HK1081588A - Pulse gasification and hot gas cleanup apparatus and process - Google Patents

Description

Pulse gasification and hot gas purification apparatus and method

RELATED APPLICATIONS

This application is based on and claims priority from provisional patent application 60/382302 filed on 5/22/2002.

Background

In conventional energy generation systems and other methods of direct combustion, a major concern with certain fuel utilizations is the particulates produced by the combustion of the fuel. These particles remain in the combustion gas stream. Since the airflow to operate such a system may adversely affect the life of the equipment, the airflow should be substantially free of these particulate matter. Although conventional particulate removal devices (particulate removal devices) may be used to remove some of the larger solid particulate matter from a combustion gas stream, these devices are generally not capable of removing smaller particulates from the gas stream. Similar problems exist with many gas streams where the particulate matter in suspension does not originate from combustion.

U.S. patent 5353721 to Mansour et al and 5197399 to Mansour et al describe a pulse combustion apparatus (pulsed combustion apparatus) and method, which are incorporated herein by reference for all purposes; the pulse combustion apparatus and method are used for acoustically focusing particulates generated by the combustion of fuel to remove particulates from a combustion effluent stream. After removing particulates from the combustion effluent gas stream, the gas stream can then be used in various processes and systems. For example, in one embodiment, the effluent stream is used to rotate a turbine to generate energy.

Tests have been carried out in this way in a Process Development Unit (PDU) using pulverized bituminous coal and four different sorbents for sulfur capture (sulfur capture), with the following test results: (1) the combustion efficiency is over 99 percent; (2) sulfur capture as high as 98%; (3) NO_xThe emission is in the range of 0.3-0.6 lb/MMBtu; and (4) solids loading (similar to turbine inlet solids loading) at cyclone outlet off-gas as low as 23 ppmw. The solids loading results were well below the initial target of 100-150ppmw, and good enough to meet the New resource Performance Standard (NSPS) (< 0.03lb/MMBtu) for power plant particulate emissions.

However, while operation in a combustion or lean burn mode provides satisfactory and encouraging results, the process is thermodynamically limited and presents various problems associated with emission control. In particular, the following limitations become apparent:

● under oxidizing or lean burn conditions, sulfur retention (sulfur retentions) or calcium utilization decreases as operating temperature increases. For example, at temperatures as high as about 1000 ℃ (1832 ° F), the Ca/S molar feed ratio requiring 95% sulfur capture is quite favorable, but rises dramatically with further increases in temperature. This limits the gas turbine inlet temperature and, in turn, the cycle or plant efficiency.

● low NO although pulse combustor is inherent_xThe plant, but the oxidation mode of operation, the presence of rich nitrogen (fuel bound nitrogen) and the high temperature all favor NO_xAnd (4) forming. Therefore, further reduction of NO is desired_xParticularly in the case of a demand for increased gas turbine inlet temperatures.

● higher temperatures (> 1000 ℃ or 1832 ℃ F.) in the enclosure favor sonic entrapment but not sulfur capture. This tends to limit the extent to which the solids loading in the cyclone outlet off-gas is reduced.

Accordingly, there is a need for improved attachment devices and methods.

Disclosure of Invention

In accordance with one embodiment of the present invention, an apparatus and process for gasifying feedstocks (e.g., coal, coke, other solid fuels, heavy liquid hydrocarbons, slurries, etc.) is described that produces a clean medium gas with in-situ hot gas cleanup. In a particular embodiment, the process uses a pulse gasification unit that combines one or two gasification stages. The method promotes acoustic agglomeration of the particles, thereby facilitating particle collection using conventional separation devices; and to facilitate the utilization of suitable adsorbents to capture gaseous pollutants in acoustically enhanced environments. The apparatus may be used in a variety of different configurations, such as a combined cycle configuration resulting from varying the combination of fuel cells, gas turbines and steam turbines for energy production, and a cogeneration configuration (gasification configuration) for the production of combined heat and electrical energy, for hydrogen production, liquid fuel production or direct iron reduction.

In one embodiment, for example, a gasifier (gasfield) system includes a pulse combustion device for first stage gasification, a U-tube arrangement for deslagging (slag), a vertical entrained flow section for second stage gasification, and primary and secondary cyclones for particulate capture. Oxygen and steam may be used as gasification agents to increase the product gas heating value and in turn to promote flame stability and eliminate (turn down) partial oxidation. For example, partial oxidation may occur in the first stage, while the dominant steam reforming process may occur in the second stage.

In the second stage, sorbent particles are injected into the gas stream under the influence of a strong acoustic field. The acoustic field acts to improve sorbent calcination by increasing the mass transfer rate in the gas film and the particles. In addition, the sorbent particles act as dynamic filter centers (filter foci), providing a high density of stagnant foci for capturing the finer entrained fly ash fraction. The regenerated sorbent may be used for in situ sulfur capture, and may include a sulfur recovery unit to produce a sulfur-containing byproduct. The by-product may be, for example, ammonium sulfate or sulfuric acid.

In a particular embodiment, the system of the present invention is used to generate a gas stream having a fuel or heating value (heatvalue). The system may include a fluid channel including a first stage section and a second stage section. The fluid channel may include a U-shaped portion that transitions the first stage portion to the second stage portion. The pulse combustion device includes a pulse combustor connected to at least one resonance tube (resonance tube), and the pulse combustion device may be placed in communication with the first stage portion of the fluid passageway. The pulse combustion device may be configured to combust solid or liquid fuels, as well as to generate a pulsating combustion stream (pulsating combustion stream) and an acoustic pressure wave (acoustic pressure wave). The fluid channel may be shaped to transmit the acoustic pressure waves from the first stage section to the second stage section.

The system may further include a sulfur capture agent injection port for injecting a sulfur capture agent into the second stage portion of the fluid channel. The sulfur capture agent may be configured to remove sulfur-containing gases from the pulsed combustion gas stream and to sonify any particulates contained in the pulsed combustion gas stream. Particulate removal devices, such as low velocity cyclones and high velocity cyclones, receive the combustion gas stream from the fluid passageway. The particulate removal device may be used to remove particulates from a gas stream. After removing particulates from the gas stream, the gas stream can be used in a variety of processes. For example, in one embodiment, the gas stream may be used to power a gas or steam turbine or may be used to power a fuel cell.

In addition to systems that generate gas, the present invention also relates to various methods for generating a gas stream having a fuel or heating value. In one embodiment, for example, the method may include the steps of combusting a solid or liquid fuel in a pulse combustion device and generating a pulsed combustion gas stream and an acoustic pressure wave. The pulse combustion apparatus may be operated under sub-stoichiometric conditions. As used herein, sub-stoichiometric conditions refer to combustion conditions where the amount of oxygen is insufficient to completely combust the fuel source. In the present invention, for example, the pulse combustion device may be operated at a stoichiometric level of about 30% to about 60%. Furthermore, solid or liquid fuel can be supplied to the pulse combustion device not only together with the oxygen source but also together with steam. The steam can be used to control the stoichiometry, control the temperature, and for steam reforming.

After the pulsating combustion gas stream and acoustic pressure wave are formed, they may be directed through a fluid passageway. At least a portion of the fluid channels may be operated under reducing conditions to promote steam gasification (steam gasification). In the steam gasification process, endothermic reactions occur in which hydrocarbon compounds are cracked and hydrogen is generated. Hydrogen and lower molecular weight hydrocarbon gases are useful energy sources.

According to the method of the present invention, a sulfur capture agent may be injected into the fluid channel. The sulfur capture agent may capture sulfur contained in the pulsed combustion gas stream. The sulfur capture agent also acoustically agglomerates with the particulates contained in the pulsating combustion gas stream.

The combustion gas stream containing hydrogen and entrained particles is then filtered from the fluid passageway using any suitable particulate removal device. For example, in one embodiment, a dual cyclone separator may be used to remove the agglomerated particles. The resulting product gas stream can then be used as desired for various processes.

In one embodiment, the agglomerated particles removed from the combustion gas stream may be supplied to a heated fluidized bed. The fluidizing medium in the fluidized bed may contain oxygen that causes an exothermic reaction in the fluidized bed. For example, in one embodiment, the sulfides contained in the agglomerated particles may be converted to sulfates. In an alternative embodiment, when the sulfur capture agent is ceria, the agglomerated particles may be placed in a fluidized bed to regenerate the ceria and produce sulfur dioxide. The gas stream generated in the fluidized bed can then be treated to remove sulfur dioxide.

In one embodiment, the fluid channel may include a first stage section and a second stage section. The first stage portion may be maintained at a temperature of less than about 4000 ° F and may include a first outlet temperature. In another aspect, the second stage section can include a second outlet temperature. The second outlet temperature may be less than the first outlet temperature, and may be no greater than about 1900 ° F, such as less than about 1700 ° F.

Conditions within the first stage portion of the fluid passageway may be maintained so as to allow partial oxidation, steam gasification and slagging. Slag may be periodically removed from the fluid passage as it forms.

However, within the second stage section of the flow channels, reducing conditions may be present to promote steam gasification (also known as steam reforming), which promotes the production of hydrogen and other lower molecular weight hydrocarbons.

Other features and aspects of the present invention are described in more detail below.

Drawings

A full and enabling disclosure of the present invention, including the best mode thereof, directed to one of ordinary skill in the art, is set forth more particularly in the remainder of the specification, which makes reference to the appended figures, in which like reference numerals refer to like parts throughout.

FIG. 1 is a schematic block diagram of one embodiment of a pulse gasification system of the present invention;

FIG. 2 shows a front view of one embodiment of a pulse gasifier of the present invention;

FIG. 3 is a cross-sectional view of one embodiment of a pulse gasifier of the present invention;

FIG. 4 is a cross-sectional view of one embodiment of a pulse combustion device that may be used in the systems and methods of the present invention;

FIG. 5 is a graph of the relationship between% sulfur capture and adiabatic gas temperature under reducing conditions, in accordance with an embodiment of the present invention;

FIG. 6 Sulfur Retention amounts (in CaS or CaSO) according to an embodiment of the invention₄In form) and temperature;

FIG. 7 is a schematic diagram of an embodiment of a pulse gasifier combined cycle for coal according to the present invention; and

FIG. 8 is a graph of net plant efficiency (net plant efficiency) versus coal feed to a pulse gasifier, according to an embodiment of the present invention.

Repeat use of reference characters in the present specification and drawings is intended to represent same or analogous features or elements of the invention.

Detailed Description

It is to be understood by one of ordinary skill in the art that the present discussion is a description of exemplary embodiments only, and is not intended as limiting the broader aspects of the present invention, which broader aspects are embodied in the exemplary constructions.

The present invention is generally directed to an innovative pulse gasification system that overcomes many of the limitations of existing pulse gasification systems and may be configured to comply with a new emissions target of one tenth of NSPS. For example, in one embodiment, the systems and methods of the present invention may be configured to emit less than about 0.12lb/MMBtu of sulfur dioxide, less than about 0.06lb/MMBtu of Nitrogen Oxides (NO)_x) And/or less than about 0.003 lb/MMBtu.

In one embodiment, the pulse gasifier system includes a pulse unit for first stage gasification, a U-tube arrangement for deslagging, and may also include a vertical entrainment flow section for second stage gasification and primary and secondary cyclones for particulate capture. The feedstock can be coal, coke, biomass, heavy liquid hydrocarbons, and the like, and can be in the form of solids, heavy liquids, slurries, and the like. Oxygen and steam may be used as gasification agents to increase product gas heating value, as well as to promote flame stability and turndown. This also helps to increase gas turbine inlet temperature and plant efficiency in the case of a combined cycle configuration. Air may be used as a gasifying agent, although in some cases it may also reduce the heating value of the gas due to the dilution of nitrogen. The compressed air can be used for pneumatic transport of the solid fuel from the metering tank (meteringbin) into the pulse gasifier. Superheated steam may also be used as the transport/carrier fluid. In some embodiments, superheated steam is the preferred carrier for the dry solid feedstock.

Pulse gasifiers include one or two gasification stages to promote good carbon conversion, high acoustic pressure levels for acoustic agglomeration, and good in situ sulfur capture. In the case of two stages, the first stage can be operated in slagging mode and under sub-stoichiometric conditions. In the presence of oxygen and steam, the volatile substances in the raw materials are removed and partially oxidized, and heat is released to enable the steam/raw material gasification reaction to be carried out. High operating temperatures (e.g., 2500 ° F-3400 ° F) can ensure high carbon conversion as well as aid in ash melting and slag flow.

In conventional slagging gasifiers, the slag zone corresponds to the active zone (active zone) of gas-solid mixing, combustion and tapping, all of which takes place on the furnace floor (hearth plate). The design and ability to keep the tapping process functional is sometimes important. It is state of the art to retain solids within the gasifier and still allow the liquid slag to be discharged through the slag outlet at a desired rate. In the pulse gasifier of the present invention, the slag zone may correspond to an active and a passive zone. In the active zone, partial oxidation, steam gasification and slagging can occur while the slag is discharged from the passive zone. Thus, the deslagging process/hardware design is relatively simple, and essentially the only requirement is not to allow the slag tap to freeze shut.

In a two-stage configuration, a U-tube connection arrangement may be provided between the first and second stages to ensure that slag can be collected efficiently and discharged from a port at the bottom of the U-tube. It is desirable for the slag to flow into the slag tap hole, primarily along the bottom of the front half of the U-bend, and then into the slag quench tank. Furthermore, this configuration forces the exit jets (exit jets) coming out of the exhaust pipe to hit the recessed portion and rotate. This enhances mixing within the chamber and increases the residence time of the carbon to optimize the carbon conversion efficiency. The second stage may or may not be employed. This will depend on the operating temperature of the first stage, as determined by the reactivity of the feedstock, and the slagging temperature of the ash (e.g. biomass and lignite are non-refractory and have a lower ash slagging temperature). In other embodiments, the selected feedstock may not be able to produce slag or the system may be configured to prevent slagging.

In the case of a two-stage system, the second stage may include a vertical refractory-lined section in which additional feedstock is injected to react with the hot gases from the first stage to increase the product gas heating value; and cooling the product gas to a threshold for in situ sulfur capture. Additional ports may be provided directly below the riser (riser) in the second stage to capture any sorbent-ash buildup that settles down. Oxygen and steam may be used to fluidize the media in the agglomerate capture section. For example, oxygen may be used to increase the char conversion and steam may be used to adjust the temperature in the second stage. In an alternative embodiment, steam is injected only into the second stage to promote the endothermic reaction that occurs during steam gasification.

The average gas temperature in the second stage may be between about 1000 ° F to about 2500 ° F. Examining the temperature dependence of sulfur capture at equilibrium under reducing conditions indicates that the gas temperature is in a suitable temperature range (e.g., from about 1400 ° F to about 2400 ° F) for achieving greater than 90% sulfur capture efficiency using calcium-based sorbents, as shown in fig. 5-6. The sulfur capture efficiency in the dynamic (non-equilibrium) case depends on the temperature of the particles, not the temperature of the gas.

Due to endothermic calcination, limestone or dolomite sorbents generally require time to reach gas temperature. This strategy is sometimes employed in the second stage so that near the bottom where the temperature is highest, sorbent is injected to assist in calcination. If a regenerable sorbent is used, such as ceria, the sorbent may be injected further downstream of the U-bend or in the middle region of the second stage. If desired, the residence time of the adsorbent in the second stage can be controlled by optimizing the position of the adsorbent injection port. Thus, in this embodiment, the sorbent particles flow into the intermediate portion of the second stage (temperature maintained at about 2000 ° F) well before the thermodynamics place a limit on sulfur capture. Such a strategy may ensure maximum sulfur capture for a given sorbent particle residence time. If necessary, a powdered alkali getter material (e.g., acid clay, hectorite or kaolin) may also be injected into the second stage to aid in alkali vapor capture.

The agglomeration of ash in the second stage can have significant benefits. For example, in some cases, such agglomeration may facilitate the utilization of one or more conventional particulate capture devices (e.g., hot cyclones) to reduce particulates in the gas stream to an acceptable level without resorting to more expensive candle filtration or problematic slag screens. In this case, the second stage effectively acts as a dynamic filter; in a dynamic filter, fly ash from coal fines is bound together with larger sorbent particles due to collisions between fine particles and sorbent centers.

Sonic agglomeration is a pre-treatment process that increases the average size of entrained particles, making it possible to obtain high collection efficiency by using a hot cyclone. It is often desirable to use two cyclones, with the primary cyclone being a low velocity cyclone that captures the agglomerates with minimal disruption, and the secondary cyclone being a high velocity, high efficiency cyclone that captures the fines. The relatively clean product gas from the secondary cyclone may be used for energy production, or steam production, or as a process fuel, or for hydrogen production, or for direct reduction of iron, or for fuel production and other synthesis gas applications. The solid capture from the hot cyclone contains both spent adsorbent and some unconverted carbon. The degree of unconverted carbon can be controlled and generally depends on process objectives and performance requirements.

In one embodiment, in the second stage, sorbent particles are injected into the gas stream under the influence of a strong acoustic field. The acoustic field acts to increase the efficiency of sulfur capture by increasing the mass transfer rate of the gas film and particles. In addition, the sorbent particles act as dynamic filter centers (filter foci), providing a high density of stagnant foci for capturing a finer fraction of entrained (in the vibrating flow field) fly ash. The particle size of the fly ash fraction is typically about 20 microns or less, and in some embodiments, about 1-20 microns. Thus, by introducing adsorbent particles centered primarily in the size range of 20-150 microns, a bimodal distribution is created. Bimodal distribution provides several advantages. First, by increasing the density (in the gas) of large stagnant trap centers (steady trap centers), a fast agglomeration rate can be obtained. Again, agglomeration can be effectively carried out at significantly lower acoustic frequencies than a unimodal distribution containing only the finer fly ash fraction.

In some cases, the efficiency of particle agglomeration at low frequencies may be important. The agglomeration rate is greatly influenced by the sound intensity level (acoustic intensity level). Lower frequency operation is generally more efficient because the attenuation of low frequencies is generally less than the attenuation of high frequencies. Furthermore, low frequencies do not affect the performance of the turbine blades, while frequencies in the kilohertz range may couple to the natural frequencies of the system and cause blade fatigue failure. Finally, the 50% entrainment cutoff (cut-off) particle diameter increases with decreasing frequency, so lower frequency operation results in entrainment of a larger portion of a given particulate material size distribution, and less restriction to the upper limit of particle growth.

Some of the chemical reactions in the high temperature (e.g., 1800 ° F-3400 ° F) first stage are believed to be as follows:

and (3) combustion:

partial oxidation:

with CO₂And (3) gasification:

by H₂O gasification:

H₂oxidation of (2):

and (3) oxidation of S:

reduction of sulfur:

ash conversion: ash being halides, sulfides, oxides

For a two-stage configuration, the hot fuel gas from the first stage can react with the fuel injected into the inlet of the second stage (if desired). In this case, volatile substances in the additional fuel are removed and vaporized. Further, the injected sorbent is calcined downstream and, if applicable, sulfided. The temperature in the second stage decreases from the inlet (about 2500F) to the outlet (about 1700F). Some of the chemical reactions in this region are believed to be as follows:

and (3) combustion:

partial oxidation:

with CO₂And (3) gasification:

by H₂O gasification:

gas replacement:

and (3) gasification:

NH₃forming:

H₂oxidation of (2):

and (3) oxidation of S:

and (3) S conversion:

ash conversion: ash being halides, sulfides, oxides

And (3) calcining:

and (3) vulcanization:

(OR)

If the fuel contains more than trace amounts (-10 ppm) of halogen (Cl, F, Br, I), acid gas (HCl, HF, etc.) and ash halides (NaCl, KCl, etc.) sometimes formed from the halogen can be captured and clean fuel gas produced. However, the temperature range for effective capture of these species is typically low and may be between about 1000 ° F to about 1400 ° F. Sodium-based absorbents (canasite, baking soda, etc.) are preferably used to absorb acid gases (HCl, HF, etc.) and alkaline getters (kaolin, acid clay, diatomaceous earth, alumina, etc.) are preferably used to capture alkalis (NaCl, KCl, etc.) through a combination of physical adsorption and chemical reaction. The corresponding reaction is as follows:

halogen conversion:

acid gas removal:

alkali removal:

in the formula, the letters in the parentheses () represent the phase of the substance, i.e., the letter "s" represents a solid; "g" represents a gas; "v" represents steam.

As described above, the fuel gas is typically cooled to a temperature of about 1200F to remove acid gases and alkaline vapors. If halogen is present in the feedstock, the second stage exit temperature (e.g., about 1200F.) may be lower than the temperature without halogen (e.g., from about 1700F. to about 1900F.). This can be achieved by using fuel gas cooling, which can be done either externally or internally. For example, a water jacket surrounding the second stage column section upstream of the outlet may provide external cooling. Since the medium to be cooled is mainly a gas or a gas-solid mixture, the heat transfer surface area required for fuel gas cooling is usually quite large, which may result in a quite high second stage. Furthermore, the corrosive nature of the fuel gas may require careful selection of the heat exchanger materials, which may increase the cost of the unit. Thus, in some embodiments, water may be sprayed directly into the fuel gas through an atomizer spray head (atomizer spray head) for cooling. The addition of water mass is typically small relative to the fuel gas mass due to sensible and latent heat contributions. For example, the water injection rate typically does not exceed about 5% of the fuel gas flow rate (by mass). The calorific value of the generated fuel gas is slightly low. Alternatively, the fuel gas may be cooled downstream of the cyclone separator and passed through a bed of sorbent particles to remove acid gases, a sulfur polisher (sulfur polisher) to further reduce the sulfur content, and a hot gas barrier absorption filter (barrier filter) to remove any entrained particulate matter.

Typically, 50-100% of the fuel is vaporized through the first stage, and the remainder (0-50%) may be injected into the inlet of the second stage. The actual fuel split (fuel split) between the first and second stages will depend on the application, fuel properties and unit size. Stoichiometry also depends on application, fuel properties and unit size. For example, the first stage stoichiometry may range between 30-60%, and the overall stoichiometry may be between 25-50% limits.

Computer simulations show that: if the fuel is free of halogens, the clean fuel gas produced in the pulse gasifier should have a heating value (on a wet weight basis) on the order of 275 Btu/scf. If there is halogen in the fuel, the heating value will be lower, depending on the concentration of halogen in the fuel, between 250 and 275 Btu/scf.

If desired, the pulse gasifier may be used in combined cycle configurations resulting from a change in the combination of fuel cells, gas turbines, and steam turbines for power generation, as well as in combined production configurations for combined heat and electrical power generation, hydrogen generation, liquid fuel generation, direct reduced iron or other synthesis gas applications. One embodiment of energy generation will be described below. Other embodiments for different applications may be formed by combining a pulse gasifier with components such as fuel cells, gas turbines, pressure swing adsorption units (pressure swing adsorbers) for hydrogen production, liquefaction reactors for fuel production, and the like.

Referring to fig. 1, fig. 1 shows a block diagram of one embodiment of the process of the present invention. It should be understood, however, that FIG. 1 is provided for illustrative purposes only and is not intended to limit the present invention in any way.

Referring now to fig. 7, fig. 7 shows one embodiment of a more detailed system of the present invention. In particular, FIG. 7 depicts one embodiment of a pulse gasification combined cycle made in accordance with the present invention.

As shown, the pulse gasification combined cycle ("PGCC") includes the following:

● coal handling and supply system (CHFS);

● sorbent handling and supply system (SHFS);

● basic and acid gas getter handling and supply system (AGHFS);

● pulse gasifier, hot cyclone and topping combustor (topping combustor);

● gas turbine generator set;

● atmospheric fluidized bed sulfater/burner (AFBSC);

● Heat Recovery Steam Generator (HRSG);

● a steam turbine generator set and a steam cycle assembly;

● dust-collecting chamber (Baghouse);

● ash, spent sorbent and slag handling and storage systems; and

● air separation plant.

Details of the system and method shown in fig. 7 are described below. It should be appreciated that fig. 7 is provided for exemplary purposes only and is not intended to limit any aspect or feature of the present invention. For example, none of the vapors shown in FIG. 7 may be construed as necessary or critical to the present invention. Furthermore, the features and aspects illustrated and described in FIG. 7 may be used in other embodiments of the invention.

In the embodiment shown in fig. 7, the combined cycle has an open gas cycle and a closed steam cycle. This embodiment produces a fuel gas having a heating value equivalent to that of the fuel gas produced in an oxygen-blown (IGCC). This embodiment is flexible enough to accommodate Greenfield applications and retrofit (retrofit) applications.

As shown in fig. 7, the system includes a primary pulse gasifier 10, embodiments of which are also shown in fig. 2 and 3. The pulse gasifier 10 includes a pulse combustion device 12 contained within a fluid passageway 14. Referring to fig. 4, fig. 4 shows an embodiment of the pulse combustion device 12. The pulse combustion device 12 includes a combustion chamber 18 in communication with a resonance tube 20. The combustion chamber 18 may be connected to a single resonance tube (as shown) or a plurality of parallel tubes with inlets communicating with the pulse combustor, respectively. Fuel, an oxygen source, and/or steam are delivered to the combustor 18 through a fuel line 22 and an air delivery system 24. The pulse combustion device 12 may burn gaseous, liquid or solid fuels. For most applications, for example, gaseous fuel may be used to initiate a start. Once operational, liquid or solid fuel may then be supplied to the combustion chamber.

To regulate the amount of fuel and gas supplied to the combustion chamber 18, the pulse combustion device 12 may include at least one valve 26. The valve 26 may be a pneumatic valve, however, a mechanical valve or the like may also be used.

During operation of the pulse combustion device 12, a suitable fuel, oxygen source and steam mixture is passed through the valve 26 into the combustion chamber 18 and detonated. During start-up, an auxiliary ignition device, such as a spark plug or pilot, may be provided. The explosion of the fuel mixture results in a dramatic increase in volume and the development of combustion products that pressurize the combustion chamber. Due to the hot gas expansion, a preferential flow in the direction of the resonance tube 20 is obtained with a significant momentum. Due to the inertia of the gas in the resonator tube 20, a vacuum is created within the combustion chamber 18. Only a small portion of the exhaust gas is then allowed to return to the combustion chamber under the balancing effect of the escaping resonance tube gas. Because the pressure in the combustion chamber 18 is below atmospheric pressure, more fuel and gas enters the combustion chamber 18 and auto-ignition occurs. In addition, the valve 26 thus restricts reverse flow and a new cycle is started. After the first cycle begins, the operation thereafter is self-sustaining.

The pulse combustion device 12 generates a pulsating flow and a sound pressure wave of combustion products. In one embodiment, the pulse combustion device produces a pressure swing or fluctuation that ranges from peak to peak between about 1psi and about 40psi, and more particularly between about 1psi and about 25 psi. These fluctuations are substantially sinusoidal. The degree of pressure fluctuation is from about 150dB to about 194dB, or more, over the acoustic pressure range or level of intensity. The acoustic pressure wave may have a frequency between about 20Hz and about 1500 Hz. However, for most applications, low frequencies are preferred. For example, the frequency may be between about 25Hz to about 250 Hz.

Although any suitable carbonaceous fuel may be combusted in the pulse combustion device 12 of the embodiment shown in fig. 7, coal is used as the fuel source. As shown, the system includes a coal handling and supply system 28. The coal is pulverized and combined with a carrier gas, and then supplied to the combustion apparatus 12. The carrier gas may be compressed air as shown in fig. 7. In this particular embodiment, the compressed air is obtained from a compressor 30, the illustrated compressor 30 being generally coupled to a gas turbine 32.

In addition to coal, a source of oxygen and/or steam is also supplied to the pulse combustion device 12. In this embodiment, for example, substantially pure oxygen is combined with steam and supplied to the pulse combustion device 12. The oxygen is obtained from an air separation plant 34, and the air separation plant 34 receives compressed air from the compressor 30.

For most applications, the pulse combustion device 12 is operated under sub-stoichiometric conditions. In particular, an amount of oxygen that is insufficient to completely combust the fuel source is supplied to the pulse combustion device. For example, in one embodiment, oxygen is supplied to the combustion unit at about 30% to about 60% of the stoichiometric level (on a molar basis).

As described above, oxygen may be supplied to the pulse combustion device 12 along with steam. A sufficient amount of steam may be added to regulate the temperature of the pulsating combustion products and to promote steam reforming in the flow channels 14. For example, some fuels are reformed via endothermic reactions when steam is present. The endothermic reaction takes heat away from the system, thereby regulating the temperature of the resulting pulsating combustion gas stream. Typically, a sufficient amount of steam may be present to maintain the temperature of the combustion products below about 4000 ° F, for example below about 3400 ° F. For example, in one embodiment, the temperature may be maintained from about 1800 ° F to about 3400 ° F, such as between about 2500 ° F to about 3400 ° F.

As shown, the fluid channel 14 has a U-shaped portion. In some embodiments, the fluid channel 14 may remain a single stage system. However, in other embodiments, the fluid channel may be divided into: comprising a first stage 36 and a downstream second stage 38 of the pulse combustion device 12. Generally, when slag is formed in the process, a two-stage system may be required. For example, when refractory raw materials are used, such as petroleum coke or raw coal (raw coal) as shown in FIG. 7, slag may form. For another example, when coal is used as the feedstock, slag may form when the temperature is raised above about 2000 ° F.

Thus, in one embodiment of the present invention, multiple processes may occur within the first stage 36 of the fluidic channel 14. For example, not only is a pulsating combustion gas flow and acoustic pressure waves created in the first stage, but also partial oxidation of the fuel source, steam gasification of the fuel source and slagging occur in the first stage. In a particular advantage, because the fluid channel 14 has a U-shaped portion, once the slag is formed, the slag is introduced directly into the port and collected by the slag handling system 40. The U-shaped section also enhances mixing of the pulsating combustion gas stream exiting the pulse combustion device 12.

In the second stage 38 of the fluid passageway 14, the temperature of the pulsating combustion gas stream is generally low and various additives may be added to the gas stream. For most applications, reducing conditions may be maintained within the second stage 38 to promote steam reforming and the associated endothermic reactions.

In an optional embodiment, for example, a portion of the pulverized coal from the coal treatment and supply system 28 is injected into the second stage 38. After the second stage of injecting fuel into the fluid passage, the fuel is subjected to steam gasification. If necessary, a greater amount of vapor may be injected into the second stage 38 of the fluid channel 14, as shown in FIG. 7. A lesser amount of oxygen may be present in the second stage. However, for most applications, oxidation should not be the primary driving force.

As shown in FIG. 7, the sulfur capture agent is injected into the second stage 38 from the sorbent treatment and supply system 42. The sulfur capture agent serves two functions. First, the sulfur capture agent is desulfurized from the pulsating combustion gas stream. Second, the sulfur capture agent also aids in the agglomeration of fly ash or other small particles contained within the pulsating combustion gas stream.

In one embodiment, the sulfur capture agent may be limestone, dolomite, or mixtures thereof. These sulfur capturing agents capture sulfur by an endothermic reaction. Thus, it may be necessary to heat the limestone and dolomite before the desired reaction takes place. Thus, more of these reagents can be injected into the U-shaped portion of the fluid channel.

However, in an alternative embodiment, ceria may be used as the sulfur capture agent. The ceria may be added generally anywhere along the length of the second stage 38.

As described above, the sulfur trapping agent becomes entrained with the particulates contained within the pulsating combustion gas stream due to the presence of the acoustic pressure wave. Some of the accretions will continue to advance with the pulsating combustion gas flow. However, other agglomerations may fall within the second stage 38. Ports (not shown) may be provided directly below the riser in the second stage to act to capture any such accretions.

When halogens are present in the pulsed combustion gas stream, in some embodiments, it may be necessary to also inject an alkaline getter into the second stage 38 of the fluid passageway 14. For example, alkaline getters may also be injected into the second stage through the alkaline and acid gas getter treatment and supply systems 44.

When removing the halogen, a lower temperature may be required. In this regard, the system may also include a water port 46 designed to inject or inject water into the second stage 38 as well as cool the pulsating combustion gas stream.

The inlet temperature to the second stage 38 may vary between about 1800 ° F to about 3000 ° F. Likewise, the outlet temperature of the second stage may also vary. For example, in some embodiments, the outlet temperature may be less than about 1900 ° F, such as less than about 1700 ° F. However, when halogen is present, the outlet temperature may be less than about 1400 ° F, for example between about 1000 ° F to about 1200 ° F.

The pressure within the fluid passageway 14 may vary depending on the particular application. For example, the pressure within the fluid passage may vary from atmospheric pressure to about 20 times atmospheric pressure. For example, in one embodiment, the pressure may be between about 10 times atmospheric pressure to about 20 times atmospheric pressure.

Generally, the pulse gasifier 10 may convert from about 90% to about 96% of the carbon contained in the fuel source. The gas formed by the pulse gasifier may contain relatively large amounts of hydrogen, as well as other gases. Other gases may include, for example, carbon dioxide, carbon monoxide, and lighter hydrocarbons.

The heating value of the clean gas generated in the pulse gasifier is on the order of 250Btu/scf (wet weight basis). This value is comparable to the heating value of the gas produced in the oxygen blown IGCC, but higher than the heating value of the gas produced in the air blown IGCC and the secondary-generation PFBC.

As shown in fig. 7, the product gas stream from the pulse gasifier 10 is fed to a pair of cascaded (tandem) cyclones 48 and 50. Among particular advantages, low energy cyclones 48 and 50 can be used to remove the entrained particulates due to the effective entrainment that occurs within the pulse gasifier. In one embodiment, the cyclone separator 48 may be a low velocity cyclone that removes larger particles. For example, the gas flow rate in the cyclone separator 48 may be between about 30 feet/second and about 75 feet/second.

On the other hand, the second cyclone 50 can be a high velocity, high efficiency cyclone that is well designed to remove smaller particulates, such as fines. The gas flow rate in the cyclone 50 can be, for example, between about 50 feet/second and about 200 feet/second.

After the cyclone separators 48 and 50 are used to remove particulate matter from the product gas stream, the product gas can be used in a variety of processes with little restriction. For example, in one embodiment, as shown in FIG. 7, the product gas stream can be used to generate electricity. For example, as shown in FIG. 7, the product gas stream exiting the cyclone 50 is supplied to a topping combustor 52. The topping combustor 52 comprises a burner that combusts a product stream and raises the gas temperature. For example, in one embodiment, the gas temperature may be increased to between about 2300 ° F to about 2600 ° F. To combust the product gas stream, the topping combustor may, if desired, combine the product gas stream with a source of oxygen, such as air.

The burner contained within the topping burner may be any suitable combustion device. For example, in one embodiment, the burner contained within the topping burner may be a pulse burner or a low Btu fuel gas burner. Examples of low Btu fuel gas burners have been developed by GE Environmental Services, inc.

As shown in fig. 7, the topping combustor generates a flue gas stream (flue gas stream), which is then supplied to the gas turbine 32. In particular, the flue gas stream is used to rotate the turbine 54 and to generate electrical power. As also shown in FIG. 7, in one embodiment, the flue gas stream from the turbine is supplied to a heat recovery steam generator 56, and the heat recovery steam generator 56 is used to generate steam from the feed water. The flue gas then exits the heat recovery steam generator 56 and is released to the atmosphere through stack 58.

In an alternative embodiment, rather than supplying the product gas stream to a gas turbine as shown in FIG. 7, the product gas stream may be supplied to a fuel cell. In this embodiment, the topping combustor 52 is not required. Instead, various gas conditioning and polishing systems may be incorporated into the system to purge the gas from the gas supply to the fuel cell. In particular, the gas conditioning and polishing system can be used to concentrate the amount of hydrogen contained in the product gas for use in a fuel cell.

As noted above, in the process of the present invention, sulfur is captured from a pulsed combustion gas stream. The sulfur is contained in the sulfur capturing agent. The sulfur capture agent in the fluid passageway 14 and in the cyclones 48 and 50 is collected. In some embodiments, further processing of the agglomerated particles is desired. In this regard, as shown in fig. 7, the system further comprises an atmospheric fluidized bed sulfater 60. For example, in one embodiment, the sulfur capture agent may be lime or limestone. In a reducing environment, as may occur in the flow channels 14, the sulfur captured by the sorbent is primarily through the formation of sulfides. Unfortunately, calcium sulfide reacts with water to release hydrogen sulfide. Therefore, safe disposal of the spent adsorbent requires its conversion to a more stable sulfate form. In the process of the present invention, this conversion can easily occur in the sulfater 60.

Specifically, the solids collected from the pulse gasifier 10 and the cyclones 48 and 50 shown in fig. 7 are supplied to a pressure drop device (pressure drop) 62 and into a sulfater 60. The solids captured by the cyclone contain spent adsorbent and unconverted carbon. In fact unconverted carbon is a desirable feature because it can be used to generate energy to maintain the sulfater at the required temperature for sulfide conversion.

Sulphur capture by lime/limestone is a complex process which involves the following reactions:

(1)

(2)

depending on the temperature and gas conditions, the following reactions may also occur:

(3)

(4)

(5)

(6)

under favorable operating conditions in the second stage, reaction (2) is expected to occur. However, in AFBSC60, reactions (3-6) can occur. Reaction (6) is desired. However, reactions (3) and (5) are often undesirable because they result in the release of captured sulfur. Taking into account Ca-O₂-S phase diagram, showing that reaction (5) is most likely to occur under reducing conditions and at higher temperatures.

Thus, the sulfator is typically operated at less than about 2200F and oxidation conditions to form CaSO₄And maintain its stability. The sulfater maintaining these requirements can be configured as a fluidized bed operating at a temperature of about 1550 ° F. The bed is fluidized using air corresponding to a superstoichiometric operation, which ensures that the oxidation reaction gets excess oxygen and that the oxidation conditions are maintained in the fluidized bed. In the sulfater 60, the unconverted carbon from the second stage is combusted to maintain the temperature of the fluidized bed at the desired level. Examination of Ca-O in the presence of carbon Combustion products₂The phase equilibrium data for the S system indicate that the presence of CO will have an undesirable effect on sulfate formation. Excess oxygen feed to the sulfater will ensure CO₂Dominate. Additional fresh adsorbent may also be provided to the fluidized bed to ensure that sulfur oxides, if formed, can be captured in the fluidized bed.

As shown in fig. 7, in one embodiment, raw coal may also be supplied to the sulfater if the carbon content is too low. However, for most systems, further addition of a fuel source to the sulfater 60 may not be necessary.

When sulfater 60 is incorporated into the system of the present invention, various energy integration steps may occur to further increase the efficiency of the overall process. For example, as shown in fig. 7, in one embodiment, compressed air from compressor 30 may be supplied and preheated by a fluidized bed of sulfater 60. The preheated compressed air may then be supplied to the topping combustor 52 for combustion with the product gas stream. This can be done to increase the heat input to the gas cycle. Furthermore, the fluidized bed may also incorporate tube banks designed to generate steam. In addition, the resulting flue gas exiting the fluidized bed of the sulfater 60 may be supplied to a heat recovery steam generator 64, and the heat recovery steam generator 64 may also generate steam. Steam from the fluidized bed, steam from the heat recovery steam generator 64, and steam from the heat recovery steam generator 56 may all be supplied to the steam turbine 66 to generate more electrical power. Alternatively, the formed steam may be supplied to the pulse gasifier 10, as desired.

As shown, after the flue gas stream generated by the sulfater 60 exits the heat recovery steam generator 64, the gas is supplied to a baghouse 68 and filtered. Any particulates captured by the baghouse are transported to the ash reservoir 70. On the other hand, the filtered gas is supplied to a stack 58 and released into the atmosphere.

Rather than using limestone as a sulfur capture agent as shown above, in an alternative embodiment, ceria may be used to capture sulfur. If a sorbent such as ceria is used to capture sulfur, the spent sorbent can be regenerated in an air or oxygen rich environment. The reaction corresponds to the following:

for example, the above reaction can occur in a sulfater 60, shown in fig. 7, which is more like a fluidized bed.

The SO produced can be reduced by direct sulfur reduction or Claus desulfurization (Claus process)₂To produce elemental sulphur or to produce sulphuric acid or ammonium sulphate.

The first approximation estimates (first-order estimate) the cycle efficiency of a combined cycle of different fuel lysates between a pulse gasifier and an AFBSC, as shown in fig. 7. FIG. 8 shows net plant efficiency (in HHV) versus coal feedstock fraction to a pulse gasifier. For this fraction, 1 corresponds to the total coal supplied to the pulse gasifier, and 0 corresponds to the total coal supplied to the AFBSC. Greenfield applications will require a coal feed fraction close to 1, while retrofit applications will correspond to low values for this fraction (typically between 0.1 and 0.5). The net plant efficiency curve shows two cases: (1) a 2100 ° F gas turbine inlet temperature and 1450psia/1000 ° F steam cycle, and (2) a 2300 ° F gas turbine inlet temperature and 2400psia/1000 ° F steam cycle. Case 1 is a typical retrofit application and case 2 is more suitable for Greenfield applications. Net power plant efficiency increases with increasing fraction of coal feedstock supplied to the pulse gasifier, as predicted by higher efficiency of gas cycle energy production due to higher temperature increases. Under advanced cycle conditions associated with Greenfield applications, the net plant efficiency approaches 45%. By replacing the compressed air with steam generated in the pulse gasifier, further improvements in the efficiency of the steam cooled gas turbine blades can be expected. For typical retrofit applications, the net plant efficiency is designed to be between 33% and 37%. Of course, in all cases, other benefits can also be derived from the ability to meet one tenth of the NSPS emission target, a simpler combustor island (combustor island) configuration without the need for barrier absorption filters and without the need for extraneous sorbents.

The advantages of the comparison between pulsed gas combined cycle ("PGCC") and advanced energy generation technology are listed in Table 1, according to preliminary estimates. PGCCs offer comparable performance with fewer components and show the potential for significant capital cost savings.

Table 1:

generating	IGCC		Second one		PGCC
						O2	Air (a)	PFBC	Transportation of
	Barrier absorption filter	Is that	Is that	Is that						Is that	Whether or not
Syngas cooler					Is that	Is that	Whether or not	Is that	Whether or not
	Air separation unit	Is that	Whether or not	Whether or not						Whether or not	Is that
Off-site gas purification					Is that	Is that	Whether or not	Is that	Whether or not
	Sulfur recovery	Is that	Whether or not	Whether or not						Whether or not	Whether or not
Liquid effluent					Is that	Whether or not	Whether or not	Whether or not	Whether or not
	Treatment efficiency,% (in HHV)	37-42	40-44	44-46						～45	～45
Sound wave enhanced sulfur capture					Whether or not	Whether or not	Whether or not	Whether or not	Is that
	Capital cost savings for PGCC, $/kW	200-300	100-200	50-150						50-100	--

In addition, the PGCC system may provide some or all of the following benefits:

● eliminate one or more stages of barrier absorption filters for hot gas particulate purification due to sound wave enhanced ash accretion. This enhances reliability, plant availability, reduces capital and operating and maintenance costs, and requires less real estate.

● effective in-situ sulfur capture in a sonic enhancement mode, as well as sorbent regeneration and sulfur recovery, improves performance, reduces waste, increases revenue and improves economic benefits.

● hot gas purge increases process efficiency and reduces net heat rate.

● alternative fuels and/or biomass may be co-combusted in the system.

● capital cost savings are between $ 200 and $ 300/kW compared to current IGCC systems.

● provides modularity and is suitable for shop manufacturing.

● the system can be provided in small sizes (25MWe equivalent or larger) and the system can be used in niche applications involving feedstocks such as petroleum coke, bitumen, etc.

● are suitable for use in renewable energy and Greenfield applications.

● the staged gasification mode of operation contributes to NO_xEmission control and flexibility to move from one gas turbine to another as gas turbine progressesThe turbine inlet temperature was gradually increased (eventually to 2600 ° F).

● the burner island can be fuelled with 100% coal and requires a secondary fuel, such as natural gas or fuel oil, for start-up only.

● the pulse gasifier system can be retrofitted to AFBC as an add-on or topping device to make up a combined cycle application.

● show promise for achieving higher cycle efficiencies (-45%), lower emissions (-1/10 for NSPS), and lower cost electrical power.

● no liquid effluent flows from the power plant.

● provide modularity and are suitable for shop manufacturing.

● allow for staged or stepwise construction.

● have no external or unproven material of construction.

● the system may be configured for combined heat and energy (CHP) applications for hydrogen production, for direct reduction of iron, or for production of liquid fuels.

These and other modifications and variations to the present invention may be practiced by those of ordinary skill in the art, without departing from the spirit and scope of the present invention. Further, it should be understood that aspects of the various embodiments may be interchanged both in whole or in part. Furthermore, those skilled in the art will appreciate that the foregoing description is by way of example only, and is not intended to limit the invention, which is further described by the appended claims.

Claims (52)

1. A system for generating a gas stream having a fuel or heating value, comprising:

a fluid channel comprising a first stage portion and a second stage portion, the fluid channel comprising a U-shaped portion that transitions the first stage portion to the second stage portion;

a pulse combustion device in communication with the first stage section of the fluid channel, the pulse combustion device comprising a pulse combustor connected to at least one resonant tube, the pulse combustion device configured to combust a solid or liquid fuel and generate a pulsed combustion gas stream and an acoustic pressure wave, the fluid channel shaped to transmit the acoustic pressure wave from the first stage section to the second stage section;

a sulfur capture agent injection port for injecting a sulfur capture agent into the second stage section of the fluid channel, the sulfur capture agent configured to remove sulfur-containing gases from the pulsed combustion gas stream and to sonically agglomerate with any particulates contained in the pulsed combustion gas stream; and

a particulate removal device in communication with the fluid passageway for receiving the combustion gas stream and removing particulates contained in the gas stream.

2. The system as defined in claim 1, further comprising a solid or liquid fuel injection port disposed to inject solid or liquid fuel into the second stage section of the fluid channel.

3. The system as defined in claim 1 wherein the sulfur capture agent injection ports are disposed on or near the U-shaped portion.

4. The system as defined in claim 1 wherein the sulfur capture agent injection port is disposed along an intermediate region of the second stage section.

5. The system as defined in claim 1, further comprising a nozzle for injecting water into the second stage section of the fluid channel.

6. The system as defined in claim 1, further comprising a steam port and an oxygen port for injecting steam and oxygen into the pulse combustion device.

7. The system defined in claim 1, further comprising a debris removal port disposed along the U-shaped portion of the fluid passageway.

8. The system as defined in claim 1 wherein the pulse combustion device is configured to generate acoustic pressure waves having a frequency of about 20 to about 250 hertz.

9. The system defined in claim 1 wherein the fines removal apparatus comprises a first cyclone and a second cyclone, the first cyclone comprising a low velocity cyclone for removing the agglomerates and the second cyclone comprising a high efficiency cyclone for removing fines.

10. The system as defined in claim 1, wherein the fluid passageway coupled to the pulse combustion device is configured such that the first stage portion of the fluid passageway operates at a first outlet temperature and the second stage portion operates at a second outlet temperature, the first outlet temperature being greater than the second outlet temperature, the second outlet temperature being less than about 1700 ° F.

11. The system as defined in claim 1, further comprising a topping combustor disposed to receive the combustion gas stream exiting the particulate removal device, the topping combustor comprising a burner for combusting the combustion gas stream.

12. The system as defined in claim 1, further comprising a sulfater that receives the particulates collected by the particulate removal device, the sulfater comprising a heated fluidized bed in communication with a gas port configured to inject fluidizing gas into the fluidized bed, the fluidizing gas comprising oxygen, the sulfater configured to sulfate any sulfur captured by the sulfur capturing agent.

13. The system as defined in claim 12 wherein the system further comprises a topping combustor disposed to receive the combustion gas stream from the particulate removal device, the topping combustor comprising a combustor configured to combust the combustion gas stream, and wherein the sulfater preheats the air stream supplied to the combustor of the topping combustor.

14. The system as defined in claim 1, further comprising a power generation device for generating electrical energy configured to receive the combustion gas stream exiting the particulate removal device.

15. The system defined in claim 14 wherein the power plant comprises a gas turbine or a steam turbine.

16. The system as defined in claim 14 wherein the power generation means comprises a fuel cell.

17. A system for generating a gas stream having a fuel or heating value, comprising:

a fluid channel comprising a first stage portion and a second stage portion;

a pulse combustion device in communication with the first stage section of the fluid channel, the pulse combustion device comprising a pulse combustor connected to at least one resonant tube, the pulse combustion device configured to combust a solid or liquid fuel and generate a pulsed combustion gas stream and an acoustic pressure wave, the fluid channel shaped to transmit the acoustic pressure wave from the first stage section to the second stage section;

a sulfur capture agent injection port for injecting a sulfur capture agent into the second stage section of the fluid channel, the sulfur capture agent configured to remove sulfur-containing gases from the pulsed combustion gas stream and to sonically agglomerate with any particulates contained in the pulsed combustion gas stream;

a particulate removal device in communication with the fluid passageway for receiving the combustion gas stream and removing particulates contained therein;

a topping burner in communication with the particulate removal device for receiving the combustion gas stream, the topping burner comprising a burner configured to combust the combustion gas stream; and

a sulfater for receiving the particulates collected by the particulate removal device, the sulfater comprising a heated fluidized bed in communication with a fluidizing gas port through which fluidizing gas containing oxygen is injected into the fluidized bed, the sulfater being configured to sulfate any sulfur captured by the sulfur capturing agent.

18. The system as defined in claim 17, further comprising a power generation device for receiving the heated combustion gas stream from the topping combustor and generating electrical power.

19. The system defined in claim 17 wherein the power plant comprises a gas turbine or a steam turbine.

20. The system as defined in claim 17, further comprising a solid or liquid fuel injection port positioned to inject solid or liquid fuel into the second stage section of the fluid channel.

21. The system as defined in claim 17, further comprising a nozzle for injecting water into the second stage section of the fluid channel.

22. The system as defined in claim 17, further comprising a steam port and an oxygen port for injecting steam and oxygen into the pulse combustion device.

23. The system as defined in claim 17 wherein the pulse combustion device is configured to generate acoustic pressure waves having a frequency between about 20 and about 250 hertz.

24. The system defined in claim 17 wherein the fines removal apparatus comprises a first cyclone and a second cyclone, the first cyclone comprising a low velocity cyclone for removing accretions and the second cyclone comprising a high efficiency cyclone for removing fines.

25. The system as defined in claim 17, wherein the fluid passageway coupled to the pulse combustion device is configured such that the first stage portion of the fluid passageway operates at a first outlet temperature and the second stage portion operates at a second outlet temperature, the first outlet temperature being greater than the second outlet temperature, the second outlet temperature being less than about 1700 ° F.

26. A method for producing a gas stream having a fuel or heating value, comprising:

combusting a solid or liquid fuel in a pulse combustion device and generating a pulsating combustion gas stream and an acoustic pressure wave, the pulse combustion device operating at sub-stoichiometric conditions;

passing the pulsating combustion gas stream and the acoustic pressure wave through a fluid channel, the fluid channel containing steam and at least a portion of the fluid channel being maintained under reducing conditions, wherein organic components contained in the combustion gas stream undergo an endothermic reaction to form hydrogen;

injecting a sulfur capture agent into the fluid channel, wherein the sulfur capture agent captures sulfur contained in the pulsating combustion gas flow, and the sulfur capture agent is also attached to particles contained in the pulsating combustion gas flow by sound; and

the combustion gas stream is filtered to remove the entrained particulates.

27. The method as defined in claim 26 wherein the fluid passageway includes a first stage section and a second stage section, the reducing conditions being maintained in the second stage section, the first stage section having a first outlet temperature and the second stage section having a second outlet temperature, the first outlet temperature being greater than the second outlet temperature, the second outlet temperature being less than about 1900 ° F.

28. A process as defined in claim 27, wherein the first outlet temperature is between about 2500 ° F and about 3400 ° F.

29. The method defined in claim 26 wherein the steam is supplied by a pulse combustion device to produce sub-stoichiometric conditions, the steam further serving to control the temperature of the pulsed combustion gas stream.

30. A method as defined in claim 26, wherein a solid or liquid fuel is injected into the flow channel, and the solid or liquid fuel undergoes an endothermic reaction in the flow channel to form hydrogen gas.

31. The method defined in claim 27 wherein the first stage section contains oxygen and is at a temperature sufficient to produce slag and wherein the method further includes the step of periodically removing slag from the fluid passageway.

32. The method defined in claim 31 wherein the partial oxidation, steam gasification and slagging all occur in the first stage section of the flow path.

33. The method as defined in claim 32 wherein only steam gasification occurs in the second stage section of the flow channel.

34. The method as defined in claim 33 wherein the method further comprises the step of injecting steam into the second stage section of the fluid channel.

35. A process as defined in claim 26, wherein the sulfur capture agent has a median particle size of at least 20 microns.

36. A process as defined in claim 26, wherein the sulfur capture agent comprises limestone, dolomite, or mixtures thereof.

37. A method as defined in claim 26, wherein the sulfur capture agent comprises ceria.

38. The method as defined in claim 37 further comprising the step of heating the filtered agglomerated particles to a temperature sufficient to regenerate the ceria.

39. The method as defined in claim 26 further comprising the step of injecting an alkaline getter into the fluid passageway and into contact with the pulsed combustion gas stream.

40. The method as defined in claim 26 wherein the acoustic pressure wave has a frequency between about 20hz and about 250hz and an intensity of at least about 150 dB.

41. The method as defined in claim 27 further comprising the step of injecting water into the second stage section to cool the pulsed combustion gas stream.

42. A process as defined in claim 41, wherein the amount of water added to the second stage section is up to about 5% of the mass flow of the combustion gas stream.

43. The method defined in claim 26 wherein the combustion gas stream is filtered by a first cyclone and a second cyclone, the first cyclone comprising a low velocity cyclone and the second cyclone comprising a high velocity cyclone.

44. The process defined in claim 26 wherein the agglomerate particles filtered from the combustion gas stream contain sulfides and wherein the process further comprises the step of sulfating the sulfides.

45. A process as defined in claim 44 wherein the agglomerated particles are sulfated by being supplied to a fluidized bed under oxidizing conditions, the fluidized bed being at a temperature of less than about 2200 ° F.

46. The method as defined in claim 26 further comprising the step of supplying the filtered combustion gas stream to a topping combustor, the topping combustor combusting the combustion gas stream to form a fuel gas stream, the fuel gas stream being supplied to a power generation device that generates electrical power.

47. The method defined in claim 46 wherein the power plant comprises a gas turbine or a steam turbine.

48. A method as defined in claim 26, wherein the filtered combustion gas stream is supplied to a fuel cell for generating electrical energy.

49. A method for producing a gas stream having a fuel or heating value, comprising:

combusting a solid or liquid fuel in a pulse combustion device and generating a pulsating combustion gas stream and an acoustic pressure wave, wherein the acoustic pressure wave has a frequency between about 25 hertz and about 250 hertz, operating the pulse combustion device under sub-stoichiometric conditions;

directing a pulsating combustion gas stream through a fluid channel, the fluid channel comprising a first stage section and a second stage section, the first stage section having a first outlet temperature and the second stage section having a second outlet temperature, the first outlet temperature being higher than the second outlet temperature;

supplying steam to the pulse combustion device with the solid or liquid fuel, the amount of steam present in the pulse combustion device being sufficient to maintain a temperature within the first stage portion of the flow path of less than about 3500 ° F, with partial oxidation, steam gasification, and slagging all occurring in the first stage portion of the flow path;

periodically removing slag from the fluid passage;

injecting a sulfur capture agent into the second stage portion of the fluid passageway, the sulfur capture agent capturing sulfur contained in the pulsating combustion gas stream, the sulfur capture agent also acoustically associated with particulates contained in the pulsating combustion gas stream;

maintaining reducing conditions in the second stage section of the flow channel, steam gasification occurring in the second stage section, thereby forming hydrogen; and

the combustion gas stream remaining in the second stage section of the fluid channel is filtered to remove the entrained particulates.

50. The method defined in claim 49 wherein the filtered combustion gas stream is supplied to a turbine that produces electrical power.

51. The method defined in claim 49 wherein the filtered combustion gas stream is supplied to a fuel cell that produces electrical power.

52. A method as defined in claim 49, wherein steam is supplied to the second stage section of the flow channel to maintain reducing conditions.