 can be significantly faster than the evaporation of volatiles off the coal particle surface facing the center. Therefore, there can be a volume expansion of gases near the hot walls of one or more tubes 75 forcing the ash particles to the center.
Housing 72 can also include a carbon monoxide separator 100 and a hydrogen separator 102 for separating both carbon monoxide and hydrogen from the process stream after it exits gasification chamber 76. Carbon monoxide separator 100 generally includes a polymeric membrane, ceramic membrane, filter, or other suitable means. Hydrogen separator 102 is typically a palladium membrane or similar. Pressure swing absorption can also be used to separate hydrogen from the process stream.
In the embodiment illustrated in FIG. 2, gasification chamber 76 is in the form of tubes that extend through combustion chamber 74. However, although not illustrated, in other embodiments, the combustion chamber can include at least one tube that extends through the gasification chamber.
Referring now to FIG. 3, another aspect of the disclosed subject matter is a method 200 for gasifying a fuel source. The fuel source can be combustible materials such as, but not limited to, coal, biomass, and/or other combustible materials selected by those skilled in the art. For example, biomass such as, but not limited to, leaves, garden wastes, wood chips, waste paper, municipal solid wastes, agricultural waste (e.g., switch grass, wheat straw, etc.), animal wastes (e.g., chicken, cow, sheep, dog, etc. litter), treated sewage sludge, grease, waste oils, and/or other combustible biomass.
In some embodiments, the fuel source utilized is coal. For a process stream including a mixture of coal and water, the mixture can be gasified in a gasification chamber according to reaction [1]:
C+H₂O
CO+H₂ [1]
Reaction [1] involves reforming carbon by steam and can be referred to as a steam reforming (SR) reaction. In order to gain the benefits related to catalytic conversion, which are discussed later, systems and methods of the disclosed subject matter include SR reactions that are carried out at temperatures of less than 1000 degrees Celsius. For example, the SR reaction can be carried out at temperatures between 600-1000 degrees Celsius. Alternatively, the SR reaction can be carried out at temperatures between 700-900 degrees Celsius. More particularly, the SR reaction can be carried out at temperatures between 800-850 degrees Celsius.
At 210, a determination is made whether to mix a portion of water with the fuel source before gasifying the fuel source. If water is added, the method continues at 212 where the water is mixed with the fuel source to develop a process stream 214. If coal is selected as the fuel source, any suitable ratio of water to coal can be utilized. For example, water can be mixed with coal at a particular ratio to obtain a slurry having a suitable viscosity. In some embodiments, a viscosity of from about 20 centipoises to about 500 centipoises can be utilized. In certain embodiments, a viscosity of from about 100 to 200 centipoises can be utilized. Water can also be mixed with coal at a particular ratio to obtain a desired energy conversion efficiency. Water can also be mixed with coal at a particular ratio to obtain a desired syngas output capacity. Coal particle size ranging from approximately 20 μm to 250 μm can be utilized. As discussed in greater detail below with respect to the simulation results, typically, the portion of water is mixed with the fuel source so that a water to fuel source ratio ranges from about 0.7 to about 1.0. At 216, process stream 214 is gasified in a first chamber. A primary heat source 218, which is discussed further below, is generally applied to the first chamber to carry out the gasification process.
After gasification, process stream 214 generally contains one or more product gases, including carbon monoxide and hydrogen, particulate matter including ash, impurities, and/or unreacted fuel source, e.g., coal, and water. At 220, hydrogen is separated from process stream 214. A portion of the hydrogen can be used to generate a consumable energy such as, but not limited to, electricity. At 222, particulate matter is separated from a hydrogen-depleted process stream 214. At 224, water is separated from a hydrogen and particulate matter depleted process stream 214. A separated water stream 226 can then optionally be mixed with the fuel source at 212 and gasified at 216.
At 228, process stream 214, which primarily includes carbon monoxide, is divided according to predetermined ratios. Optionally, process stream 214 can be further processed before to refine the carbon monoxide present in the stream prior to division of the stream.
A first portion 230 is divided from process stream 214 and forwarded to an energy producing process such as, but not limited to, a SOFC at 232 to produce consumable energy such as, but not limited to, electricity and sequestration-ready carbon dioxide. However, any suitable power-generating systems can be utilized in systems and methods according to the disclosed subject matter, as will be readily apparent to one of ordinary skill in the art. The remaining portion of process stream 214, a second portion 234, can be mixed at 236 with a predetermined amount of oxygen 238. In some embodiments, second portion 234 of the carbon monoxide is generally about 20 to about 60 percent of the carbon monoxide contained in the process stream. In another embodiment, second portion 234 of the carbon monoxide is generally about 30 to about 50 percent of the carbon monoxide contained in the process stream.
At 240, at least a portion of second portion 234, which can include a portion of oxygen 238, is combusted in a second chamber in the presence of one or more catalysts to generate a heat energy 242. In an embodiment where coal is selected as the fuel source, the catalytic combustion reaction can be represented by reaction [2]:
2CO+O₂
2CO₂. [2]
Heat energy 242 is generally indirectly applied from the second chamber to the first chamber as primary heat source 218 to gasify process stream 214. It is preferred that the gasification of second portion 234 is substantially driven from heat energy 242, which is generated from combusting at least a portion of the one or more product gases, which generally include carbon monoxide, in the presence of one or more catalysts. A maximum temperature while combusting second portion 234, which includes one or more product gases, is about 1300 degrees Celsius.
Carbon dioxide 244 is typically generated while combusting at least a portion of the one or more product gases, e.g., second portion 234. The carbon dioxide that is generated can be sequestration-ready. At least a portion of carbon dioxide 244 can be recycled by gasifying it with process stream 214. Alternately, hydrogen can be recycled and catalytically combusted with air to provide the required heat without carbon dioxide generation.
Using a personal computer, simulations of the systems and methods of the disclosed subject matter have been performed using a simulator application sold under the 5 trademark ASPEN. Flow sheets were programmed to study the effect of changing the water to carbon molar ratio (S/C) and the effect of the amount of or percentage by weight of carbon dioxide generated in equation [1] above that is recycled into the gasification chamber (R). Similar to system 20 in FIG. 1, the simulations utilized a gasification chamber, a catalytic combustion chamber, and processes for separating carbon monoxide and carbon dioxide. To simplify calculations, coal was assumed to be a bituminous coal that does not contain sulfur or generate ash. A moisture or water separator and a hydrogen separator were combined as one unit and a cool down heat exchanger was inserted between the gasification chamber and water/hydrogen separator to drop the temperature from the gasification chamber outlet to a typical temperature for a separation unit. The water/hydrogen separator, carbon monoxide separator, and carbon dioxide separator were modeled as ideal separators.
In the simulations described herein, hydrogen production rate (kg/hr) and energy (MJ/hr) were calculated as a function of the relative amount of carbon monoxide recycled to the catalytic combustion chamber versus the SOFC (COR). For example, if 40 percent by weight of the carbon dioxide generated in equation [1] is recycled to the catalytic combustion chamber, the COR=0.4.
Simulation 1: No recycling of carbon dioxide to catalytic combustion chamber (R=0). In this first simulation, equal molar amounts of water and C were fed into the gasification chamber (i.e., S/C=1.0) and the amount of carbon dioxide recycled to the catalytic combustion chamber was set to zero (i.e., R=0). As shown in FIG. 4, hydrogen production rate remains constant at about 0.84 kg/hr for 0.5 kmol/hr of coal regardless of the COR value. The energy required to run the gasification chamber exceeds the energy generated by the catalytic combustion chamber if not enough carbon monoxide is recycled to the catalytic combustion chamber. The results show that about 48% of the carbon monoxide generated by reaction [1] above can be sent to the catalytic combustion chamber (versus 52% to the SOFC) to run the gasification chamber without additional energy. Analysis shows that from the 52% carbon monoxide provided to the SOFC, about 13.5 kW of electricity can be generated by a typical SOFC from one kmol of coal. This translates to about 1,000,000 kd/day of hydrogen produced assuming a 100 MWe SOFC utilizing about 50% of the carbon monoxide generated by equation [1] in the gasification chamber.
Simulation 2: 25 percent of carbon dioxide recycled to catalytic combustion chamber (R=0.25). One option available in the systems and methods of the disclosed subject matter is the possibility of recycling a portion of the carbon dioxide that is produced in the catalytic combustion chamber to the gasification chamber. As shown in FIG. 5, if 25% of the carbon dioxide is recycled to the gasification chamber, more hydrogen is produced as compared to when 0% carbon dioxide is recycled to the gasification chamber. Moreover, less carbon monoxide needs to be recycled to the catalytic combustion chamber to generate enough power to run the gasification chamber without additional input of energy.
Simulation 3: 50 percent of carbon dioxide recycled to catalytic combustion chamber (R=0.5). Referring now to FIG. 6, if 50% of the carbon dioxide is recycled to the gasification chamber, more hydrogen is produced at low carbon monoxide recycle ratios, but rapidly decreases to value below that of R=0 and R=0.25 as COR increases. Moreover, even less carbon monoxide needs to be recycled to the catalytic combustion chamber than R=0.25 to allow the catalytic combustion chamber to generate enough power to run the gasification chamber without additional input of energy.
Without being bound by theory, the following reactions shown in Table 1 along with the enthalpies of each reaction can be considered to understand the results of the simulation between R=0, R=0.25, and R=0.5 for S/C=1.0.

TABLE 1

Primary reactions taking place in the gasification chamber

Name of Reaction	Reaction	ΔH (kJ/mol)

Steam Reforming (SR)	C + H₂O CO + H₂	+175
Boudouard	C + CO₂ 2CO	+173
Water-Gas Shift (WGS)	CO + H CO₂+ H₂	−41
Methanation	2C + 2H₂O CH₄+ CO₂	+105

Referring now to FIG. 7, in the absence of carbon dioxide recycle to the gasification chamber, SR reaction is the primary reaction taking place although some methanation reaction occurs. The amount of methane and water generally remains constant. This can be because the temperature of the reformer is fixed and additional heat generated or required factors into the heat balance calculations. Hence, the reactions occurring in the gasification chamber do not change with varying amounts of carbon monoxide in the catalytic combustion chamber.
However, with the introduction of carbon dioxide into the gasification chamber, the Boudouard reaction, which has a slightly lower enthalpy of reaction than the SR reaction, appears to be favored. The Boudouard reaction generates two carbon monoxide molecules for each carbon (coal) molecule reacted with carbon dioxide. The carbon monoxide can then be shifted to hydrogen by the WGS reaction, which is exothermic and, hence, more efficient than the SR reaction, which can explain the lower energies requirement observed for the same amount of carbon monoxide supplied to the combustion chamber with increasing values of R (see FIG. 6). An overall reduction for energy required in the gasification chamber can also allow more yield of hydrogen.
As shown in FIG. 7, less methane is produced when R=0.25 as compared to R=zero. Particularly, at about carbon monoxide split ratios of 0.4 and greater, a condition is achieved where methane production is effectively zero whereas water production increases even faster. FIG. 5 shows that the maximum hydrogen production occurs at COR values of about 0.4 and 0.5. This occurs because at COR values greater than about 0.4, additional carbon dioxide begins to hinder the WGS reaction as water production dramatically increases and hydrogen production decreases.
Referring again to FIG. 6, the effect of increasing the carbon dioxide recycle ratio to 0.5 for S/C=1.0 is illustrated. Free hydrogen decreases more rapidly than R=0.25 because, as discussed above, the concentration of carbon dioxide into the gasification chamber increases twice as fast compared to the case of 25% recycle. For this scenario, although the COR is less for the catalytic combustion chamber to operate the gasification chamber, the amount of hydrogen generated is less than the 25% recycled case, but still more than the baseline. If the amount of hydrogen produced is less important than the amount of energy needed, then opting for a 50% carbon dioxide recycle can enable the generation of about 30% more power compared to 25% recycle with a 10% less hydrogen production. For example, if the objective is to generate clean power by combusting the carbon monoxide and hydrogen in an Integrated Gasification Combined Cycle (IGCC) configuration, then a 50% carbon dioxide recycle is likely desired. If, however, the objective is to generate large amounts of hydrogen for distribution or fuel cell applications, then a carbon dioxide recycle of 25% is likely desired.
Simulation 4: Relative ratio of water to coal supplied to the gasification chamber (S/C=0.7, 1.0, and 1.5). FIG. 8 illustrates the results of various S/C values for a 25% carbon dioxide recycle (R=0.25). Of the conditions investigated, S/C=1.5 gave the highest hydrogen generation rates. The amount of carbon monoxide to be recycled to the catalytic combustion chamber (i.e., COR value) was the same as that of the results obtained for S/C=1.0 and R=zero (see FIG. 4) with nearly 37% more hydrogen production. Conversely, compared to S/C=1.0 and R=0.25, about 15% more hydrogen can be generated while using about 10% more carbon monoxide for combustion.
Still referring to FIG. 8, a steam to carbon ratio of 0.7 is the least favorable from an energy requirement and hydrogen production standpoint. Effectively, enough steam may not exist to generate significant amounts of hydrogen and the major gasification reaction occurring is the Boudouard reaction. It is, however, very energy efficient. Hence, if the goal is to gasify carbon for energy generation, then low S/C values with high R values are generally desired.
For S/C ratio of greater than 1.0, a slipstream of product carbon monoxide can be shifted to carbon dioxide+hydrogen via the WGS reaction in a downstream shift reactor with the excess water (above the 1-1 water/carbon molar ratio). The hydrogen can be diffused away leaving a carbon dioxide stream, which can be combined with the upstream for sequestration.
Systems and methods according to the disclosed subject matter include indirectly heating the reactor to provide the necessary heat in an entrained flow configuration, e.g., coal, biosolids, and/or steam and/or carbon dioxide, using heat from a form of catalytic combustion. Patent catalytic partial oxidation of the coal or biosolids is accomplished using reaction path, whereby a recycled product gas, e.g., carbon monoxide, is catalytically oxidized to produce the necessary heat to produce the product gases.
Direct catalytic partial oxidation of a solid feedstock, i.e., coal or biosolids, is generally not feasible. In order to catalytically combust solid carbon, a reaction path in which some product gas from an endothermic reaction such as, but not limited to, the Buodouard reaction, CO₂+C−2CO is catalytically combusted(CO+1/2CO₂+catalyst-CO₂+heat) to drive the endothermic reaction, yielding catalytic partial oxidation of the solid feedstock, i.e., C(solid)+1/2O₂+catalyst−CO.
In addition, the geometry of at least one system according to the disclosed subject matter, which produces a high surface/volume ratio, maximizes the heat transfer between the combustor and the gasification reactor, and lends itself to not only large scale power generation, but also to mass produced small scale gasification systems including even micro reactor gasifiers. Systems according to the disclosed subject matter are suited for modular configurations and can be part of a biorefinery when biomass is used as the feedstock. Systems according to the disclosed subject matter allow for easier adjustment of the operating parameters for differing feedstock's than in a conventional oxygen or air blown gasifier, which cannot be utilized effectively for certain biomass feedstock.
Systems and methods according to the disclosed subject matter can produce a sequestration ready stream of carbon dioxide, separate from the product gases. In a conventional oxygen blow gasifier, there is typically a portion of carbon dioxide mixed with the product gases.
Systems and methods according to the disclosed subject matter provide a gasification process that generates hydrogen and carbon monoxide, which can be used to produce consumable energy such as, but not limited to, electricity. In addition, carbon monoxide generated during the gasification of coal can be partitioned so that a portion of the carbon monoxide is utilized to drive the gasification reaction. Moreover, only one fuel source, e.g., coal or a biomass, is required to produce both the hydrogen and the heat needed to drive the system, thereby eliminating or reducing the need for secondary fuel sources, such as, but not limited to, methane and the like, to provide the necessary heat to drive the gasification reaction.
As described above, systems and methods according to the disclosed subject matter can provide a unique reactor design that can operate at sufficiently low and uniform temperatures due to catalytic oxidation of product gases and allow the use of conventional materials and technologies in various processes of the present application, such as, but not limited to, hydrogen separation.
Moreover, systems and methods of the disclosed subject matter allow a wide variation in product gas composition to be obtained in a controlled fashion. Regardless of the product gas composition, separate sequestration ready carbon dioxide stream can be produced.
In addition, systems and methods of the disclosed subject matter require less oxygen to obtain specific hydrogen/carbon monoxide ratios in the product gases than in conventional single stage oxygen blown gasifier due to the catalytic combustion of the product gases.
Systems and methods of the disclosed subject matter allow improved plant efficiencies over standard gasification techniques. For example, economic gasification of low rank high moisture coals that have maximum dry solids contents of around 50% is likely possible.
Systems and methods of the disclosed subject matter can be produced in multiple small units as well as large central plants because heat transfer properties can be enhanced at small scales. As a result, a wide range of economical applications such as, but not limited to, a bench top operation are possible.
Catalytic combustion of carbon monoxide to carbon dioxide or hydrogen to water using air or oxygen provides several benefits. For example, utilizing catalysis to achieve the conversion of carbon monoxide to carbon dioxide and energy utilizing catalysis can allow the systems and methods of the disclosed subject matter to 1) operate outside homogeneous flammability regimes, 2) generate heat on the surface of the catalyst (as opposed to the gas phase), and 3) produce little or no emission gases.
First, the ability of the catalyst to operate outside the flammability regime normally needed by homogeneous systems allows for thermal efficiency gains. For example, to maintain a stable homogenous flame, temperatures near 2000 degrees Celsius are typically needed. However, combustion and heat transfer materials generally cannot withstand temperatures greater than 1250 degrees Celsius and usually are required to be kept below 1000 degrees Celsius. This necessitates the use of secondary (dilution) air to cool the combustion products to temperatures that the heat exchanger materials can withstand which results in one direct loss of efficiency.
Second, the ability of the catalyst generate heat on its surface during the carbon monoxide to carbon dioxide conversion allows for efficient heat transfer to the gasification reaction. The heterogeneous reaction requires one or both of the reactants to be adsorbed on the surface of the catalyst. In the case of carbon monoxide oxidation, carbon monoxide molecule is strongly adsorbed to the catalyst surface, which then reacts with oxygen to generate carbon dioxide. During this reaction, there is a heat release on the surface of the catalyst, which is transferred to the gasification reaction. FIG. 9 shows a conceptual depiction of the systems and methods of the disclosed subject matter where the heat release can occur on the catalyst. Referring now to FIG. 10, this is contrasted with conventional indirectly heated homogeneous gasification systems that are known in the prior art, where the heat release can occur in the bulk.
The heat transfer across the catalyst support and the metal substrate can be nearly 1000 times faster than the heat transfer that occurs across the momentum boundary layer. Calculations indicate that the primary mechanism of heat transfer from the metal surface to the gasification reaction likely occurs via radiation. The coal particles, which can be considered a black body, can be maintained at a temperature close to that of the gasification reaction conditions, i.e., approximately 600K, while the surface of the metal substrate can be nearly 1200K. Hence, there can be a considerable driving force for radiative heat transfer.
This is in contrast to the homogeneous system where the heat release is in the bulk flow of the combustion side. In that case, the heat must be transferred through the momentum boundary layer, then through the metal heat exchanger, and finally into the gasification reaction. This is a much slower and less efficient process.
Systems and methods according to the disclosed subject differ from fixed bed, fluidized bed, and multi-stage gasifiers. For example, simulation of a conventional single stage entrained flow gasifier with the same feed conditions produces slightly less than 0.7 kg/hr and requires twice as much oxygen as compared to Simulation 1 above. In addition, there is about 15% carbon dioxide in the conventional gasifier product stream as compared to about 1.5% carbon dioxide in Simulation 1 above. Because of the reduced oxygen requirements of the systems and methods according to the disclosed subject, economic gasification of low rank coals with high moisture contents can be feasible.
The ability of systems and methods according to the disclosed subject to operate the carbon monoxide combustion reaction at near stoichiometric conditions allows conversion of the carbon monoxide to carbon dioxide to occur with minimum dilution of nitrogen if air is used. If oxygen is used from an air separation unit, this can permit minimum oxygen usage with no need for excess oxygen. Therefore, the air separation unit can be properly sized to supply just the right amount of oxygen.
It has also been shown that catalytic combustion likely has the ability to interrupt NOx formation pathways and not allow carbon based emissions, such as, but not limited to, carbon monoxide and unburned hydrocarbons (UHC) to be released. Therefore, for embodiments according to the disclosed subject matter where oxygen is used to combust the carbon monoxide to carbon dioxide, it is likely that there will be no gas phase emissions. This is in contrast to a homogeneous system where NOx, especially thermal and fuel bound NOx, are routinely formed.
Systems and methods according to the disclosed subject matter can be up or down due to their catalytic nature. Systems and methods according to the disclosed subject matter can scale with gas velocity because the heat transfer aspects (i.e. radiation) can be very insensitive to geometric scaling parameters. Scalability can be done in at least two ways. First, systems according to the disclosed subject matter can be replicated many times over, effecting economies of mass production. Second, systems according to the disclosed subject matter can also be scaled up in the traditional sense. This is likely easier than scaling up other types of systems where heat loss must be considered.
Systems and methods according to the disclosed subject matter offer a modular design. Modular designs allow for rapid development cycles and the ability to swap modules in and out upon technological advances. Incremental construction of energy conversion facilities, and therefore incremental investment, can open the door for groups like developing nations who are excluded in the case of single large-scale investments. Higher reliability can result from the use of systems in which the failing of one component among thousands has a negligible effect. Modular scaling can allow for a flexible response to shortages. The development of automated controls and maintenance systems can provide efficient responses in these areas, as well as in standard operation. Central housing in large plants can be effective in applying the modular approach. Less materials, controls, and operation and maintenance can be required than an equivalent energy output from a number of dispersed modules and the central plant can have an enhanced flexibility to respond to changes. Individual units can include fuel-conditioning models, which, for example, can convert coal, coal slurries, biomass, or orimulsion into a syngas. Upstream units can prepare the input fuel; downstream energy conversion units can combust or electrochemically generate electric power. Other units can be designed to create specialty fuels like methanol, ultra clean Fischer Trospch diesel, or hydrogen.
Catalyst science has not evolved to the point where an a-priori prediction about performance of a given formulation can be given. Therefore, it is a benefit of the systems and methods of the disclosed subject matter that they can be easily and cheaply modified to accept new formulations as they are being developed. A modular approach can afford this in two significant ways. First, as the reactor train is being moved from an exhausted part of the tar sand field to a more fertile one, new catalysts can be quickly and easily installed, thus adding little, if any, downtime to the transfer. Second, as new formulations are being developed, they can be tested in-situ and compared directly against the ones already in operation. If the new catalysts yield different product compositions, in the overall system operation, this will not amount to a significant change in ultimate product quality.
Because catalytic systems are like living systems, their performance changes with time. One can develop a startup scheme where a bank of a given number of units is initially brought on line to satisfy a given demand. As those units age, new units can continuously be brought on line without having to bring the entire system offline. Therefore, there can be a continuous replacement scheme of these reactors with the net production being unchanged.
Although the disclosed subject matter has been described and illustrated with respect to embodiments thereof, it should be understood by those skilled in the art that features of the disclosed embodiments can be combined, rearranged, etc., to produce additional embodiments within the scope of the invention, and that various other changes, omissions, and additions may be made therein and thereto, without parting from the spirit and scope of the present application.

Claims

1. A method for gasifying a process stream, the method comprising:

providing a process stream including a fuel source;

applying a primary heat source to a first chamber containing the process stream;

gasifying the process stream in the first chamber so as to produce a gasified process stream including one or more product gases;

conducting at least a portion of the one or more product gases to a second chamber;

combusting the at least a portion of the one or more product gases in the presence of one or more catalysts in the second chamber to generate a heat energy; and

conducting the heat energy from the second chamber to the first chamber so as to provide the primary heat source.

2. A method according to claim 1, wherein the one or more product gases include at least one of hydrogen, carbon monoxide, and combinations thereof.

3. A method according to claim 1, further comprising:

before gasifying the fuel source, mixing an amount of water with the process stream.

4. A method according to claim 3, wherein the water to fuel source molar ratio of the amount of water ranges from about 0.7 to about 1.0.

5. A method according to claim 2, wherein the one or more product gases include hydrogen, and the method further comprises:

separating substantially all of the hydrogen from the process stream; and

generating a consumable energy with at least a portion of the hydrogen.

6. A method according to claim 3, further comprising:

separating substantially all of the water from the process stream; and

prior to gasifying, mixing at least a portion of the water with the process stream.

7. A method according to claim 2, further comprising:

dividing the process stream, which includes an amount of carbon monoxide, into first and second process streams each of which includes a portion of the carbon monoxide from the process stream before it is divided; and

generating a consumable energy with at least a portion of the carbon monoxide contained in at least one of the first and second process streams.

8. A method according to claim 7, further comprising:

mixing oxygen with at least one of the first and second process streams to prepare the at least one of the first and second process streams for combustion.

9. A method according to claim 7, wherein the portion of the carbon monoxide in the second process stream is from about 20 to about 60 percent by weight of the carbon monoxide contained in the process stream before it is divided.

10. A method according to claim 9, wherein the carbon monoxide in the second process stream is from about 30 to about 50 percent by weight of the carbon monoxide contained in the process stream before it is divided.

11. A method according to claim 1, further comprising:

generating carbon dioxide while combusting at least a portion of the one or more product gases; and

gasifying a portion of the carbon dioxide with the process stream.

12. A method according to claim 11, wherein the portion of the carbon dioxide gasified is from about 0 to about 50 percent by weight of the carbon dioxide generated while combusting at least a portion of the one or more product gases in the presence of the one or more catalysts.

13. A method according to claim 1, wherein gasifying the process stream is driven substantially from the heat energy generated from combusting at least a portion of the one or more product gases in the presence of one or more catalysts.

14. A method according to claim 1, wherein the fuel source is at least one of coal, a biomass, and combinations thereof.

15. A method according to claim 1, wherein gasifying the fuel source includes a maximum temperature of about 850 degrees Celsius.

16. A method according to claim 1, wherein combusting the one or more product gases includes a maximum temperature of about 1300 degrees Celsius.

17. A system for gasifying a process stream, the system comprising:

a first chamber for gasifying the process stream to produce a gasified process stream including at least one of one or more product gases, water, and particulates, the gasification chamber including sidewalls;

a primary heat source for heating the first chamber; and

a second chamber for combusting the process stream, said second chamber in fluid communication with the first chamber and at least a portion of the process stream, the second chamber including one or more portions that are in thermal communication with respective ones of the sidewalls of the gasification chamber, the second chamber including interior surfaces having a coating formed from one or more catalysts, the second chamber being configured to combust at least a portion of the process stream to generate a heat energy that serves as the primary heat source and is provided to the first chamber via the one or more portions that thermally communicate with the first chamber.

18. A system according to claim 17, wherein the one or more product gases include at least one of hydrogen, carbon monoxide, and combinations thereof.

19. A system according to claim 17, further comprising:

an oxygen supply in fluid communication with the second chamber.

20. A system according to claim 18, further comprising:

a separator for separating the hydrogen from the process stream.

21. A system according to claim 17, further comprising:

a separator for separating water from the process stream.

22. A system according to claim 18, further comprising:

at least one of a divider for dividing the process stream or a separator for separating carbon monoxide from the process stream.

23. A system according to claim 22, further comprising:

at least one of a fuel cell, a gas turbine engine, or an internal combustion engine capable of generating a consumable energy in the form of electricity from at least a portion of the carbon monoxide.

24. A system according to claim 17, wherein the one or more catalysts include one or more of precious group metals, hexaaluminates, spinels, zeolites, base metal formulations, and combinations thereof.

25. A system according to claim 17, wherein the first chamber and the second chamber are modular.

26. A system according to claim 17, wherein the process stream includes a fuel source including at least one of coal and a biomass.

27. A catalytic reaction gasifier for gasifying a process stream, the gasifier comprising:

a housing including one or more inlets and one or more outlets;

a combustion chamber defined within the housing, the combustion chamber including a plurality of interior surfaces;

one or more catalysts positioned within the combustion chamber; and

a gasification chamber separate from but positioned so as to be in thermal communication with the combustion chamber, the gasification chamber including a first end and a second end, the first end being operably connected with the one or more inlets for receiving the process stream and the second end being operably connected with the one or more outlets.

28. A gasifier according to claim 27, wherein the gasification chamber includes at least one tube that extends through the combustion chamber thereby allowing the gasification chamber to thermally communicate with the combustion chamber.

29. A gasifier according to claim 27, wherein the combustion chamber includes at least one tube that extends through the gasification chamber thereby allowing the gasification chamber to thermally communicate with the combustion chamber.

30. A gasifier according to claim 27, wherein the process stream includes a fuel source including at least one of coal and a biomass.

31. A gasifier according to claim 27, wherein the combustion chamber and the gasification chamber are configured so that a portion of heat energy generated in the combustion chamber heats the gasification chamber thereby gasifying the process stream into a process stream containing hydrogen.

32. A gasifier according to claim 31, further comprising:

at least one separator for separating hydrogen, particulates, water, or carbon monoxide from the process stream.

33. A gasifier according to claim 31, wherein the one or more outlets include a first outlet for exhausting gases from the combustion chamber, a second outlet for exhausting solid wastes from the gasification chamber, a third outlet for exhausting gaseous wastes from the gasification chamber, and a fourth outlet for exhausting hydrogen from the gasification chamber.

34. A gasifier according to claim 27, wherein the one or more inlets include a first inlet for receiving the fuel source and a second inlet for receiving carbon monoxide, oxygen, or a combination thereof.

35. A gasifier according to claim 27, wherein the one or more catalysts are selected from the group consisting of precious group metals, hexaaluminates, spinels, zeolites, base metal formulations, and combinations thereof.