Patent Application
20120273176
The subject matter disclosed herein relates to gasification cooling systems, such as radiant syngas coolers, which cool gas from a gasifier.
Integrated gasification combined cycle (IGCC) power plants are capable of generating energy from various hydrocarbon feedstock, such as coal, relatively cleanly and efficiently. IGCC technology may convert the hydrocarbon feedstock into a gas mixture including carbon monoxide (CO) and hydrogen (H2), e.g., syngas, by reaction with steam in a gasifier. These gases may be cooled, cleaned, and utilized as fuel in a conventional combined cycle power plant. For example, a radiant syngas cooler (RSC) may receive and cool the syngas upstream from a water gas shift reactor and/or other gas cleaning units. To that end, RSCs typically include heat exchanger tubing that exchanges heat with the syngas to generate a cooled syngas as the syngas flows through the RSC. The heat exchanger materials may be disposed in various locations within the RSC, such as within its interior as well as within a circumferential wall of the RSC vessel. Unfortunately, many current RSC designs unevenly distribute the heated syngas flow amongst these heat exchanger materials, giving rise to inefficiencies in the syngas cooling process. These process inefficiencies may complicate the RSC design necessary to achieve optimal syngas cooling via heat exchange in the RSC.
In one embodiment, a gasification cooling system includes a housing having an inlet, an outlet, and a fluid passage disposed between the inlet and the outlet. The gasification cooling system also includes an annular wall disposed about the fluid passage, and a fluid stream is adapted to flow in a flow direction from the inlet toward the outlet. The gasification cooling system further includes one or more tangential fluid jets circumferentially disposed about the annular wall of the fluid passage and adapted to inject fluid into the fluid passage to annularly circulate the fluid stream throughout the fluid passage as the fluid stream flows in the flow direction.
In another embodiment, a gasification cooling system includes a housing having a fluid passage extending in a flow direction lengthwise along the housing. The gasification cooling system also includes an annular wall disposed about the fluid passage and including a membrane adapted to cool a syngas in the fluid passage as the syngas flows in the flow direction. The gasification cooling system further includes a plurality of fluid jets disposed about the annular wall and adapted to inject fluid into the fluid passage to direct the syngas in a circumferential direction toward the membrane as the syngas flows in the flow direction.
In another embodiment, a system includes a gasification cooling device including a housing having an inlet, an outlet, and a fluid passage disposed between the inlet and the outlet. A fluid stream is adapted to flow in a flow direction from the inlet toward the outlet to contact heat exchanger tubing adapted to cool the fluid stream. A tangential fluid jet is coupled to the housing of the gasification cooling device and is adapted to inject a fluid into the fluid passage to circulate the fluid stream in a circumferential direction as the fluid stream flows in the flow direction.
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:
As described in detail below, provided herein are embodiments of gasification cooling systems that include one or more fluid jets capable of annularly circulating a fluid stream as the stream flows in a downstream direction from an inlet toward an outlet of the system. In various embodiments, these fluid jets may be positioned in a variety of suitable locations within a gasification cooling system, such as in a circumferential arrangement disposed about an annular wall of a gasification vessel. Additionally, in these embodiments, the fluid jets may be placed in any lengthwise location along the annular wall, such as upstream of heat exchanger tubing. When appropriately positioned within the gasification cooling system, the one or more fluid jets tangentially inject fluid into the gasification vessel, thus circulating the hot fluid stream (e.g., syngas) that is flowing substantially lengthwise through the vessel. The foregoing feature may enable the dispersion of the fluid stream throughout the volume of the gasification vessel, such as toward a perimeter of the vessel having a membrane suitable for heat transfer from the fluid stream. Additionally, the inclusion of the fluid jets in the gasification cooling system may increase circulation of the fluid stream about the heat exchanger tubing disposed in a fluid passage of the vessel thereby enabling efficient heat transfer between the fluid stream and a coolant running through the heat exchanger tubing. Still further, by altering the flow rate of the fluid stream traveling through the fluid passage and/or the temperature of the injected fluid, the operability of the gasification cooling system may be more precisely controlled as compared to typical non-jet cooling systems.
It should be noted that the fluid jets may be disposed in a variety of systems and devices, such as those found in industrial equipment, power plants, or other applications. In the embodiments described herein, the foregoing features are located in an annular wall of a radiant syngas cooler (RSC) configured to cool syngas originating from a gasifier in an integrated gasification combined cycle (IGCC) power plant. However, in other embodiments, the fluid jets may be located in any suitable region of various gasification cooling systems that are designed to cool any type of fluid stream. As such, the features of the illustrated RSC may be subject to considerable variations in size, shape, and placement based on factors such as the type of gasifier used in the overall process, the fuel source utilized, and so forth. Accordingly, features of the fluid jets may have configurations other than those illustrated that are within the scope of the disclosed jets.
Still further, embodiments of a control system that utilizes feedback regarding the desired cooling process parameters are provided to control the cooling of the fluid stream in a spatially effective manner. In other words, embodiments of the disclosed control systems control one or more parameters of the fluid jets to affect the cooling process in a way that is spatially variable to improve cooling efficiency. For example, in certain embodiments, the control system may independently adjust a forcing frequency, a flow rate, or both, of one or more fluid jets in a plurality of fluid jets directed into the cooling vessel. These fluid jets may include syngas jets, air jets, carbon dioxide jets, oxygen jets, nitrogen jets, or a combination thereof. The independent control of these fluid jets selectively enables a uniform or non-uniform distribution of forcing frequencies, flow rates, or both, among the plurality of fluid jets in some embodiments. In this manner, the disclosed control systems may be responsive to variations in the cooling process, inputs received from a user, and so forth, for example, by responding with spatial variations in inputs affecting the cooling process. In other words, the spatial variations in inputs may be provided merely with a change in the forcing frequency of one or more fluid jets, or the spatial variations in inputs may be provided by changing the forcing frequency, flow rate, or both, among the plurality of fluid jets (i.e., a non-uniform distribution among jets). However, in many embodiments, only a single fluid jet may be employed, and the control system may be configured to control parameters of the single fluid jet to increase the efficiency of the heat transfer from the fluid stream.
Turning now to the drawings,
The solid fuel of the fuel source 102 may be passed to a feedstock preparation unit 104. The feedstock preparation unit 104 may, for example, resize or reshape the fuel source 102 by chopping, milling, shredding, pulverizing, briquetting, or palletizing the fuel source 102 to generate feedstock. Additionally, water, or other suitable liquids may be added to the fuel source 102 in the feedstock preparation unit 104 to create slurry feedstock. In other embodiments, no liquid is added to the fuel source, thus yielding dry feedstock.
The feedstock may be passed to a gasifier 106 from the feedstock preparation unit 104. The gasifier 106 may convert the feedstock into a syngas, e.g., a combination of carbon monoxide and hydrogen. This conversion may be accomplished by subjecting the feedstock to a controlled amount of steam and oxygen at elevated pressures, e.g., from approximately 20 bar to 85 bar, and temperatures, e.g., approximately 700 degrees Celsius-1600 degrees Celsius, depending on the type of gasifier 106 utilized. The gasification process may include the feedstock undergoing a pyrolysis process, whereby the feedstock is heated. Temperatures inside the gasifier 106 may range from approximately 150 degrees Celsius to 700 degrees Celsius during the pyrolysis process, depending on the fuel source 102 utilized to generate the feedstock. The heating of the feedstock during the pyrolysis process may generate a solid, (e.g., char), and residue gases, (e.g., carbon monoxide, hydrogen, and nitrogen). The char remaining from the feedstock from the pyrolysis process may weigh up to approximately 30% of the weight of the original feedstock.
A combustion process may then occur in the gasifier 106. The combustion 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 700 degrees Celsius to 1600 degrees Celsius. Next, steam may be introduced into the gasifier 106 during a gasification step. The char may react with the carbon dioxide and steam to produce carbon monoxide and hydrogen at temperatures ranging from approximately 800 degrees Celsius to 1100 degrees Celsius. In essence, the gasifier utilizes steam and oxygen to allow some of the feedstock to be “burned” to produce carbon monoxide and energy, which drives a second reaction that converts further feedstock to hydrogen and additional carbon dioxide.
In this way, a resultant gas is manufactured by the gasifier 106. This 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 dirty syngas, and, after leaving the gasifier 106, the dirty syngas is typically mixed with waste, such as slag 108, which may be a wet ash material. The dirty syngas and the slag 108 exiting the gasifier 106 are at elevated temperatures, and, to separate and cool the syngas and slag mixture, a radiant syngas cooler (RSC) 146 is employed. The slag and dirty syngas mixture enters the RSC 146 where the slag 108 is separated from the dirty syngas, as illustrated in
Embodiments of the radiant syngas coolers disclosed herein may include one or more features, such as one or more tangential fluid jets, that circulate the dirty syngas within the RSC 146 for cooling, for example, by directing the heated syngas toward the exchanger tubing and/or a membrane disposed about the perimeter of the RSC 146. Further, the RSC 146 may also include a control system that is capable of controlling a flow rate and/or a forcing frequency of the fluid injected via the one or more jets to increase or maximize the cooling capacity of the RSC 146. These and other features of certain embodiments of the present invention are discussed in more detail below with respect to the RSC shown in
After the dirty syngas is cooled and separated from the slag 108, a gas cleaning unit 110 may be utilized to clean the dirty syngas. The gas cleaning unit 110 may scrub the dirty syngas to remove the HCl, HF, COS, HCN, and H2S from the dirty syngas, which may include separation of sulfur 111 in a sulfur processor 112 by, for example, an acid gas removal process in the sulfur processor 112. Furthermore, the gas cleaning unit 110 may separate salts 113 from the dirty syngas via a water treatment unit 114 that may utilize water purification techniques to generate usable salts 113 from the dirty syngas. Subsequently, the gas from the gas cleaning unit 110 may include clean syngas.
If desired, a gas processor 116 may be utilized to remove residual gas components 117 from the clean syngas. However, removal of residual gas components 117 from the clean syngas is optional, since the clean syngas may be utilized as a fuel even when containing the residual gas components 117, e.g., tail gas. At this point, the clean syngas may include approximately 1-10% CO (e.g., 3% CO), approximately 30-60% H2 (e.g., 55% H2), and approximately 30-60% CO2 (e.g., 40% CO2) and is substantially stripped of H2S. This clean syngas may be transmitted to a combustor 120, e.g., a combustion chamber, of a gas turbine engine 118 as combustible fuel.
The IGCC system 100 may further include an air separation unit (ASU) 122. The ASU 122 may operate to separate air into component gases by, for example, distillation techniques. The ASU 122 may separate oxygen from the air supplied to it from a supplemental air compressor 123, and the ASU 122 may transfer the separated oxygen to the gasifier 106. Additionally the ASU 122 may transmit separated nitrogen to a diluent nitrogen (DGAN) compressor 124.
The DGAN compressor 124 may compress the nitrogen received from the ASU 122 at least to pressure levels equal to those in the combustor 120, so as not to interfere with the proper combustion of the syngas. Thus, once the DGAN compressor 124 has adequately compressed the nitrogen to a proper level, the DGAN compressor 124 may transmit the compressed nitrogen to the combustor 120 of the gas turbine engine 118.
The compressed nitrogen may be transmitted from the DGAN compressor 124 to the combustor 120 of the gas turbine engine 118. The gas turbine engine 118 may include a turbine 130, a drive shaft 131 and a compressor 132, as well as the combustor 120. The combustor 120 may receive fuel, such as 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 124, and combusted within combustor 120. This combustion may create hot pressurized exhaust gases.
The combustor 120 may direct the exhaust gases towards an exhaust outlet of the turbine 130. As the exhaust gases from the combustor 120 pass through the turbine 130, the exhaust gases may force turbine blades in the turbine 130 to rotate the drive shaft 131 along an axis of the gas turbine engine 118. As illustrated, the drive shaft 131 is connected to various components of the gas turbine engine 118, including the compressor 132.
The drive shaft 131 may connect the turbine 130 to the compressor 132 to form a rotor. The compressor 132 may include blades coupled to the drive shaft 131. Thus, rotation of turbine blades in the turbine 130 may cause the drive shaft 131 connecting the turbine 130 to the compressor 132 to rotate blades within the compressor 132. This rotation of blades in the compressor 132 causes the compressor 132 to compress air received via an air intake in the compressor 132. The compressed air may then be fed to the combustor 120 and mixed with fuel and compressed nitrogen to allow for higher efficiency combustion. Drive shaft 131 may also be connected to load 134, which may be a stationary load, such as an electrical generator for producing electrical power, for example, in a power plant. Indeed, load 134 may be any suitable device that is powered by the rotational output of the gas turbine engine 118.
The IGCC system 100 also may include a steam turbine engine 136 and a heat recovery steam generation (HRSG) system 138. Heated exhaust gas from the gas turbine engine 118 may be transported into the HRSG 138 and used to heat water and produce steam used to power the steam turbine engine 136. The steam turbine engine 136 may drive a second load 140. The second load 140 may also be an electrical generator for generating electrical power. However, both the first and second loads 134, 140 may be other types of loads capable of being driven by the gas turbine engine 118 and steam turbine engine 136. In addition, although the gas turbine engine 118 and steam turbine engine 136 may drive separate loads 134 and 140, as shown in the illustrated embodiment, the gas turbine engine 118 and steam turbine engine 136 may also be utilized in tandem to drive a single load via a single shaft. The specific configuration of the steam turbine engine 136, as well as the gas turbine engine 118, may be implementation-specific and may include any combination of sections.
Exhaust from, for example, a low-pressure section of the steam turbine engine 136 may be directed into a condenser 142. The condenser 142 may utilize a cooling tower 128 to exchange heated water for chilled water. The cooling tower 128 acts to provide cool water to the condenser 142 to aid in condensing the steam transmitted to the condenser 142 from the steam turbine engine 136. Condensate from the condenser 142 may, in turn, be directed into the HRSG 138. Again, exhaust from the gas turbine engine 118 may also be directed into the HRSG 138 to heat the water from the condenser 142 and produce steam.
In combined cycle systems such as IGCC system 100, hot exhaust may flow from the gas turbine engine 118 and pass to the HRSG 138, where it may be used to generate high-pressure, high-temperature steam. The steam produced by the HRSG 138 may then be passed through the steam turbine engine 136 for power generation. In addition, the produced steam may also be supplied to any other processes where steam may be used, such as to the gasifier 106. The gas turbine engine 118 generation cycle is often referred to as the “topping cycle,” whereas the steam turbine engine 136 generation cycle is often referred to as the “bottoming cycle.” By combining these two cycles as illustrated in
The illustrated vessel 148 also includes heat exchanger tubing 158, which may be in the upper region 147 of the RSC 146. The tubing 158 may include a plurality of conduits disposed along the radial axis 126 of the RSC 146 and running parallel in direction with the vessel 148 relative to the axial axis 125. Chilled liquid, such as water, may flow through the tubing 158. Thus, during use, the tubing 158 may act as a heat exchanger within the RSC 146, and may circulate the coolant to an external heat exchanger for removal of heat. That is, a chilled liquid may be circulated through the tubing 158 and heated up as the hot syngas contacts the outer surfaces of the heat exchanger tubing 158. As such, the liquid flowing through the heat exchanger tubing 158 may enter the tubing at a lower temperature than the liquid leaving the tubing 158. Accordingly, the tubing 158 may be made of a thermally resistant material suitable for use with hot syngas.
Further, the vessel 148 also includes a membrane 159 disposed about a perimeter of the RSC 146 that defines an outer wall of the vessel 148. In some embodiments, the membrane 159 may be formed from a material capable of operating as a heat exchanger for removal of heat from a fluid in contact with the membrane 159. That is, in certain embodiments, both the heat exchanger tubing 158 and the membrane 159 may operate to cool a liquid (e.g., syngas) flowing through the RSC 146. To that end, one or more tangential fluid jets, as represented by arrows 161, are circumferentially disposed about the annular wall of the vessel 148 to inject fluid into the RSC 146. Once injected, the circularly directed fluid may interact with a hot fluid stream flowing in a substantially downward direction from the inlet 152 toward the outlet 154 to annularly circulate the hot fluid stream. As such, the one or more tangential fluid jets 161 may facilitate efficient cooling of the hot fluid stream by distributing the hot fluid stream both amongst the tubes of the heat exchanger tubing 158 as well as toward the perimeter membrane 159 of the vessel 148.
For example, in the illustrated embodiment, during operation of the RSC 146, the syngas generated in the gasifier 106 enters the RSC 146 as a mixture of syngas and slag (i.e., a hot fluid stream). The slag 108 and the syngas are substantially separated in the throat region 153 of the RSC 146 and, after separation, follow distinct flow paths through the remainder of the length of the RSC 146. The syngas, after being separated from the slag flow stream, generally flows in a downward manner parallel to the tubing 158, as indicated by arrows 160. That is, the syngas flows through a gas passage of the RSC 146 that extends in the flow direction 160 lengthwise along the vessel 148. As the syngas flows in direction 160 through the gas passage, the fluid jets 161 inject fluid that circulates the syngas about the fluid passage, thus directing the syngas toward the membrane 159 of the vessel 148. Accordingly, the syngas enters the RSC 146 through the inlet 152 in a mixture with the slag, separates from the slag, is annularly circulated about the fluid passage, flows lengthwise through the interior region 156 of the RSC 146, and then exits the RSC 146 through the outlet 154. In this manner, the syngas may come in contact with the heat exchanger tubing 158 and the perimeter membrane 159 of the RSC 146, and the tubing 158 as well as the membrane 159 may act to cool the syngas as it travels through the RSC 146. One result of this cooling process may be the generation of steam in the tubing 158, which may, for example, be transmitted to the high pressure drum 145 (see
The RSC 146 may also include a conduit 162 in the lower region 149 of the RSC 146 that may aid in directing the cooled syngas and separated slag out of the RSC 146. For example, as the slag 108 exits the conduit 162, the slag 108 may flow in a generally downward direction 164 to exit the RSC 146 via a quench cone 166. In contrast, the cooled syngas may flow in a general upward direction 168 towards a transfer line 170 as the syngas exits the conduit 162. The transfer line 170 may be used to transmit the syngas to the gas cleaning unit 110 and/or the gas turbine engine 118 (see
Although a single fluid jet 188 is illustrated in the embodiment of
Turning now to the operation and control of the fluid jet 188 in the illustrated embodiment, a control system 190 is provided to control the injection of fluid from the fluid jet 188 into the chamber 184 of the RSC 146. For example, the control system 190 may be configured to control jet parameters such as forcing frequency, fluid composition, temperature, jet distribution, and so forth, to exhibit control over the cooling process based on the given application. For example, in some embodiments, the control system 190 may receive inputs from an operator regarding operational parameters, such as the type of fuel being utilized to generate the syngas, the syngas flow rate, and so forth, and may utilize these inputs to determine appropriate jet parameters. Further, in some embodiments, the control system 190 may receive feedback regarding the cooling performance of the system from one or more sensors disposed within the gasification cooling system. For example, in one embodiment, temperature sensors may be disposed in a grid within the RSC 146 and/or at the outlet of the RSC 146, and, based on feedback from the temperature sensors, the control system 190 may adjust parameters of the fluid jet 188 until the received feedback falls within a desired tolerance interval.
To that end, the control system 190 may include suitable electrical circuitry, for example, volatile or non-volatile memory, such as read only memory (ROM), random access memory (RAM), magnetic storage memory, optical storage memory, or a combination thereof. Furthermore, a variety of control parameters may be stored in the memory along with code configured to provide a specific output. For instance, the control system 190 may be programmed to acquire and time stamp received data, such as temperature sensor data, at a first frequency and output control data to the fluid jet 188 at a second frequency. As appreciated, the first and second frequencies may be the same or different from one another, and may vary depending on the application and specific design considerations. However, any suitable frequencies may be used for the first and second frequencies or the data may be transmitted in any other suitable manner. Still further, in some embodiments, the control system 190 may only store data from the most recent sensor measurements or operator inputs (e.g., data may only be stored for the prior 30 minutes), thus eliminating historical data from its memory as more recent sensor data or operational inputs become available. In such embodiments, the control system 190 may be configured to access historical data stored in the memory as necessary. In other embodiments, the control system 190 may retain all or a larger amount of historical data as a baseline for controlling the gasification cooling system or may access stored programs to guide jet operation.
In the illustrated embodiment, to exhibit the desired control over the syngas cooling process, the control system 190 is coupled to a flow controller 192 (e.g., a valve) and a forcing frequency drive 194 (e.g., acoustic speaker 198, amplifier 200, and signal generator 202) to control the flow and forcing frequency associated with a fluid 196 being injected into the chamber 184 of the RSC 146. During operation, the fluid jet 188 (or set of fluid jets) receives the fluid 196 flowing along an airflow path having the flow controller 192 and the forcing frequency drive 194. Concurrently, the control system 190 controls operational characteristics of the fluid jet 188 (or set of fluid jets) to vary the fluid flow rate and/or the forcing frequency of the fluid jet in a uniform manner or non-uniform manner depending on the given application. For example, in embodiments in which multiple fluid jets are provided, the control system 190 may independently control each individual jet to substantially improve the distribution of the syngas 182 within the chamber 184, thereby providing a more uniform distribution of the hot syngas between the heat exchanger tubing and the membrane of the vessel walls for improved syngas cooling. For example, the independent control of the flow rate and forcing frequency of individual jets of a plurality of jets may substantially reduce pockets of undesirably high temperature syngas by more uniformly cooling the syngas through the use of the heat exchanger tubing and the vessel membrane. Thus, by providing and controlling one or more fluid jets of the gasification system, disclosed embodiments may modify the cooling process in the RSC 146 to more fully utilize the cooling capacity of the RSC 146.
More specifically, as further illustrated in the forcing frequency drive 194 of
In other embodiments, the forcing frequency drive 194 may include other non-illustrated components that force the expelled fluid flow to change shape, size, or mixing characteristics. For example, the forcing frequency drive 194 may include any components that are configured to vibrate or modulate fluid flow at a desired frequency of change. For instance, in one embodiment, vibrating valves may be used to vibrate the fluid flow at a desired frequency. In another embodiment, the pressure of the fluid flow may be pulsed at a desired frequency. In such embodiments, the forcing frequency drive 194 may include valves, pulsation mechanisms, vibration mechanisms, and/or modulation mechanisms configured to change the acoustic properties of the fluid flow.
During operation, the control system 190 independently or uniformly controls the fluid jets 204, 206, 208, and 210. Again, the independent or uniform control may include variations in the forcing frequency, forcing amplitude, and flow rate of one or more of the fluid jets, thereby changing the spatial impact of the fluid jets on the cooling process. In particular, the control system 190 may adjust the forcing frequency, amplitude, and flow rate of each fluid jet to change the shape, size, penetration, and mixing characteristics of the injected fluid to affect the cooling of the syngas flowing through the RSC 146. Thus, by virtue of the independent control that may be exhibited in some embodiments, the control system 190 is able to adjust the spatial distribution of fluid jet characteristics (e.g., flow rate, frequency, and amplitude) among the plurality of jets 204, 206, 208, and 210 to effectuate efficient syngas cooling by utilizing the cooling capacity of both the heat exchanger tubing 158 and the membrane 159 of the RSC 146.
More specifically, during operation, the fluid jet 204 injects fluid into the chamber 184, for example, in a substantially circular manner indicated by arrows 228, to annularly circulate the syngas throughout the chamber 184. Likewise, the jets 206, 208, and 210, also circumferentially inject fluid into the chamber 184, as indicated by arrows 230, 232, and 234, respectively, to direct the syngas in a circular direction to both guide the syngas toward the membrane 159 and disperse the syngas about the surfaces of the heat exchanger tubes 158. The foregoing features of disclosed embodiments may enable efficient heat transfer between the syngas and the heat exchanger materials of the RSC 146. Still further, such control and operation alters the flow rate of the syngas traveling through the fluid passage, thus enabling the operability of the gasification cooling system to be more precisely controlled as compared to typical non-jet cooling systems.
Still further, the method 236 includes monitoring the operational mode and parameters throughout the cooling operation (block 244) and modifying the fluid composition, flow rate, forcing frequency, temperature, and/or jet distribution based on this monitoring process (block 246). In this way, the control system may adapt the operation of the fluid jets throughout the cooling operation to cool the hot syngas in an efficient manner. It should be noted that in some embodiments, operation of the control system may be limited to blocks 242, 244, and 246 of the illustrated method, for example, in instances in which the control system is preloaded with a desired default start setting.
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.
