US20140026483A1

US20140026483A1 - Systems for preheating feedstock

Info

Publication number: US20140026483A1
Application number: US13/562,246
Authority: US
Inventors: Sunil Ramabhilkh Mishra; Anindra Mazumdar
Original assignee: General Electric Co
Current assignee: General Electric Co
Priority date: 2012-07-30
Filing date: 2012-07-30
Publication date: 2014-01-30
Also published as: CN103571544A; AU2013207555A1

Abstract

Systems for preheating feedstock are provided. In one embodiment, a system includes at least one energy source disposed in a gasification plant and configured to provide an energy, and a feedstock supply configured to deliver a solid feedstock. The system further includes a feed bin disposed downstream of the feedstock supply, wherein the feed bin is configured to receive the solid feedstock and to provide a dry feedstock. The system additionally includes a gasifier disposed downstream from the feed bin, wherein the gasifier is configured to produce a syngas from the dry feedstock. The system further includes a heating system configured to use the energy to heat the solid feedstock directly, heat the solid feedstock indirectly, or a combination thereof, to remove moisture from the solid feedstock in the feed bin.

Description

BACKGROUND OF THE INVENTION

The subject matter disclosed herein relates to raw material treatment. More specifically, disclosed embodiments of the invention relate to the preheating of feedstock.
Fossil fuels, such as coal or petroleum, may be used in the production of electricity, chemicals, synthetic fuels, or for a variety of other applications. In certain applications, the fossil fuels may be gasified. Gasification involves the incomplete combustion of a carbonaceous fuel with limited oxygen at a very high temperature to produce syngas (e.g.; a fuel containing carbon monoxide and hydrogen), which enables higher efficiency and cleaner emissions than the fuel in its original state.
Different carbonaceous fuels may be gasified with varying success. That is, a lower moisture content value generally indicates that a fuel is more easily combustible and more efficiently gasified. The moisture content value of a material is a measure of the amount of water present in the material. For example, petcoke, which is produced from cracking petroleum, has relatively low moisture content and, therefore, is easily gasified. In contrast, low rank coals and biomass may have high moisture content and are, therefore, difficult to gasify. In some instances, biomass such as corn stalks and switchgrass may contain so much moisture that it becomes too inefficient to gasify the fuel. In addition, high moisture in fuels degrades flowability and causes frequent plugging during handling and conveyance. Possible nuisances include fouling of baghouses and bridging of fuel nozzles. Unfortunately, moisture removal may be difficult and cost-prohibitive.

BRIEF DESCRIPTION OF THE INVENTION

Certain embodiments commensurate in scope with the originally claimed invention are summarized below. These embodiments are not intended to limit the scope of the claimed invention, but rather these embodiments are intended only to provide a brief summary of possible forms of the invention. Indeed, the invention may encompass a variety of forms that may be similar to or different from the embodiments set forth below.
In a first embodiment, a system includes at least one energy source disposed in a gasification plant and configured to provide an energy, and a feedstock supply configured to deliver a solid feedstock. The system further includes a feed bin disposed downstream of the feedstock supply, wherein the feed bin is configured to receive the solid feedstock and to provide a dry feedstock. The system additionally includes a gasifier disposed downstream from the feed bin, wherein the gasifier is configured to produce a syngas from the dry feedstock. The system further includes a heating system configured to use the energy to heat the solid feedstock directly, heat the solid feedstock indirectly, or a combination thereof, to remove moisture from the solid feedstock in the feed bin.
In a second embodiment, a system includes at least one energy source configured to provide an energy. The system further includes a feedstock supply configured to deliver a solid feedstock. The system also includes a fluidization system disposed downstream of the feedstock supply, wherein the fluidization system is configured to receive the solid feedstock and to provide a dry fluidized feedstock. The system additionally includes a heating system configured to use the energy to heat the solid feedstock in the fluidization system to remove moisture from the solid feedstock.
In a third embodiment, a system includes a fluidization system configured to fluidize a solid feedstock. The fluidization system includes a feed bin configured to dry the solid feedstock, a conveyor, a cyclone, a baghouse, and a hopper. At least one energy source is disposed in a gasification plant and is configured to provide an energy to the feed bin to dry the solid feedstock.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

FIG. 1 illustrates a block diagram of an embodiment of gasification system;

FIG. 2 illustrates a schematic diagram of an embodiment of a fluidization system included in the gasification system of FIG. 1;

FIG. 3 depicts a block diagram of an embodiment of energy sources suitable for delivering an energy to the fluidization system of FIG. 2; and

FIG. 4 depicts a block diagram of an embodiment of a process useful in removing moisture from a feedstock.

DETAILED DESCRIPTION OF THE INVENTION

One or more specific embodiments of the present invention will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.
The disclosed embodiments include systems and methods for drying fuel feedstock, including high moisture content feedstock such as low rank coals (e.g., PRB coal) and/or biomass. Fuel feedstock may have its moisture removed through evaporation by the application of heat. Unfortunately, the drying of fuel feedstock may use, for example, approximately 50-100 million btu/hr, depending on the feedstock flow rate and the amount of drying desired. Moreover, the drying of high moisture content feedstock uses additional energy, because the energy input is proportional to the desired drying amount. The disclosed embodiments may be used to more efficiently dry feedstock, including high moisture content feedstock, by reusing energy sources from existing plant components. For example, in a gasification plant, the sources of energy may include low level steam (e.g., steam at below 75 PSIG), hot vent gas generated in dry feed systems, flue gases captured in a heat recovery steam generation (HRSG) system, heated cooling water from sources such as (ASU) systems or cooling water circuits, extraction air from gas turbine systems, hot water exciting lockhopper systems, and other “waste” heat generated by the gasification plant. Indeed, low level steam “waste” heat, vent fluids, flue/stack fluids, and/or boiler feed fluids may be reused. By reusing energy in this manner, the efficiency of the plant may be substantially increased.
In general, the energy recovered from the plant may be used to dry the feedstock through a variety of systems. For example, certain embodiments may use coils and/or tubes embedded or otherwise attached to feed bins. These coils and/or tubes may carry hot fluids (e.g., steam, water), which transfers heat to the feedstock to remove moisture. Other embodiments may use a fluid jacket (e.g., steam jacket) disposed on a feed bin. In yet other embodiments where the feedstock is disposed in a feedstock bed (e.g., coal bed), hot gas may be purged into the feedstock bed to dry the feedstock. Advantageously, these aforementioned systems may also be retrofitted into an existing plant. Additionally, methods are described herein that improve plant efficiency by selecting an energy source (e.g., low level steam “waste” heat, vent fluids, flue/stack fluids, and/or boiler feed fluids) based on current plant operations, business conditions, and/or forecasted events (e.g., market forecasts, weather forecasts), as described in more detail below. By selecting an combining energy sources for the drying of the feedstock based on plant operations, business conditions, and/or forecasted events, the systems and methods described herein may provide for added efficiencies and cost optimizations.
With the foregoing in mind and turning now to FIG. 1, the figure depicts an embodiment of a gasification plant incorporating the techniques disclosed herein. More specifically, FIG. 1 is a diagram of an embodiment of an integrated gasification combined cycle (IGCC) power plant system 10 that may gasify carbonaceous fuels into a syngas. Components of the IGCC system 10 include a feedstock preparation and fluidization system 11. The fluidization system 11 may provide a fluidized (e.g., flowing like a fluid) feedstock suitable for use in a gasifier. Included in the feedstock preparation and fluidization system 11 is a feedstock delivery system 12, which may be used to deliver a fuel for the IGCC system 10. The feedstock delivery system 12 may deliver a particulate fuel such as coal, petroleum coke, biomass, tars, asphalt, biomass, or other carbon containing items. The fuel may be dried in a drying system 13 before delivery into a downstream fluidization vessel 14. A controller 15 may also be used to control the delivery, drying, and fluidization of the delivered fuel by the fluidization system 11, and may then direct the fluidization vessel 14 to provide fluidized fuel to a gasifier 16. The gasifier 16 may include a fluidized bed gasifier, a updraught gasifier, a downdraught gasifier, a cross-draught gasifier, a double fired gasifier, an entrained bed gasifier, a molten bath gasifier, a moving bed gasifier, or a combination thereof.
The drying system 13 may use various moisture removal energy sources 17 from the IGCC system 10, as described in more detail below, to lower the moisture content of the feedstock provided by the feedstock delivery system 12. The energy sources 17 may include, but are not limited to, waste heat 19, steam 21 (e.g., low level steam), gas 23 (e.g., purge gas, vent gas, flue gas), liquids 25 (e.g., hot water), and electricity 27 (e.g., spare electricity). Examples of energy sources 17 may include waste heat 19 (e.g., steam 21, gas 23, and/or liquids 25), from compressors (e.g., 40, 42), air separation units (e.g., 38), gasifiers (e.g., 16), gas treatment units (e.g., 20), turbines (e.g., 36, 52), heat recovery steam generators (e.g., 54), or any combination thereof. The controller 15 may be used to improve the efficiency of drying of the feedstock, and may additionally be used to improve the overall efficiency of the IGCC system 10 by providing for processes, as described in more detail below, suitable for using the moisture removal energy sources 17.
The gasifier 16 may convert the fluidized fuel into syngas, e.g., a combination of carbon monoxide and hydrogen. This conversion may be accomplished by subjecting the non-aqueous slurry to a controlled amount of steam and oxygen at elevated pressures (e.g., from approximately 600 psi-1200 psi) and temperatures (e.g., approximately 2200° F.-2700° F.), depending on the type of gasifier 16 utilized. The heating of the non-aqueous slurry during a pyrolysis process may generate a solid (e.g., char) and residue gases (e.g., carbon monoxide, hydrogen, and nitrogen). The char remaining from the non-aqueous slurry from the pyrolysis process may only weigh up to approximately 30% of the weight of the original feedstocks.
The combustion reaction in the gasifier 16 may include introducing oxygen to the char and residue gases. The char and residue gases may react with the oxygen to form carbon dioxide and carbon monoxide, which provides heat for the subsequent gasification reactions. The temperatures during the combustion process may range from approximately 2200° F. to approximately 2700° F. In addition, steam may be introduced into the gasifier 16. In essence, the gasifier utilizes steam and oxygen to allow some of the non-aqueous slurry to be burned to produce carbon monoxide and energy, which may drive a second reaction that converts further feedstock to hydrogen and additional carbon dioxide.
In this way, a resultant gas may be manufactured by the gasifier 16. The resultant gas may include approximately 85% of carbon monoxide and hydrogen, as well as CH₄, HCl, HF, COS, NH₃, HCN, and H₂S (based on the sulfur content of the feedstock). This resultant gas may be termed “untreated syngas.” In the depicted embodiment, some waste heat 19 and/or steam 21 generated from the gasifier 16 may be provided as energy sources 17 useful in drying feedstock. The gasifier 16 may also generate waste, such as slag 18, which may be a wet ash material. As described in greater detail below, a gas treatment unit 20 may be utilized to treat the untreated syngas. The gas treatment unit 20 may scrub the untreated syngas to remove the HCl, HF, COS, HCN, and H₂S from the untreated syngas, which may include separation of sulfur 22 in a sulfur processor 24 by, for example, an acid gas removal process in the sulfur processor 24. Furthermore, the gas treatment unit 20 may separate salts 26 from the untreated syngas via a water treatment unit 28, which may utilize water purification techniques to generate usable salts 26 from the untreated syngas. Subsequently, a treated syngas may be generated from the gas treatment unit 20. Energy 17 from the gas treatment unit 20, sulfur process 24, and water treatment unit 28, such as waste heat 19, steam 21, hot gas 23, hot liquids 25, and electricity 27 may also used to dry feedstock.
A gas processor 30 may be utilized to remove residual gas components 32 from the treated syngas, such as ammonia and methane, as well as methanol or other residual chemicals. However, removal of residual gas components 32 from the treated syngas is optional since the treated syngas may be utilized as a fuel even when containing the residual gas components 32 (e.g., tail gas). At this point, the treated syngas may include approximately 3% CO, approximately 55% H₂, and approximately 40% CO₂, and may be substantially stripped of H₂S. The gas processor 30 may also provide for energy 17 useful in drying the feedstock, including waste heat 19, steam 21, hot gas 23, hot liquids 25, and electricity 27. The treated syngas may be directed into a combustor 34 (e.g., a combustion chamber) of a gas turbine engine 36 as combustible fuel.
The IGCC system 10 may further include an air separation unit (ASU) 38. The ASU 38 may separate air into component gases using, for example, distillation techniques. The ASU 38 may separate oxygen from the air supplied to it from a supplemental air compressor 40 and may transfer the separated oxygen to the gasifier 16. Additionally, the ASU 38 may direct separated nitrogen to a diluent nitrogen (DGAN) compressor 42. The DGAN compressor 42 may compress the nitrogen received from the ASU 38 at least to pressure levels equal to those in the combustor 34, so as to not interfere with proper combustion of the syngas. Thus, once the DGAN compressor 42 has compressed the nitrogen to an adequate level, the DGAN compressor 42 may direct the compressed nitrogen to the combustor 34 of the gas turbine engine 36. The ASU 38, air compressor 40, and DGAN compressor 42 may provide energy 17. For example ASU 38 intercoolers may provide heated cooling water, and the compressors 40 and 42 may provide hot gases (e.g., air, nitrogen).
As described above, the compressed nitrogen may be transferred from the DGAN compressor 42 to the combustor 34 of the gas turbine engine 36. The gas turbine engine 36 may include a turbine 44, a drive shaft 46, and a compressor 48, as well as the combustor 34. The combustor 34 may receive fuel, such as the syngas, which may be injected under pressure from fuel nozzles. This fuel may be mixed with compressed air as well as compressed nitrogen from the DGAN compressor 42 and combusted within the combustor 34. This combustion may create hot pressurized exhaust gases.
The combustor 34 may direct the exhaust gases towards an exhaust outlet of the turbine 44. As the exhaust gases from the combustor 34 pass through the turbine 44, the exhaust gases may force turbine blades in the turbine 44 to rotate the drive shaft 46 along an axis of the gas turbine engine 36. As illustrated, the drive shaft 46 may be connected to various components of the gas turbine engine 36, including the compressor 48.
The drive shaft 46 may connect the turbine 44 to the compressor 48 to form a rotor. The compressor 48 may include blades coupled to the drive shaft 46. Thus, rotation of turbine blades in the turbine 44 may cause the drive shaft 46 connecting the turbine 44 to the compressor 48 to rotate blades within the compressor 48. The rotation of blades in the compressor 48 causes the compressor 48 to compress air received via an air intake in the compressor 48. The compressed air may then be fed to the combustor 34 and mixed with fuel and compressed nitrogen to allow for higher efficiency combustion. The drive shaft 46 may also be connected to a load 50, which may be a stationary load, such as an electrical generator, for producing electrical power in a power plant. Indeed, the load 50 may be any suitable device that is powered by the rotational output of the gas turbine engine 36. Additionally, the engine 36 may provide energy 17 useful in drying feedstock. For example, extraction air from the turbine 44 may exchange heat with diluent nitrogen and be provided as energy 17.
The IGCC system 10 also may include a steam turbine engine 52 and a heat recovery steam generation (HRSG) system 54. The steam turbine engine 52 may drive a second load 56, such as an electrical generator for generating electrical power. However, both the first and second loads 50, 56 may be other types of loads capable of being driven by the gas turbine engine 36 and the steam turbine engine 52, respectively. In addition, although the gas turbine engine 36 and the steam turbine engine 52 may drive separate loads 50, 56, as shown in the illustrated embodiment, the gas turbine engine 36 and the steam turbine engine 52 may also be utilized in tandem to drive a single load via a single shaft. The specific configuration of the steam turbine engine 52, as well as the gas turbine engine 36, may be implementation-specific and may include any combination of sections. Further, the steam turbine 52 may provide energy 17, including as input steam, bleed steam, and “spent” steam, useful in drying feedstock.
Heated exhaust gas from the gas turbine engine 36 may be directed into the HRSG 54 and used to heat water and produce steam used to power the steam turbine engine 52. Exhaust from the steam turbine engine 52 may be directed into a condenser 58. The condenser 58 may utilize a cooling tower 60 to exchange heated water for chilled water. In particular, the cooling tower 60 may provide cool water to the condenser 58 to aid in condensing the steam directed into the condenser 58 from the steam turbine engine 52. Condensate from the condenser 58 may, in turn, be directed into the HRSG 54. Again, exhaust from the gas turbine engine 36 may also be directed into the HRSG 54 to heat the water from the condenser 58 and produce steam. Further, the condenser 58 and/or cooling tower 60 may direct energy 17, such as hot water, to the feedstock preparation and fluidization system 11, for use in removing moisture from the feedstock.
As such, in combined cycle systems such as the IGCC system 10, hot exhaust may flow from the gas turbine engine 36 to the HRSG 54, where it may be used to generate high-pressure, high-temperature steam. The steam produced by the HRSG 54 may then be passed through the steam turbine engine 52 for power generation. Further, flue gas and/or steam from the HRSG 54 may be used as energy 17. In addition, the produced steam may also be supplied to any other processes where steam may be used, such as to the gasifier 16. The gas turbine engine 36 generation cycle is often referred to as the “topping cycle,” whereas the steam turbine engine 52 generation cycle is often referred to as the “bottoming cycle.” By combining these two cycles as illustrated in FIG. 1, the IGCC system 10 may lead to greater efficiencies in both cycles. In particular, exhaust heat from the topping cycle may be captured and used to generate steam for use in the bottoming cycle.
Turning to FIG. 2, the figure depicts an embodiment illustrating further details of the feedstock preparation and fluidization system 11 useful in drying and fluidizing the feedstock for delivery to the gasifier 16 shown in FIG. 1. By using the energy source 17, including the waste heat 19, steam 21, gases 23, liquids 25, and/or electricity 27, the feedstock preparation and fluidization system 11 may improve the efficiency of the plant 10 by reducing the energy used in converting the feedstock to syngas, providing increased flow of drier fuel, reducing plugging of the fuel, providing improved protection against frozen fuel and resultant abrasion-related issues, and in general, increasing plant availability.
In the depicted embodiment, feedstock may be delivered by the feedstock delivery system 12 into vibrating screens 62. For example, the vibrating screens 62 may deliver the feedstock into feedstock feed bins 64 through a vibratory motion. The feed bin 64 may include a metal bin or container suitable for storing feedstock. The energy source 17 may then provide a heat suitable for removing moisture from the feedstock disposed in the feed bins 64. As mentioned above, the sources of heat provided by the energy source 17 may include waste heat 19, steam 21, gas 23, liquids 25, and electricity 27. Conduits 66, including but not limited to fluid conduits and electrical conduits, may be used to deliver energy (e.g., waste heat 19, steam 21, gas 23, liquids 25, and electricity 27) to the feed bins 64. Depending on the type of energy delivered, several techniques may be used to directly or indirectly heat the feedstock, as described in more detail below with respect to FIG. 3. As depicted, actuators 68 (e.g., valves, electrical circuits) may be used to control the delivery of energy into the feed bins 64. For example, the controller 15 may be communicatively coupled to the actuators 68 to control the delivery of energy. It is to be noted that the controller 15 may also be communicatively coupled to other machinery in the fluidization system 11 to control the fluidization of fuel.
After removing moisture from the feedstock, the feedstock may be weighed by the feedstock weigh feeders 70 (e.g., vibratory weigh feeder) suitable for weighing the feedstock and moving the feedstock to conveyers 72 (e.g., screw conveyors). By providing drier feedstock, the energy sources 17 may enable a more efficient delivery of fuel, for example by removing water mass and thus conveying more combustible fuel instead of fuel with non-combustible components (e.g., water). The dryer fuel may then be provided to impact mill and dryers 74. Because the drier fuel contains less moisture, less energy may be used by the impact mill and dryers 74 when compared to fuel delivered without pre-drying. For example, less of a steam 76 provided by a steam heating system 78 may be used to dry the feedstock in the impact mill and dryers 74.
Cyclone separators 80 and vibrating screens 82 may be used to further process the feedstock and deliver the feedstock. For example, the cyclone separators 80 may deliver feedstock to bag houses 84 (e.g., filters) for filtering. A recycle fan blower system 85 may aid in recycling fluid and/or feedstock. Likewise, the vibrating screens 82 may deliver feedstock to a ground feedstock storage bin 86 with the aid of an inert purge gas source 88, such as a nitrogen gas source 88. The inert gas source 88 may also provide purge gas to bag houses 90. The bag houses 90 may also deliver feedstock to the ground feedstock storage bin 86, and the purge gas may then be vented to the atmosphere by using atmospheric vents 92, 94, 96. Pumps 98 and 100 may aid in venting the purge gas to the atmosphere. For example, pump 98 may vent the purge gas directly to the atmospheric vent 92, while pump 100 may vent the purge gas through a mercury guard bed 102, and then to the atmospheric vent 94. A high pressure conveyance source 104 may be fluidly coupled to a startup cyclone 106. Dry, heated feedstock may be delivered from the startup cyclone 106 through a recycle hopper 108 into the ground feedstock storage bin 86. Feedstock may also be delivered from one or more dry feed pumps 110.
The ground feedstock storage bin 86 may deliver dry feedstock for further processing and eventual gasification, for example, through pump feed hoppers 112. The gasifier 16 (shown in FIG. 1) may then gasify the dry feedstock, as described above. By using the energy source 17 to provide for dry fuel, the fluidization system 11 may improve the efficiency of the plant 10. For example, efficiency may be improved by reducing the energy used in converting the feedstock to syngas, providing increased flow of drier fuel, reducing plugging of the fuel, providing improved protection against frozen fuel and/or minimize abrasion-related issues.
It is to be noted that, in other embodiments, the energy sources 17 may be directed to feeders 70, conveyors 72, impact mill and dryers 74, cyclones 80, vibrating screens 82, baghouses 84, feedstock storage bins 86, baghouses 90, cyclones 106, and/or hoppers 108, and used to dry the feedstock. By using the techniques described herein, approximately greater than 5%, 6%, 7%, 10%, 15%, 30%, 50%, 90%, 95% of the moisture in the feedstock may be removed. Such an amount (e.g., greater than 5%, 6%, 7%, 10%, 15%, 30%, 50%, 90%, 95%) of the moisture may be removed at the feed bin 64, at the feeders 70, at the conveyors 72, at the impact mill and dryers 74, at the cyclones 80, at the vibrating screens 82, at the baghouses 84, at the feedstock storage bins 86, at the baghouses 90, at the cyclones 106, at the hoppers 108, or at a combination thereof.
FIG. 3 is a block diagram of an embodiment of the energy source 17, including the waste heat 19, steam 21, gas 23, liquid 25, and electricity 27, used provided to certain systems, such as the feed bin 64, through conduits 66. As noted above, the energy sources 17 may also be provided to system 11, which may include feeders 70, conveyors 72, impact mill and dryers 74, cyclones 80, vibrating screens 82, baghouses 84, feedstock storage bins 86, baghouses 90, cyclones 106, and/or hoppers 108, to dry the feedstock.
As illustrated, the waste heat 19 uses conduits 114, the steam 21 uses conduits 116, the gas 23 uses conduits 118, the liquid 25 uses conduits 120, and electricity 27 uses lines/conduits 122. Each of the conduits 114, 116, 118, 120, and/or 122 may deliver energy to be used in removing moisture from the feedstock. The energy may be converted, for example, into heat, by a variety of techniques, as described in more detail below.
In the depicted embodiment, a waste heat recovery unit 124 may be used to apply waste heat to the feed bin 64. The waste heat recovery unit 124 may include recuperators in which a waste heat stream of fluids may be used to warm, for example, metal tubes carrying a heat delivery fluid, and the heat delivery fluid may be used to remove moisture from the feedstock. The waste heat recovery unit 124 may also include regenerators in which the waste heat stream is recycled through the feedstock until little usable heat is left to remove moisture. The waste heat recovery unit 124 may additionally include a heat pipe exchanger combining thermal conductivity and phase transition to more efficiently manage the transfer of heat between two solid interfaces. The waste heat recovery unit 124 may further include a thermal wheel, such as a rotary heat exchanger having a circular honeycomb matrix of heat absorbing material. The waste heat recovery unit 124 may also similarly include an economizer (e.g., Green's economizer), and heat pumps that may boil organic fluids. The waste heat recovery unit 124 may likewise include a run around coil that may include two or more multi-row finned tube coils connected to each other by a circuit of pumped pipes. Additionally or alternatively, the aforementioned techniques (e.g., recuperators, regenerators, heat pipe exchangers, thermal wheels, economizers, heat pumps, run around coils) may be used alone, or in combination, in a steam heat exchanger 126, a gas heat exchanger 128, and/or a liquid heat exchanger 130.
Electricity 27 may also be provided to an electrical heater 132 to remove feedstock moisture. The electrical heater 132 may include a conduction heater (e.g., radiative heater) in which heating occurs through conduction. The electrical heater 132 may also include convection heaters heating the feedstock through convection. For example, electric immersion heaters, fan heaters, electrode heaters, storage heaters, electric heat pump, and the like, may be included in the electrical heater 132. The heating systems 124, 126, 128, 130, and 132 may deliver a heat of approximately between 66° C. to 290° C., 50° C. to 100° C., 75° C. to 200° C., 100° C. to 300° C. By using sources of energy 17 that may have been otherwise left unused to heat the feedstock, more efficient gasification and plant operations may be enabled.
FIG. 4 is a block diagram of an embodiment of a process 134 that may be used for removing moisture from feedstock, including low rank coals and/or biomass. The process 134 may include non-transitory machine readable media storing code or computer instructions that may be used by a computing device (e.g., the controller 15) to implement the techniques disclosed herein. In the depicted embodiment, an energy source 17 may be selected (block 136). The energy source 17 may include waste heat 19, steam 21 (e.g., low level steam), gas 23 (e.g., purge gas, vent gas, flue gas), liquids 25 (e.g., hot water), and/or electricity 27 (e.g., spare electricity). The selection of the energy sources 17 may include using current plant conditions, business conditions and/or forecasted events.
For example, if the plant is 10 is producing excess electricity, then some of the excess may be provided as electricity 27. Likewise, if the plant is producing unused hot steam 21, gas 23, liquids 25, or more generally, producing waste heat 19, then the aforementioned energy may be used. The energy 17 may then be directed (block 138), for example, to the feed bins 64, feeders 70, conveyors 72, impact mill and dryers 74, cyclones 80, vibrating screens 82, baghouses 84, feedstock storage bins 86, baghouses 90, cyclones 106, and/or hoppers 108 for heating of the feedstock. As mentioned above, energy 17 may be directed from the HRSG 54, the steam turbine 52, cooling tower 60, gas treatment unit 20, sulfur processor 24, gasifier 16, ASU 38, air compressor 40, DGAN 42, turbine 44, compressor 48, load 50, steam turbine 52, HRSG 54, load 56, condenser 58, and/or cooling tower 60. By selecting and combining energy sources 17 that may otherwise go unused, the efficiency of the plant 10 may be improved.
The energy 17 may then remove moisture from the feedstock (block 140). As mentioned above, various techniques may be used to apply the energy 17 to remove the moisture (block 140), including but not limited to waste heat recovery units 124, steam heat exchangers 126, gas heat exchangers 128, liquid heat exchangers 130, and/or electrical heaters 132. The reduced-moisture feedstock may then be provided, for example, to a gasifier (block 142) for conversion into syngas. By applying a variety of energy sources 17, for example, to dry the feedstock in feed bins 64, the disclosed embodiments may improve feedstock flowability, reduce plugging, and more generally, improve overall plant efficiency.
Technical effects of the invention include providing systems and methods for drying solid feedstock by reusing energy from existing plant components. In particular, as described above, medium pressure steam may be redirected from existing plant components, such as a water-gas shift reactor and/or a sulfur recovery unit, and used to dry solid feedstock. The disclosed embodiments may be part of new installations or, alternatively, may be implemented as retrofit additions to existing solid fuel preparation systems. In addition, the disclosed embodiments may be applied to any other applications that use a steam to dry a solid feed.
This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.

Claims

1. A system, comprising:

at least one energy source disposed in a gasification plant, wherein the at least one energy source is configured to provide an energy;

a feedstock supply configured to deliver a solid feedstock;

a feed bin disposed downstream of the feedstock supply, wherein the feed bin is configured to receive the solid feedstock and to provide a dry feedstock;

a gasifier disposed downstream from the feed bin, wherein the gasifier is configured to produce a syngas from the dry feedstock; and

a heating system configured to use the energy to heat the solid feedstock directly, heat the solid feedstock indirectly, or a combination thereof, to remove moisture from the solid feedstock in the feed bin.

2. The system of claim 1, comprising a feedstock weigh feeder disposed downstream of the feed bin, wherein the at least one energy source is configured to provide the energy to the feedstock weigh feeder for drying of the solid feedstock, and wherein the feedstock weigh feeder is configured to weigh and to move the solid feedstock.

3. The system of claim 1, wherein the at least one energy source comprises a heat recovery steam generation system (HRSG), a steam turbine, a gas turbine, a cooling tower, a gas treatment unit, a water treatment unit, a sulfur processor, a gasifier, an air separation unit (ASU), a compressor, a condenser, or a combination thereof.

4. The system of claim 1, wherein the energy comprises a waste energy source, a steam, a gas, a liquid, an electric power, or a combination thereof.

5. The system of claim 4, wherein the heating system comprises a waste heat recovery unit, a steam heat exchanger, a gas heat exchanger, a liquid heat exchanger, an electrical heater, or a combination thereof.

6. The system of claim 4, wherein the heating system comprises a waste heat recovery unit, and wherein the waste heat recovery unit comprises a recuperator, a regenerator, a heat pipe exchanger, a thermal wheel, an economizer, a heat pump, a run around coil, or a combination thereof.

7. The system of claim 1, wherein the gasification plant comprises an integrated gasification combined cycle (IGCC) power plant.

8. The system of claim 1, wherein the solid feedstock comprises low rank coal, biomass, or a combination thereof.

9. The system of claim 1, wherein the heating system is configured to remove at least 10% of the moisture from the solid feedstock to produce the dry feedstock.

10. The system of claim 1, comprising a feedstock weigh feeder, a conveyor, an impact mill and dryer, a cyclone, a vibrating screen, a baghouse, a hopper, or a combination thereof, configured to dry the solid feedstock with the energy from the at least one energy source.

11. A system, comprising:

at least one energy source configured to provide an energy;

a feedstock supply configured to deliver a solid feedstock;

a fluidization system disposed downstream of the feedstock supply, wherein the fluidization system is configured to receive the solid feedstock and to provide a dry fluidized feedstock; and

a heating system configured to use the energy to heat the solid feedstock in the fluidization system to remove moisture from the solid feedstock.

12. The system of claim 11, comprising a gasifier configured to gasify the dry fluidized feedstock, wherein the gasifier comprises a fluidized bed gasifier, a updraught gasifier, a downdraught gasifier, a cross-draught gasifier, a double fired gasifier, an entrained bed gasifier, a molten bath gasifier, a moving bed gasifier, or a combination thereof.

13. The system of claim 11, wherein the fluidization system comprises a feed bin, a feedstock weigh feeder, a conveyor, an impact mill and dryer, a cyclone, a vibrating screen, a baghouse, a hopper, or a combination thereof, configured to dry the solid feedstock with the energy from the at least one energy source.

14. The system of claim 13, wherein the feed bin is disposed upstream of the feedstock weigh feeder, the feedstock weigh feeder is disposed upstream of the conveyor, the conveyor is disposed upstream of the impact mill and dryer, the impact mill and dryer is disposed upstream of the cyclone, the cyclone is disposed upstream of the baghouse, the baghouse is disposed upstream of the hopper, and the hopper is disposed upstream of the gasifier.

15. The system of claim 11, wherein the at least one energy source comprises a heat recovery steam generation system (HRSG), a steam turbine, a gas turbine, a cooling tower, a gas treatment unit, a water treatment unit, a sulfur processor, a gasifier, an air separation unit (ASU), a compressor, a condenser, or a combination thereof.

16. A system, comprising:

a fluidization system configured to fluidize a solid feedstock, the fluidization system comprising:

a feed bin configured to dry the solid feedstock;

a conveyor;

a cyclone;

a baghouse; and

a hopper, wherein at least one energy source disposed in a gasification plant is configured to provide an energy to the feed bin to dry the solid feedstock.

17. The system of claim 16, wherein the fluidization system comprises a feedstock weigh feeder, an impact mill and dryer, and a vibrating screen, and wherein the conveyor, the cyclone, the baghouse, the feedstock weigh feeder, the impact mill and dryer, the vibrating screen, or a combination thereof, configured to dry the solid feedstock.

18. The system of claim 17, wherein the feed bin is disposed upstream of the feedstock weigh feeder, the feedstock weigh feeder is disposed upstream of the conveyor, the conveyor is disposed upstream of the impact mill and dryer, the impact mill and dryer is disposed upstream of the cyclone, the cyclone is disposed upstream of the baghouse, the baghouse is disposed upstream of the hopper, and the hopper is disposed upstream of the gasifier.

19. The system of claim 16, wherein the feed bin comprises a waste heat recovery unit, a steam heat exchanger, a gas heat exchanger, a liquid heat exchanger, an electrical heater, or a combination thereof, configured to dry the solid feedstock.

20. The system of claim 16, wherein the at least one energy source comprises a heat recovery steam generation system (HRSG), a steam turbine, a gas turbine, a cooling tower, a gas treatment unit, a water treatment unit, a sulfur processor, a gasifier, an air separation unit (ASU), a compressor, a condenser, or a combination thereof.