TW201727047A - System and method for high efficiency power generation using a carbon dioxide circulating working fluid - Google Patents

Abstract

The present invention provides methods and system for power generation using a high efficiency combustor in combination with a CO2 circulating fluid. The methods and systems advantageously can make use of a low pressure ratio power turbine and an economizer heat exchanger in specific embodiments. Additional low grade heat from an external source can be used to provide part of an amount of heat needed for heating the recycle CO2 circulating fluid. Fuel derived CO2 can be captured and delivered at pipeline pressure. Other impurities can be captured.

Description

High-efficiency power generation system and method using carbon dioxide circulating working liquid

Cross-reference to related applications

The priority of this patent application is based on U.S. Provisional Patent Application No. 61/299,272, filed on Jan. 28, 2010, and U.S. Patent Application Serial No. 12/714,074, filed on Feb. 26, 2010. The U.S. Provisional Patent Application Serial No. 61/155,755, filed on Feb. 26, 2009, the entire disclosure of which is hereby incorporated by reference.

The present invention is directed to a power generation (e.g., electric power) system and method for transmitting energy generated by high efficiency combustion of fuel by using a circulating liquid. In particular, this system and method can use carbon dioxide as a circulating liquid.

It is estimated that in the next 100 years, while developing and deploying carbon-free energy, petrochemical fuels will continue to provide most of the world's electricity demand. However, known power generation methods that burn fossil fuels and/or suitable biomass are affected by increased energy costs and increased carbon dioxide (CO ₂ ) production and other emissions. Global warming has gradually been seen as a potentially catastrophic consequence of the carbon emissions that have been developed and increased in developing countries. Solar energy and wind power may not replace fossil fuel combustion in the short term, and nuclear energy has risks associated with nuclear expansion and nuclear waste disposal.

From conventional fossil fuel power generation apparatus, or a suitable protoplast now increasing demand for delivery to a subject is eligible storage site (sequestration site) of the high-pressure CO ₂ up. However, since even the best design for CO ₂ capture, the existing technology can only provide very low thermal efficiency, and therefore, this requirement proves to be difficult to implement. Further, to achieve the high construction cost of CO ₂ capture, and the CO ₂ is compared to system divergence to the atmosphere, which results in significantly higher power costs. Accordingly, the art in this regard can be reduced to CO ₂ emissions, and / or more convenient production of CO ₂ sequestration high-efficiency power generation systems and methods always increased demand.

The present invention provides a binding circulating liquid (e.g., a liquid CO ₂ cycle) of efficient combustion (e.g., a combustor cooling ET) of the power generation method and system for utilization. In particular, the circulating liquid can be introduced into the combustor together with a fuel for combustion and an oxidant such that a high pressure, high temperature liquid stream comprising the circulating liquid and any combustion products is produced. The liquid stream can be directed to a power plant, such as a turbine. Advantageously, the liquid stream can be maintained at a relatively high pressure during expansion into the turbine such that the pressure ratio across the turbine (ie, the pressure at the turbine inlet and the turbine outlet) The ratio between the pressures at the point) is less than about 12. The liquid stream can then be further processed to separate components of the liquid stream, which can include passing the liquid stream through a heat exchanger. In particular, the circulating liquid, at least a portion of which may be recovered from the liquid stream, may pass through the same heat exchanger to heat the circulating liquid prior to being introduced into the burner. In such an embodiment, it is useful to operate the heat exchanger (e.g., by selecting a low heat source) such that the heat exchanger has only a small amount between the turbine discharge and the recovered liquid at the hot end of the heat exchanger. Temperature difference.

In certain aspects, the present invention provides a power generation system capable of generating a low-efficiency power generation and construction costs, and also generates at the line pressure of substantially pure CO _2, for storage. The CO ₂ can also be recycled into the power generation system.

The systems and methods of the present invention are characterized by the ability to use a wide variety of fuel sources. For example, the high efficiency combustor used in accordance with the present invention may utilize gaseous (eg, natural gas or coal derived gas), liquid (eg, hydrocarbon, bitumen), and solid (eg, coal, lignite, petroleum coke) fuel. Even further fuels (as otherwise described herein) can be used.

In other aspects, the method and system of the present invention is particularly usefully, they can not provide optimum efficiency than CO ₂ capture existing coal burning power plant. Such existing power plants use bituminous coal with a 1.7 Torr mercury condensing pressure to provide an optimum efficiency of about 45% (lower calorific value, or "LHV"). The system of the present invention may thus exceed the efficiency, but also for storage, or other disposition may be delivered at a desired pressure CO _2.

In still another aspect, the present invention provides the ability to reduce the physical size and construction cost of a power generation system as compared to current technologies that utilize similar fuels. Thus, the method and system of the present invention can significantly reduce the cost of building a system associated with a power generation system.

Yet still further, the system and method of the present invention may be contemplated use, and / or CO ₂ produced (in particular the carbon in the fuel from CO ₂₎ in almost 100% recovery. In particular, the CO ₂ can be provided as a dried, purified gas at line pressure. Furthermore, the present invention provides the ability to separately recover other fuels and burn derivative-derived impurities for other uses, and/or disposal.

In a particular aspect, the present invention is directed to a combination with a circulating liquid (e.g. CO ₂₎ generation method. In a particular embodiment, the power generation method according to the present invention may comprise carbonaceous fuel, O _2, CO ₂ cycle, and a liquid introduced into the combustor. Specifically, the CO ₂ is introduced at a pressure of at least about 8 MPa (preferably at least about 12 MPa) and at a temperature of at least about 200 ° C (preferably at least about 400 ° C). The method further comprising combusting the fuel to provide a product stream comprising combustion of CO _2. In particular, the combustion product stream can have a temperature of at least about 800 °C. Further, the method may comprise expanding the combustion product stream across a turbine to generate power, the turbine having the combustion product stream for receiving an inlet and an outlet to release CO comprises a turbine exhaust stream ₂ . Preferably, the ratio of the pressure of the combustion product stream at the inlet to the turbine discharge stream at the outlet is less than about 12. In a particular embodiment, the desired that the CO ₂ at a pressure of at least about 10MPa, 20MPa pressure of at least about at least a temperature of about 400 deg.] C, or at least a temperature of about 700 deg.] C is introduced into the combustor. Even further possible processing parameters are also described herein.

In some embodiments, the liquid CO ₂ cycle which may be introduced into the combustor transpiration cooling, in one of the O _2, and wherein the carbonaceous fuel, or both mixed. In other embodiments, the liquid CO ₂ cycle which may be introduced into the combustor cooling evapotranspiration, as all or part of a transpiration cooling liquid, the cooling liquid through evapotranspiration ET formed in the cooling of a combustor, or The evapotranspiration liquid supply channel is introduced. In a particular embodiment, the liquid CO ₂ cycle which may be introduced into the combustor as the evaporable liquid.

This combustion is characterized in particular by the actual combustion temperature. For example, combustion is carried out at a temperature of at least about 1,500 °C. In other embodiments, the combustion is carried out at a temperature of at least about 1,600 °C to about 3,300 °C.

The invention also features the purity of CO ₂ in the O ₂ stream. For example, in some embodiments, ambient air is useful. However, in certain embodiments, it may be beneficial to purify the oxygen content. For example, the O ₂ can be provided as a first-class, wherein the O _{2 has} a molar concentration of at least 85%. Even further specific concentrations are also described herein.

In a particular embodiment, the combustion product stream can have a temperature of at least about 1,000 °C. Further, the combustion product stream having a pressure is introduced into the combustor of CO ₂ is at least about 90%, or at least about 95% of the pressure of the burner is introduced into the pressure of CO _2.

In some embodiments, the pressure ratio of the combustion product to the turbine inlet may be from about 1.5 to about 10, or may be from about 2 to about 8, as compared to the pressure of the turbine discharge at the turbine outlet. Even further possible ratios are also provided here.

The invention may be characterized by the ratio of the particular material being introduced into the combustion chamber. For example, the CO ₂ in the ratio of CO ₂ in the circulating liquid fuel is introduced into the combustor based on the mole of carbon may be from about 10 to about 50, or from about 10 to about 30. Even further possible ratios are provided here.

Feature of the present invention may be further characterized, at least a portion of CO ₂ can be recovered in the turbine exhaust stream and reintroduced into the burner. At least a portion of the CO ₂ can be discharged from the system (e.g., for storage, or other disposition), for example, through a conduit.

In a particular embodiment, the turbine discharge stream may be CO ₂ in the gaseous state. In particular, the turbine discharge stream can have a pressure of less than, or equal to, 7 MPa.

In other embodiments, the method of the present invention further comprises passing the turbine exhaust stream through at least one heat exchanger that cools the turbine exhaust stream, and providing one of the CO ₂ circulating liquid streams having a temperature of less than about 200 ° C. . This can usefully contribute to removing one or more dependent components (i.e., addition of components other than CO ₂₎ under conditions to provide CO ₂ circulating liquid stream. In a particular embodiment, this can include passing the turbine discharge stream through at least two heat exchangers in series. More specifically, the first heat exchanger in the series can receive the turbine discharge stream and reduce its temperature, the first heat exchanger being formed of a superalloy that can withstand at least about 900 °C.

The method of the present invention may also comprise performing the flow a circulating liquid CO _2, or more separate steps to remove the liquid present in the circulation flow in addition to CO ₂ other than one or more dependent components (as previously Mentioned). In particular, the one or more dependent components may comprise water.

The method of the invention also includes compressing a stream of CO ₂ . For example, after expanding the combustion product stream and cooling the turbine discharge stream, it is beneficial to compress the stream to recover it back to the burner. Specifically, the method may comprise The liquid CO ₂ cycle via a flow, or more compressors (e.g., pump), to the CO ₂ cycle liquid stream compressed to a pressure of at least about 8MPa. This can further comprise, that the CO ₂ cycle liquid flow through the at least two compressors in series, to the CO ₂ cycle pressurized liquid stream. In certain embodiments, the CO ₂ cycle liquid stream may be pressurized to a pressure of at least about 15Mpa. Even further pressure ranges are desirable (as otherwise described). In other embodiments, the pressurized stream of liquid CO ₂ cycle which may be specifically provided to be in a supercritical fluid state. In some embodiments, at least a portion of the pressurized CO ₂ may be introduced into a pressurized fluid flow conduit CO ₂ cycle in order for storage (or other disposition, as was said before) .

In addition to pressure, the present invention also comprises a method of heating the liquid flow CO ₂ circulation previously cooled, to turn back to the combustor (i.e., recovery of the _circulating flow of liquid CO). In some embodiments, this may include the CO ₂ cycle pressurized liquid stream 200 is heated to at least about deg.] C, at least about 400 ℃, or a temperature of at least about 700 deg.] C. In certain embodiments, the temperature of the pressurized circulating liquid CO ₂ stream may be heated to a temperature than the turbine exhaust stream is less than about 50 ° C. Even further possible temperature ranges are also provided here. Specifically, such a heating may comprise, so that the pressurized fluid flow of the CO ₂ cycle (s) through the same heat exchanger used to cool the turbine exhaust stream. Such heating may also include inputting heat from an external source (i.e., in addition to the heat captured from the heat exchangers). In a particular embodiment, heating can include using heat recovered from an O ₂ separation unit. Preferably, this additional heat is introduced at the cold end of the heat exchanger unit (or in front of a heat exchanger in the series operating at the highest temperature range when a series connection of heat exchangers is used).

In certain embodiments, the invention features a property that the combustion product stream can allow for selective execution of multiple turbines. For example, in some embodiments, the combustion product stream can be comprised of one or more combustible components (eg, a component selected from the group consisting of H ₂ , CO, CH ₄ , H ₂ S, NH) ₃ , and its combination) a reducing liquid. This can be controlled by the ratio of O ₂ to the fuel used. In some embodiments, the combustion product stream may include the complete oxidation of ingredients, e.g., CO _2, H ₂ O, and SO ₂ ,, and has been listed on the restored such ingredients. The actual composition achieved may depend on the ratio of O ₂ and the fuel used in the feed to the evapotranspiration burner. In particular, a turbine used in such an embodiment may include two or more units each having an inlet and an outlet. In a particular embodiment, the turbine units are operable such that the operating temperatures at the inlet are substantially the same, which may include adding some O ₂ to the first turbine unit (or when using three or more units) The liquid flow at the exit of the preceding turbine unit). O ₂ is provided to allow a burning the combustible components or more, under a series of entering the turbine raises the temperature of the stream before. This results in the ability to maximize the power generated from the combustion gases in the presence of the circulating liquid.

In other embodiments, the turbine discharge stream can be an oxidizing liquid. For example, the turbine discharge stream can include an excess of O ₂ .

In some embodiments, the invention features the state of the various streams. For example, the turbine exhaust stream may be in a gaseous state after the step of expanding the combustion product stream across the turbine. This gas may be through at least one heat exchanger to cool the gas turbine exhaust stream, and further separating the components from any of the slave CO _2. Thereafter, at least a portion of the separated CO ₂ can be pressurized and converted to a supercritical liquid form and passed again through the same heat exchanger for the CO ₂ recovered into the combustor. heating. In a particular embodiment, the temperature of the turbine discharge stream entering the heat exchanger (or when using a first heat exchanger in series) from the expansion step and leaving the same heat exchanger to recover into the combustion this is heated, pressurized, the temperature difference between the temperature of CO ₂ supercritical fluid may be less than about 50 ℃.

As previously mentioned, the fluid flow exiting the fuel burner may include the CO ₂ cycle, and a liquid, or more further ingredients, e.g., combustion products. In some embodiments, usefully recovering at least a portion of the CO _2, and re-introduced into the fuel burner. Therefore, the circulating liquid can be a recovered liquid. Of course, CO ₂ from an external source can be used as the circulating liquid. The turbine exhaust may be cooled in a heat exchanger economizer, and the recovered heat is used to heat can be recovered in the high pressure CO _2. The cooled turbine exhaust exiting the low temperature end of the heat exchanger may comprise components derived from the fuel or the combustion process, such as H ₂ O, SO ₂ , SO ₃ , NO, NO ₂ , Hg, and HCl. In other embodiments, these components can be removed from the stream using a suitable method. Other components in this stream may include those derived from the inert gaseous fuel or oxidant impurities, e.g., N _2, argon (Ar), and an excess O _2. These can be removed by suitable processing of the separation. In a further embodiment, the turbine discharge must be at a pressure that is less than the condensing pressure of the CO ₂ in the turbine discharge at the temperature of the available cooling device such that there is no CO ₂ liquid when the turbine discharge is cooled. meet form, as this will allow liquid from the _separation contains the minimum amount of water vapor in the gaseous CO.'s, to allow water to be condensed. In a further embodiment, the purified CO ₂ can now be compressed to produce a high pressure recovery CO ₂ cycle along with at least a portion of the CO ₂ in the liquid representing carbon oxide (derived from the carbon fed to the fuel). A liquid stream that can be introduced into a pressurized line for storage. Due to the high pressure of the turbine discharge stream, the ability to transfer CO ₂ directly into the pressurized line from the combustion process with minimal further processing, or compression, is significantly different from conventional methods (where CO ₂ is restored to The advantage of being close to atmospheric pressure (ie, about 0.1 MPa) or being diverged to the atmosphere. Furthermore, the CO ₂ for storage according to the present invention can be delivered in a more efficient and economical manner than is conventional.

Entering the heat recovery of the CO ₂ stream (ideally, at above critical pressure) specific heat is high, and decreases as temperature rises. It is particularly advantageous that at least a portion of the heat at the lowest temperature level is derived from an external source, which may be, for example, a low pressure flow supply that provides heat to the condensation, in further embodiments, the heat source It may be derived from the supply of oxidant under adiabatic mode to the burner of the cryogenic air separation air plant used in the compression of the operator (which does not ship is used to provide heat to the heat recovery CO ₂ stream of the transfer fluid closed cycle flow of Extraction of compressed heat and internal cooling).

In one embodiment, the power generation method of the present invention may comprise the steps of: a fuel, O _2, and CO ₂ cycle liquid introduced into a burner, the CO ₂ at a pressure of at least about 8Mpa, and at least about 200 ℃ of temperature is introduced; the fuel combustion, comprising providing a stream of CO ₂ combustion product, which combustion product stream having a temperature of at least about 800 deg.] C; expansion of the combustion product stream across a turbine to generate power, the turbine having an inlet pressure ratio to receive the combustion product stream and an outlet of the turbine to release CO ₂ comprises a discharge stream, wherein, in the combustion product stream at the inlet compared to the outlet of the turbine of the exhaust stream is less than about 12: recovering heat from the turbine exhaust stream by passing the turbine exhaust stream through a heat exchange unit to provide a cooled turbine exhaust stream; the cooled turbine exhaust stream is removed from the cooled turbine exhaust stream plus a CO, ₂ or more slave components to provide a purified, cooled turbine exhaust stream; a first compressor using the purified, cooled turbine exhaust Compressed to a pressure above the critical pressure of CO _2, to provide a supercritical CO ₂ flow of the circulating liquid; the supercritical CO ₂ circulating liquid stream is cooled to a density of at least about 200kg / m ^3, a temperature; The supercritical, The high density CO ₂ circulating liquid is passed through a second compressor to pressurize the CO ₂ circulating liquid to a pressure required to be input to the burner; the supercritical, high density, high pressure CO ₂ circulating liquid is passed through the same heat switching means, so that the recovered heat is used to increase the temperature of the liquid CO ₂ cycle; an additional amount of heat supplied to the super-critical, high density, high pressure liquid CO ₂ cycle, such that for recycled to the combustor And the difference between the temperature of the CO ₂ circulating liquid leaving the heat exchange unit and the temperature of the turbine discharge stream is less than about 50 ° C; and recovering the heated, supercritical, high density CO ₂ circulating liquid to the burner in.

In particular embodiments, such systems and methods are particularly useful in combination with existing power generation systems and methods (eg, conventional coal fired power plants, nuclear energy reactors, and other systems that utilize conventional boiler systems and method). Thus, in some embodiments, between the expanding step and the retracting step as described above, the method of the present invention can include passing the turbine exhaust stream through a second heat exchange unit. Such a second heat exchange unit may use heat from the turbine discharge stream to heat one or more streams derived from a steam power generation system (eg, a conventional boiler system, including a coal fired power plant and a nuclear power reactor) . The heated vapor stream can then be passed through one or more turbines for power generation. The flow leaving the turbines can be processed by circulating back through the parts of a conventional power generation system (e.g., a boiler).

In a further embodiment, the method of the present invention may be characterized by one or more of the following steps: cooling the turbine discharge stream to a temperature below its water dew point; further cooling by an ambient temperature cooling medium The turbine discharge stream; condensing water with the one or more subordinate components to form a solution comprising one or more of H ₂ SO ₄ , HNO ₃ , HCl, and mercury; the cooled turbine The discharge stream is pressurized to a pressure of less than about 15 MPa; a product CO ₂ stream is withdrawn from the supercritical, high density, high pressure CO ₂ recycle liquid stream prior to passage through the primary heat exchange unit; a portion of the combustion product stream is passed used as fuel; in the presence of a circulating liquid CO ₂ to O ₂ combustion of a carbonaceous fuel, the carbon-containing fuel, O _2, CO _2, and providing a ratio of the circulating liquid so that the carbonaceous fuel is only partially oxidized to produce Including a non-combustible component, CO ₂ , and one or more of the H ₂ , CO, CH ₄ , H ₂ S, and NH ₃ oxidized combustion product streams; The temperature is sufficiently low to provide the ratio Fuel, O _2, and CO ₂ cycle ,, so that all the liquid components of the stream of non-combustible solid is in particle form; The partial oxidation product stream through a combustion, more or more filters; use this filter to The remaining amount of the non-combustible component is reduced by at least about 2 mg/m ^{3 of} the partial oxidized combustion product stream; coal, lignite, or petroleum coke is used as the fuel; and the particulate form fuel is provided as a slurry having CO ₂ .

In a further embodiment, the invention is described in relation to a method of power generation comprising the steps of introducing a carbonaceous fuel, O ₂ , and a CO ₂ recycle liquid into an evapotranial cooling combustor, the CO ₂ being at least about 8 MPa. a pressure, and a temperature of at least about 200 ° C is introduced; combusting the fuel to provide a combustion product stream comprising CO ₂ having a temperature of at least about 800 ° C; expanding the combustion product stream across a turbine, To generate electricity, the turbine has an inlet to receive the combustion product stream, and an outlet to release a turbine discharge stream comprising CO ₂ , wherein the combustion product stream at the inlet is compared to the outlet at the outlet The turbine discharge stream has a pressure ratio of less than about 12; passing the turbine discharge stream through at least two heat exchangers in series that recover heat from the turbine discharge stream and provide the CO ₂ recycle liquid stream; from the CO ₂ recycle liquid stream removing the liquid present in the circulation flow combined with a CO, ₂ or more components of the slave; the circulating liquid CO ₂ stream through at least two compressors in series, which is the circulation of the liquid CO ₂ Pressure is increased to at least about 8MPa, ₂ and the conversion of CO in the circulating liquid from a gas state to a supercritical fluid state; and the supercritical CO ₂ fluid circulating through the heat exchanger at least two series of the same, which is used to recover the heat of the circulating liquid CO ₂ is increased to a temperature of at least about 200 ℃ (or alternatively, to increase the flow than the turbine exhaust temperature of less than about 50 ℃). This may in particular include the introduction of additional heat from an external heat source (i.e., a heat source that is not directly derived from the turbine discharge stream passing through the (equal) heat exchanger).

In a further embodiment, the present invention is to provide an efficient method of generating electric power from the combustion of carbonaceous fuel in the absence of CO ₂ released to the atmosphere. Specifically, the method may comprise the steps of: the carbonaceous fuel, O _2, and a recovered liquid is a CO ₂ cycle defined stoichiometric ratio is introduced into a transpiration cool the combustor, the CO ₂ at least about 8MPa The pressure, and a temperature of at least about 200 ° C, is introduced; combusting the fuel to provide a combustion product stream comprising CO ₂ having a temperature of at least about 800 ° C; expanding the combustion product stream across a turbine, To generate electricity, the turbine has an inlet to receive the combustion product stream, and an outlet to release a turbine discharge stream comprising CO ₂ , wherein the combustion product stream at the inlet is compared to the outlet at the outlet The turbine discharge stream has a pressure ratio of less than about 12; passing the turbine discharge stream through at least two heat exchangers in series that recover heat from the turbine discharge stream and provide the CO ₂ recycle liquid stream; passing the CO ₂ recycle liquid stream at least two compressors in series, which the CO ₂ cycle liquid pressure to at least about 8MPa, and the circulation of the liquid CO ₂ in the gas state to a transition from a supercritical fluid State; CO ₂ cycle so that the liquid flow through a separation unit, wherein the required stoichiometric amount of CO ₂ is recovered, and is directed to the burner, and any excess CO ₂ recovery performed in the absence of atmospheric release; and subjecting the recovered CO ₂ circulating liquid through the same series of at least two of the heat exchanger, the temperature of which CO ₂ and the circulating liquid to at least about 200 ℃ (or alternatively using heat is withdrawn prior to introduction into the burner Ground, increased to no more than about 50 ° C) than the temperature of the turbine discharge stream; wherein the efficiency of the combustion is greater than 50%, which is produced by the total low calorific value thermal energy of the carbonaceous fuel generated relative to combustion The ratio of net electricity is calculated.

In another aspect, the invention can be described as providing a power generation system. In particular, a power generation system in accordance with the present invention can include an evapotranspiration burner, a power generation turbine, at least one heat exchanger, and at least one compressor.

In certain embodiments, the transpiration cooled combustor may have to receive at least one of a carbonaceous fuel inlet, O _2, CO ₂ cycle, and a liquid stream. The burner may further have at least one combustion stage, the combustion of the fuel in the _circulating liquid is present the CO.'S, and providing a defined pressure (e.g., at least about 8MPa) and a temperature (e.g., at least about 800 ℃) one comprising Combustion product stream of CO ₂ .

The power generating turbine is in fluid communication with the burner, and having an inlet for receiving the combustion product stream and an outlet of the turbine to release CO ₂ comprises a discharge stream. The turbine may be adapted to control the pressure drop such that the ratio of the pressure of the combustion product stream at the inlet to the pressure of the turbine discharge stream at the outlet is less than about 12.

The at least one heat exchanger can be in fluid communication with the turbine to receive the turbine exhaust stream. The (other) The heat exchanger can transfer heat from the turbine exhaust stream to the flow of liquid CO ₂ cycle.

The at least one compressor is in fluid communication with the at least one heat exchanger. This (and other) compressors may be adapted to the CO ₂ cycle liquid stream is compressed to a desired pressure.

In addition to the foregoing, the power generation system according to the present invention may further include one or more separation devices positioned between the at least one heat exchanger and the at least one compressor. Such (s) may be separating means for removing CO ₂ present in the circulating liquid in a plus CO, ₂ or more components of the slave.

Still further, the power generation system can include an O ₂ separation unit that includes one or more heat generating components. Accordingly, the power generation system can also include one or more heat transfer components that transfer heat from the O ₂ separation unit to the CO ₂ recycle liquid upstream of the combustor. Alternatively, the power generation system can include an external heat source. This may be, for example, a supply of low pressure steam that provides heat to the condensation. Thus, the system may comprise a power, or more heat transfer part which transfers heat from the vapor to the liquid CO ₂ cycle upstream of the burner.

In a further embodiment, the power generation system of the present invention may comprise one or more of the following: a first compressor adapted to compress the CO ₂ circulating liquid stream to a pressure above the critical pressure of the CO ₂ ; a second compressor adapted to compress the CO ₂ circulating liquid stream to a pressure required to be input to the burner; a cooling device adapted to cool the CO ₂ circulating liquid stream to a density greater than about 200 kg/m ³ Temperature; one or more heat transfer components, the one or more heat transfer components transferring heat from an external source to the CO ₂ circulating liquid upstream of the combustor and downstream of the second compressor; a second burner located upstream of and in fluid communication with the evapotranspiration burner; one or more filters or separation devices, the one or more filters or separation devices being located in the second burner And between the evapotranspiration burners; a mixing device for forming a slurry of particulate fuel material and a fluidizing medium; and a grinding device for atomizing a solid fuel.

In other embodiments, the present invention can provide a power generation system that can include the following: one or more injectors for providing fuel, a CO ₂ circulating fluid, and an oxidant; an evapotranspiration burner having at least a combustion stage that combusts the fuel and provides a discharge liquid stream at a temperature of at least about 800 ° C and a pressure of at least about 4 MPa (preferably, at least about 8 MPa); a power generating turbine having an inlet and an outlet; And wherein power is generated as the liquid stream expands, the turbine being designed to maintain the liquid flow at a desired pressure such that the ratio of pressure at the inlet to the outlet is less than about 12; a heat exchanger for cooling the liquid stream leaving the turbine outlet and heating the _circulating liquid CO; for leaving the heat exchanger through the liquid stream into a more, and a means of CO _2, or Multiple further parts for recovery or disposal. In a further embodiment, the power generation system can also include one or more devices for delivering at least a portion of the CO ₂ separated from the liquid stream to a pressurized line.

In a particular embodiment, a system in accordance with the present invention may include one or more components that are trimmed as described herein with a conventional power generation system (e.g., a coal fired power plant, a nuclear power reactor, or the like). For example, a power generation system can include two heat exchange units (eg, a primary heat Switching unit, and a slave heat exchange unit). The primary heat exchange unit may be substantially the other manner of unit as described herein, and the slave heat exchange unit may be a unit having a flow for transferring heat from the turbine discharge stream to one or more (eg, from A boiler associated with the conventional power generation system) to superheat the vapor streams. Thus, a power generation system in accordance with the present invention can include a slave heat exchange unit positioned between the turbine and the primary heat exchange unit and in fluid communication with the turbine and the primary heat exchange unit. Similarly, the power generation system can include a boiler that communicates with the slave heat exchange unit liquid via at least one steam stream. Still further, the power generation system can include at least one further power generating turbine having an inlet for receiving the at least one steam stream from the slave heat exchange unit. Thus, the system can be described as including a primary power generation turbine and a slave power generation turbine. The primary power generating turbine can be a turbine that communicates with the burner fluid of the present invention. The slave power generation turbine may be a turbine that communicates with a vapor stream liquid, particularly a supercritical steam stream that is superheated by the heat of the exhaust stream from the primary power generation turbine. Such a system having one or more parts from a conventional power generation system is described herein, particularly in relation to FIG. 12 and Example 2. The use of the terms of the primary power generation turbine and the slave power generation turbine should not be construed as limiting the scope of the invention and only to provide clarity of the description.

In a further aspect of the invention, an external flow to the high temperature end of the heat exchanger is heated by heat transfer from the cooled turbine discharge stream, and as a result, the high pressure recovery stream will leave the heat The exchanger enters the burner at a low temperature. In this example, the amount of fuel burned in the combustor will increase, allowing the turbine inlet temperature to be maintained. The calorific value of the additionally combusted fuel is equal to the additional heat load imposed on the heat exchanger.

In some embodiments, the present invention is to provide a processing plant to produce shaft power from a CO ₂ cycle in the cycle-based liquids. In a further embodiment, the invention provides a process that can meet certain conditions. In certain embodiments, the present invention is still further characterized in that one or more of the following actions, or to carry out the operation of the device so: compressing the liquid to the CO ₂ cycle exceeds the critical pressure of CO ₂ Pressure; directly burning a solid, liquid, or gaseous hydrocarbon-containing fuel in substantially pure O ₂ to prepare for mixing a CO ₂ -rich supercritical recovery liquid to achieve a desired power turbine inlet temperature, for example, greater than about 500 ° C (or other temperature range as described herein); a supercritical stream formed by combustion products and a recovered CO ₂ -rich liquid are diffused, in particular, expanded above, in a turbine generated with shaft power a pressure of about 2 MPa, and a pressure (for example, about 7.3-7.4 MPa) at which the liquid CO ₂ liquid phase occurs when the liquid is cooled to a temperature consistent with the use of the ambient temperature cooling device; a heat exchanger, which is cooled in the turbine exhaust heat exchanger, and the heat recovered is transferred to a CO ₂ rich supercritical fluid; ambient temperature by a cooling device for cooling a heat exchanger to leave CO ₂ containing stream comprising at least a small amount, and separating a liquid phase concentration of CO ₂ in water, and comprising at least a small amount of water vapor concentration in the gas phase CO _2; to allow gaseous CO ₂ and liquid water or weakly acidic with close contacts between Performing a water separation in a manner that requires a residence time (eg, up to 10 seconds) to cause a reaction involving SO ₂ , SO ₃ , H ₂ O, NO, NO ₂ , O ₂ , and/or Hg to occur More than 98% of the sulfur present in the first class is converted to H ₂ SO ₄ , and in the first class more than 90% of the nitrogen oxides are converted to HNO ₃ , and in the first class more than 80% of the mercury is converted to soluble mercury. a compound; separating non-condensing components (eg, N ₂ , Ar, and O ₂ ) by cooling the gas phase CO ₂ to a temperature near the freezing point of the CO ₂ separated by gas/liquid phase, and in the gas phase Leaving N ₂ , Ar, and O _{2 is} dominant; compressing a purified gaseous CO ₂ stream to a cooling by an ambient temperature cooling device in a gas compressor produces a high density CO ₂ liquid (eg, at least about 200 kg / m ^3, preferably at least about 300kg / m ³ or more is preferably at least greater 400kg / m ³ density) pressure; ambient cooling means to cool the compressed CO ₂ to form the high-density supercritical fluid (e.g., a density of at least about 200kg / m ^3, preferably at least 300kg / m ^3, or more preferably At least about 400 kg/m ³ ); compressing a high-density CO ₂ liquid to a pressure higher than the critical pressure of the CO ₂ in a compressor; separating a high-pressure CO ₂ stream into two split streams, one entering a heat The cold end of the exchanger, and the second heating with an external heat source available below about 250 ° C; promoting efficient heat transfer (including the use of a selective external heat source) to allow heat to enter a heat exchanger the temperature difference between a hot end temperature of the turbine exhaust end of the same stream leaving the heat exchanger and a recovery liquid CO ₂ cycle is less than about 50 ℃ (as described herein or other temperature threshold); and a CO ₂ circulating liquid compressed to a pressure of about 50MPa to about 8MPa (as described herein or other pressure ranges); and an O ₂ stream with at least a portion of a recovered CO ₂ cycle, and a stream of liquid carbon-containing fuel stream Mixing to form a self-ignition temperature below the fuel a separate liquid stream (or slurry, if a powdered, solid fuel is used), and the ratio thereof is adjusted to provide insulation from about 1,200 ° C to 3,500 ° C (or other temperature ranges as described herein) flame temperature; at least a portion of a liquid stream has been _circulating CO combustion products recovered are mixed to produce a temperature of about 500 deg.] C to fall within the range of 1,600 deg.] C (or other temperature range as described herein) is a mixed a liquid stream; producing a turbine discharge stream having a pressure of from about 2 MPa to about 7.3 MPa (or other pressure range, as described herein); utilizing a plant derived from a cryogenic O ₂ (particularly, in the adiabatic mode) One or more compressors, and/or a CO ₂ compressor (in particular, in the adiabatic mode) operating heat of compression to externally heat a portion of a high pressure CO ₂ circulating liquid stream, the heat Transferring by a suitable heat transfer liquid (including the CO ₂ liquid itself); heating one or more external liquid streams in a heat exchanger using equal additional fuel combusted in a combustor, wherein One or more of the external liquid streams Steam may be included, which may be superheated in the heat exchanger; externally heated by a portion of the recovered CO ₂ recycle liquid stream using heat supplied by a condensed stream provided by an external source; Cooling a CO ₂ -containing stream (which exits the cold end of the heat exchanger) to provide heat for heating an externally supplied liquid stream; providing an O ₂ feed stream, wherein the O ₂ mole The concentration is at least about 85% (or other concentration ranges as described herein); operating a combustor such that upon exiting the combustor (i.e., a combustion product stream) and entering a total gas stream of a turbine The O ₂ concentration is greater than about 0.1% molar; a power generation process is performed such that only one power generating turbine is used; a power generation process is performed such that only one burner is used, thereby substantially completely combusting the input into the burner a carbon fuel; operating a combustor such that the amount of O ₂ in the O ₂ stream entering the combustor is lower than the amount required for stoichiometric combustion of the fuel stream entering the combustor, and thus causing the combustion H ₂ product stream and produce a Wherein one of carbon (CO) or both; use of two or more turbines and a processing implementation, each having a turbine are defined a discharge pressure, wherein, H ₂ and CO wherein one or two Appearing in the exhaust stream leaving the first turbine (and, if applicable, the succeeding turbine other than the last turbine in the turbine series), and some or all of H ₂ and CO in the second And adding an O ₂ stream to the inlet of the succeeding turbine to perform combustion to raise the operating temperature of each of the second or more turbines to a higher value, which causes the exhaust stream from the last turbine Excess O _{2 in} , for example, an excess of greater than about 0.1% molar.

In a further embodiment, the present invention may provide one or more of the following: heating a CO ₂ recycle liquid in a heat exchange system by the cooled turbine discharge stream such that the turbine discharge stream is cooled to a temperature below its water dew point; cooling the medium by an ambient temperature and derivatization with fuel and including combustion of H ₂ SO ₄ , HNO ₃ , HCl, and other impurities (eg, Hg and ionic compounds in solution) other metals) in the condensed water cooled turbine exhaust stream; the purified liquid CO ₂ cycle in a first compressor compressed above its critical pressure but below the pressure of 10Mpa; cooling the circulating liquid to a density of more than 600kg / m3 point; compression to overcome pressure drop in the system and feed the liquid CO ₂ into the cycle required for the combustion chamber pressure in a compressor in the high density liquid CO ₂ cycle; removing a _liquid CO ₂ product stream the liquid CO ₂ product stream comprising substantially carbon combustion fuel stream formed in all the CO _2, the CO ₂ stream is taken from the first compressor or the second compressor discharge flow; the direct Switch, or by heating the side stream comprising liquid CO ₂ cycle is supplied at a temperature level above the dew point of the water-cooled turbine exhaust stream to the additional amount of heat to the liquid _circulating CO.'S one, so that in The temperature difference between the circulating CO ₂ liquid and the turbine discharge at the hot end of the heat exchanger is less than 50 ° C; using a fuel comprising a carbonaceous fuel to produce H ₂ , CO, CH ₄ , H ₂ S, NH ₃ , and a first-class non-flammable residue having a non-flammable residue partially oxidized by O ₂ in an evapotranial cooling burner, the burner being fed with a portion of the circulating CO ₂ stream to Cooling the partially oxidized combustion product to a temperature of from 500 ° C to 900 ° C, where the ash appears as solid particles that can be completely removed from the outlet liquid stream by the filtration system; flowing in the side stream circulating liquid CO ₂ flow separation point remixed heated to provide a temperature difference between 10 deg.] C and between 50 deg.] C between the cooled turbine exhaust stream and heating the circulating liquid CO ₂ stream; leaving the heat exchanger to provide cooling End turbine discharge pressure So that no liquid CO ₂ is formed when the stream is cooled before the water is separated from the impurities; a minimum portion of the turbine discharge stream is utilized to make the conventional steam power generation derived from the associated boiler system and nuclear energy reactor a plurality of superheated steam flow system; provide additional thermal low CO ₂ stream to the loop, so as to be in a vapor from an external source (e.g., a power station) one or more pressure level of the steam; using A diverter discharge stream exiting the cold end of the heat exchanger system to provide heating of at least a portion of the condensate exiting the steam condenser of the steam power generation system; the circulating CO ₂ stream for heat discharge from an open cycle gas turbine to provide additional thermal low; plus part of the fuel gas derived from coal oxidation of CO ₂ plus CO ₂ as a second fuel to the burner, in order to complete the burn; the ratio of O ₂ to operate the fuel a separate burner, so that the fuel is partially oxidized comprising _2, H ₂ O, and CO sO ₂ oxidation products, as well as the remaining fuel is oxidized comprising H _2, CO, and the composition of H ₂ S; ₂ in the overall discharge flow is required by the first injected into the turbine pressure ratio of O operation on two turbine combustion component has been reduced, and thus the intermediate pressure before being expanded by the second turbine flow The intermediate pressure stream is reheated to a higher temperature.

Even further embodiments are included in the invention as disclosed in the further description of the invention as set forth in the various drawings and/or herein.

220‧‧‧ burner installation

222‧‧‧ combustion chamber

222A‧‧‧ entrance section

222B‧‧‧Exports

223‧‧‧End wall

2338‧‧‧ Pressure suppression components

60‧‧‧cooled turbine discharge

61‧‧‧Cooled turbine discharge from the mixed phase

65‧‧‧Purified working liquid 65

236‧‧‧Recovered working fluid

236a, 236b, 52, 56, 62, 74, 73, 71, 71b, 72a, 72b, 1044, 1045, 1039, 1038, 1301, 1035‧‧ ‧ flow

254, 1055‧‧‧carbon fuel

250A‧‧‧Slurry

254A‧‧ ‧powder

255‧‧‧Liquidized substances

250‧‧‧Mixed settings

242‧‧‧Oxygen

230‧‧‧Evapotranspiration parts

2331‧‧‧External evapotranspiration

2332‧‧‧Internal evapotranspiration

231‧‧‧ Buffer layer

2339‧‧‧Insulation parts

2350‧‧‧heat removal device

2336‧‧‧ wall

210‧‧‧Evapotranspiration

2337‧‧‧ channel

2333A‧‧‧First Evapotranspiration Supply Channel

2333B‧‧‧Second evapotranspiration supply channel

2335‧‧‧ Multiple flow paths or holes or other suitable openings

2A‧‧‧Central Collection

100, 100A, 100B, 100C‧‧‧ centrifugal separator device

2‧‧‧Central collection pipeline

4‧‧‧Export tube

12‧‧‧Collection pipeline

5‧‧‧Export nozzle

6‧‧‧Water-cooled section

9‧‧‧ Valve

7‧‧‧ pipeline

8‧‧‧Separated lines

14‧‧‧Export nozzle or pipe

20‧‧‧Sewage pit

1‧‧‧ cyclone

3‧‧‧Export channel

11‧‧‧ branch channel

125‧‧‧pressure housing

2340‧‧‧Separator device

85, 62b, 70, 67, 66‧ ‧ Circulating liquid flow

80‧‧‧ Pipeline liquid flow

720‧‧‧Tube shunt

620‧‧‧ Pressurizing unit

520‧‧‧Separation unit

420‧‧‧ heat exchanger

50‧‧‧ Turbine discharge

320‧‧‧Diffusion turbine

530, 640, 1370, 1320‧‧‧ cooling water heat exchanger

540, 1360‧‧‧ separator

550‧‧‧Separation unit

62a‧‧‧Liquid water flow

650, 1380‧‧ ‧ compressor

630‧‧‧First compressor

430‧‧‧First heat exchanger

440‧‧‧second heat exchanger

450, 1310‧‧‧ third heat exchanger

480, 910, 252‧‧ ‧ mixer

460‧‧‧Splitter

470‧‧‧ side heater

40, 1054‧‧‧Combustion product stream

330, 340‧‧‧ turbine

42‧‧‧First discharge stream

30‧‧‧Air separation unit

241‧‧‧ Air

900‧‧‧grinding device

256‧‧‧cooling flow

930‧‧‧Oxidant burner

920, 1390, 1350‧‧ ‧

68‧‧‧ side extraction

940‧‧‧Filter

86, 1058‧‧‧CO ₂ flow

257‧‧‧Combustion flow

80‧‧‧CO ₂ pipeline liquid flow

1209, 1210‧‧‧ generator

Q‧‧‧Hot

1056‧‧‧Oxygen flow

1053, 1051, 1047‧‧‧CO ₂ circulating liquid flow

1049‧‧‧CO ₂ product stream

1050‧‧‧ pump discharge

1048‧‧‧CO ₂ circulating liquid

1042, 1043‧‧‧ line

1046‧‧‧ Acid flow

1340‧‧‧Circular pump

1330‧‧‧ column

1040‧‧‧cooled flow

1001

1100‧‧‧Diffusion turbine discharge

1037‧‧‧Drain flow

1031‧‧‧High-pressure flow

1800‧‧‧ power station

1057, 1036‧‧‧ condensate

1052‧‧‧LP steam flow

1032‧‧‧ medium pressure flow

1033‧‧‧ flow

1200‧‧‧Three-stage turbine

1220‧‧ ‧Condenser

1230‧‧‧ Feeding water pump

1810‧‧‧ coal

Having described the invention in a general term, reference will now be made to the drawings, which are not to be drawn to the drawings, and wherein: FIG. 1 is an evasive cooling burner apparatus that can be used in accordance with certain embodiments of the present disclosure. Schematic; FIG. 2 is an exemplary cross-sectional view of a wall of an evapotranable member that can be used in a burner assembly in certain embodiments of the present disclosure; FIGS. 3A and 3B are schematic illustrations of what can be used in the present disclosure Hot fit processing of the evapotranspiration assembly of the burner apparatus in some embodiments; FIG. 4 is a schematic illustration of a combustion product contamination removal apparatus useful in accordance with certain embodiments of the present disclosure; A flow chart showing a power cycle according to an embodiment of the present disclosure; and a sixth flowchart showing a flow of a CO ₂ circulating liquid through a separation unit according to an embodiment of the present disclosure; and FIG. 7 is a view showing the flow according to the present disclosure. A flow chart of the pressurization of two or more compressors or pumps connected in series in the pressurizing unit in one embodiment; and FIG. 8 is a flow chart showing the heat exchanger unit according to an embodiment of the present disclosure. Figure, where three The other heat exchangers are used in series; FIG. 9 is a flow chart showing a turbine unit utilizing two turbines operating in series in a reduction mode in accordance with an embodiment of the present disclosure; A flowchart of a power generation system and method using a two-burner according to an embodiment of the present disclosure; FIG. 11 is a flow chart showing a specific example of a power generation system and method according to an embodiment of the present disclosure; and FIG. 12: A flow chart showing another example of a power generation system and method incorporating a conventional coal fired boiler in accordance with an embodiment of the present disclosure.

The invention will now be described more fully hereinafter with reference to the various embodiments. These embodiments are provided to make this disclosure more complete and complete, and the scope of the invention is fully conveyed by those of ordinary skill in the art. Indeed, the present invention may be embodied in many different forms and should not be construed as being limited to the embodiments set forth herein. Instead, these embodiments are provided so that this disclosure will satisfy the applicable legal requirements. The singular forms "a", "the", and "the"

By using the present invention provides a highly efficient fuel burner (e.g., to cool the combustor ET) power generation systems and methods, and associated circulating liquid (e.g., CO ₂ liquid circulation). The circulating liquid is provided to the combustor along with a suitable fuel, any necessary oxidant, and any related materials useful for efficient combustion. In a particular embodiment, the method can be practiced with a burner operating at very high temperatures (eg, in the range of about 1,600 ° C to about 3,300 ° C, or other temperature ranges disclosed herein), as well as circulating liquids The presence may act to moderate the temperature of the liquid stream exiting the combustor such that the liquid stream can be utilized in the energy transfer produced by the electrical power. In particular, the combustion product stream can be expanded to span at least one turbine for power generation. Expanding the gas stream may be cooled to remove various components from the stream, e.g., water, and heat the expanded gas stream from the recovered heat can be used for the liquid CO ₂ cycle. The purified circulating liquid stream can then be pressurized and heated for recovery via the burner. If you want, then, part of the combustion product stream from the CO ₂ (i.e., those generated by the CO ₂ by the carbon-containing fuel is combusted in the presence of oxygen is formed) can be pulled out for sequestration or other disposal, For example, it is passed to the CO ₂ line. The system and method may utilize specific parts and process parameters to maximize the efficiency of the system and method (particularly in avoiding CO ₂ release to the atmosphere at the same time). As specifically described herein, the circulating liquid is exemplified by the use of CO ₂ as a circulating liquid. While the use of liquid CO ₂ cycle according to the invention is advantageous, such as disclosed and should not be construed that may be used to limit the scope of the necessary circulation of the liquid in the present invention, unless otherwise indicated.

In certain embodiments, a power generation system according to the present invention may use a circulating liquid including CO ₂ as a main. In other words, the chemical properties of the circulating liquid immediately before the input is the burner such that the circulating liquid includes a significant amount of CO _2. In this context, the term "significant" may mean that the liquid comprises at least about 90% molar concentration, at least about 91% molar concentration, at least about 92% molar concentration, at least about 93% molar concentration, At least about 94% molar concentration, at least about 95% molar concentration, at least about 96% molar concentration, at least about 97% molar concentration, at least about 98% molar concentration, or at least about 99 % molar concentration of CO ₂ . Preferably, the liquid in the cycle prior to entering the combustor comprises substantially only CO _2. In this context, the term "substantially only" can mean at least about 99.1% molar concentration, at least about 99.25% molar concentration, at least about 99.5% molar concentration, at least about 99.75% molar concentration, at least about 99.8% molar concentration, or at least about 99.9% of the molar concentration of CO _2. In the burner, CO ₂ can be any oxidizing agent, and any fuel mixed with combustion of a derivative, or more fuel can be derived from the other ingredients. Thus, the circulating liquid leaving the combustor (which may be described herein as a combustion product stream) may include CO ₂ and minor amounts of other materials such as water (H ₂ O), oxygen (O ₂ ), nitrogen (N ₂ ). , argon (Ar), sulfur dioxide (SO ₂ ), sulfur trioxide (SO ₃ ), nitrogen monoxide (NO), nitrogen dioxide (NO ₂ ), hydrogen chloride (HCl), mercury (Hg), and from combustion treatment Trace amounts of other ingredients derived (eg, particulates, such as ash, or liquefied ash), which include additional combustibles. As will be described in more detail below, the combustion process can be controlled such that the nature of the liquid stream can be reduced, or oxidized, which can provide the benefits that will be specifically described.

The systems and methods of the present invention may incorporate one or more burners that are useful for combustion of a suitable fuel, as described herein. Preferably, at least one burner used in accordance with the present invention is a high efficiency burner capable of providing substantially complete combustion at a relatively high combustion temperature. High temperature combustion is particularly useful to provide substantially complete fuel combustion, and thus maximize efficiency. In various embodiments, high temperature combustion can be expressed at at least about 1,200 ° C, at least about 1,300 ° C, at least about 1,400 ° C, at least about 1,500 ° C, at least about 1,600 ° C, at least about 1,750 ° C, at least about 2,000 ° C, at least about Combustion at a temperature of 2,500 ° C, or at least about 3,000 ° C. In further embodiments, high temperature combustion can be expressed at about 1,200 ° C to about 5,000 ° C, about 1,500 ° C to about 4,000 ° C, about 1,600 ° C to about 3,500 ° C, about 1,700 ° C to about 3,200 ° C, about 1,800 ° C to about Combustion at a temperature of 3,100 ° C, about 1,900 ° C to about 3,000 ° C, or about 2,000 ° C to about 3,000 ° C.

In certain embodiments, high temperature combustion in accordance with the present invention may be accomplished using an evapotranspiration burner. One example of an evapotranial cooling combustor that can be used in the present invention is described in U.S. Patent Application Serial No. 12/714,074, filed on Feb. In some embodiments, an available evaporative cooling burner in accordance with the present invention may include one or more heat exchange zones, one or more cooling liquids, and one or more evapotranspiration liquids.

According to the invention, the use of an evapotranial cooling burner is particularly advantageous in terms of fuel combustion for power generation over conventional techniques. For example, the use of evapotranspiration can effectively prevent corrosion, fouling, and erosion in the combustor. This further allows the burner to be at a sufficiently high temperature Work within the range to provide complete, or at least substantially complete, combustion of the fuel used. These, as well as further advantages, are further described herein.

In a particular aspect, an evapotranspiration burner useful in accordance with the present invention can include a combustion chamber defined at least in part by an evapotranation member, wherein the evapotranspiration member is at least partially surrounded by a pressure suppression member. The combustion chamber can have an inlet portion and an opposite outlet portion. The inlet portion of the combustion chamber is configurable to receive a carbonaceous fuel for combustion at a combustion temperature in the combustion chamber to form a combustion product. The combustion chamber can be further configured to direct combustion products to the outlet portion. The transpiration member can be configured to direct evapotranic material therethrough to the combustion chamber to buffer combustion products and interactions between the transpiration members. Additionally, the evapotranspiration can be introduced into the combustion chamber to achieve a desired outlet temperature for the combustion products. In a particular embodiment, the evapotranible material can comprise, at least in part, the circulating liquid.

The combustion chamber wall may be lined with a layer of porous material, the evaporable substance (e.g., CO _2, and / or H ₂ O), and whereby the flow is guided.

In other aspects, the internal transpiration member 2332 can be expanded from the inlet portion 222A of the ET member 230 to the outlet portion 222B. In some examples, the perforated/porous structure of the internal ET member 2332 can be substantially completely (radial The inlet portion 222A is expanded to the outlet portion 222B such that the evapotranspiration liquid 210 is substantially introduced into the entire length of the combustion chamber 222. That is, in general, the entirety of the internal transpiration member 2332 can be configured with a perforated/porous structure such that substantially the entire length of the combustion chamber 222 can be subjected to evapotranspiration. More particularly, in some aspects, the cumulative perforation/hole region can be substantially equal to the surface area of the internal evapotranspiration member 2332. In still other aspects, the perforations/holes can be spaced apart at an appropriate density such that the evaporative material can be substantially uniformly dispensed from the internal transpiration member 2332 into the combustion chamber 222 (i.e., without lack of evapotranspiration) The flow or the presence of "dead spots"). In one example, the square inch of the internal transpiration component 2332 can include a square inch A perforation/hole array of the rank of 250 x 250 to provide approximately 62,500 holes per square inch, such perforations/holes being spaced by a distance of approximately 0.004 inches (0.1 mm). The ratio of the pore area to the total wall area (% porosity) can be, for example, about 50%. The array of holes can vary over a wide range to suit the design parameters of other systems, for example, the desired pressure drop relative to the flow rate across the evapotranspiration component. In some examples, an array size of from about 10 x 10 to about 10,000 x 10,000 per inch having a porosity of from about 10% to about 80% can be used.

The flow of evapotranic material through the porous evapotranspiration layer and optionally through additional supply can be configured to achieve a desired total exit liquid vent temperature from the combustor. In some embodiments, such temperatures may fall within the range of from about 500 °C to about 2,000 °C, as described further herein. This flow can also be used to cool the transpiration member to a temperature below the maximum allowable operating temperature of the material from which the evapotranspiration member is formed. The evapotranspiration can also be used to prevent any liquid, or solid ash materials, or other contaminants in the fuel that may impact, contaminate, or otherwise damage the walls. In such an example, the ET component may require the use of a material having reasonable thermal conductivity such that incident radiant heat may be conducted radially outward through the porous evaporative component and then from the surface of the porous layer structure to The convective heat transfer of the liquid radially inward through the evapotranspiration is truncated. Such a configuration may allow the contiguous portion of the flow directed through the transpiration member to be heated to a temperature within a desired range, for example, from about 500 ° C to about 1,000 ° C, while maintaining the temperature of the porous evapotrans simultaneously Within the design range of the materials used. Suitable materials for the porous evaporative component may include, for example, porous ceramics, refractory metal fiber blankets, drilled cylindrical sections, and/or sintered metal layers or sintered metal powders. The second function of the transpiration member is to ensure that the substantially flat evapotranic liquid flows radially inwardly, and longitudinally along the burner to achieve a good mixing between the effluent liquid stream and the combustion products while simultaneously increasing A flat axial flow along the length of the combustion chamber. The third function of the ET component is to achieve a radial inward velocity of the diluting liquid to provide a buffer or use Other means intercept solid, and/or liquid particles of ash or other contaminants in the products of combustion, thereby avoiding impact on the surface of the evapotranspiration and avoiding clogging or other damage. For example, such a factor may only be important when burning a fuel (eg, coal) with residual inert incombustible residue. The inner wall of the burner pressure line surrounding the transpiration member can also be insulated to isolate the high temperature effluent liquid stream in the burner.

One embodiment of a burner apparatus that can be used in accordance with the present invention is schematically illustrated in Figure 1, which is generally indicated by numeral 220. In this example, the burner assembly 220 can be configured to combust a particulate solid (eg, coal) to form a combustion product, although any other suitable combustible carbonaceous material (as disclosed herein) can also be used. For fuel. The combustion chamber 222 can be defined by an evaporative component 230 that is configured to introduce an effluent liquid therethrough into the combustion chamber 222 (ie, to facilitate evapotranspiration cooling, and/or to buffer) The combustion product and the interaction between the evaporative component 230). It will be understood by those of ordinary skill in the art that the evaporative component 230 can be generally cylindrical to define a combustion chamber 222 that is generally cylindrical and has an inlet portion 222A and an outlet portion 222B. The evapotranspiration member 230 can be at least partially surrounded by a pressure suppression member 2338. The inlet portion 222A of the combustion chamber 222 can be configured to receive a fuel mixture from a mixing arrangement generally indicated by the symbol 250. In other embodiments, such a mixing arrangement may be absent, and one or more of the materials input into the burner may be separately added via separate inlets. According to a particular embodiment, the fuel mixture can be combusted in the combustion chamber 222 at a particular combustion temperature to form a combustion product, wherein the combustion chamber 222 can be further configured to direct the combustion product to the outlet portion. Part 222B. A heat removal device 2350 (see, for example, Figure 2) can be associated with the pressure suppression component 2338 and configured to control its temperature. In a particular example, the heat removal device 2350 can include a heat transfer jacket defined at least in part by a wall 2336 relative to the pressure suppression member 2338, wherein a liquid can be defined therebetween The water loops the loop in 2337. In an embodiment, the circulating liquid can be water.

In a particular aspect, the porous internal transpiration member 2332 is thus configured to introduce the effusion liquid into the combustion chamber 222 such that the evapotranspiration 210 is at a right angle generally relative to the inner surface of the internal transpiration member 2332. An angle of (90°) enters the combustion chamber 222. In addition to these advantages, the introduction of the evapotranspiration 210 at a right angle generally relative to the internal esteam component 2332 also facilitates, or otherwise enhances, slag liquid, or solid droplets, or other contaminants, or heat. The effect of the swirling of the combustion liquid from the inner surface of the inner transpiration member 2332. When there is no contact between the slag liquid or solid droplets, the droplets can be prevented from coalescing into larger droplets or populations, which are known in the art to be between droplets or particles and solid walls. It happens immediately after contact. Introducing the evapotranspiration 210 at a right angle generally relative to the internal transpiration member 2332 can facilitate, or otherwise enhance, prevent possible impact and damage to the internal transpiration member from being perpendicular to and adjacent to the interior The effect of the formation of a vortex of combustion liquid at a sufficient velocity of the evapotranspiration component. In such an example, the external transpiration member 2331, the pressure suppression member 2338, the heat transfer jacket 2336, and/or the insulation layer 2339 can be configured (individually, or collectively) to provide an associated evapotranible substance/liquid A "various" effect of delivery of 210 that reaches and passes through the internal transpiration member 2332 and into the combustion chamber 222 (i.e., provides a substantially evenly distributed supply). That is, a substantially uniform supply of the evapotranspiration 210 into the combustion chamber 222 (according to flow rate, pressure, or any other suitable and appropriate measurement) may be by configuring the external evapotranspiration component 2331, the pressure suppression component 2338. The heat transfer jacket 2336, and/or the heat insulating layer 2339 is achieved to provide a uniformly supplied evapotranspiration 210 to the internal evapotranspiration member 2332, or the evapotranspiration material 210 has an outer surface of the internal evapotranspiration member 2332. The supply may be specially customized and configured to achieve a substantially uniform distribution of the evapotranspiration 210 in the combustion chamber 222. Such a substantially uniform distribution avoids other forms of formation and possible impact and damage to internal transpiration components by the interaction of non-uniform evapotranic liquid and combustion liquid flow. The formation of a hot combustion liquid vortex.

The mixing arrangement 250, when present, can be configured to mix the carbonaceous fuel 254 with enriched oxygen 242 and a recovered working liquid 236 to form a fuel mixture. The carbonaceous fuel 254 can be provided in the form of a solid carbonaceous fuel, a liquid carbonaceous fuel, and/or a gaseous carbonaceous fuel. The oxygen enriched 242 can be oxygen having a molar purity greater than about 85%. The supply of oxygen-rich 242, for example, can be performed by any air separation system/technique known in the art, such as, for example, cryogenic air separation treatment, or high temperature ion-permeable membrane oxygen separation treatment. (from the air). As described herein, the recovered working fluid 236 can be carbon dioxide. In the example where the carbonaceous fuel 254 is particulate solids (eg, pulverized coal 254A), the mixing arrangement 250 can be further configured to mix the particulate solid carbonaceous fuel 254A and a liquefied material 255. According to one aspect, the particulate solid carbonaceous fuel 254A may have an average particle size between about 50 microns to about 200 microns, and according to yet another aspect, the liquefied material 255 may include water and / or liquid CO _2, which is density of between about 450kg / m ³ to about 1100kg / m ^3. More specifically, the liquefied material 255 can be formed in conjunction with the particulate solid carbonaceous fuel 254A, for example, slurry 250A between about 25 and about 55 weight percent of the particulate solid carbonaceous fuel 254A. Although in FIG. 1, the oxygen 242 is shown to be mixed with the fuel 254 and the recovered working liquid 236 prior to introduction into the combustion chamber 222, those of ordinary skill in the art will understand that, in some In the example, the oxygen 242 is detachably introduced into the combustion chamber 222 when necessary or desired.

The mixing arrangement 250, in some aspects, can include, for example, an array of spaced apart injection nozzles (not shown) that can be disposed in the evapotranspiration associated with the inlet portion 222A of the cylindrical combustion chamber 222. Near the end wall 223 of the component 230. Injecting the fuel/fuel mixture into the combustion chamber 222 in this manner can provide, for example, a large surface area injected fuel mixed inlet stream, which in turn facilitates mixing the injected fuel inlet stream by irradiation Fast Fast heat transfer. Therefore, the temperature of the injected fuel mixture can be rapidly increased to the ignition temperature of the fuel, and thus can cause tight combustion. While these values are dependent on a number of factors, such as the architecture of a particular injection nozzle, the injection rate of the fuel mixture can fall, for example, in the range of between about 10 m/sec and about 40 m/sec. Such an injection setting can take many different forms. For example, the implant arrangement can include, for example, an array of holes having a diameter ranging from about 0.5 mm to about 3 mm, wherein the injected fuel is injected at a rate of between about 10 m/s and about 40 m/s. In the meantime.

As shown more particularly in FIG. 2, the combustion chamber 222 can be defined by the evaporative component 230, which can be at least partially surrounded by a pressure suppression component 2338. In some examples, the pressure suppression component 2338 can be further at least partially surrounded by a heat transfer jacket 2336, wherein the heat transfer jacket 2336 can cooperate with the pressure suppression component 2338 to define one or more passages 2337 therebetween. Thereby, the low pressure water flow can be circulated. While passing through an evaporation mechanism, the recycled water can thus be used to control and/or maintain the selected temperature of the pressure suppression component 2338, for example, in the range of from about 100 °C to about 250 °C. In some aspects, a thermal insulation layer 2339 can be disposed between the evaporative component 230 and the pressure suppression component 2338.

In some examples, the transpiration member 230 can include, for example, an external transpiration member 2331 and an internal transpiration member 2332 that is disposed from the pressure suppression member 2338 relative to the external transpiration member 2331, And the combustion chamber 222 is defined. The outer transpiration member 2331 can be constructed of any suitable high temperature resistant material such as, for example, steel and steel alloys, including stainless steel and nickel alloys. In some examples, the outer transpiration member 2331 can be configured to define a first evapotranspiration supply passage 2333A extending therebetween from its surface adjacent the surface of the insulating layer 2339 to its surface adjacent to the inner venting member 2332. In some examples, the first evapotranspiration liquid supply passage 2333A can correspond to the pressure suppression component 2338, the heat transfer jacket 2336, and/or the second evapotranspiration liquid supply passage 2333B defined by the insulation layer 2339. The first and second evapotranspiration liquid supply passages 2333A, 2333B can thus be configured to cooperate to direct an evapotranspiration liquid therebetween through the internal evapotranspiration member 2332. In some examples, as shown in FIG. 1, for example, the evapotranspiration liquid 210 can include the recovered working fluid 236, and can be obtained from the same source associated therewith. Such a first and a second liquid supply path ET 2333A, 2333B, if necessary, can be insulated for delivering a sufficient pressure and a sufficient supply of the liquid ET 210 (i.e., CO _2), and further such that the ET Liquid 210 is directed through the internal esteam component 2332 and into the combustion chamber 222. The method involved in the evaporative component 230 and associated evapotranspiration 210 (as disclosed herein) may allow the burner assembly 220 to be here at a relatively high pressure and a relatively high temperature. Expose different ways to operate.

In this regard, the internal transpiration member 2332 can be constructed, for example, as a porous ceramic material, a perforated material, a laminate, a porous blanket that is randomly oriented in two dimensions and sequentially ordered fibers, or any other suitable The material, or a combination thereof, exhibits the desired features as disclosed herein, i.e., a plurality of flow passages or holes or other suitable openings 2335 for receiving and directing the evapotranspiration through the internal esteam component 2332. Porous ceramics and other non-limiting examples suitable for use in such evapotranspiration systems include alumina, zirconia, transformation-toughened zirconium, copper, molybdenum, tungsten, copper-infiltrated tungsten. Tungsten-coated molybdenum, tungsten-coated copper, various high-temperature nickel alloys, rhenium-sheathed or coated materials. Sources of suitable materials include, by way of example, CoorsTek, Inc. (Golden, CO) (zirconium); UltraMet Advanced Materials Solutions (Pacoima, CA) (refractory metal coating); Orsam Sylvania (Danvers, MA) (tungsten/copper); And MarkeTech International, Inc. (Port Townsend, WA) (tungsten). Suitable for use as Examples of the perforated material of the evapotranspiration cooling system include all of the above materials and suppliers (wherein the perforated end structure can be obtained by perforating the initial non-porous structure by a known method in a known manufacturing technique), suitably Examples of laminates include all of the materials described above, as well as suppliers (wherein the laminated end structures can be achieved by, for example, using known methods in conventional manufacturing techniques to achieve the desired end porosity). Obtained by laminating a non-porous or partially porous structure).

3A and 3B illustrate that in an aspect of the burner assembly 220, the structure defining the combustion chamber 222 is permeable to the transpiration member 230 and the surrounding structure (eg, disposed on the evapotranspiration member 230 and the pressure suppression) A "hot" interface between the pressure suppression member 2338 or the heat insulating layer 2339) between the components 2338 is assembled. For example, when relatively relatively "cold", the size of the transpiration member 230 can be smaller, radial, and/or axial relative to the surrounding pressure suppression member 2338. Thus, when inserted into the pressure suppression member 2338, radial, and/or axial gaps can occur therebetween (see, for example, Figure 3A). Of course, such a dimensional difference can facilitate insertion of the evapotranspiration member 230 into the pressure suppression member 2338. However, for example, when heated toward an operating temperature, the evaporative component 230 can be configured to extend radially, and/or axially to reduce, or eliminate, the gap (see, for example, section 3B). Figure). In doing so, an interference axial and/or radial assembly can be formed between the transpiration member 230 and the pressure suppression member 2338. In some examples, an evapotranspiration component 230 includes an external evapotranspiration component 2331 and an internal transpiration component 2332 that can be placed under compression. Thus, a suitable high temperature resistant friable material (eg, porous ceramic) can be used to form the internal evapotranspiration component 2332.

With such an arrangement of the internal transpiration member 2332, the evapotranspiration 210 can include, for example, carbon dioxide directed through the internal transpiration member 2332 (ie, from the same source as the recovered working fluid 236) such that The evapotranspiration 210 immediately forms a buffer layer 231 (i.e., a "steam wall") adjacent the internal evapotranspiration member 2332 within the combustion chamber 222, wherein the buffer layer 231 can be configured to buffer the internal transpiration member 2332 an interaction with a liquefied non-combustible element associated with the combustion product and heat. That is, in some examples, the evapotranspiration liquid 210 can be delivered through the internal evapotranspiration component 2332, for example, at least under pressure within the combustion chamber 222, wherein the evapotranspiration liquid 210 enters the combustion chamber flow rate of 222 (i.e., CO ₂ flow) sufficient to enable the evaporable liquid 210 is mixed with the combustion products as well as the combustion product is cooled, thereby forming an inlet connection on demand in the downstream processing of the liquid mixture leaving sufficient temperature (i.e., A turbine may require, for example, an inlet temperature of about 1,225 ° C), but wherein the exiting liquid mixture is still high enough to maintain slag droplets or other contaminants in the fluid, or liquid state of the fuel. The liquid state of the non-combustible elements of the fuel may help, for example, to separate such contaminants from the combustion products in liquid form, preferably in a free flowing, low viscosity form, which will It is not possible to hinder or otherwise damage any removal system performed for such separation. In practice, such a demand may depend on various factors, such as the type of solid carbonaceous fuel (i.e., coal) used, as well as the particular characteristics of the slag formed in the combustion process. That is, the combustion temperature in the combustion chamber 222 can cause any non-combustible elements in the carbonaceous fuel to be liquefied in the combustion products.

In a particular aspect, the porous internal transpiration member 2332 is thus configured to direct the evapotranic liquid into the combustion chamber 222 in a radially inward manner, thereby forming a liquid barrier wall, or buffer layer 231, the liquid barrier wall The buffer layer 231 is associated with the surface of the internal evapotranspiration member 2332 that defines the combustion chamber 222 (see, for example, Figure 2). The surface of the internal transpiration member 2332 is also heated by the products of combustion. In this connection, the porous internal transpiration member 2332 can be configured to have suitable thermal conductivity such that the evapotranspiration liquid 210 passing through the internal transpiration member 2332 is heated while the porous internal transpiration member 2332 is simultaneously cooled, resulting in a definition The temperature of the surface of the internal transpiration member 2332 of the combustion chamber 222 falls within the highest combustion temperature range Medium, approximately, for example, 1,000 °C. The liquid barrier wall or buffer layer 231 formed by the combination of the evapotranspiration liquid 210 and the internal esteam component 2332 thus buffers the interaction of the internal evapotranspiration component 2332 with the high temperature combustion products and slag or other contaminant particles, and The internal transpiration member 2332 is thus buffered from contact, contamination, or other damage. Further, the evapotranspiration liquid 210 can be introduced into the combustion chamber 222 via the internal evapotranation member 2332 in a manner to adjust the combustion chamber 222 at a desired temperature (e.g., about 500 ° C to about 2,000 ° C). The evapotranspiration 210 around the outlet portion 222B and an exiting mixture of the combustion products.

In a particular embodiment, the burner assembly 220 can thus be configured to provide an efficient, evapotranspiration of a relatively complete combustion of a fuel 254 at a relatively high operating temperature as described herein. Cool the burner unit. In some examples, such a burner assembly 220 can perform one or more cooling liquids, and/or one or more evapotranspiration liquids 210. Additional parts may also be implemented in connection with the burner assembly 220. For example, an air separation unit may be provided to separate N ₂ and O ₂ , and a fuel injector device may provide for receiving O ₂ from the air separation unit and circulating the O ₂ and a CO ₂ liquid and including a gas, A liquid, a supercritical liquid, or a fuel stream of a solid particulate fuel that is slurried in a high density CO ₂ liquid is combined.

In another aspect, the evapotranspiration burner assembly 220 can include a fuel injector to inject a pressurized fuel stream into the combustion chamber 222 of the combustor assembly 220, wherein the fuel stream can include A treated carbonaceous fuel 254, a conditioned medium 255 (which may include the recovered working liquid 236, as discussed herein), and oxygen 242. The (rich) oxygen 242 and the recovered working liquid 236 can be combined into a homogeneous supercritical mixture. The amount of oxygen present is sufficient to combust the fuel and produce a combustion product having the desired composition. The burner assembly 220 can also include a combustion chamber 222 configured to be a high pressure, high temperature combustion volume to receive the fuel stream and enter the combustion by defining a porous evapotranation component 230 of the combustion chamber 222. An evapotranspiration liquid 210 of volume. The feed rate of the evapotranspiration liquid 210 can be used to control the burner unit outlet portion/turbine inlet portion temperature to a desired value, and/or to cool the evapotranspiration member 230 to be compatible with forming the evapotranspiration member 230. The temperature of the material. The evapotranspiration liquid 210 directed through the transpiration member 230 provides a liquid/buffer layer at the surface of the transpiration member 230 defining the combustion chamber 222, wherein the liquid/buffer layer can be avoided by certain fuel combustion chambers. The resulting particles of ash or liquid slag interact with the exposed walls of the evaporative component 230.

The combustion chamber 222 can be further configured such that the fuel stream (and the recovered working fluid 236) can be injected at a pressure greater than the pressure at which the combustion occurs, or otherwise introduced into the combustion chamber 222. The burner assembly 220 can include a pressure suppression component 2338 that at least partially surrounds the evapotranspiration member 230 defining the combustion chamber 222, wherein a thermal insulation component 2339 can be disposed to the pressure suppression component 2338 and the evapotranspiration component 230 between. In some examples, a heat removal device 2350, for example, a jacketed water cooling system defining a water circulation jacket 2337, can be combined with the pressure suppression member 2338 (i.e., circumscribing to a "shell" forming the burner assembly 220. The pressure suppression member 2338), the evapotranspiration liquid 210 to which the transpiration member 230 of the burner device 220 is coupled, may be, for example, a small amount of H ₂ O, and/or an inert gas (for example, N ₂ or argon mixed CO ₂ , the evaporative component 230 may comprise, for example, a porous metal, a ceramic, a composite matrix, a layered manifold, any other suitable structure, Or a combination thereof. In some aspects, combustion within the combustion chamber 222 can produce a high pressure, high temperature combustion product stream that can be subsequently directed to a power generating device, such as a turbine, for expansion associated therewith, as in A more comprehensive description of this.

The relatively higher pressure performed by the embodiment of a burner apparatus disclosed herein can act to concentrate the energy thereby generated into a relatively high intensity in a minimum volume, the essence of which This results in a relatively high energy density. Relatively high The energy density enables downstream processing of this energy to be performed in a more efficient manner than at lower pressures, and thus provides a feasibility factor for the technology. Thus, aspects of this disclosure provide an intensity level that is greater than the energy density of an existing power plant (i.e., 10-100 times). This higher energy density increases the efficiency of the process, but also reduces the cost of the equipment required to perform the energy conversion from self-heating to electrical power (by reducing the size and quality of the device, thereby reducing the cost of the device).

As discussed herein in other ways, the burner apparatus used in the methods and systems of the present invention can be used to combust a variety of different carbonaceous fuel sources. In a particular embodiment, the carbonaceous fuel can be substantially completely combusted such that the combustion product stream does not include a liquid, or solid, non-combustible material. However, in some embodiments, a solid carbonaceous fuel (e.g., coal) useful in the present invention may result in the appearance of non-combustible materials. In a particular embodiment, the burner apparatus can include the ability to achieve a combustion temperature that causes the non-combustible elements in the solid carbonaceous fuel to be liquefied during the combustion process. In such an example, the manner in which the liquefied non-combustible element is removed can be applied. The completion of the removal may, for example, utilize a cyclonic separator, an impact separator, or a graded refractory particulate filter bed disposed in a toroidal configuration, or a combination thereof. In a particular embodiment, the droplets may be removed from the high temperature circulating liquid stream by a series of cyclonic separators (e.g., a separator device 2340 shown in Figure 4). . In general, aspects of such a cyclonic separator as disclosed herein may include a plurality of centrifugally disposed centrifugal separation devices 100 (including an inlet centrifugal separator device 100A configured to receive the combustion products/leave a liquid stream and the liquefied non-combustible elements associated therewith, and an outlet centrifugal separator device 1008 configured to discharge a combustion product/outflow liquid stream having substantially removed therefrom These liquefied non-combustible components. Each centrifugal separator device 100 includes a plurality of centrifugal separator elements, or a cyclone 1, operatively disposed in parallel with a central collection line 2, wherein each centrifugal separator element, or cyclone 1, is configured to be self-contained The liquefaction of the combustion product/exit liquid stream is removed from at least a portion of the liquefaction The flaming elements, and the removed portions of the liquefied non-combustible elements, are directed to a sump 20. Such a separator device 2340 can be configured to operate at an elevated pressure and, thus, can further include a pressure-containing housing configured to collect the centrifugal separators The device and the sump. According to such an aspect, the pressure bearing housing 125 can be an extension of the pressure suppression member 238 (which also surrounds the burner assembly 220), or the pressure bearing housing 125 can be associated with the burner assembly 220. The pressure suppressing member 2338 is combined with a separate member. In either case, due to the elevated temperature experienced by the separator device 2340 via the exiting liquid stream, the pressure bearing housing 125 can also include a operatively coupled therewith to remove heat generated therefrom. A heat dissipation system, for example, a heat transfer jacket (not shown) having a liquid circulating therein. In some aspects, a heat recovery device (not shown) can be operatively coupled to the heat transfer jacket, wherein the heat recovery device can be configured to receive liquid circulated in the heat transfer jacket and regain Thermal energy from the liquid.

In a particular embodiment, the (slag removal) separation gas unit 2340 (shown in FIG. 4) can be configured to be disposed in series with the burner unit 220 around its outlet portion 222B for receipt therefrom This leaves the liquid stream/combustion product. The evapotranspiration from the burner assembly 220 is cooled away from the liquid stream, and together with the liquid slag (non-combustible elements) droplets therein, can be directed through a conical reducer 10 into the inlet centrifugal separator device 100A. A central collection provides 2A. In one aspect, the separator device 2340 can include three centrifugal separator devices 100A, 100B, 100C (although it will be understood by those of ordinary skill in the art that a separator device can include one, two, three, or More centrifugal separator units, when necessary or desirable. In this example, the three centrifugal separator devices 100A, 100B, 100C, which are operatively arranged in series, provide a 3-stage cyclone separation unit. Each centrifugal separator device includes, for example, a plurality of centrifugal separator elements (cyclonic 1) disposed about the corresponding central collection line 2, the central collection of the inlet centrifugal separator device 100A providing 2A and these central collection tubes Lane 2, and the intermediate centrifugal separator device 100C, each are sealed at their outlet ends. In these examples, the exiting liquid stream is directed into branch passages 11 of each of the centrifugal separator elements (cyclones 1) corresponding to the respective centrifugal separator devices 100. The branch passages 11 are configured to be combined with the inlet ends of the respective cyclones 1 to form a tangential inlet thereof (which causes, for example, the exiting liquid flow entering the cyclone 1 in the spiral flow) The wall of the cyclone 1 interacts). The outlet passage 3 from each of the cyclones 1 then follows the route into the inlet portion of the central collection line 2 of the respective centrifugal separator device 100. At the outlet centrifugal separator device 100B, the exiting liquid stream (having a substantially non-combustible element separated therefrom) is from the central collection line of the outlet centrifugal separator device 100B, and via a collection line 12 and an outlet The nozzle 5 is directed such that the "clean" exiting liquid stream can then be directed to a subsequent process, for example, associated with the switching device. Thus, an exemplary three-stage cyclonic separation arrangement allows the slag in the exiting liquid stream to be removed to, for example, less than 5 ppm by mass.

At each stage of the separator device 2340, the separated liquid slag is guided from each of the cyclones 1 via an outlet pipe 4 extending to a sump 20. The separated liquid slag is then introduced into an outlet nozzle or line 14 extending from the sump 20 and the pressure bearing housing 125 to remove, and/or re-acquire, components therefrom. In effecting the removal of the slag, the liquid slag may be directed through a water-cooled section 6, or otherwise through a section having a high pressure, cold water connection, wherein the interaction with water causes the liquid slag to solidify, and/ Or form granular. The mixture of solidified slag and water can then be separated into a slag/water liquid mixture in a line (collection provided) 7, which can be removed by a suitable valve 9, especially after the pressure drop, at the same time Any remaining gas can be removed via a separate line 8. In some embodiments, one of the associated systems of sequential operations may allow for continuous operation of the system.

Since the separator device 2340 can be compared to relatively high temperature combustion products The flow (i.e., at a temperature sufficient to maintain the non-flammable elements in liquid form at a lower viscosity) may, in some instances, be desired to be exposed to and associated with the combustion product/outflow liquid stream. The surface of the separator device 2340 of one of the liquefied non-combustible elements may be composed of a material configured to have one of high temperature resistance, high corrosion resistance, and low thermal conductivity. Examples of such materials may include zirconia and alumina, although such examples are not intended to be limiting of any type. Thus, in certain aspects, the separator device 2340 can be configured to substantially remove the liquefied non-combustible elements from the combustion product/exit liquid stream and maintain the non-combustible elements in a low viscosity liquid state Form, at least until its removal from the sump 20. Of course, in embodiments where a non-solid fuel is used and the non-combustible material is not included in the combustion product stream, there is no need to additionally add the slag separator.

In some embodiments, the separator device 2340 can be used to separate particulate solid ash residues from the combustion of any fuel (eg, coal) that produces a non-combustible solid residue. For example, the coal can be ground to a desired size (eg, such that less than 1% by weight of the particulate or powdered coal can include the size of particles having a size greater than 100 μm) and formed using liquid CO ₂ Slurry. In certain embodiments, the temperature of the liquid CO ₂ may be at about -40 ℃ to about -18 ℃. The slurry can include from about 40% to about 60% by weight of coal. The slurry can then be pressurized to the desired combustion pressure. Referring to FIG. 1, the recovered working fluid 236 can be separated in relation to the mode of entering the combustor 220. A first portion (stream 236a) can be input into the combustor 220 via the mixing arrangement 250, and a second portion (stream 236b) can be input to the combustor by traversing the evaporative cooling layer 230. 220. As mentioned earlier, it is possible to cause the reducing gas mixture (e.g., _{including, H 2, CH 4, CO} , H 2 S, and / or NH ₃₎ in the form of O ₂ fuel ratio of the burner 220 is operated. The cooling layer through evapotranspiration into the burner part 236 of the working fluid can be recovered to the combustion gas mixture is cooled and the like to the liquid CO ₂ cycle to a temperature substantially below the solidification temperature of the ash ( For example, it falls within the range of about 500 ° C to about 900 ° C). The total gas stream 5 from the separator unit 2340 can pass through a filtration unit which can reduce the level of the remaining solid ash particles to a very low value (e.g., about 2 mg/m ³ below the gas passing through the filter). ). This clean gas is then combusted in a second burner where it can be diluted with another portion of recovered working liquid 236. In such an embodiment, the recovered working fluid 236 can be dispensed between two burners as needed.

Any carbonaceous material can be used as a fuel in accordance with the present invention. In particular, the fuels available include, but are not limited to, various grades and types of coal, wood, due to the high pressures and temperatures maintained by the oxygen-fired burner apparatus used in the methods and systems of the present invention. , oil, fuel oil, natural gas, coal-based fuel gas, tar from tar sands, bitumen, biomass, algae, classified flammable solid waste, asphalt, used tires, diesel, Gasoline, jet fuel (JP-5, JP-4), vaporized from hydrocarbonaceous materials, or pyrolyzed gases, ethanol, solid and liquid biomass fuels. This can be seen as an important difference from conventional systems and methods. For example, conventional systems known to burn solid fuels (eg, coal) require quite different designs than systems used to burn non-solid fuels (eg, natural gas).

The fuel can be suitably treated to allow injection into the combustion apparatus at a sufficient speed and at a pressure above the combustion chamber. Such a fuel may be in the form of a liquid, slurry, gel, or paste having suitable fluidity and viscosity at ambient or elevated temperatures. For example, the fuel can be provided at a temperature of from about 30 ° C to about 500 ° C, from about 40 ° C to about 450 ° C, from about 50 ° C to about 425 ° C, or from about 75 ° C to about 400 ° C. Any solid fuel material can be ground, or chopped, or otherwise treated to properly reduce the particle size. Fluidization, or slurrying media can be added as needed to achieve the proper form and to meet the flow requirements of high pressure pumps. Of course, depending on the form of the fuel (i.e., liquid, or gaseous), a fluidized medium may not be needed. As such, in some embodiments, The recycled circulating liquid can be used as the fluidizing medium.

In accordance with the present invention, an effusion liquid suitable for use in a combustor can include any liquid that can flow through the liner in a sufficient amount and pressure to form the vapor wall. In this embodiment, CO ₂ may be a desirable effluent liquid because the vapor wall formed has good thermal insulation properties as well as visible light and UV light absorption characteristics. CO ₂ can be used as a supercritical liquid. Other examples of liquids include ET H ₂ O, cooled from the recovered downstream of the combustion product gases, oxygen, hydrogen, natural gas, methane, and other light hydrocarbons. The fuel can be used, inter alia, as an effluent liquid during the beginning of the burner to achieve an appropriate operating temperature and pressure in the burner prior to injection of the primary fuel source. Fuel can also be used as an effluent liquid to adjust the operating temperature and pressure of the burner during switching between primary fuel sources (eg, when switching from coal to biomass as the primary fuel). In some embodiments, two or more evapotranible liquids can be used. Furthermore, different effluent liquids can be used at different locations along the burner. For example, a first evapotranic liquid can be used in a high temperature heat exchange zone, and a second escaping liquid can be used in a lower temperature heat exchange zone. The evapotranspiration liquid can be optimized for the temperature and pressure conditions of the combustion chamber from which the vapor wall forms the vapor wall. In the present example, the ET recovery liquid is preheated CO _2.

In one aspect, the invention provides a method of generating electricity. In particular, these methods of using liquid CO ₂ cycle, which is preferably the so recovered through the method. The process of the present invention also uses high efficiency burners, such as, for example, the evapotranspiration burners previously described. In some embodiments, the method is generally described in relation to the flow chart shown in FIG. As can be seen therein, a burner 220 is provided, and various inputs are also provided therein. A carbonaceous fuel 254 and O ₂ 242 (as needed) can be introduced into the combustor 220 along with a recovered working liquid 236 (CO ₂ in this embodiment). A hybrid setting 250 as illustrated by the dashed line indicates that this part is selectively present. In particular, any combination of two or all three materials (fuel, O ₂ , and CO ₂ recycle liquid) may be combined in the mixing arrangement 250 prior to introduction into the combustor 220.

In various embodiments, it is desirable that the material entering the burner exhibits specific physical features that are desirable for efficient operation of the power generation process. For example, in certain embodiments, is desired, the circulating liquid in a CO ₂ pressure of CO ₂ in the defined and / or temperature is introduced into the combustor. Particularly, advantageous is the burner, is introduced into the CO _2, having a pressure of at least about 8MPa. In a further embodiment, the burner is introduced into the CO ₂ in at least about 10 MPa or may, at least about 12MPa, 14MPa at least about, at least about 15MPa, 16MPa at least about, at least about 18MPa, 20 MPa or at least about, at least about 22MPa At least about 24 MPa, or at least about 25 MPa. In other embodiments, the pressure may be from about 8 MPa to about 50 MPa, from about 12 MPa to about 50 MPa, from about 15 MPa to about 50 MPa, from about 20 MPa to about 50 MPa, from about 22 MPa to about 50 MPa, from about 22 MPa to about 45 MPa, from about 22 MPa to About 40 MPa, about 25 MPa to about 40 MPa, or about 25 MPa to about 35 MPa. Further, for the burner, is introduced into the CO _2, it is advantageous, having a temperature of at least about 200 ℃. In a further embodiment, is introduced into the burner CO ₂ in the can at least approximately 250º, at least about 300º, at least about 350º, at least about 400º, at least about 450º, at least about 500º, at least about 550º, at least about 600º, A temperature of at least about 650o, at least about 700o, at least about 750o, at least about 800o, at least about 850o, or at least about 900o.

In some embodiments, it is desirable that the fuel introduced into the combustor is provided under specific conditions. For example, in certain embodiments, it is desirable that the carbonaceous fuel be introduced into the combustor at a defined pressure, and/or temperature. In some embodiments, the carbonaceous fuel is equivalent to the condition of the liquid CO ₂ cycle, or substantially is introduced into the burner, under similar conditions. The terms "substantially similar conditions" may represent a condition parameter is parameter reference condition (e.g., condition parameters of the liquid CO ₂ cycle) is within 5% as described herein falls within 4%, within 3%, 2 Within %, or within 1%. In certain embodiments, the carbonaceous fuel may first be mixed with the liquid CO ₂ cycle prior to introduction into the burner. In such embodiments, the contemplated that the carbon-containing fuel and liquid CO ₂ cycle will be at the same, or substantially similar conditions (which may include in particular conditions related to the liquid CO ₂ cycle described). In other embodiments, the carbonaceous fuel may be separated from the liquid circulation of the CO ₂ is introduced into the combustor. In such a case, the carbonaceous fuel is still relevant, such as liquid CO ₂ cycle at a pressure as described is introduced. In some embodiments, it is useful, prior to introduction into the burner, the carbonaceous fuel is maintained in the liquid CO ₂ cycle different temperatures. For example, the carbonaceous fuel can be from about 30 ° C to about 800 ° C, from about 35 ° C to about 700 ° C, from about 40 ° C to about 600 ° C, from about 45 ° C to about 500 ° C, from about 50 ° C to about 400 ° C, A temperature of from about 55 ° C to about 300 ° C, from about 60 ° C to about 200 ° C, from about 65 ° C to about 175 ° C, or from about 70 ° C to about 150 ° C is introduced into the burner.

In other embodiments, the desired is introduced into the combustor of O ₂ is provided under specific conditions. Such conditions can be accompanied by the method of providing O ₂ . For example, to provide a desired pressure at a particular O _2. In particular, it is beneficial for the O ₂ introduced into the burner to have a pressure of at least about 8 MPa. In a further embodiment, the pressure of O ₂ introduced into the combustor can be at least about 10 MPa, at least about 12 MPa, at least about 14 MPa, at least about 15 MPa, at least about 16 MPa, at least about 18 MPa, at least about 20 MPa, At least about 22 MPa, at least about 24 MPa, at least about 25 MPa, at least about 30 MPa, at least about 35 MPa, at least about 40 MPa, at least about 45 MPa, or at least about 50 MPa. The provision of O ₂ may comprise the use of an air separator (or oxygen separator), for example, a cryogenic O ₂ concentrator, an O ₂ transport separator, or any similar device, for example, for separation from ambient air. a O ₂ O ₂ in the ion transport separator. The provision of O ₂ as described above may be separately or in combination with pressurizing the O ₂ to achieve the desired pressure. Such an action can cause heating of O ₂ . In some embodiments, the desired, O ₂ and by the pressurized gas in the reach of the inherently different temperature. For example, it is desirable that the temperature of O ₂ supplied to the burner is from about 30 ° C to about 900 ° C, from about 35 ° C to about 800 ° C, from about 40 ° C to about 700 ° C, from about 45 ° C to about 600 ° C, From about 50 ° C to about 500 ° C, from about 55 ° C to about 400 ° C, from about 60 ° C to about 300 ° C, from about 65 ° C to about 250 ° C, or from about 70 ° C to about 200 ° C. Further, in some embodiments, the O ₂ can be in the liquid CO ₂ cycle, and / or conditions of the carbonaceous fuel is equal to, or substantially is introduced into the burner, under similar conditions. This may result from the mixing of the various components prior to introduction into the burner, or a particular method that may result from the O ₂ being introduced into the burner. In a particular embodiment, the O ₂ can be combined with a defined molar ratio of CO ₂ such that the O ₂ supply temperature can be the same as the CO ₂ recycle liquid. For example, when the combustion while viable at temperatures below 100 deg.] C, and the CO ₂ may be in a supercritical pressure. This eliminates the risk of burning associated with pure O ₂ heating due to the CO ₂ dilution effect. Such mixtures may be from about 1: 2 to about 5: 1, about 1: 1 to about 4: 1, or about 1: 1 to about 3: 1 CO ₂ / O ₂ ratio.

In some embodiments, usefully supplied to the burner of O ₂ is substantially purified (i.e., it is in relation to other aspects of the molar content of components occur naturally in the air and improve O _2). In certain embodiments, the O ₂ may have a purity greater than about 50% molar, greater than about 60% molar, greater than about 70% molar, greater than about 80% molar, greater than about 85% molar, Greater than about 90% molar, greater than about 95% molar, greater than about 96% molar, greater than about 97% molar, greater than about 98% molar, greater than about 99% molar, or greater than about 99.5% molar. In other embodiments, the O ₂ may have a molar purity of from about 85% to about 99.6%, from about 85% to about 99%, from about 90% to about 99%, from about 90% to about 98%, Or about 90% to about 97%. All of the CO ₂ recovered from the carbon in the fuel contributes to higher purity in the range of at least about 99.5% mole.

The CO ₂ recycle liquid can be introduced into the combustor at the inlet of the combustor along with the O ₂ and the carbonaceous fuel. However, as previously related to cool the combustor ET description, the liquid CO ₂ cycle which may be introduced through one or more evaporable liquid supply path formed in the transpiration cooling in the combustor burner transpiration cooling, to As all or part of the transpiration cooling liquid introduced into the transpiration member. In some embodiments according to the present invention, the liquid CO ₂ cycle which may be introduced into the combustor (i.e., the O ₂ and fuel together), liquid CO ₂ cycle and at the inlet of the combustor can through a The transpiration member is introduced into the burner as all or part of the evapotranspiration liquid. In other embodiments, the CO ₂ cycle may only be transmitted through the liquid is introduced into the member evapotranspiration burner, as all or part of the transpiration cooling liquid (i.e., no CO _2, and O ₂ will be the This fuel is introduced into the burner inlet).

In some embodiments, the invention features a ratio of various components that are introduced into the combustion chamber. In order to achieve maximum combustion efficiency, it is useful to burn the carbonaceous fuel at high temperatures. However, the temperature of the combustion and the temperature of the combustion product stream exiting the combustor may need to be controlled within defined parameters. To this end, it is useful to provide a specific ratio of the CO ₂ circulating liquid to the fuel such that the combustion temperature, and/or turbine inlet temperature can be controlled within a desired range, while also maximizing the conversion to electrical power. The amount of energy. In certain embodiments, this ratio may be adjusted by circulating the flow of liquid CO ₂ to carbon and to reach the fuel. As more fully described herein, the desired ratio can be affected by the desired turbine inlet temperature and the temperature difference between the inlet and outlet streams at the hot end of the heat exchanger. This ratio may particularly be described as a ratio of the CO ₂ cycle with liquid CO ₂ in the carbonaceous fuel in the presence of carbon in order to determine the molar amount of CO ₂ introduced to the combustor, in some embodiment, is integrally provided to the CO ₂ content of the burner (i.e., the fuel and O ₂ were introduced at the inlet, and any one is used as the cooling liquid ET CO ₂₎ is included in the calculation. However, in certain embodiments, may be separately calculated based on the amount of CO ₂ at the inlet is introduced in the combustor (i.e., excluding any is used as a cooling liquid ET CO _2). In the embodiment where CO ₂ is introduced into the burner as only one evaporative cooling liquid, the calculation is based on the amount of CO ₂ introduced into the burner as the evaporative cooling liquid. Thus, the mole ratio may be described in relation to the content of the input fuel input in the combustor to the combustor carbon inlet of CO _2. Alternatively, the ratio may also be described as the molar content of CO ₂ input to the burner through the chilled cooling liquid associated with carbon in the fuel input to the combustor.

In certain embodiments, CO ₂ is introduced into the circulating liquid and the burner fuel ratio of carbon (in mole basis) may be from about 10 to about 50 (i.e., fuel per 1 mole to about 10 carbon Moer's CO ₂ to fuel is about 50 moles of CO ₂ per 1 mole of carbon. In a further embodiment, the ₂ ratio in the circulating liquid of CO in the carbon in the fuel may be from about 15 to about 50, from about 20 to about 50, from about 25 to about 50, from about 30 to about 50, about 15 to about 45, about 20 to about 45, about 25 to about 45, about 30 to about 45, about 15 to about 40, about 20 to about 40, about 25 to about 40, or about 30 to about 40. In other embodiments, the ratio of ₂ to CO in the circulating liquid carbon in the fuel can be at least about 5, at least about 10, at least about 15, at least about 20, at least about 25, or at least about 30.

The ratio of CO ₂ introduced into the combustor to the molar ratio of carbon present in the carbonaceous fuel can have an important impact on the thermal efficiency of the overall system. This impact on efficiency is also impacted by the design and functionality of further parts of the system, including heat exchangers, water separators, and pressurizing units. This in conjunction with various components of the system and method results in the ability to achieve such specific CO ₂ / C ratio of the high thermal efficiency. Systems and methods previously known not to include the various elements described herein will typically require a CO ₂ /C molar ratio that is significantly lower than the CO ₂ /C molar ratio used in the present invention to achieve close proximity. The efficiency of this described. However, the present invention has been used to identify efficient CO ₂ recovery system and method which allows the use of far more than the conventional art of CO ₂ / C mole ratio is possible. A further advantage of the use of the high CO ₂ /C molar ratio according to the present invention is the dilution of impurities in the combustion stream. Corrosion, or erosion effects of impurities (eg, chloride and sulfur) on system parts can thus be greatly reduced. Today, high-chlorine, and/or high-sulfur coal cannot be used in known systems because the combustion products from such coals, including HCl and H ₂ SO ₄ , are too corrosive and corrosive to power plant components. Unbearable. Many other impurities (for example, solid ash particles and volatile materials containing components such as lead, iodine, antimony, mercury, etc.) can also cause serious internal damage to power plant components at high temperatures, and the dilution effect of CO ₂ recovery can be greatly Improve, or eliminate the harmful effects of such impurities on power plant components. Next, the choice of CO ₂ /C molar ratio can involve complex considerations regarding efficiency and the impact of factory part erosion and corrosion, as well as the design of parts and functions of the CO ₂ recovery system. In the present invention, along with conventional techniques can not be expected in case of high thermal efficiency, efficient recovery of CO _2, and thus possible to increase the CO ₂ / C molar ratio. This high CO ₂ /C molar ratio thus conveys at least the advantages described first.

Similarly, it is useful to control the amount of O ₂ introduced into the burner. This may depend in particular on the operational nature of the burner. As described more fully herein, the methods and systems of the present invention may allow for a full oxidation mode, a full reduction mode, or both. An amount of O ₂ in a fully oxidized mode, supplied to the burner is preferably at least achieve complete oxidation of carbonaceous fuel stoichiometry necessary. In certain embodiments, the amount of O ₂ provided may exceed at least about 0.1% molar, at least about 0.25% molar, at least about 0.5% molar, at least about 1% molar, of the stoichiometric amount mentioned, At least about 2% molar, at least about 3% molar, at least about 4% molar, or at least about 5% molar. In other embodiments, the amount of O ₂ provided may exceed from about 0.1% to about 5% of the stoichiometric amount, from about 0.25% to about 4%, or about 0.5%. The ear is about 3% molar. In the fully reduced mode, the amount of O ₂ supplied to the combustor is preferably the stoichiometry necessary to convert the carbonaceous fuel to the constituents H ₂ , CO, CH ₄ , H ₂ S, and NH ₃ plus At least about 0.1% Mo, at least about 0.25% Mo, at least about 0.5% Mo, at least about 1% Mo, at least about 2% Mo, at least about 3% Mo, at least about 4% Mo, or At least about 5% molar excess. In other embodiments, the amount of O ₂ provided may exceed the stoichiometric amount of from about 0.1% molar to about 5% molar, from about 0.25% molar to about 4% molar, or about 0.5% Mo. The ear is about 3% molar.

In some embodiments, the method of the present invention is characterized by the physical state of CO ₂ from beginning to end in each step of the process. CO ₂ may be identified as being present in various states depending on the object conditions of the material. CO ₂ has triple points at 0.518 MPa and -56.6 ° C, but CO ₂ also has a critical pressure and temperature at 7.38 MPa and 31.1 ° C. After crossing this critical point, i.e. CO.'S ₂ in the presence of supercritical fluid, and the ability to hold a particular state ₂ while maximizing the power generation efficiency has been achieved by the present invention at a particular point in the cycle will CO. In a particular embodiment, the supercritical fluid is introduced in the form of the CO ₂ in the combustor is preferably.

Typically, an understanding of the efficiency of a power generation system or method is to describe the ratio of the energy output of the system or method to the energy of the input system or method. In the case of a power generation system or method, efficiency is generally described as the total low heat of the fuel or power (eg, megawatts or Mw) output to the burner grid and the fuel that produces electricity (or power). The ratio between the total lower heating value thermal energy. This ratio is then referred to as net system or method efficiency (based on LHV). This energy efficiency may be taken into account all the required internal processing system or method, including the generation of purified oxygen (e.g., via an air separation unit), for CO ₂ is transferred to a pressurized CO ₂ pressurized pipeline, and the need for energy Other system or method conditions entered.

In various embodiments, the system and method of the present invention mainly using CO ₂ as a working fluid in the cycle, in this cycle, a carbonaceous fuel at a pressure exceeding the critical pressure of CO ₂ in substantially pure O ₂ Combustion (i.e., in a combustor) is performed to produce a combustion product stream. This stream expands across a turbine and then through a recuperator heat exchanger. In the heat exchanger, a turbine discharge the recovered CO ₂ cycle heating the liquid in a supercritical state. This preheated, recovered CO ₂ recycle liquid is fed to the combustor. In the combustor, it is mixed with product from the combustion of the carbonaceous fuel to provide a total flow at a defined maximum turbine inlet temperature. The present invention at least partially provides excellent efficiency by recognizing the advantages presented by minimizing temperature differences at the hot end of the multiple heat exchanger. This can be minimized by using a low temperature level heat recovery in the CO ₂ into the heating part and before reaching the burner. At these low temperature levels, the specific heat and density of supercritical CO ₂ is very high, and this additional heating allows the turbine exhaust stream to preheat the CO ₂ to a much higher temperature, and this can be significantly reduced The temperature difference at the hot end of the complex heat exchanger. A useful low temperature heat source in a particular embodiment is an air compressor used in a thermally operated cryogenic air separation plant, or a hot exhaust stream from a conventional gas turbine. In a particular embodiment of the invention, the temperature difference at the hot end of the multiple heat exchanger can be less than about 50 °C, and preferably falls within the range of about 10 °C to about 30 °C. The use of low pressure ratios (eg, below about 12) is a further factor that can increase efficiency. The use of CO ₂ coupled with low pressure as a working fluid reduces energy consumption when the pressure discharged from the cooling turbine is raised to the recovery pressure. A further advantage is that with a very small additional parasitic power consumption from nearly 100% carbon capture from the fuel, one of the fuels converted to CO _{2 is} quantified as a CO ₂ generation that is higher than the CO ₂ of the line pressure. The ability of a high pressure liquid at a critical pressure (typically from about 10 MPa to about 20 MPa). Such system and method parameters are further described in greater detail herein.

Returning to Figure 5, the carbonaceous fuel 254 introduced into the combustor 220 along with the O ₂ 242 and the recovered working fluid 236 is combusted to provide a combustion product stream 40. In a particular embodiment, such as previously described, the burner 220 is an evapotranspiration burner. Combustion temperature may vary depending on the particular processing parameters, e.g., the type of carbonaceous fuel used, such fuel is introduced into the combustor in a ratio of CO ₂ to carbon moire, and / or introduced into the burner The Mohr ratio of CO ₂ to O ₂ . In a particular embodiment, as described above, the combustion temperature is the temperature described in relation to the description of the evapotranspiration burner. In a particularly preferred embodiment, combustion temperatures in excess of about 1,300 ° C are advantageous as described herein.

It is also useful to control the combustion temperature such that the products of combustion exiting the burner have a desired temperature. For example, it is useful that the combustion product stream exiting the combustor has a temperature of at least about 700 ° C, at least about 750 ° C, at least about 800 ° C, at least about 850 ° C, at least about 900 ° C, at least about 950 ° C. At least about 1000 ° C, at least about 1050 ° C, at least about 1100 ° C, at least about 1200 ° C, at least about 1300 ° C, at least about 1400 ° C, at least about 1500 ° C, or at least about 1600 ° C. In some embodiments, the combustion product stream can have a temperature of from about 700 ° C to about 1,600 ° C, from about 800 ° C to about 1,600 ° C, from about 850 ° C to about 1,500 ° C, from about 900 ° C to about 1,400 ° C, about 950 ° C. To about 1,350 ° C, or about 1000 ° C to about 1,300 ° C.

As mentioned above, the pressure of the CO ₂ can be a key parameter for maximizing the efficiency of the power cycle during the entire power generation cycle. It is also important to have a defined pressure for the combustion product stream while it is important to have a particularly defined pressure for the material introduced into the combustor. Specifically, the pressure of the combustion product stream can be related to the pressure of the burner is introduced into the liquid CO ₂ cycle. In a particular embodiment, the pressure of the combustion product stream may be introduced into the combustor is at least about 90% of the pressure of the CO _2, i.e., in which the circulating liquid. In a further embodiment, the combustion product stream pressure may be introduced into the burner at least about 91% of the pressure of CO _2, at least about 92%, at least about 93%, at least about 94%, at least about 95% At least about 96%, at least about 97%, at least about 98%, or at least about 99%.

The chemical makeup of the burner product stream exiting the combustor may vary depending on the type of carbonaceous fuel used. Importantly, the combustion product stream will comprise recovered and reintroduced into the burner is further circulation or CO _2. Moreover, an excess of CO ₂ (including the combustion of fuel produced by the CO ₂₎ may be taken from the circulation of the liquid CO ₂ for sequestration or other disposal does not comprise a release to the atmosphere (in particular for directly transferred to a CO ₂ pipeline pressure). In a further embodiment, the combustion product stream may include water vapor, SO ₂ , SO ₃ , HCI, NO, NO ₂ , Hg, excess O ₂ , N ₂ , Ar, and the possibility of occurring in the fuel for combustion. One or more of the other contaminants. Unless removed (e.g., by the process described herein), otherwise present in the combustion product stream in the continuous material may be a stream of liquid CO ₂ cycle. Such materials with the advent of CO ₂ may be referred to herein as "subordinate components."

As can be seen in Figure 5, the combustion product stream 40 can be directed to a turbine 320 wherein the combustion product stream 40 expands to produce a power source (e.g., via a generator to generate electricity, which is not shown in the legend). . The turbine 320 may have an inlet for receiving the combustion product stream 40 and a turbine outlet to release CO ₂ comprises a discharge stream 50. Although a single turbine 320 is shown in FIG. 5, it will be appreciated that more than one turbine may be used, multiple turbines may be connected in series, or alternatively separated by one or more further parts. For example, a further burning part, a compression part, a separator part, or the like.

Again, processing parameters can be tightly controlled in this step to maximize cycle efficiency. The efficiency of current natural gas power plants is critically dependent on the turbine inlet temperature. For example, extensive work has been performed that is costly to achieve a turbine technology that allows inlet temperatures as high as about 1,350 °C. The higher the temperature at the turbine inlet, the higher the efficiency of the power plant, but the more expensive the turbine, and potentially the shorter the lifespan. Some companies are tempted to pay higher prices and have a shorter period of validity. While in some embodiments, the present invention may utilize such a turbine to further increase efficiency, this is not required. In a particular embodiment, the system and method of the present invention achieves the desired efficiency while utilizing turbine inlet temperatures in a much lower temperature range. Thus, features of the present invention may be such that a particular efficiency is achieved while providing a combustion product stream to a turbine inlet at a defined temperature (as described herein), which may Significantly less than the temperature required in the prior art to achieve the same efficiency for the same fuel.

As previously mentioned, the combustion product stream 40 exiting the combustor 220 preferably has a pressure that closely matches the pressure of the recovered working fluid 236 entering the combustor 220. Thus, in certain embodiments, the temperature and pressure of the combustion product stream 40 is such that present in the stream in the CO ₂ in the supercritical fluid state. As the combustion product stream 40 expands across the turbine 320, the pressure of the stream is reduced. Preferably, the pressure drop is controlled such that the pressure of the combustion product stream 40 and the pressure of the turbine discharge stream 50 are at a defined ratio. In certain embodiments, the ratio of the pressure of the combustion product stream at the inlet of the turbine to the turbine discharge stream at the outlet of the turbine is less than about 12. This can be defined as the ratio of inlet pressure (I _p ) to outlet pressure (O _p ) (ie, I _p /O _p ). In further embodiments, the pressure ratio can be less than about 11, less than about 10, less than about 9, less than about 8, or less than about 7. In other embodiments, the inlet pressure to outlet pressure ratio at the turbine can be from about 1.5 to about 12, from about 2 to about 12, from about 3 to about 12, from about 4 to about 12, from about 2 to about 11约约约约约约约约约8。 4 to about 10, about 4 to about 9, or about 4 to about 8.

In a particular embodiment, the desired is the condition at which the turbine discharge stream may be such that the CO ₂ stream is no longer in a supercritical fluid state, but is in a gaseous state. For example, providing CO ₂ in a gaseous state can help remove any dependent components. In some embodiments, the turbine exhaust stream has a pressure below the CO ₂ may be in a supercritical state pressure. Preferably, the turbine discharge stream has a pressure of less than about 7.3 MPa, less than or equal to about 7 MPa, less than or equal to about 6.5 MPa, less than or equal to about 6 MPa, less than or equal to about 5.5 MPa, less And equal to about 5 MPa, less than or equal to about 4.5 MPa, less than or equal to about 4 MPa, less than or equal to about 3.5 MPa, less than or equal to about 3 MPa, less than or equal to about 2.5 MPa, less than or equal to about 2 MPa. Or less than or equal to about 1.5 MPa, in other embodiments, the turbine discharge stream may have a pressure of from about 1.5 MPa to about 7 MPa, from about 3 MPa to about 7 MPa, or from about 4 MPa to about 7 MPa. Preferably, the pressure of the turbine discharge stream is less than the condensation pressure (e.g., ambient cooling) at which the CO ₂ encounters the cooling temperature of the stream, and therefore, in accordance with the present invention, the CO ₂ downstream of the turbine 320 ( And, preferably, the CO ₂ ) upstream of the pressurizing unit 620 is maintained in a gaseous state, and is not allowed to reach a condition in which liquid CO ₂ can be formed.

While the combustion product stream through the turbine may cause some temperature reduction, the turbine discharge stream will typically have a temperature that prevents removal of any subordinate components that are present in the combustion product stream. For example, the turbine discharge stream can have a temperature of from about 500 ° C to about 1000 ° C, from about 600 ° C to about 1000 ° C, from about 700 ° C to about 1000 ° C, or from about 800 ° C to about 1000 ° C. Because of the relatively high temperature of the combustion product stream, it is beneficial that the material used to form the turbine can withstand such temperatures. It may also be useful for the turbine to include a material that provides good chemical resistance to the pattern of dependent materials present in the combustion product stream.

Accordingly, in some embodiments, it is useful to pass the turbine discharge stream 50 through at least one heat exchanger 420 that can cool the turbine discharge stream 50 and provide a cooled turbine discharge having a temperature that falls within a defined range. Stream 60, in a particular embodiment, having the cooled turbine exhaust stream 60 leaving the heat exchanger 420 (or the last heat exchanger in series when two or more heat exchangers are used) Temperature less than about 200 ° C, less than about 150 ° C, less than about 125 ° C, less than about 100 ° C, less than about 95 ° C, less than about 90 ° C, less than about 85 ° C, less than about 80 ° C, less At about 75 ° C, less than about 70 ° C, less than about 65 ° C, less than about 60 ° C, less than about 55 ° C, less than about 50 ° C, less than about 45 ° C, or less than about 40 ° C.

As mentioned earlier, it is beneficial that the pressure of the turbine discharge is related to the combustion There is a specific ratio of logistics pressure. In a particular embodiment, the turbine discharge stream will pass directly through one or more of the heat exchangers described herein without passing through any additional components of the system. Thus, the pressure ratio can also be described as the pressure at which the combustion product stream exits the combustor than the hot end of the stream entering the heat exchanger (or the first heat exchanger when a tandem heat exchanger is used) The ratio of the pressure at the time. Again, the pressure is preferably less than about 12, and in other embodiments, the ratio of pressure between the combustion product stream and the stream entering the heat exchanger can be less than about 11, less than about 10, less than About 9, less than about 8, or less than about 7, in other embodiments, the pressure ratio can be from about 1.5 to about 10, from about 2 to about 9, from about 2 to about 8, from about 3 to about 8, or About 4 to about 8.

While the use of an evapotranial cooling burner allows for high heat combustion, the system and method of the present invention is characterized by the ability to provide a turbine exhaust stream to a temperature that is sufficiently low to reduce the cost associated with the system, increasing the Heat exchangers, as well as heat exchangers that improve the efficiency and stability of the system. In a particular embodiment, the heat exchanger has a hottest operating temperature of less than about 1,100 ° C, less than about 1,000 ° C, less than about 975 ° C, less than about 950 ° C, less than about 10,000 ° C in the system or method according to the present invention. About 925 ° C, or less than about 900 ° C.

In certain embodiments, it is particularly useful that the heat exchanger 420 includes at least two heat exchangers in series to receive the turbine discharge stream 50 and to cool it to a desired temperature, using a heat exchanger The profile may vary depending on the conditions of the stream entering the heat exchanger. For example, the turbine exhaust stream 50 can be at a relatively high temperature, as described above, and, therefore, usefully, the heat exchanger designed to withstand the harsh conditions of the high performance material directly receives the heat exchanger Turbine discharge stream 50. For example, in the first heat exchanger string may comprise INCONEL ^® alloy or a similar material. Preferably, the first heat exchanger in series is capable of continuously withstanding an operating temperature of at least about 700 ° C, at least about 750 ° C, at least about 800 ° C, at least about 850 ° C, at least about 900. °C, at least about 950 ° C, at least about 1000 ° C, at least about 1,100 ° C, or at least about 1,200 ° C. Land also is one or more of such a heat exchanger comprises a material with good chemical resistance to the patterns present in the combustion product stream dependent material, INCONEL ^® alloy available from Special Metals Corporation, and some embodiments may include an austenitic nickel-chromium-based alloys (austenitic nickel-chromium-based alloys ), examples of the alloy may be used ^{include, INCONEL ® 600, INCONEL ® 601} , INCONEL ® 601GC, INCONEL ® 603CO 2L, INCONEL ® 617 , INCONEL ^® 625, INCONEL ^® 625LCF, INCONEL ^® 686, INCONEL ^® 690, INCONEL ^® 693, INCONEL ^® 706, INCONEL ^® 718, INCONEL ^® 718SPF ^TM , INCONEL ^® 722, INCONEL ^® 725, INCONEL ^® 740, INCONEL ^® CO ₂ ^{-750, INCONEL ® 751, INCONEL ®} MA754, INCONEL ® MA758, INCONEL ® 783, INCONEL ® 903, INCONEL ® N06230, INCONEL ® C-276, INCONEL ® G-3, INCONEL ® HCO 2, INCONEL ® 22. An example of an advantageous heat exchanger design is a diffusion bonded compact plate heat exchanger made of a high temperature material with chemically ground fins in the plate. Suitable heat exchangers can be included under the trade name HEATRIC ^® (available from Meggitt USA, Houston, TCO ₂ ).

Preferably, the first of the series exchangers is sufficient to transfer heat from the turbine discharge stream such that one or more other exchangers present in the series exchanger may be made of more conventional materials. For example, stainless steel, in a particular embodiment, at least two heat exchangers, or at least three heat exchangers, are used in series to cool the turbine discharge stream to a desired temperature. In particular, the use of a plurality of heat exchangers in series may be followed by subsequent transfer of heat from the turbine discharge stream to the CO ₂ circulating liquid for reheating prior to introduction of the circulating liquid into the combustor. Seen in the narrative.

In some embodiments, the method and system are characterized in that they can be a single stage combustion method or system. This can be achieved by using a high efficiency burner, such as the aforementioned transpiration cooling burner. It is essential that the fuel can be substantially completely combusted in the separate combustor such that it does not necessarily provide a combustor in series to completely combust the fuel. Accordingly, in some embodiments, the method and system of the present invention can be described as the sole burner of the evapotranspiration burner. In further embodiments, the methods and systems can be described as occurring only in the separate evapotranial cooling combustor before the effluent stream passes into the heat exchanger. In still other embodiments, the method and method can be described as the turbine exhaust stream passing directly into the heat exchanger without passing through another burner.

After cooling, the cooled turbine exhaust stream 60 exiting the at least one heat exchanger may undergo further processing to separate any dependent components remaining in the cooled turbine exhaust stream 60 from the combustion of the fuel. As shown in FIG. 5, the cooled turbine exhaust stream 60 can be directed to one or more separation units 520. As discussed in more detail later, in particular, the features of the present invention is the ability to efficient power generation method using carbonaceous fuel without CO ₂ release to the atmosphere to provide combustion case, this may at least partially be formed by containing The CO ₂ in the combustion of the carbon fuel is used as a circulating liquid in the power generation cycle. In some embodiments, although continuous combustion and recovery of CO ₂ as the circulating liquid may cause accumulation of CO ₂ in the system, in such cases, it is useful to abandon at least a portion of the CO ₂ from the circulating liquid ( for example, an amount roughly equivalent to the amount of CO ₂ from the combustion of carbonaceous fuels derived), thus giving up the CO ₂ can be disposed of by any suitable method. In a particular embodiment, the CO ₂ may be directed to the pipeline for archiving or disposal by appropriate means, as the next narrator.

The specification of the required CO ₂ piping system is that the CO ₂ enters the pipeline substantially without the need for water to avoid eroding the carbon steel used in the pipeline, although the "wet" CO ₂ can be directly introduced into the stainless steel. In the CO ₂ pipeline, but not always possible, in fact, based on cost considerations, it is more desirable to use carbon steel pipe. Accordingly, in some embodiments, the liquid present in the CO ₂ cycle in water (e.g., formed during the combustion of a carbonaceous fuel, in the combustion product stream and to maintain the turbine exhaust stream and a liquid CO ₂ cycle The water in the stream) can be largely removed as a liquid phase from the cooled CO ₂ recycle liquid stream, which in a particular embodiment can be cooled by the ambient temperature using a gas phase mixture. upon cooling to low temperatures, there is provided a liquid pressure lower than the CO ₂ cycle (e.g., gaseous) present in the gas mixture of CO ₂ is liquefied in a pressure point being reached, for example, particularly, the CO ₂ cycle The liquid can be supplied at a pressure of less than 7.38 MPa during the separation of the subordinate components. Even lower pressures may be required if a low ambient temperature range or a cooling mode that is substantially below ambient temperature is used. This allows the water to be separated in a liquid form and also minimizes the contaminants of the purified working liquid 65 leaving the separation unit, which can also limit the turbine discharge pressure to at least the critical pressure of the turbine exhaust gas. a value. The true pressure can depend on the temperature at which the ambient cooling is available. For example, if water separation occurs at 30 ° C, a pressure of 7 MPa allows a limit of 0.38 MPa for the CO ₂ condensing pressure. In some embodiments, exit the heat exchanger, and enters the separation unit of the CO ₂ cycle fluid pressure may be provided as follows: from about 2MPa to about 7MPa, 2.25MPa to about 7MPa, 2.5MPa to about 7MPa, 2.75MPa to about 7 MPa, 3 MPa to about 7 MPa, 3.5 MPa to about 7 MPa, 4 MPa to about 7 MPa, or 4 MPa to about 6 MPa. In another embodiment, the pressure may be substantially the same as the pressure at the turbine outlet.

In a particular embodiment, the purified working liquid 65 after separation of water, which does not include water vapor, or substantially does not include water vapor. ₂ wherein some embodiments, the purified recycle stream is CO, water vapor included only at less than 1.5% molar basis, less than 1.25% of the molar basis, less than 1 at molar basis %, less than 0.9% under the Mohr base, less than 0.8% under the Mohr base, less than 0.7% under the Mohr base, less than 0.6% under the Mohr base, less than 0.5 under the Mohr base. %, less than 0.4% under the Mohr base, less than 0.3% under the Mohr base, less than 0.2% at the Mohr base, or less than 0.1% at the Moore basis. In some embodiments, the amount of water vapor in the purified CO ₂ stream comprises a liquid circulation may be only about 0.01% to about 1.5% at a molar basis, about 0.01% at a mole basis to about 1%, From about 0.01% to about 0.75% at the base of the mole, from about 0.01% to about 0.5% at the base of the mole, from about 0.01% to about 0.25% at the base of the mole, and from about 0.05% to about 0.5 at the base of the mole. %, or about 0.05% to about 0.25% of the molar basis.

Can highly advantageously to provide in the above-defined temperature and pressure conditions of liquid CO ₂ cycle in order to help the dependent component (e.g. water) was separated. In other words, the present invention is particularly provided to maintain the _circulating liquid at the conditions at the required CO.'S, _2, and so that the state prior to separation may be in the water facilitates the separation of the CO ₂ cycle liquid CO. By providing the CO ₂ in the circulating liquid of the pressure, the temperature of the liquid stream can be reduced to allow water to flow in the liquid state and will therefore be more easily separated point ₂ from a gaseous CO.

In certain embodiments, intended to provide further drying conditions such that the liquid purified CO ₂ cycle may be completely or substantially anhydrous. As previously mentioned, the water may be separated leaving a small portion (i.e., low concentrations) in water in the CO ₂ cycle from the liquid CO ₂ cycle depending on the material in a liquid phase. In some embodiments, it is acceptable, so that the liquid CO ₂ cycle continues with a small portion of water remaining therein. In other embodiments, usefully, so that the liquid CO ₂ cycle for further processing, in order to help remove any remaining water or partially. For example, a low concentration of water can be removed by a desiccant dryer or other means as appropriate in accordance with the disclosure herein.

In particular, in the CO ₂ cycle to provide the defined liquid pressure to facilitate such re-separation unit may maximize the efficiency of the power cycle. Specifically, there is provided in the defined range of pressure liquid CO ₂ cycle in the vapor phase may be such that the liquid purified CO ₂ cycle is compressed to a high pressure in the case of minimum consumption in the power. As previously described, need such a pressure, so that the portion of the purified liquid CO ₂ cycle is recovered into the burner part is supplied and the desired line pressure (e.g., from about 10MPa to about 20MPa). This further clarifies the benefits of minimizing the inlet to outlet pressure ratio of the diffusion turbine, as previously described. This effect of increasing the overall cycle efficiency, and also allow the discharge pressure from the turbine falls within the desired range, for separating water and other components from the slave liquid CO ₂ cycle.

The CO ₂ cycle flow of liquid through a separation unit 520 set forth in Example 6. FIG. As can be seen, the cooled turbine exhaust stream 60 from the heat exchanger can be further removed from the cooled turbine exhaust stream 60 by using water to further remove the hot cold water heat exchanger 530 (or any similarly functional device). , and a discharge of the mixed phase cooled turbine discharge stream 61, wherein the CO ₂ gas is maintained, and the water in the liquid CO ₂ cycle has been converted to a liquid phase. For example, the cooled turbine exhaust stream 60 through the cold water heat exchanger 530 allows the liquid CO ₂ cycle cooled to a temperature less than about 50 ℃, less than about 55 ℃, less than about 40 ℃, less than about 45 °C, less than about 40 ° C, or less than about 30 ° C. Preferably, the pressure of the liquid CO ₂ cycle is not substantially changed by the cold water heat exchanger 530. The cooled turbine exhaust stream 61 of the mixed phase is directed to a water separation unit 540 from which the liquid water stream 62a is discharged. Moreover, exiting the water separation unit 540 is an enriched CO ₂ circulating liquid stream 62b that can exit the separator 520 directly as the purified working liquid 65. In an alternate embodiment (as illustrated by the flow represented by the dashed line and as illustrated by the part), the carbon dioxide rich recycle liquid stream 62b can be directed to one or more additional separation units 550 to remove more subordinate components, just as A more comprehensive narrative. In a particular embodiment, any more subordinate component liquid CO ₂ cycle which may be removed after removal of water. Subsequently, the CO ₂ cycle fluid exiting the one or more additional separation units, as the working liquid 65 purified. However, in some embodiments, the cooled phase turbine exhaust stream 61 of the mixed phase may be first directed to remove one or more dependent components prior to removal of water, and the partially purified stream may then be directed The water separation unit 540. It will be appreciated that those skilled in the art, as disclosed in the present disclosure, will be able to conceive various combinations of separators as desired, and all such combinations are incorporated in the present invention.

As previously mentioned, in addition to water, liquid CO ₂ cycle which may also comprise other ingredients dependent, for example, derived from the fuel combustion-derived, and oxygen-derived impurities, such components can also be dependent on and around water separation at the same time from the cooled, liquid gas removed CO ₂ cycle. For example, in addition to water vapor, subordinate components such as SO ₂ , SO ₃ , HCI, NO, NO ₂ , Hg, and excess O ₂ , N _{2 ,} and Ar may also be removed. These subordinate components of the liquid CO ₂ cycle (generally considered impurities, or contaminants) and an appropriate method may be utilized in addition to CO ₂ cycle completely from the cooled liquid (e.g., in U.S. Patent Application Publication 2008/0226515 And the method as defined in European Patent Application No. EP 1 952 874 and EP 1 953 486, the entire disclosure of which is incorporated herein by reference. While SO ₂ and SO ₃ can be converted to sulfuric acid 100%, >95% of NO and NO ₂ can be converted to nitric acid. In this CO ₂ cycle any excess liquid oxygen may be isolated as an oxygen-enriched stream to be recycled to the selective burner. Any inert gas (e.g., N ₂ and Ar) appears to be discharged in a low pressure atmosphere, in certain embodiments, the liquid CO ₂ cycle can therefore be purified, so that the CO derived from the combustion of the carbon in fuel ₂ can be delivered ultimately in the form of a high density, purified stream. In a particular embodiment, the purified ₂ CO CO ₂ concentration in the circulating liquid may be comprised of at least 98.5 mole%, at least 99% mole, mole of at least 99.5%, or at least 99.8% mole. Further, the liquid CO ₂ cycle which may be provided at a desired pressure, so as to directly input a CO ₂ pipeline, e.g., at least about 10 MPa or at least about 15MPa, or at least about 20MPa.

As a summary of the foregoing, combustion of the carbonaceous fuel 254 in the presence of O ₂ 242 and a recovered working fluid 236 in an evapotranial cooling combustor can result in a combustion product stream having a relatively high temperature and pressure. 40. This includes a relatively larger amount of CO ₂ combustion product stream 40 through a turbine 320 to expand the combustion product stream 40, thereby reducing the pressure of the flow, and power generation. The turbine discharge stream 50 exiting the outlet of the turbine 320 is at a reduced pressure but still at a relatively high temperature. Since the combustion product stream contaminants and impurities, advantageously, the separated first and impurities such contaminants before the liquid back to the CO ₂ cycle system revenue. To achieve this separation, the turbine discharge stream 50 is cooled by passing through the one or more heat exchangers 420. Separation of such dependent products (eg, water and any other contaminants as well as impurities) can be achieved. As previously mentioned, in order to recover the CO ₂ recycle liquid back to the burner, the CO ₂ recycle liquid must be reheated and repressurized. In certain embodiments, the present invention is that, while performing special processing steps to maximize the efficiency of the power cycle, but also to avoid contamination (e.g., CO ₂₎ emissions into the atmosphere. This can be seen particularly in reheating for leaving the separation unit the cooled and purified liquid CO ₂ cycle and repressurization.

As further illustrated in FIG. 5, the purified working liquid 65 exiting the one or more separation units 520 may pass through one or more pressurizing units 620 (eg, a pump, a compressor, or Similarly, to increase the pressure of the purified working liquid 65. In certain embodiments, the purified working liquid 65 can be compressed to a pressure of at least about 7.5 MPa or at least about 8 MPa. In some embodiments, a single unit may be pressurized to a CO pressure of the purified _circulating liquid is increased to the desired pressure of 220 herein is introduced into the combustor.

In a particular embodiment, pressurization may be performed using two or more compressors (eg, pumps) connected in series in the pressurizing unit 620. One such embodiment is shown in Figure 7, wherein the purified working liquid 65 is passed through a first compressor 630 to compress the purified working liquid 65 to a first pressure (which is preferably higher than The critical pressure of the CO ₂ ), and thus the stream 66 is formed. Stream 66 can be directed to recoverable heat (e.g., heat formed by the pressurization of the first compressor) and thus a cooling water heat exchanger 640 that forms stream 67, preferably at a temperature near ambient . Stream 67 may be directed to be used to the pressure of a second pressurized liquid CO ₂ cycle is greater than the first pressure to a second compressor 650. As aforementioned, the second pressure may be substantially similar to that required for _circulating the liquid input (or recovering) the burner to the CO pressure.

In a particular embodiment, the first compressor 630 may be used to increase the pressure of the working liquid 65 is purified, so that the liquid purified CO ₂ cycle may be converted to a gas phase supercritical fluid state. In a particular embodiment, the purified liquid CO ₂ cycle may be pressurized to a pressure of about 7.5MPa to about 20MPa in the first compressor 630, from about 7.5MPa to about 15MPa, from about 7.5MPa to about 12MPa, about 7.5 MPa to about 10 MPa, or about 8 MPa to about 10 MPa. Next, the stream 66 exiting the first compressor 630 (which is in a supercritical liquid state) can be cooled by the CO ₂ circulating liquid to a high density liquid sufficient to form a pump that can be pumped more efficiently to even higher pressures. The temperature of the cooling water heat exchanger 640 (or any similarly acting device). In view of the large volume of CO ₂ used as the circulating liquid in recovery, it is important that pumping a large volume of CO ₂ in a superfluid state can be said to be an important energy extraction in the system, however, the present invention can be achieved by increasing the frequency and thus reduce the CO ₂ supercritical CO ₂ (which is pumped back to the burner for recovery) is provided to increase the total volume efficiency with advantages. In a particular embodiment, after being discharged from the chilled water heat exchanger 640 (and before heating through the heat exchange unit 420), the CO ₂ circulating liquid can provide a density of at least about 200 kg/m ³ . of at least about 250kg / m ^3, at least about 300kg / m ^3, at least about 350kg / m ^3, at least about 400kg / m ^3, at least about 450kg / m ^3, at least about 500kg / m ^3, at least about 550kg / m ^3, at least about 600kg / m ^3, at least about 650kg / m ^3, at least about 700kg / m ^3, at least about 750kg / m ^3, at least about 800kg / m ^3, at least about 850kg / m ^3, at least about 900kg / m ^3, at least about 950kg / m ^3, or at least about 1000kg / m ^3. In a further embodiment, the density is about 150kg / m ³ to about 1,100kg / m ^3, about 200kg / m ³ to about 1,000kg / m ^3, about 400kg / m ³ to about 950kg / m ^3, about From 500 kg/m ³ to about 900 kg/m ³ , or from about 500 kg/m ³ to about 800 kg/m ³ .

In a particular embodiment, the stream 66 by the CO ₂ cycle cooling liquid 640 may be cooling water heat exchanger to a temperature of less than about 60 ℃, less than about 50 ℃, less than about 40 ℃, or less than about 30 °C. In other embodiments, the CO ₂ recycle liquid exits the chilled water heat exchanger 640 to a stream 67 temperature of from about 15 ° C to about 50 ° C, from about 20 ° C to about 45 ° C, or from about 20 ° C to about 40 °C. Preferably, the CO ₂ circulating liquid in the stream 67 entering the second compressor 650 is in a condition conducive to energy efficiency, and the flow pump is driven to introduce the CO ₂ circulating liquid into the burner. The pressure required. For example, pressurized, supercritical CO ₂ circulating liquid stream 70 may be further pressurized to a pressure of at least about 12MPa, at least about 15MPa, 16MPa at least about, at least about 18MPa, 20 MPa or at least about, or at least about 25MPa. In some embodiments, the pressurized supercritical CO ₂ and then circulating the liquid stream 70 may be pressurized to a pressure of about 15MPa to about 50 MPa, about 20MPa to about 45MPa, 25MPa, or from about to about 40MPa. Any type of compressor that can operate under the pressures mentioned and that can achieve the pressure can be used, for example, a high pressure multi-stage pump.

Exiting the one or more of the pressurizing unit 620 is pressurized CO ₂ cycle liquid stream 70 can be directed back to the previously used to cool the turbine exhaust heat exchanger 50 such flow. As shown in FIG. 5, which has been pressurized liquid CO ₂ cycle via a first flow splitter 70 720, a liquid conduit to form CO ₂ and 80 CO ₂ cycle flow of liquid stream 85 (which is substantially equal to CO ₂ Circulating liquid stream 70, except for the actual amount of CO ₂ present in the stream). Thus, in some embodiments, the CO ₂ cycle pressurized liquid stream, at least a portion of the CO ₂ for sequestration is introduced into a pressurized line. The CO ₂ is removed from the circulating liquid flow and is directed line (or other storage or disposal means) may depend on the amount of CO ₂ is introduced into the combustor in a CO ₂ content of the desired change, to control the combustion temperature and the real amount of CO ₂ exiting the burner present in the combustion exhaust stream. In some embodiments, the amount of CO ₂ recovered, as previously described, can be substantially the amount of CO ₂ formed by the combustion of the carbonaceous fuel in the combustor.

In order to achieve high efficiency operation, it is helpful to that exiting the pressing unit 620 has the liquid CO ₂ cycle is heated to the supercritical fluid has a much lower specific heat on the temperature. This is equivalent to providing a very large heat input over a relatively low temperature range. Using an external heat source (e.g., relatively low temperature heat source) to provide additional heat to a portion of said liquid CO ₂ cycle has been recovered, so that the exchanger unit 420 is capable of turbine exhaust stream 50 and the heat exchange The unit 420 operates (either when a two or more heat exchangers in series are used) in the case where the temperature difference between the recovered working liquids 236 at the hot end of the first heat exchanger is small. In a particular embodiment, the CO ₂ cycle the pressurized fluid through the one or more heat exchangers for the pressurized liquid CO ₂ cycle is heated to the flow of the pressurized flow of liquid CO ₂ cycle enters the combustion It is useful in terms of the temperature required for the device. In certain embodiments, the CO ₂ cycle prior to the liquid stream to enter the burner, the pressurized CO ₂ cycle which liquid stream is heated to a temperature of at least about 200 ℃, at least about 300 ℃, at least about 400 ℃, at least about 500 ° C, at least about 600 ° C, at least about 700 ° C, or at least about 800 ° C. In some embodiments, it can be heated to a temperature of from about 500 ° C to about 1,200 ° C, from about 550 ° C to about 1,000 ° C, or from about 600 ° C to about 950 ° C.

Figure 8 illustrates an embodiment of a heat exchanger unit 420 in which three individual heat exchangers are used in series to recover heat from the turbine discharge stream 50, thereby providing conditions suitable for removing subordinate components. the cooled turbine discharge stream 60 and recovered while recovering the working fluid to increase the heat to 236, and the pressurized before it is introduced into the burner, a circulating liquid supercritical CO ₂ stream 70 (or 85). As described further above, the systems and methods of the present invention can be used to trim conventional power systems (e.g., coal-fired power plants) to increase efficiency, and/or its output. In some embodiments, the heat exchanger unit 420, as described below, may thus be referred to as a primary heat exchange unit in such a trim, where a slave heat exchange unit is also used (as in Figure 12). As stated in the article). The secondary heat exchange unit, for example, can therefore be used to superheat a steam stream. The use of such terms as the primary heat exchange unit and the dependent heat exchange unit is not to be construed as limiting the scope of the invention, and is merely intended to provide a clear description.

In the embodiment included in FIG. 8, the turbine exhaust stream 50 first enters the heat exchanger series 420 by passing through the first heat exchanger 430 to provide a lower temperature than the turbine exhaust stream 50. The flow of temperature 52. When the first heat exchanger 430 receives the hottest stream in the series (ie, the turbine exhaust stream 50) and thus the heat in the series of heat exchangers 420 that falls within the highest temperature range, it can be described as A high temperature heat exchanger. As previously mentioned, the first heat exchanger 430 receiving the relatively higher temperature turbine exhaust stream 50 can include a special alloy or other material that can be used to adapt the heat exchanger to recover the temperatures mentioned, the turbine exhaust stream 50 The temperature can be significantly reduced by passing through the first heat exchanger 430 (which can also be applied to other embodiments using less than three, or more than three, individual heat exchangers). In certain embodiments, the temperature of the stream 52 from the first heat exchanger 430 can be at least about 100 ° C lower than the temperature of the turbine exhaust stream 50, at least about 200 ° C, at least about 300 ° C, at least about 400 ° C, at least about 450 ° C, at least about 500 ° C, at least about 550 ° C, at least about 575 ° C, or at least about 600 ° C. In a particular embodiment, the temperature of stream 52 can be from about 100 ° C to about 800 ° C, From about 150 ° C to about 600 ° C, or from about 200 ° C to about 500 ° C. In the preferred embodiment, the pressure of the stream 52 exiting the first heat exchanger 430 is substantially similar to the pressure of the turbine discharge stream 50. In particular, the pressure of the stream 52 exiting the first heat exchanger 430 may be at least 90%, at least 91%, at least 92%, at least 93%, at least 94%, at least 95 of the pressure of the turbine discharge stream 50. %, at least 96%, at least 97%, at least 98%, at least 99%, at least 99.5%, or at least 99.8%.

The stream 52 exiting the first heat exchanger 430 passes through the second heat exchanger 440 to produce a stream 56 having a temperature that is less than the temperature of the stream 52 entering the second heat exchanger 440. When the second heat exchanger 440 transmits heat falling within an intermediate temperature range (ie, smaller than the first heat exchanger 430 but larger than the third heat exchanger 450), it can be described It is an intermediate temperature heat exchanger. In some embodiments, the temperature difference between the first stream 52 and the second stream 56 can be substantially less than the temperature difference between the turbine discharge stream 50 and the stream 52 exiting the first heat exchanger 430. In some embodiments, the temperature of the stream 56 exiting the second heat exchanger 440 can be about 10 ° C to about 200 ° C lower than the temperature of the stream 52 entering the second heat exchanger 440, about 20 ° C to about 175 ° C, from about 30 ° C to about 150 ° C, or from about 40 ° C to about 140 ° C. In a particular embodiment, the temperature of stream 56 can range from about 75 °C to about 600 °C, from about 100 °C to about 400 °C, or from about 100 °C to about 300 °C. Again, it may be preferred that the pressure of stream 56 exiting the second heat exchanger 440 is substantially similar to the pressure of the stream 52 entering the second heat exchanger 440. In particular, the pressure of the stream 56 exiting the second heat exchanger 440 may be at least 90%, at least 91%, at least 92%, at least 93%, at least the pressure of the stream 52 entering the second heat exchanger 440. 94%, at least 95%, at least 96%, at least 97%, at least 98%, at least 99%, at least 99.5%, or at least 99.8%.

The stream 56 exiting the second heat exchanger 440 passes through the third heat exchanger 450 to produce the cooled turbine exhaust stream 60 having a lower temperature than the stream 56 entering the third heat exchanger 450. When the third heat exchanger 450 transfers heat in the lowest temperature range of the heat exchanger series 420, it can be described as a low temperature heat exchanger. In some embodiments, the temperature of the cooled turbine exhaust stream 60 exiting the third heat exchanger 450 may be about 10 ° C to about 250 ° C lower than the temperature of the stream 56 entering the third heat exchanger 450, about 15 From °C to about 200 ° C, from about 20 ° C to about 175 ° C, or from about 25 ° C to about 150 ° C. In a particular embodiment, the cooled turbine exhaust stream 60 can have a temperature of from about 40 ° C to about 200 ° C, from about 40 ° C to about 100 ° C, or from about 40 ° C to about 90 ° C. Again, it may be preferred that the pressure of the cooled turbine exhaust stream 60 exiting the third heat exchanger 450 is substantially similar to the pressure of the stream 56 entering the third heat exchanger 450. In particular, the pressure of the cooled turbine exhaust stream 60 exiting the third heat exchanger 450 may be at least the pressure of the stream 56 entering the third heat exchanger 450. 90%, at least 91%, at least 92%, at least 93%, at least 94%, at least 95%, at least 96%, at least 97%, at least 98%, at least 99%, at least 99.5%, or at least 99.8%.

The cooled turbine exhaust stream 60 entering the third heat exchanger 450 (and thus exiting the heat exchanger unit 420, in general) may be directed to one or more separation units 520. Also as described above, the CO ₂ cycle separated liquid stream may be subjected to one or more of the patterns to be removed from the slave component stream, the pressurized circulating fluid is then returned to the combustor is recovered as the ( Optionally, there is a portion of the separated CO ₂ that enters a CO ₂ line or other storage or disposal device without being vented to the atmosphere.

Referring back to FIG. 8, the CO ₂ cycle pressurized liquid stream 70 (or 85, if the first by a separation means, as shown in FIG. 5.) can be guided back through the same series of three heat exchangers Therefore, the former through the heat exchanger such recovered heat can be used to grant the pressurized liquid CO ₂ cycle 220 in stream 70 before entering the burner. Typically, by which is granted by the three heat exchangers (450,440, and 430) to the pressurized liquid CO ₂ cycle thermal heat flow 70 may be relatively recovered with such heat exchangers The amount (as above) is proportional.

In certain embodiments, the invention features a temperature difference between the streams exiting and entering the heat exchanger (or the last heat exchanger in the series). Referring to Figure 8, this is particularly relevant to the temperature difference between the cooled turbine exhaust streams 60 and 70. In particular, the temperature difference at the cold end of the heat exchanger (of the last heat exchanger in the series) is greater than zero, and may range from about 2 ° C to about 50 ° C, about 3 ° C to about 40 ° C, about 4 ° C to about 30 ° C, or about 5 ° C to about 20 ° C.

In some embodiments, the CO ₂ cycle the pressurized liquid stream 70 can be directly connected in series through the three heat exchangers. For example, the CO ₂ cycle the pressurized liquid stream 70 (i.e., at relatively low temperatures by) through the third heat exchanger 450, at an increased temperature to form a stream 71, which may Passing directly through the second heat exchanger 440 to form a stream 73 at an increased temperature that can pass directly through the first heat exchanger 430 to form the high temperature, pressurized, recovered CO that can be introduced into the combustor 220 ₂ working liquid stream 236.

However, in a particular embodiment, the present invention is that the use of an external heat source to further increase the temperature of the recovered liquid CO ₂ cycle. For example, as set forth in FIG. 8, in which the pressurized liquid CO ₂ cycle stream 70 flows through the third heat exchanger 71 after 450, is formed, the second heat exchanger by direct substitution 440 The split stream 460 can be split into two streams 71b and 72a by dividing the stream 71. Stream 71b can pass through the second heat exchanger 440. As described above, stream 72a can be used in addition to the heat exchanger itself such granted, the further pressurized liquid stream 70 CO ₂ cycle granted an additional amount of heat of the heater 470 side.

71 from the pressurized CO ₂ cycle in which the liquid flow stream is directed to the second heat exchanger 440, and the amount of heater-side system 470 may depend on the working conditions and the CO ₂ cycle pressurized liquid stream It varies in order to enter the desired final temperature of the combustor 220. In certain embodiments, the molar ratio of CO ₂ in stream 71b directed to the second heat exchanger 440 and CO ₂ in the stream 72a directed to the side heater 470 can be from about 1:2 to about 20: 1 (i.e., stream 72a approximately 2 per mole of CO ₂ in the society 's high 71b 1 mole of CO _2, to about 1 mole per stream 72a to 71b society' s high CO ₂ in a CO mole 20 ₂ ). In still other embodiments, the molar ratio of CO ₂ directed to the second heat exchanger 440 in stream 71b and CO ₂ directed to the side heater 470 in the stream 72a may be from about 1:1 to about 20:1, approximately 2:1 to approximately 16:1, approximately 2:1 to approximately 12:1, approximately 2:1 to approximately 10:1, approximately 2:1 to approximately 8:1, or approximately 4:1 to About 6:1.

The side heater may comprise any means may be used to heat the CO ₂ cycle granted to the liquid. In some embodiments, the energy (i.e., heat) provided by the side heaters can be input into the system from an external source. However, in a particular embodiment in accordance with the invention, the efficiency of the cycle can be increased by utilizing waste heat generated at one or more points in the cycle. For example, the generation of O ₂ used to input the burner can generate heat. Known air separation units can generate heat as a by-product of the separation process. Further, usefully, the increased pressure of the O ₂ can be provided, such as described above, and such pressurization of the gas can also generate heat as a by-product. For example, O ₂ can operate a cryogenic air separation process by generating, wherein the oxygen pumped by the cooled liquid oxygen stored (which has been sufficiently heated to ambient temperature) and subjected to pressure in the process. Such a cryogenic oxygen pumping plant can have two air compressors, all of which can be operated adiabatically in a no inter-stage cooling manner, so that the temperature of the hot, pressurized air can be Cool down to near and/or above the temperature of the stream heated by the external source (eg, stream 72a, in Figure 8). In the setting of the prior art, when the secondary cooling system is required to eliminate the by-product heat, such heat is not utilized, or can be practically consumed as a system. However, in the present invention, a coolant may be used to recover the heat generated from the air separation process, and to provide the heat to the side heater illustrated in Fig. 8, in other embodiments The side heater itself may be the air separation unit (or an associated device), and the CO ₂ circulating liquid (eg, stream 72a in FIG. 8) may itself pass directly through the air separation unit Or circulating a coolant system associated therewith to recover heat generated in the air separation process, and more particularly, the added heat can be obtained by adiabatically operating the CO ₂ compressor and removing The heat of compression in the after-cooler is achieved by resisting the transfer of heat of compression to heat a portion of the circulating heat transfer liquid of the high pressure CO ₂ circulating liquid, or by direct heat transfer to the high pressure recovered CO ₂ This is achieved by circulating a liquid stream (eg, stream 72a in Figure 8). Furthermore, such heat is not necessary to limit to add in relation to the position of FIG. 8, but may since the separated liquid CO ₂ cycle (but preferably in the CO ₂ cycle is the liquid component in such dependent It is input to the cycle at any point directly before the heat exchanger at the upstream of the burner input. Of course, any similar method that utilizes waste generated in the power generation cycle can be included. Among the disclosures of this disclosure are, for example, the use of a supply stream at an appropriate temperature, or a hot exhaust gas from a conventional open-cycle gas turbine.

The amount of heat imparted by the side heater 470 can vary depending on the materials and equipment used and the final temperature at which the recovered working fluid 236 is required to enter the combustor 220. In some embodiments, the side heater 470 is effective to increase the temperature of the stream 72a by at least about 10 ° C, at least about 20 ° C, at least about 30 ° C, at least about 40 ° C, at least about 50 ° C, at least about 60 ° C, At least about 70 ° C, at least about 80 ° C, at least about 90 ° C, or at least about 100 ° C. In other embodiments, the side heater 470 is effective to increase the temperature of the stream 72a by at least about 10 ° C to about 200 ° C, at least about 50 ° C to about 175 ° C, or at least about 75 ° C to about 150 ° C. In a particular embodiment, the side heater 470 causes the increase in temperature of the stream 72a to fall within at least about 15 ° C of the temperature of the stream 73 exiting the heat exchanger 440, at least within about 12 ° C, at least about 10 ° C, At least about 7 ° C, or at least about 5 ° C.

By the additional heat source thereby, if the amount of CO ₂ in the stream is directed through the second heat exchanger 440, the stream 71 leaving the third heat exchanger 450 can be in the second heat exchanger 440 The heat convection 71 that is available is additionally heated in addition to the ability to heat. By the same time the flow diverter can be completely granted to the contents of the portion of circulating liquid stream 71b CO ₂ in the second heat exchanger 440 is available, can be obtained from the side heater 470 heat may also be awarded to the flow completely portion 72a of the contents of the liquid CO ₂ cycle. Thus, visually that if all the amount of 71 CO ₂ in the circulating liquid flow is directed to both the second heat exchanger 440, rather than being split and separately heated (as described above), when using the method of replacement shunt The temperature of the combined stream entering the first heat exchanger 430 may be greater than the temperature of the stream 73 exiting the second heat exchanger 440. In some embodiments, the increase in heat obtained by the splitting process is of sufficient importance to limit whether the recovered working fluid 236 has been sufficiently heated prior to entering the combustor.

As can be seen in Figure 8, stream 71b exiting the splitter 460 passes through the second heat exchanger 440 to form a stream 73 that is directed to the mixer 480 to discharge the stream 73 from the side heater 470. Stream 72b is combined. Subsequently, the combined stream 74 430, by which the temperature of the first heat exchanger to the turbine exhaust stream temperature entering the CO ₂ cycle of the first liquid when the heat exchanger 430 to substantially close. The proximity of the liquid stream at the hot end of the first heat exchanger can be applied to other embodiments of the invention that use less than three or more than three heat exchangers, and can be applied after discharge from the turbine The first heat exchanger through which the CO ₂ recycle liquid passes. The ability to achieve close proximity of the liquid to the temperature at the hot end of the first heat exchanger can be a key feature of the present invention to achieve the desired level of efficiency. In certain embodiments, the turbine discharge stream from the turbine enters the temperature of the first heat exchanger in the array (ie, after expansion into the turbine) and the CO ₂ recycle liquid exits the heat exchanger for recovery The difference between the temperatures entering the burner may be less than about 80 ° C, less than about 75 ° C, less than about 70 ° C, less than about 65 ° C, less than about 60 ° C, less than about 55 ° C, less than about 50. ° C, less than about 45 ° C, less than about 40 ° C, less than about 35 ° C, less than about 30 ° C, less than about 25 ° C, less than about 20 ° C, or less than about 15 ° C.

As can be seen from the foregoing, the efficiency of the system and method of the present invention can be achieved by precisely controlling the turbine discharge stream 50 and the recovered working fluid 236 between the heat exchangers 420 (or in the series illustrated in Figure 8). The first heat exchanger 430) significantly benefits from the difference at the hot end. In a preferred embodiment, this temperature difference is less than 50 °C. While not wishing to be bound by theory, it has been found, according to the present invention, the heat available for heating the recovered liquid CO ₂ cycle (e.g., from the one or more turbine exhaust heat exchanger The heat recovered by the flow may not be sufficient to adequately heat the entire stream of recovered CO ₂ recycle liquid. The present invention has been known to overcome this by splitting convection 71 so that stream 71b enters heat exchanger 440 and stream 72a enters external heat source 470, wherein external heat source 470 provides an additional, external source of heat The temperature of stream 72b exiting the external heat source 470 is raised to a temperature substantially close to stream 73 exiting heat exchanger 440, as previously described. Streams 72b and 73 then combine to form stream 74, and the flow rate of stream 71b (and stream 72a) can be controlled by the temperature differential at the cold end of heat exchanger 440. The amount of external heat required to overcome the aforementioned thermal deficiencies can be minimized by minimizing the temperature of the stream 56 as low as possible and minimizing the difference in cold junction temperature of the heat exchanger 440. The water vapor present in stream 56 from the combustion products will reach its dew point at a temperature that depends on the composition of stream 56 and its pressure. Below this temperature, water condensation greatly increases the effective mCp of stream 56 to cooled turbine exhaust stream 60, as well as providing all of the heat required to heat total recycle stream 70 to stream 71. The temperature of stream 56 exiting heat exchanger 440 is preferably within about 5 °C of the dew point of stream 56. Preferably, the temperature difference between streams 56 and 71 at the cold end of heat exchanger 440 can be at least about 3 ° C, at least about 6 ° C, at least about 9 ° C, at least about 12 ° C, at least about 15 ° C, at least about 18 ° C, or at least about 20 ° C.

Returning to Figure 5, the recovered working fluid 236 may be preheated prior to being recovered into the combustor 220, such as in relation to receiving the at least one heat exchange of the hot turbine exhaust stream 50 after passing through the diffusion turbine 320. The person described by the device 420. In order to maximize the efficiency of the cycle, it is useful to have the heat exchanger 420 at the highest possible inlet temperature consistent with the available materials constituting the hot gas inlet path and the highly stressed turbine blades, and at the system operating pressure. The diffusion turbine 320 is operated at the maximum temperature allowed in the process. The hot inlet path of the turbine inlet stream and the first row of turbine blades can be cooled by any useful means. In some embodiments, it may be used by the high pressure portion of the recovered liquid CO ₂ cycle and maximize efficiency. In particular, the relatively low temperature liquid CO ₂ cycle (e.g., falling in the range of from about 50 deg.] C to about 200 ℃) available from the cold end of the cycle before the heat exchanger 420, or when a plurality of heat exchange in series are used The unit is retracted from an intermediate point of the heat exchanger 420 (e.g., from stream 71, 72a, 71b, 72b, 73, or 74 in Fig. 8). The blade cooling liquid can be discharged from a hole in the turbine blade and can be directly input into the turbine flow.

The combustion gas produced by the operation of a high efficiency combustor (e.g., the transpiration cooling combustor described herein) is an oxidizing gas having an excess oxygen concentration (e.g., in the range of from about 0.1% to about 5% moles). Alternatively, the combustion gas that the burner can produce is a reducing gas having a certain concentration of one or more of H ₂ , CO, CH ₄ , H ₂ S, and NH ₃ . This is particularly advantageous in that, according to the invention, it becomes possible to use an electric turbine having only one turbo unit, or one series turbine unit (for example, 2, 3 or more units). Beneficially, in a particular embodiment using a series unit, all of the units can operate at the same inlet temperature, and this enables the power output of a given first turbine feed pressure to overall pressure ratio to be maximized.

An example of a turbine unit 320 that utilizes two turbines 330, 340 operating in series in a reduced mode is shown in FIG. As seen herein, the combustion product stream 40 is directed to the first turbine 330. In such an embodiment, the combustion product stream 40 is designed (eg, by controlling the fuel used, the amount of O ₂ used, and the operating conditions of the combustor) to have one or more combustion components therein. The reducing gas, as previously described, expands across the first turbine 330 to produce electrical power (e.g., associated with a generator, not shown in this illustration), and forms a first exhaust stream 42. Before being introduced into the second turbine 340, a predetermined amount of O ₂ may be added to the first turbine exhaust stream 42 to combust the combustible components present in the first turbine exhaust stream 42 , leaving an excess At the same time as oxygen, the inlet temperature of the second turbine unit 340 is also raised to substantially the same value as the first turbine unit 330. For example, the temperature of the exhaust stream 42 from the first turbine unit 330 can fall in the range of about 500 °C to about 1,000 °C. When in the reduction mode, the addition of O ₂ to the exhaust stream 42 at this temperature can cause the gas in the stream to be heated to a temperature range of from about 700 ° C to about 1,600 ° C by combustion of excess fuel gas, which is substantially The temperature range of the combustion product stream 40 prior to exiting the combustion chamber 220 and entering the first turbine unit 330 is the same. In other words, the operating temperatures at the inlet of each of the two turbines are substantially the same. In a particular embodiment, the difference in operating temperatures at the inlets of the turbines is no more than about 10%, no more than about 9%, no more than about 8%, no more than about 7%, no more than about 6%, no More than about 5%, no more than about 4%, no more than about 3%, no more than about 2%, or no more than about 1%. A similar reheating step for the additional turbine unit can also be carried out to the extent remaining fuel. If desired, combustion can be enhanced by the use of a suitable catalyst in the oxygen feed combustion space.

In some embodiments, power cycling as described herein can be used to trim existing power plants, for example, by introducing high temperature, high pressure heating liquids (such as the turbine discharge streams described herein) into a conventional Langken cycle. (Rankine cycle) The steam superheat cycle of a power station. This may be a coal fired, or nuclear power plant with a boiling water reactor (BWR), or a pressurized water reactor (PWR) thermal cycle. This is to effectively increase the efficiency and power output of the steam Langken power station by superheating the steam to a temperature much higher than the temperature of the superheated steam generated in the prior system. If a pulverized coal fired boiler is used, the steam conditions in a nuclear power plant are typically as high as about 320 ° C while the steam temperature is currently up to about 600 ° C. With overheating that may be accompanied by heat exchange in the systems and methods of the present invention, the steam temperature may rise above 700 °C. This causes the thermal energy to be directly converted into additional shaft power, which is the additional fuel that is converted to a steam-based power station without increasing the amount of condensed steam due to the extra fuel that is superheated by the combustion. This can be achieved by providing a slave heat exchange unit. For example, as otherwise described herein, the turbine discharge stream described in relation to the method and system of the present invention can be directed through the slave heat exchanger prior to passing through the primary heat exchange unit. The heat obtained in the slave heat exchange unit can be used to superheat steam from the boiler. As previously mentioned, the superheated steam can be directed to one or more turbines for power generation. After passing through the slave heat exchange unit, the turbine discharge stream can then be directed to the primary heat exchange unit, as otherwise described herein. Such systems and methods are described in Example 2 and illustrated in Figure 12. In addition, there may be a taken from the low pressure steam inlet of the steam turbine final, and use it to heat the circulating liquid CO ₂ recovery section has, as aforementioned. In a particular embodiment, the condensate from the steam power plant can be heated to an intermediate temperature prior to de-aeration using the CO ₂ circulating liquid stream exiting the cold end of the heat exchange unit ( For example, in some embodiments, at a temperature of about 80 °C). This heating normally uses the bleed steam taken from the inlet of the final LP steam turbine stage, so that the net effect on the steam power plant efficiency of the current side steam heating can be compensated by preheating the condensation. It saves the steam for distribution.

The above general power generation method (i.e., power generation cycle) can be performed in accordance with the present invention using an appropriate power generation system as described herein. In general, a power generation system in accordance with the present invention can include any of the components described herein in relation to the power generation method. For example, a power generation system may include O ₂ in the presence of liquid CO ₂ cycle and a carbonaceous fuel combustion burner. In particular, the burner can be an evapotranial cooling burner as described herein, however, other burners that can operate under otherwise described conditions can also be used. In particular, the characteristics of the burner may be related to the combustion conditions in which it operates and the particular parts of the burner itself. In some embodiments, the system may comprise for carbonaceous fuel (and selective, the class of the medium) to provide the O ₂ and CO ₂ cycle one or more fluid injectors. The system can include parts for removing liquid slag. The burner can generate a fuel gas at a temperature at which solid ash particles can be effectively filtered out of the gas, and the gas can be mixed with quenched CO ₂ and burned in a second burner . The combustor may include at least one combustion stage of the combustion of carbonaceous fuel in the presence of the circulating liquid CO _2, including providing said pressure herein is the temperature and CO ₂ in a combustion product stream.

The system may further include a power generating turbine in fluid communication with the combustor, the turbine may have an inlet for receiving the combustion product stream and the release of a turbine comprising an outlet stream of CO ₂ emissions. Electricity can be generated as the liquid stream expands. The turbine is designed to maintain the liquid flow at a desired pressure ratio ( _Ip / _Op ) as described herein.

Still further, the system may comprise at least one heat exchanger in fluid communication with the turbine, the turbine exhaust stream to receive the stream and cooling, thus forming a flow of liquid CO ₂ cycle cooling. Similarly, the at least one heat exchanger can be used to heat the CO ₂ circulating liquid input to the combustor, and in particular, the (equal) heat exchanger is characterized by being allowed to be subjected to the special conditions so described. Construction material for operation.

Isolating the flow of liquid _circulating system may also include the CO leaving the heat exchanger is used for CO ₂ and one or more other additional ingredients for recovery or disposal. In particular, the system may include means for water (as described herein or other impurities) separated from the CO ₂ cycle for the liquid flow.

The system can further include one or more devices (eg, compressors) in fluid communication with the at least one heat exchanger (and/or in fluid communication with one or more separation devices) to compress and purify CO ₂ recycle liquid. Further, the system may include the liquid CO ₂ cycle is separated into two streams apparatus, wherein the first stream through a heat exchanger and enters the combustor, and a second stream delivered into the pressurized tube Road (or other device used to sequester and/or dispose of the CO ₂ ).

In some embodiments, even further parts may be included in the system. For example, the system can include an O ₂ separation unit to deliver O ₂ into the combustor (or into an injector, or a similar device that mixes O ₂ with one or more other materials). In some embodiments, the air separation unit can generate heat. Thus, the system is concerned, is usefully further comprise one or more heat transfer parts to transfer the heat from the air separation unit to the combustor upstream of the circulating liquid CO ₂ stream. In further embodiments, the system in accordance with the present invention may include any and all of the components described herein in connection with the power generation cycle and the power generation method.

In other embodiments, the present invention encompasses systems and methods that are particularly useful in power generation for use in fuels that leave incombustible residues upon combustion. In certain embodiments, such a non-combustible material can be passed through a suitable device, such as a contaminant as illustrated in FIG. The device is removed and removed from the combustion product stream. However, in other embodiments, it is useful to manage the non-combustible material by using a multi-burner system and method, such as illustrated in FIG.

As shown in Figure 10, the coal fuel 254 can be passed through a grinding apparatus 900 to provide a powdered coal. In other embodiments, the coal fuel 254 can be provided under a particular condition. In a particular embodiment, the coal may have an average particle size of from about 10 [mu]m to about 500 [mu]m, from about 25 [mu]m to about 400 [mu]m, or from about 50 [mu]m to about 200 [mu]m. In other embodiments, the coal may be described as being 50%, 60%, 70% greater than coal particles having an average size of less than about 500, 450, 400, 350, 300, 250, 200, 150, or 100 microns. 80%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%, 99%, or 99.5%. The pulverized coal may be mixed with a liquefied material to provide coal in the form of a slurry. In figure 10, the pulverized coal in the mixer 910 is extracted (side draw) and ₂ side from the recovered liquid is a CO ₂ cycle CO 68 combined. In figure 10, the 68 CO ₂ is withdrawn from the extraction side has undergone a treatment provides in supercritical state in a high density liquid CO ₂ cycle is the stream 67. In a particular embodiment, the coal slurry is used to form CO ₂ may have a density of approximately 450kg / m ³ to about 1,100kg / m ³ of. More particularly, the CO ₂ side draw 68 can be mated with the particulate coal to form, for example, between about 10 weight percent to about 75 weight percent, or about 25 weight percent of the particulate coal. Up to about 55 weight percent of a slurry 225. Further, the temperature of the CO ₂ from the side draw 68 used to form the slurry can be less than about 0 ° C, less than about -10 ° C, less than about -20 ° C, or less than about - 30 ° C. In still other embodiments, the temperature at which the CO ₂ from the side draw 68 is used to form the slurry can be from about 0 ° C to about -60 ° C, from about -10 ° C to about -50 ° C, or From about -18 ° C to about -40 ° C.

The pulverized coal/CO ₂ slurry 255 is transferred from the mixer 910 to a portion of the oxidation burner 930 via the pump 920. As described herein, an O ₂ stream can be formed using an air separation unit 30 that separates air 241 into purified O ₂ . The O ₂ stream is separated into an O ₂ stream 243 directed to the partial oxidation burner 930 and an O ₂ stream 242 directed to the burner 220. In the example of the embodiment in FIG. 10, a CO ₂ stream 86 from the CO ₂ cycle is recovered a liquid stream 85 is withdrawn, for cooling the partial oxidation combustor 930. In other embodiments, the CO ₂ used to cool the partial oxidation burner 930 may be taken from the recovered working liquid 236 to replace the stream 86, or the CO ₂ may be taken from the stream 86 and the recovered working liquid 236. Both. Preferably, the amount of CO ₂ is withdrawn sufficient to cool the temperature of the stream 256, so that the ash present in solid form can be safely removed, as said further herein. The ratio of the CO ₂ coal and O ₂ to the partial oxidation burner 930 is such that the coal is only partially oxidized to produce CO ₂ and H ₂ , CO, CH ₄ , H ₂ S, and NH ₃ One or more portions of the oxidative combustion product stream 256. The CO ₂ , coal, and O _{2 are} also introduced into the partial oxidation burner 930 at a necessary ratio such that the temperature of the partially oxidized combustion product stream 256 is sufficiently low that all of the ash present in the stream 256 is A form of solid particles that are simply removed by one or more cyclone separators, and/or filters. The embodiment of Fig. 10 illustrates the removal of ash via filter 940. In a particular embodiment, the partially oxidized combustion stream 256 can have a temperature of less than about 1,100 ° C, less than about 1,000 ° C, less than about 900 ° C, less than about 800 ° C, or less than about 700 ° C. In further embodiments, the temperature of the partially oxidized combustion stream 256 can range from about 300 °C to about 1,000 °C, from about 400 °C to about 950 °C, or from about 500 °C to about 900 °C.

The filtered, partially oxidized combustion stream 257 can be directly fed to the second combustor 220, which can be an evapotranspiration combustor, as otherwise described herein. This input stream 242 with the O ₂ and the recovered ₂ CO 236 supplied with the working fluid. The combustion at this point can be carried out in a manner similar to that described herein. In the partial oxidation combustion stream 256 such combustible material may be burned in the combustor 220 and the O ₂ in the presence of CO _2, to provide the combustion flow 40. This stream is expanded across a turbine 320 to generate electricity (eg, via generator 1209). The turbine discharge stream 50 passes through a heat exchanger unit 420 (which may be a heat exchanger in series, for example, as described in relation to Figure 8). The cooled turbine exhaust stream 60 passes through the chilled water heat exchanger 530 to form a mixed phase cooled turbine exhaust stream 61 that is passed through for removal of subordinate components in the stream 62 (eg, H ₂ O, SO ₂ , Separator 540 of SO ₄ , NO ₂ , NO ₃ , and Hg). The separator 540 can be substantially similar to the tubular string 1330 as described below in relation to FIG. Preferably, the separator 540 includes a reactor that provides a contactor having a sufficient residence time to allow the impurities to react with water to form a readily removable material (eg, an acid). 65 the purified working fluid through a first compressor 630 to form stream 66 which is cooled by the cooling water heat exchanger 640, to provide the supercritical CO ₂ cycle high density liquid stream 67. As previously described, a portion of stream 67 can be withdrawn as stream 68 for use as a fluidizing medium in the mixer 910 to form the coal slurry stream 255. Furthermore, the supercritical CO ₂ cycle high density liquid stream 67 further pressurized compressor 650, to form the pressurized, high-critical, high-density liquid stream 70 CO ₂ cycle. A portion of the CO ₂ in stream 70 will be withdrawn at point 720, as described herein with respect to Figures 5 and 11, to provide stream 80 to a CO ₂ line, or other storage device. The remaining portion of CO ₂ continue to be pressurized, supercritical CO ₂ cycle high density liquid stream 85, one portion may be withdrawn as stream 86 for cooling the partial oxidation combustor 930, as described above. Additionally, the stream 85 is returned to the heat exchanger 420 (or series of heat exchangers, as described in relation to Figure 8) to heat the stream and ultimately form the recovered input to the combustor 220. Working liquid 236. As before, an external heat source can be used in conjunction with the heat exchanger unit 420 to provide the necessary efficiency. Similarly, other systems and method parameters, as described herein, may be applied to the system and method according to FIG. 10, such as flow temperature and pressure, and the turbine unit 320, the heat exchanger unit 420, Separation unit 520, as well as other operating conditions of the compressor unit 630.

experiment

In the following, the present invention will be further described with respect to particular examples, which are provided to illustrate certain embodiments of the invention and are not to be construed as limiting.

Example 1

Methane combustion power generation system and method using recycled CO ₂ circulating liquid

A particular example of a system and method in accordance with the present invention is illustrated in Figure 11, and the following description sets forth a system relating to a particular cycle under special conditions simulated by a computer.

In this method, a methane (CH ₄ ) fuel stream 254 having a temperature of 134 ° C and a pressure of 30.5 MPa and a temperature of 860 ° C and a pressure of 30.3 MPa (and thus in a supercritical fluid state) prior to introduction into an evapotranial cooling burner 220 A recovered CO ₂ working liquid 236 is combined in a mixer 252. An air separation unit 30 is used to provide concentrated O ₂ 242 at a temperature of 105 ° C and a pressure of 30.5 MPa. The air separation unit also generates heat (Q) which is extracted for processing. The O ₂ 242 is combined with the methane fuel stream 254 and the recovered CO ₂ working liquid 236 in the combustor 220 and combusted there to provide a combustion product stream 40 having a temperature of 1189 ° C and a pressure of 30 MPa. The CO ₂ , O ₂ and methane are provided at a molar ratio of about 35:2:1 (i.e., lbmol/hr, pound moles per hour). The energy input used for combustion in this example was 344,935 Btu/hr (363,932 kJ/hr).

The combustion product stream 40 is expanded across the turbine 320 to produce the turbine discharge stream 50 at a temperature of 885 ° C and a pressure of 5 MPa (the CO ₂ in the turbine discharge stream 50 is in a gaseous state), the combustion product stream 40 expanding across the The rate at which the turbine 320 produces electricity is 83.5 kilowatts per hour (kW/hr).

The vortex discharge stream 50 is then passed through three heat exchangers in series to continuously cool the stream, thereby removing the subordinate components. The temperature of the first heat exchanger 430 can be generated by 237 ° C And a flow 52 of pressure 5 MPa through which the stream 52 passes to produce a stream 56 having a temperature of 123 ° C and a pressure of 5 MPa through which the stream 56 passes to produce a temperature of 80 ° C and a pressure of 5 MPa. The turbine exhaust stream 60 has been cooled.

After the turbine is exhausted through the series of heat exchangers, the cooled turbine exhaust stream 60 can be further cooled by passing through a cooling water heat exchanger 530. Water (C) at a temperature of 24 ° C is circulated through the cooling water heat exchanger 530 to cool the cooled turbine discharge stream 60 to a temperature of 27 ° C, and thus to condense any water present in the CO ₂ circulating liquid stream . Next, the cooled turbine exhaust stream 61 of the mixed phase passes through a water separation unit 540 such that the liquid water is removed and discharged into stream 62a. Discharged from the water separation unit 540 is the "dried" purified working liquid 65 at a temperature of 34 ° C and a pressure of 3 MPa.

The dried purified working liquid 65 (which is still in a gaseous state) is then passed through a first compression unit 630 in a two-step pressurization schedule. The CO ₂ recycle liquid stream was pressurized to 8 MPa, which likewise raised the temperature of the CO ₂ recycle liquid stream to 78 °C. This requires 5.22 kW/hr of power input. Next, the supercritical fluid CO ₂ cycle via a second liquid flow 66 cooling water heat exchanger 640, in this case, the supercritical fluid CO ₂ cycle liquid stream 66 by cooling water temperature of 24 deg.] C to produce a temperature of 27 deg.] C A cooled supercritical liquid CO ₂ recycle liquid stream 67 having a pressure of 8 MPa and a density of 762 kg/m ³ . This stream is then compressed by a second unit 650, a temperature of 69 deg.] C to form a pressure of 30.5MPa and the pressurized liquid stream 70 CO ₂ cycle. This requires 8.23 kW/hr of power input. This flow splitter 720 via a line, whereby, 1lbmol the CO ₂ stream 80 is guided through a pressurized conduit, and the CO ₂ 34.1lbmol as stream 85 is directed back to the series of three heat exchange The device reheats the CO ₂ circulating liquid stream before entering the combustor 220.

The CO ₂ cycle pressurized liquid stream 85 is formed through the third heat exchanger temperature 450 114 ℃ and 30.5MPa pressure stream 71, the flow splitter 71 through 460, so that the CO ₂ is guided 27.3lbmol be reaching the the second heat exchanger 71b 440 flow, and 6.8lbmol the CO ₂ stream is directed through a side of the heater 72a 470 in. Each of stream 71b and stream 72a has a temperature of 114 ° C and a pressure of 30.5 MPa. The side heater 470 using heat (Q) from the air separation unit 30 to provide additional heat to the flow of liquid CO ₂ cycle. Stream 71b can produce a stream 73 having a temperature of 224 ° C and a pressure of 30.5 MPa through the second heat exchanger 440. Stream 72a forms stream 72b through the side heater 470, which is also at a temperature of 224 ° C and a pressure of 30.4 MPa. Streams 73 and 72b combine in mixer 480 to form a stream 74 having a temperature of 224 ° C and a pressure of 30.3 MPa, and then stream 74 passes through the first heat exchanger 430 to provide a temperature 860 at the inlet back to the combustor 220. The recovered CO ₂ working liquid 236 at ° C and a pressure of 30.0 MPa.

The calculation of the efficiency of the aforementioned simulation cycle is based on a comparison between the generated energy and the LHV of the methane fuel and the additional energy input to the system, as described above. Under the simulated conditions, an efficiency of approximately 53.9% can be achieved, which is particularly surprising in that it achieves such excellent efficiency while avoiding any CO ₂ (especially due to combustion of the carbon-containing fuel). Any CO ₂ ) atmospheric emissions.

Example 2

Power generation system and method for pulverized coal power station trimming using recovered CO ₂ circulating liquid

Another specific example of a system and method in accordance with the present invention is set forth in Figure 12, and the following description sets forth a system relating to a particular cycle under special conditions simulated by a computer.

In this simulation, what is illustrated is the ability to trim the systems and methods of conventional pulverized coal power plants.

An O ₂ stream 1056 having a pressure of 30.5 MPa is introduced into an evapotranspiration combustion together with a carbonaceous fuel 1055 having a pressure of 30.5 MPa (for example, a coal-derived gas produced by partial oxidation) and a CO ₂ circulating liquid stream 1053 at a pressure of 30.5 MPa. In the device 220. The O ₂ can be received from an air separator, or a similar device that can generate heat (Q) that can be pumped away for use in the system, for example, to create an expanded stream, or to add heat to a cooled CO. ₂ Circulating liquid flow. Combustion of the fuel in the combustor 220 produces a combustion product stream 1054 at a temperature of 1,150 ° C and a pressure of 30.0 MPa which is expanded across a turbine 320 (which may be generally referred to as a primary power generating turbine) to be driven by A generator 1029 generates electricity. The diffusion turbine discharge stream 1001 at a temperature of 775 ° C and a pressure of about 3.0 MPa is introduced into the hot end of a heat exchanger 110 where the heat from the turbine discharge stream 1001 is used to superheat the conventional pulverized coal power station 1800. The high pressure flow 1031 produced and the intermediate pressure flow 1032. Boiler fed water 1810 and coal 1810 are input to the power station 1800 to generate flow streams 1031 and 1032 by burning the coal 1810. The transfer of heat in the heat exchanger causes the equal stream flows 1031 and 1032 to be superheated from a temperature of about 550 ° C to a temperature of about 750 ° C to form flow streams 1033 and 1034 which will return to the power station (described below). . This method achieves very high steam temperatures without the need for conventional power stations to use expensive superalloys in large steam boilers that burn coal near atmospheric pressure. The equal stream flows 1033 and 1034 expand into a three-stage turbine 1200 (which is generally referred to as a slave power generating turbine) to drive a generator 1210. Stream 1035 exiting turbine 1200 is condensed in condenser 1220. The treated condensate 1036 is pumped to high pressure using a feed water pump 1230 and then vaporized and superheated in the coal fired boiler 1800 for discharge into the heat exchanger 1100, as previously described. This system is used to increase the power output and efficiency of an existing coal-fired power station.

The heat exchanger 100 is a Heatric type diffusion bonded plate heat exchanger having a chemical polishing channel typically constructed of a high temperature, high nickel content alloy (e.g., alloy 617), wherein the alloy is capable of control This heat exchanger is a high-efficiency heat transfer unit that has a high heat transfer coefficient for all liquids, allowing for important overheating under oxidation conditions and high pressure and high temperature possible for operation.

The remainder of the system and method illustrated in Figure 12, its structure and operation Both are similar to the systems and methods described herein. In particular, the diffusion turbine discharge stream 1001 is cooled in the heat exchanger 1100 and exits the cold end of the heat exchanger 1100 as a discharge stream 1037 having a temperature of 575 °C. This stream 1037 is then passed through a second heat exchanger 1300 where it is cooled to a temperature of 90 ° C and a pressure of 2.9 MPa to form stream 1038. This stream is further cooled by means of a portion of the condensate 1057 from the power station condenser 1230 to a temperature of 40 ° C in a third heat exchanger 1310 to form a stream 1039, which is further relied upon The cooling water in the cooling water heat exchanger 1320 was cooled to a temperature of 27 ° C to form a stream 1040 having a pressure of 2.87 MPa. The heat exchanger 1300 may be a Heatric 310 stainless steel diffusion bonded unit.

The cooled stream 1040 at 30 ° C is fed into the base of a packed column 1330 which is provided with a circulating pump 1340 which provides a countercurrent weak acid recycle stream for supplying the incoming gas and the washing weak acid Countercurrent contact between. SO ₂ , SO ₃ , NO and NO ₂ are converted to HNO ₃ and H ₂ SO ₄ and are absorbed by the liquid together with the condensed water and any other water soluble components, and the net liquid product from the column 1330 is removed in line 1042. In addition, as well as the pressure being reduced to atmospheric pressure, then entering a separator 1360. The dissolved CO ₂ is flashed off in line 1043, compressed to a pressure of 2.85 MPa using a pump 1350, and flows into stream 1044 to be added to stream 1045 exiting the top of column 1330. These will form the combined stream entering the combustor recycling the liquid CO ₂ cycle. The H ₂ SO ₄ and HNO ₃ diluted in water exits from the base of the separator 1360 to a stream 1046 depending on the fuel composition and temperature in the contactor column 1330. It is noted that preferably, nitric acid is present in the acid stream 1046 because nitric acid will react with any mercury present and completely remove the impurities.

The compressor 1380 enter the CO ₂ cycle recovered liquid stream is first dried to a dew point of about -60 ℃ in a desiccant drier, and then subjected to purification to remove O ₂ and low temperature separation scheme, N ₂ And Ar, for example, as shown in European Patent Application No. EP 1 952 874 A1, which is incorporated herein by reference.

The compressed, recovered CO ₂ recycle liquid stream 1047 exiting the compressor 1380 at a pressure of 8.5 MPa is cooled by 27 ° C cooling water in a cooling water heat exchanger 1370 to form a dense, supercritical CO ₂ circulating liquid 1048, which is pumped in a pump 1390 to a pressure of 30.5MPa and a temperature of 74 ℃, to form a high pressure, CO ₂ cycle is the liquid recovery flow 1050. A portion of the CO ₂ is removed from the stream 1050 as a CO ₂ product stream 1049 that will be sequestered or otherwise disposed of without venting to the atmosphere. In this embodiment, the pressure of the product stream ₂ CO 1049 is lowered to the desired line pressure is about 20MPa, and a CO.'S ₂ through the inlet conduit.

The high pressure, the liquid CO ₂ cycle recovered stream (now stream 1051) into the remaining portion of the cold end of exchanger 1300. This stream, which is a dense supercritical liquid at 74 ° C, must receive a significant amount of low grade heat to convert it to a liquid having a temperature of 237 ° and a much lower specific heat. In this embodiment, such low heat is an LP steam stream 1052 with a pressure of 0.65 MPa from a steam stream entering a low pressure steam turbine of a conventional power plant, and a low temperature oxygen derived from the supply of the O ₂ stream 1056. The compressed heat of the air compressor in the factory is provided together. The low pressure stream exits the heat exchanger 1300 to become stream 1301. Alternatively, all of the heat can be provided by using some of the available vapor streams from the coal-fired power station at pressures up to 3.8 MPa. This energy can also provide the heat (Q) formed from the air separation unit, as previously described. The recovery section of the CO ₂ stream for heating the side stream provides most of the heat exchanger at the cold end of the 1300's need, and allows a small difference in temperature at the warm end of the heat exchanger 1300 is only about 25 deg.] C, It increases overall efficiency.

The high pressure, high temperature, CO ₂ cycle recovered liquid stream 1053 leaving the heat exchanger 550 the temperature of 1300 deg.] C, and into the combustor 220, which is derived from combustion is used to cool a natural gas stream 1055 and 97% mole oxygen stream The combustion gas of 1056 (in this embodiment) is to produce a combustion product stream 1054, as described above. In this embodiment, by using the first row of turbine blades and a turbine of a thermal path from the pump discharge stream 1050, a 74 CO ₂ stream temperature of 1058 deg.] C cooled.

If the above system is operated by a separate power plant to utilize the simulated pure CH ₄ gas fuel, the CO ₂ stream 1053 which has been recovered at a temperature of about 750 deg.] C enters the combustor, and the turbine discharge temperature of about 775 to 1001 deg.] C into the The heat exchanger 1300.

The efficiency of the single power generation system in this embodiment is 53.9% (LHV). This composition includes the low temperature O ₂ plant as well as the natural gas feed and the power consumption of the O ₂ compressor. If the fuel is modeled as coal having a calorific value of 27.92 Mj/kg (eg, partially oxidized using ash removed in the first combustor and filter unit, followed by the fuel gas and CO ₂ in the second combustor) The combustion of the mixture) will be 54% (LHV). In both examples, the carbon derived from the fuel in nearly 100% CO ₂ may be generated as a line pressure 20MPa.

The system and method for using coal fuel as described above and illustrated in Fig. 12 is characterized in that it can be applied to a power station having the following special parameters. According to the present invention, the effect of converting a coal-fired power plant is calculated as follows: steam condition HP steam: 16.6MPa, 565°C, flow: 473 14kg/sec

LP steam: 4.02MPa, 565°C, flow: 371.62kg/sec

Net power output: 493.7.Mw

Coal for existing power stations: 1256.1Mw

Net efficiency: 39.31%

CO ₂ capture %: 0

Existing power plant incorporating the system and method disclosed in the present invention and upgraded converted plant: CO ₂ power system net power output: 371.7Mw

Existing power station net power: 639.1 MW

Total net power: 1010.8Mw

Coal for CO ₂ power system: 1053.6Mw

Coal for existing power stations: 1256.1Mw

Overall net efficiency: 43.76%

CO ₂ capture %: 45.6% * * Note that in this example, no CO ₂ was captured from the existing power station.

Numerous modifications and other embodiments of the invention will be apparent to those of ordinary skill in the art. Therefore, it is understood that the invention is not limited to the specific embodiments disclosed, and the modifications and other embodiments are intended to be included within the scope of the appended claims. Although specific terms are employed herein, they are used in a generic and

220‧‧‧ burner installation

222‧‧‧ combustion chamber

222A‧‧‧ entrance section

222B‧‧‧Exports

223‧‧‧End wall

2338‧‧‧ Pressure suppression components

236‧‧‧Recovered working fluid

236a‧‧‧ flow

254‧‧‧carbon fuel

250A‧‧‧Slurry

254A‧‧ ‧powder

255‧‧‧Liquidized substances

250‧‧‧Mixed settings

242‧‧‧Oxygen

Claims (23)

A method of generating electricity includes the steps of: flowing a stream containing CO ₂ at a pressure of about 12 MPa or greater and at a temperature of about 750 ° C or higher, expanding across a first turbine and a final a series of turbines to output a final turbine discharge stream comprising CO ₂ from the final turbine; passing the final turbine discharge stream through a complex heat exchanger to recover heat from the last turbine discharge stream as a heat source and form a cooled turbine exhaust stream; at least a portion of the CO from the cooled turbine exhaust stream ₂ is separated to form a CO ₂ recycle stream; the recycle stream is compressed CO ₂ to a pressure of at least about 12MPa to form a compressed recycle CO ₂ stream; with the heat from the final turbine exhaust stream recovered heat recycling at least part of the compressed CO ₂ stream, and with this differs from the final turbine exhaust stream from the recovered a thermal heat source, heat recycling at least part of the compressed CO ₂ stream to form a bound recycle the heated compressed CO ₂ stream; recycle CO ₂ stream feeding the heated compressed bound A combustor in which a carbonaceous fuel in an oxidant and the heated compressed bound is burned in the presence of CO ₂ stream is recirculated, to further bound the heated compressed recycle CO ₂ stream is heated, formed The stream comprising CO ₂ ; and the stream comprising CO ₂ is sent to the first turbine in the series. The method as defined in claim 1 range item, further comprising between said first turbine and said turbine Finally, add further heat to the stream of CO ₂ contained. The method as defined in claim item 2 range, wherein the further heat is further provided in a burner, which is a carbonaceous fuel and an oxidizer and the combustion flow containing CO _2. The method of claim 1, further comprising, after the step of compressing and before the step of delivering the combined heated recirculated CO ₂ stream to a combustor, from the compressed The recycle CO ₂ stream recovers the side stream. The method as defined in claim 4 scope item, wherein the portion is compressed from the heat of the turbine exhaust stream is finally recovered to heat the recycle of CO ₂ stream, which differs from the side stream is from the a portion of the heat source until the heat of the turbine exhaust stream is finally recycled to the heating, and wherein the portion bound to the heated so that the CO ₂ stream fed to the recycle step a burner is re-compressed Combine. The method of claim 5, wherein the side stream is heated by passing through a side heater. The method of claim 6, wherein the side heater utilizes heat recovered during an adiabatic phase of a plurality of air compressors in a cryogenic air separation unit. The method of claim 6, wherein the side heater comprises a cryogenic air separation unit comprising two compressors, the two compressors being operated adiabatically, and wherein the method comprises removing a plurality of The heat of compression in the plurality of aftercoolers is directed to a circulating heat transfer fluid that transports the heat of compression. The method as defined in claim 1, item range, which comprises heating the compressed recycle CO ₂ stream from the heat of the turbine exhaust stream is finally recovered at least a portion, and comprising differs from the turbine is discharged from the last a heat source of the heat is recovered stream heating the compressed _second flow at least part of the recirculated CO, sufficient to allow the burner to enter the bound heated temperature of the compressed CO ₂ stream recycle ratio The temperature of the last turbine discharge stream is less than about 50 °C. The method of claim 1, wherein the source different from the heat recovered from the last turbine discharge stream is an air separation unit. The method of claim 1, wherein the source different from the heat recovered from the last turbine discharge stream is a supply stream. The method of claim 1, wherein the source different from the heat recovered from the last turbine discharge stream is a hot exhaust gas from a conventional open-cycle gas turbine. The method of claim 1, wherein the multiple heat exchanger comprises a series of at least two heat exchangers. A method of generating power, comprising the steps of: having a flow of CO ₂ containing expansion across the turbine comprises a first turbine and a last one of a series of at least about 12MPa pressure and a temperature of at least about 750 deg.] C to Outputting a final turbine exhaust stream comprising CO ₂ from the last turbine; passing the final turbine exhaust stream through a complex heat exchanger to recover heat from the last turbine exhaust stream as a heat source and forming a cooled turbine exhaust stream ; at least a portion of the CO from the cooled turbine exhaust stream is separated to form a recycle stream _2, CO _2; the compressed recycle stream to a CO ₂ pressure of at least about 12MPa to form a compressed recycle CO ₂ stream; using a first heat source for heating the compressed recycling at least part of the CO ₂ stream, the first heat source from the heat of the turbine exhaust stream is finally recovered, the first with the heat source is heated by the compressed recycle CO ₂ stream multiplexing is accomplished by the heat exchanger and the second heat source from a heat recycling at least part of the compressed CO ₂ stream, which is different from the source from the second After the turbine exhaust stream is recovered from a source of the heat such that the first to the second heat source and a heat source for heating the heated compressed recycle CO ₂ stream is output from the multiplexing exchanger; has the heated compressing a recycle CO ₂ stream fed to the combustor from the complex heat exchanger in which a fuel is burned to further recycle the heated compressed CO ₂ stream is heated, forming the stream of CO ₂ comprising; and the the first stream containing CO ₂ is sent to a turbine in the series is. A power generation system comprising: a combustor configured to receive a fuel, O ₂ and a CO ₂ stream and having at least one combustion state, the combustion state combusting in the presence of the CO ₂ stream and providing a combustion product stream, the combustion product stream comprising at least a pressure of about ₂ 8MPa and at a temperature of at least about 800 deg.] C to CO; a first and a second power generating turbine power generating turbine, in series downstream from the burner, and arranged with An output of a turbine discharge stream comprising CO ₂ ; a heat exchanger configured to receive the turbine discharge stream from the second power generation turbine and to transfer heat from the turbine discharge stream to the CO ₂ stream; a plurality of separation devices downstream of the heat exchanger and configured to remove one or more components from the turbine discharge stream and output the CO ₂ stream; a compressor configured to pressurize the CO ₂ stream; and at least one heat transfer part of the heat exchanger, a source configured to the outside from the turbine exhaust stream, downstream of the heat transfer to the burner is located upstream of the compressor and the one of the CO ₂ stream. The power generation system of claim 15, wherein the compressor is configured to compress the CO ₂ stream to a first pressure that is higher than the CO ₂ critical pressure, and wherein the system includes a second compression And configured to compress the CO ₂ stream to a second, higher pressure of at least 8 MPa. A power generation system according to claim 16 comprising a cooling device between the compressor and the second compressor, and adapted to cool the CO ₂ stream to a density greater than about 200 kg/m ³ a temperature. The power generation system of claim 15, wherein the at least one heat transfer component is associated with an O ₂ generating device. The power generation system of claim 15, wherein the heat exchanger comprises at least two heat exchange units. An electric power generation system comprising: a first combustor; a first turbine; a second combustor; a second turbine; a compressor; a heat exchanger configured to discharge from the second turbine Streaming heat to a CO ₂ stream exiting the compressor, the heat exchanger comprising: a first inlet, and an outlet of the second turbine in a working setting; a first outlet, and a compressor The inlet is in a working setting; a second inlet, and an outlet of the compressor are in a working setting; and a second outlet, and an inlet of the first burner are in a working setting; and a hot inlet is located between the inlet and the outlet of the burner of the first compressor and configured to increase the heat to the turbine from a source different from a discharge stream of the CO ₂ stream. The power generation system of claim 20, wherein the heat inlet is configured to increase heat from a heat dispersion unit. The power generation system of claim 20, wherein the heat inlet is configured to increase heat from a first-rate supply. The power generation system of claim 20, wherein the heat inlet is configured to increase heat from a hot exhaust gas from a conventional open cycle gas turbine.