HK1177960B

HK1177960B - System and method for high efficiency power generation using a carbon dioxide circulating working fluid

Info

Publication number: HK1177960B
Application number: HK13104937.3A
Authority: HK
Inventors: Rodney John Allam; Miles R. Palmer; Glenn William Brown, Jr.
Original assignee: 帕尔默实验室有限责任公司; 八河流资产有限责任公司
Priority date: 2010-01-28
Filing date: 2011-01-26
Publication date: 2017-03-31

Description

System and method for efficient power generation using carbon dioxide circulating working fluid

Technical Field

The present invention relates to systems and methods for generating electricity, such as electricity, by using a circulating fluid to transfer energy generated via fuel efficient combustion. In particular, the systems and methods may use carbon dioxide as the circulating fluid.

Background

It is estimated that fossil fuels will continue to provide the majority of the world's electrical power needs over the next 100 years while non-carbon energy sources are being developed and utilized. However, the device is not suitable for use in a kitchenIn contrast, known methods of generating electricity by combustion of fossil fuels and/or suitable biomass suffer from an increase in energy consumption and carbon dioxide (CO)₂) And other emissions create increased problems. As a potentially catastrophic consequence of increased carbon emissions, global warming is gaining increasing attention in both developed and developing countries. Recently, solar and wind energy do not appear to replace fossil fuel combustion, while nuclear energy carries the risks associated with proliferation and nuclear waste disposal.

Conventional plants for generating electricity from fossil fuels or suitable biomass are increasingly burdened with capturing CO at high pressure₂To be delivered to the isolated site. However, this requirement appears to be difficult to achieve, since current technology is even for optimal CO₂The capture concerns provide only very low thermal efficiency. In addition, CO is completed₂Capital cost of capture is high compared to CO₂This results in significantly higher electricity costs for emissions to the atmosphere. Accordingly, there is an increasing need in the art for systems and methods for efficient power generation that allow for CO₂Reduced emissions and/or reduced CO generation₂The ease of isolation is improved.

Disclosure of Invention

The present invention provides for utilizing a high efficiency combustor (e.g., an evaporatively cooled combustor) in combination with a circulating fluid (e.g., CO)₂Circulating fluid) to generate electricity. Specifically, the circulating fluid may be introduced into the combustion chamber along with a combustion fuel and an oxidant such that a high pressure, high temperature fluid stream is produced comprising the circulating fluid and any combustion products. The fluid flow may be introduced into a power generation device, such as a turbine. Advantageously, the fluid flow may be maintained at a relatively high pressure during expansion in the turbine such that the pressure ratio across the turbine (i.e., the pressure at the turbine inlet to the pressure at the turbine outlet) is less than about 12. The fluid stream may then be further processed to separate components in the fluid stream, which may include passing the fluid stream through a heat exchanger. Utensil for cleaning buttockIn general, the circulating fluid (at least a portion of which may be recirculated from the fluid stream) may be passed through the same heat exchanger to heat the circulating fluid prior to introduction into the combustion chamber. In these embodiments, it may be helpful to operate the heat exchanger (e.g., by selecting a low-grade heat source) so that the heat exchanger has only a small temperature difference between the turbine exhaust and the recirculating fluid at the hot end of the heat exchanger.

In certain aspects, the present invention provides power generation systems that are capable of generating power efficiently at low capital cost, yet are capable of producing substantially pure CO at pipeline pressure₂For isolation. The CO is₂May also be recycled to the power generation system.

The systems and methods of the present invention are characterized by the ability to utilize a wide variety of fuel sources. For example, an efficient combustor used in accordance with the present invention may utilize gaseous fuels (e.g., natural gas or coal-formed gas), liquid fuels (e.g., hydrocarbons, bitumen), and solid fuels (e.g., coal, lignite, coke). Even other fuels as otherwise described herein can be used.

In other aspects, the methods and systems of the present invention are particularly useful because they can go beyond not currently providing CO₂Best efficiency of captured coal fired power plants. Such power plants can provide up to about 45% efficiency (lower heating value or "LHV") with a mercury condenser pressure (mercure condensation pressure) of 1.7 inches using bituminous coal. The system is able to exceed this efficiency while still delivering CO at the required pressure₂Isolation or other processing is performed.

In yet another aspect, the present invention provides the ability to reduce the physical size and capital cost of power generation systems as compared to current uses of similar fuels. Thus, the method and system of the present invention can significantly reduce the construction costs associated with power generation systems.

Still further, the methods and systems of the present invention can provide virtually 100% of the CO used and/or produced₂In particular CO originating from carbon present in the fuel₂. In particular, the CO₂May be provided as a dry, purified gas at pipeline pressure. In addition, the present invention provides the ability to separately recover other fuels and combustion-generated impurities for other applications and/or treatments.

In one particular aspect, the invention relates to a method of generating electricity in conjunction with the use of a circulating fluid. In particular embodiments, a method of generating power according to the present invention may include mixing a carbonaceous fuel, O₂And CO₂The circulating fluid is introduced into an evaporatively cooled combustion chamber. In particular, the CO₂Can be introduced at a pressure of at least about 8MPa (preferably at least about 12MPa) and a temperature of at least about 200 deg.C (preferably at least about 400 deg.C). The method may also include combusting a fuel to provide a fuel containing CO₂The combustion product stream of (a). Specifically, the combustion product stream may have a temperature of at least about 800 ℃. Further, the method may include expanding the combustion product stream through a turbine to generate electricity, the turbine having an inlet for receiving a combustion product stream and an outlet for releasing a CO-containing gas₂To the turbine exhaust stream outlet. Preferably, the pressure ratio of the combustion product stream at the inlet to the turbine exhaust stream at the outlet may be less than about 12. In particular embodiments, it may be desirable to introduce CO₂Is introduced into the combustion chamber at a pressure of at least about 10MPa, a pressure of at least about 20MPa, a temperature of at least about 400 ℃, or a temperature of at least about 700 ℃. Still further possible processing parameters are described herein.

In some embodiments, the CO₂The circulating fluid may be selected as the fluid with O₂And a carbonaceous fuel, or a mixture of both, is introduced into the evaporatively cooled combustion chamber. In other embodiments, CO₂The circulating fluid may be introduced into the evaporatively cooled combustion chamber as all or a portion of the evaporatively cooled fluid directed through one or more evaporatively cooled fluid supply passages formed therein. In a specific embodiment, CO₂The circulating fluid may be introduced into the combustion chamber only as an evaporative fluid.

Combustion can be specifically described by actual combustion temperatures. For example, the combustion may be conducted at a temperature of at least about 1,500 ℃. In other embodiments, the combustion may be conducted at a temperature of about 1,600 ℃ to about 3,300 ℃.

The invention may also be characterized as O₂In-stream O₂The purity of (2). For example, in some embodiments, ambient air may be useful. However, in particular embodiments, it may be beneficial to purify the oxygen content. E.g. O₂Can be used as O in₂Is provided in a stream of at least 85% molar concentration. Still further specific concentrations are described herein.

In particular embodiments, the combustion product stream may have a temperature of at least about 1,000 ℃. Moreover, the combustion product stream may have CO for introduction into the combustion chamber₂At least about 90% of the pressure or CO introduced into the combustion chamber₂A pressure of at least about 95% of the pressure.

In some embodiments, the combustion product stream at the turbine inlet may be at a turbine discharge-stream pressure ratio of about 1.5 to about 10 or may be about 2 to about 8 compared to the turbine outlet. Further possible ratios are provided herein.

The invention may be characterized by the proportions of the particular materials introduced into the combustion chamber. For example, CO introduced into the combustion chamber₂CO in the circulating fluid₂The ratio to carbon in the fuel may be from about 10 to about 50 or may be from about 10 to about 30 on a molar basis. Further possible ratios are provided herein.

The invention may also be characterized by at least a portion of the CO in the turbine exhaust stream₂Can be recirculated and reintroduced into the combustion chamber. At least a part of CO₂May be exhausted from the system (such as for isolation or other processing) through, for example, a conduit.

In particular embodiments, CO in turbine exhaust stream₂May be in a gaseous state. Specifically, the turbine exhaust stream may have a pressure less than or equal to 7 MPa.

In other embodiments, the inventive method may further comprise passing the turbine exhaust stream through at least one heat exchanger that cools the turbine exhaust streamAnd providing CO at a temperature of less than about 200 ℃₂The fluid stream is circulated. This may help to promote one or more minor components (i.e., remove CO)₂Other components) to provide CO under conditions of removal₂The fluid stream is circulated. In particular embodiments, this may include passing the turbine exhaust stream through a series of at least two heat exchangers. More specifically, a first heat exchanger in the series, which is formed of a high temperature alloy resistant to a temperature of at least about 900 ℃, is capable of receiving the turbine exhaust stream and reducing the temperature thereof.

The process of the invention may also comprise the addition of CO₂One or more separation steps are performed on the recycle fluid stream to remove CO removal as described above₂And one or more minor components present in the circulating fluid stream. In particular, the one or more minor components may comprise water.

The process of the invention may also include pressurizing the CO₂And (4) streaming. For example, after expansion of the combustion product stream and turbine exhaust stream cooling, it can be beneficial to pressurize the stream for recycle back to the combustor. Specifically, the method may comprise reacting CO₂Circulating a fluid stream through one or more compressors (e.g., pumps) to CO₂The circulating fluid stream is pressurized to a pressure of at least about 8 MPa. This may also include CO₂Circulating a fluid stream through a series of at least two compressors to pressurize the CO₂The fluid stream is circulated. In certain embodiments, CO₂The circulating fluid stream may be pressurized to a pressure of at least about 15 MPa. Still further pressure ranges may be desired, as otherwise described herein. In other embodiments, the CO is pressurized₂The circulating fluid stream may specifically be provided in a supercritical fluid state. In some embodiments, the CO is pressurized₂At least a portion of the CO in the circulating fluid stream₂May be introduced into the pressurized pipeline for isolation (or other processing, as already mentioned above).

In addition to pressurization, the inventive method may also include heating previously cooled CO₂Circulating the fluid stream for return to the combustor (i.e., recycling CO)₂A circulating fluid stream). At one endIn some embodiments, this may include heating the pressurized CO₂The circulating fluid stream is passed to a temperature of at least about 200 ℃, at least about 400 ℃, or at least about 700 ℃. In certain embodiments, the CO has been pressurized₂The recycle fluid stream may be heated to a temperature no greater than about 50 ℃ less than the turbine exhaust stream temperature. Still further possible temperature ranges are provided herein. In particular, such heating may include pressurizing the CO₂The circulating fluid stream passes through the same heat exchanger that is used to cool the turbine exhaust stream. Such heating may also include heat input from an external source (i.e., different from the heat recaptured from the heat exchanger). Such heating may also include heat input from an external source. In particular embodiments, heating may include utilizing self-O₂Heat recovered by the separation unit. Preferably, this additional heat is introduced at the cooling end of the heat exchanger unit (or, when a series of heat exchangers is used, before the heat exchangers in the series operating in the highest temperature range).

In certain embodiments, the invention may be characterized by the nature of the combustion product stream, which can allow for the optional implementation of multiple turbines. For example, in some embodiments, the combustion product stream may be a stream comprising one or more combustible components (e.g., selected from H)₂、CO、CH₄、H₂S、NH₃And combinations thereof). This may be by O₂With the proportion of fuel used. In some embodiments, the combustion product stream steam may contain fully oxidized components, such as CO₂、H₂O and SO₂And the reducing components listed above. The actual composition achieved may depend on the O in the feed to the evaporative combustor₂To the proportion of fuel used. More specifically, the turbine used in such embodiments may include two or more units having an inlet and an outlet. In particular embodiments, the turbine units may be operated such that the operating temperature at the inlet of each unit is substantially the same. This may include adding an amount of O to the fluid flow at the outlet of the first turbine unit (or, in the case of three or more units, a preceding turbine unit)₂. Providing O₂The combustible component or components can be combusted, which raises the temperature of the stream before entering the next turbine in the series. This results in the ability to maximize the power generated from the combustion gases in the presence of the circulating fluid.

In other embodiments, the turbine exhaust stream may be an oxidizing fluid. For example, the turbine exhaust stream may contain excess O₂。

In some embodiments, the invention may be characterized by various flow states. For example, the turbine exhaust stream may be in a gaseous state after the step of turboexpanding the combustion product stream. The gas may be passed through at least one heat exchanger to cool a gaseous turbine exhaust stream to CO₂Separated from any minor components. Thereafter, at least a portion of the separated CO₂Can be pressurized and converted to a supercritical fluid state and again passed through the same heat exchanger(s) to heat the CO₂For recirculation into the combustion chamber. In particular embodiments, the temperature of the turbine exhaust stream entering the heat exchanger (or, where used, the first heat exchanger in a series) from the expansion step is at the same temperature as the heated, pressurized, supercritical fluid CO exiting the same heat exchanger for recirculation into the combustion chamber₂The temperature difference therebetween may be less than about 50 deg.c.

As described above, the fluid stream exiting the fuel combustor may include CO₂A circulating fluid, and one or more other components, such as combustion products. In some embodiments, at least a portion of the CO is₂It may be useful to recirculate and reintroduce it to the fuel combustor. Thus, the circulating fluid may be a recirculating fluid. Of course, CO from an external source₂Can be used as the circulating fluid. Turbine exhaust gas may be cooled in an economizer heat exchanger, and the recovered heat may be used to heat high pressure recirculated CO₂. The cooled turbine exhaust exiting the low temperature end of the heat exchanger may contain components derived from the fuel or combustion process, such as H₂O、SO₂、SO₃、NO、NO₂Hg and HCl. In other embodimentsIn embodiments, these components may be removed from the stream using a suitable method. Other components in the stream may include inert gas impurities derived from the fuel or oxygenates, such as N₂Argon (Ar) and excess O₂. These can be removed by a separate suitable method. In further embodiments, the turbine exhaust may be at less than the CO in the turbine exhaust at the available cooling device temperature₂Condensing pressure of pressure so that when turbine exhaust is cooled, there is no CO₂The liquid phase can form because this will cause water to be removed as a liquid from the gaseous CO₂Medium effective separation of gaseous CO₂Contains a minimum amount of water vapor to condense the water. In another embodiment, purified CO₂Now together with at least a part of the CO in the fluid₂Can be compressed to produce high pressure recycle CO₂Circulating a fluid stream of said at least a portion of CO₂Representing oxidized carbon, originating from carbon in the fuel fed to the combustion chamber, which may be introduced into the booster duct for sequestration. Due to the high pressure of the turbine exhaust stream, the CO can be converted with minimal further processing or compression₂Direct transfer from the combustion process into the booster duct is a different advantage from the conventional process, in which CO is present₂Recovered at near atmospheric pressure (i.e., a pressure of about 0.1 MPa) or vented to the atmosphere. Furthermore, the CO sequestered according to the invention₂Can be transferred in a more efficient and economical manner than has been known hitherto.

Recycled CO entering a Heat exchanger₂The specific heat of the fluid (ideally above the critical pressure) is high and decreases with increasing temperature. This is particularly advantageous for at least a part of the heat at the lowest temperature level originating from an external source. This may be, for example, a low-pressure steam supply, which provides heat upon condensation. In other embodiments, such heat source may originate from operation of an air compressor used in a cryogenic air separation plant that adiabatically supplies oxidant to a combustor, without intermediate cooling, and utilizes for recycling CO₂The closed-loop circulating flow of the heat transfer fluid flow, which provides the heat of compression, extracts the heat of compression.

In one embodiment, a method of generating power according to the present invention may comprise the steps of:

mixing fuel and O₂And CO₂Introducing the circulating fluid into the combustion chamber, CO₂Introduced at a pressure of at least about 8MPa and a temperature of at least about 200 ℃;

combusting the fuel to provide a fuel containing CO₂The combustion product stream of (a), the combustion product stream having a temperature of at least about 800 ℃;

expanding the combustion product stream through a turbine having an inlet for receiving the combustion product stream and a turbine for releasing a gas comprising CO₂Wherein the pressure ratio of the combustion product stream at the inlet to the turbine exhaust stream at the outlet 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;

CO removal from cooled turbine exhaust stream₂One or more minor components that are externally present in the turbine exhaust stream to provide a cleaned, cooled turbine exhaust stream;

compressing the purified, cooled turbine exhaust stream above CO with a first compressor₂Pressure of critical pressure to provide supercritical CO₂Circulating a fluid stream;

cooling the supercritical CO₂Circulating the fluid stream to a density of at least about 200kg/m³The temperature of (a);

make supercritical, high density CO₂Circulating the fluid through a second compressor to CO₂The circulating fluid is pressurized to the pressure required by the input combustion chamber;

subjecting the supercritical, high density, high pressure CO₂Circulating fluid through the same heat exchange unit so that the heat recovered is used to augment the CO₂The temperature of the circulating fluid;

supplying an additional amount of heat to the supercritical, high density, high pressure CO₂Circulating fluid to recycle CO leaving the heat exchange unit for recycling back to the combustor₂The difference between the temperature of the cycle fluid and the temperature of the turbine exhaust stream is less than about 50 ℃; and

heating supercritical, high density CO₂The circulating fluid is recirculated into the combustion chamber.

In particular embodiments, the systems and methods may be particularly useful in combination with existing power systems and methods (e.g., conventional coal-fired power plants, nuclear reactors, and other systems and methods that utilize conventional boiler systems). Thus, in some embodiments, between the expansion step and the recovery step described above, the inventive method may include passing the turbine exhaust stream through a second heat exchange unit. The second heat exchange unit can utilize heat from the turbine exhaust stream to heat one or more streams from a steam power system (e.g., a conventional boiler system, including a coal-fired power plant and a nuclear reactor). The so heated steam stream may then be passed through one or more turbines to generate electricity. The stream exiting the turbine may be treated by circulating back through components of a conventional power system (e.g., a boiler).

In further embodiments, the method of the invention may be characterized by one or more of the following steps:

cooling the turbine exhaust stream to a temperature below its water dew point;

further cooling the turbine exhaust against an ambient temperature cooling medium;

condensing water together with the one or more minor components to form a product comprising H₂SO₄、HNO₃A solution of one or more of HCl and mercury;

pressurizing the cooled turbine exhaust stream to a pressure of less than about 15 MPa;

from supercritical, high density, high pressure CO before passing through a heat exchange unit₂Recycle fluid stream recovery of product CO₂A stream;

using a stream of partial combustion products as fuel;

in CO₂With O in the presence of a circulating fluid₂Combusting carbonaceous fuel, providing carbonaceous fuel, O₂And CO₂The proportion of the circulating fluid is such that the carbonaceous fuel is only partially oxidised to produce a partially oxidised combustion product stream comprising non-combustible components, CO₂And H₂、CO、CH₄、H₂S and NH₃One or more of;

providing a carbonaceous fuel, O in the following ratio₂And CO₂A recycle fluid in a proportion such that the temperature of the stream of partially oxidised combustion products is sufficiently low that all non-combustible components in the stream are in the form of solid particles;

passing the partially oxidized combustion product stream through one or more filters;

using the filter to reduce the residual amount of non-combustible components to less than about 2mg/m³Partially oxidized combustion products;

coal, lignite or petroleum coke is used as fuel;

is provided as containing CO₂The particulate fuel of the slurry of (a);

in further embodiments, with respect to a method of generating electricity, the invention may be described as comprising the steps of:

mixing carbon-containing fuel and O₂And CO₂Introducing the circulating fluid into an evaporatively-cooled combustion chamber, CO₂Is introduced at a pressure of at least about 8MPa and a temperature of at least about 200 ℃;

expanding the combustion product stream through a turbine to generate electricity, the turbine having a turbineAt the inlet receiving the combustion product stream and for releasing the CO-containing gas₂Wherein the pressure ratio of the combustion product stream at the inlet to the turbine exhaust stream at the outlet is less than about 12;

passing the turbine exhaust stream through a series of at least two heat exchangers, the series recovering heat from the turbine exhaust stream and providing CO₂Circulating a fluid stream;

from CO₂Recycle fluid stream CO removal₂One or more minor components present in the circulating fluid stream;

make CO₂The circulating fluid stream passes through a series of at least two compressors, which convert CO₂Increasing the pressure of the circulating fluid to at least about 8MPa and converting CO in the circulating fluid₂Converting from a gaseous state to a supercritical fluid state; and

subjecting the supercritical CO₂The circulating fluid passes through the same series of at least two heat exchangers, which use the recovered heat to drive the CO₂The temperature of the circulating fluid is increased to at least about 200 ℃ (or, optionally, to a temperature no more than about 50 ℃ less than the turbine exhaust stream temperature). This may specifically include the introduction of additional heat from an external heat source (i.e., not directly derived from passing the turbine exhaust stream through a heat exchanger).

In further embodiments, the invention may be characterized as providing a method of generating electricity from the combustion of a carbonaceous fuel without CO₂Is highly efficient for atmospheric release. Specifically, the method comprises the following steps:

mixing carbon-containing fuel and O₂And recycling CO₂The circulating fluid is introduced into the evaporatively cooled combustion chamber at a defined stoichiometric ratio, CO₂Is introduced at a pressure of at least about 8MPa and a temperature of at least about 200 ℃;

through turbineExpanding the combustion product stream to generate electricity, the turbine having an inlet for receiving the combustion product stream and a turbine for releasing a gas comprising CO₂Wherein the pressure ratio of the combustion product stream at the inlet to the turbine exhaust stream at the outlet is less than about 12;

make CO₂The circulating fluid stream passes through a series of at least two compressors, which convert CO₂Increasing the pressure of the circulating fluid to at least about 8MPa and converting CO in the circulating fluid₂Converting from a gaseous state to a supercritical fluid state;

making the CO in₂The circulating fluid stream is passed through a separation unit in which a stoichiometrically required amount of CO is passed₂Is recycled and directed to the combustor and recovers any excess CO₂Without atmospheric release; and

recycling CO₂The circulating fluid passes through the same series of at least two heat exchangers, which use the recovered heat to convert CO₂The temperature of the recycle stream is increased to at least about 200 ℃ prior to introduction into the combustor (or, optionally, to a temperature no greater than about 50 ℃ less than the temperature of the turbine exhaust stream);

wherein the efficiency of combustion is greater than 50%, calculated as the ratio of the net electrical power produced to the total lower heating value thermal energy of the carbonaceous fuel combusted to generate electricity.

In another aspect, the invention may be described as providing a power generation system. Specifically, a power generation system according to the present invention may include an evaporatively cooled combustor, a power generating turbine, at least one heat exchanger, and at least one compressor.

In particular embodiments, the evaporatively cooled combustor may have at least one inlet for receiving a carbonaceous fuel, O₂And CO₂An inlet for a circulating fluid stream. The combustion chamber may have at least one combustion stage in CO₂Combusting the fuel in the presence of the circulating fluid and providing a CO-containing gas at a defined pressure (e.g., at least about 8MPa) and temperature (e.g., at least about 800 ℃)₂The combustion product stream of (a).

The power generation turbine may be in fluid communication with the combustor and may have an inlet for receiving a flow of combustion products and for releasing a CO-containing gas₂To the turbine exhaust stream outlet. The turbine may be adapted to control the pressure drop such that the pressure ratio of the flow of combustion products at the inlet compared to the turbine exhaust flow at the outlet is less than about 12.

The at least one heat exchanger may be in fluid communication with the turbine for receiving a turbine exhaust stream. The heat exchanger(s) may transfer heat from the turbine exhaust stream to the CO₂The fluid stream is circulated.

The at least one compressor may be in flow communication with at least one heat exchanger. The compressor(s) may be adapted to compress CO₂The circulating fluid stream is pressurized to a desired pressure.

In addition to the above, the power generation system according to the present invention may further include one or more separation devices disposed between the at least one heat exchanger and the at least one compressor. Such separation device(s) may be used to remove CO₂External presence in CO₂One or more minor components in the circulating fluid.

Still further, the power generation system may include O₂A separation unit comprising one or more heat generating components. Thus, the power generation system may also include one or more heat transfer components that will be derived from O₂Heat transfer from the separation unit to CO upstream of the combustor₂The fluid is circulated. Optionally, the power generation system may include an external heat source. This may be, for example, a low pressure steam supply which will provide heat upon condensation. The power generation system may thus include one or more heat transfer components that transfer heat from the steam to the CO upstream of the combustion chamber₂The fluid is circulated.

In further embodiments, the power generation system of the present invention may include one or more of the following:

a first compressor adapted to compress CO₂Circulating fluid stream compression above CO₂A pressure of a critical pressure;

a second compressor adapted to compress CO₂Compressing the circulating fluid flow to a pressure required for input to the combustion chamber;

cooling device adapted to inject CO₂Cooling the circulating fluid stream to a density greater than about 200kg/m³The temperature of (a);

one or more heat transfer components that transfer heat from an external source to the CO upstream of the combustion chamber and downstream of the second compressor₂Circulating a fluid;

a second compressor located upstream of and in fluid communication with the evaporatively cooled combustion chamber;

one or more filters or separation devices between the second compressor and the evaporatively cooled combustor;

a mixing apparatus for forming a slurry of particulate fuel material and a fluidizing medium;

a milling device for granulating the solid fuel.

In other embodiments, the invention may provide a power generation system that may include: one or more injectors for supplying fuel, CO₂A circulating fluid and an oxidant; an evaporatively cooled combustor having at least one combustion stage that combusts a fuel and provides an exhaust fluid stream at a temperature of at least about 800 ℃ and a pressure of at least about 4MPa (preferably at least about 8 MPa); a power generating turbine having an inlet and an outlet, and wherein electricity is generated as the fluid stream expands, the turbine designed to maintain the fluid stream at a desired pressure such that the pressure ratio of the fluid stream at the inlet to the outlet is less than about 12; heat exchanger for cooling fluid flow leaving turbine outlet and for heating CO₂Circulating a fluid; and one or more devices for separating the fluid stream leaving the heat exchanger into CO₂And one or moreAnd other components for recovery or disposal. In further embodiments, the power generation system may further comprise one or more devices for separating at least a portion of the CO from the fluid stream₂Delivered to the device in the pressurized conduit.

In particular embodiments, a system according to the present disclosure may include one or more components that are retrofitted with conventional power generation systems (such as coal-fired power plants, nuclear reactors, etc.) as described above. For example, the power system may include two heat exchange units (e.g., a primary heat exchange unit and a secondary heat exchange unit). The primary heat exchange unit may be substantially as otherwise described herein, while the secondary heat exchange unit may be a unit for transferring heat from the turbine exhaust stream to one or more steam streams (e.g., from a boiler associated with a conventional power generation system) to superheat the steam streams. Accordingly, a power generation system according to the present invention may include a secondary heat exchange unit located between and in fluid communication with the turbine and the primary heat exchange unit. The power generation system also includes a boiler in fluid communication with the secondary heat exchange unit via at least one steam stream. Still further, the power generation system may include at least one other power generating turbine having an inlet for receiving at least one steam flow from the secondary heat exchange unit. Thus, the system may also be described as including a primary power generating turbine and a secondary power generating turbine. The main power generating turbine may be a turbine in fluid communication with the inventive combustor. The secondary power turbine may be a turbine in fluid communication with a steam stream, particularly a superheated steam stream, which is superheated with heat from a main power turbine exhaust stream. Such a system modified with one or more components from a conventional power generation system is described herein, particularly in connection with fig. 12 and example 2. The use of the terms primary and secondary power turbines should not be construed as limiting the scope of the invention, but merely as providing clarity in the description.

In another aspect of the invention, the external stream may be heated at the high temperature end of the heat exchanger by heat transfer from the cooling turbine exhaust stream, and thus, the high pressure recycle stream will exit the heat exchanger at a lower temperature and enter the combustor. In this case, the amount of fuel burned in the combustor may be increased so that the turbine inlet temperature is maintained. The heating value of the additional fuel combusted is equal to the additional heat load imposed on the heat exchanger.

In some embodiments, the invention may be characterized as providing a predominantly secondary CO₂The circulation of the circulating fluid produces shaft power in the process plant. In further embodiments, the present invention provides methods that may satisfy certain conditions. In particular embodiments, the invention also features one or more activities or devices for performing the activities:

introducing CO₂Circulating fluid compressed to exceed CO₂A pressure of a critical pressure;

taking into account mixed CO₂Enriched supercritical fluid, directly in substantially pure O₂Combusting a solid, liquid, or gaseous hydrogen-carbon fuel to achieve a desired power turbine inlet temperature-e.g., greater than about 500 ℃ (or other temperature as described herein);

using combustion products and recycled CO in a turbine₂Supercritical expansion of the enriched fluid formation, producing shaft power, specifically, expansion to over about 2MPa and below CO when the fluid is cooled to a temperature consistent with cooling with ambient pressure cooling medium₂The pressure at which the liquid phase occurs (e.g., about 7.3-7.4 MPa);

introducing the turbine exhaust into a heat exchanger, wherein the turbine exhaust is cooled and heat is transferred to the recirculating CO₂Enriching the supercritical fluid;

cooling the CO-containing stream leaving the heat exchanger by means of an ambient temperature cooling medium₂Flowing and containing at least a minor concentration of CO₂With a gaseous CO phase containing at least a minor concentration of water vapour₂Phase separation;

the water separation is performed in a manner that allows for a desired retention time (e.g., up to 10 seconds), wherein the gaseous CO₂By intimate contact with liquid water or a weak acid phase, SO that SO is involved₂、SO₃、H₂O、NO、NO₂、O₂And/or Hg may occur, resulting in greater than 98% of the sulfur present in the stream being converted to H₂SO₄And greater than 90% of the nitrogen oxides in the stream are converted to HNO₃And for converting greater than 80% of the mercury in the stream to soluble mercury compounds;

by cooling to near CO₂Freezing point temperature, separation of non-condensable components (such as N)₂Ar and O₂) With gaseous CO₂Phase in which the gas/liquid phase separates leaving predominantly N in the gas phase₂Ar and O₂；

Purifying the gaseous CO in an air compressor₂The stream is compressed to a pressure at which cooling by an ambient temperature cooling medium will produce high density CO₂Fluid (e.g., density at least about 200 kg/m)³Preferably at least about 300kg/m³Or more preferably at least about 400kg/m³)；

Cooling compressed CO with ambient cooling medium₂To form high density CO₂Supercritical fluids (e.g., having a density of at least about 200 kg/m)³Preferably at least about 300kg/m³Or more preferably at least about 400kg/m³)；

Compressing high density CO in a compressor₂Fluid to above CO₂A pressure of a critical pressure;

introducing high pressure CO₂The stream is separated into two separate streams — one entering the cold end of the heat exchanger, while the second stream is heated at a temperature below about 250 ℃ using an available external heating source;

facilitating efficient heat transfer (including the use of an optional external heat source) such that the temperature of the turbine exhaust stream entering the hot end of the heat exchanger is the same as the recycled CO exiting the hot end of the same heat exchanger₂The difference between the temperatures of the circulating fluids is less than about 50 ℃ (or other temperature threshold as described herein);

introducing CO₂The circulating fluid is compressed to about 8MPa to about 5MPaA pressure of 0MPa (or other pressure ranges as described herein);

make O be₂Flow and recycle CO₂A portion of the circulating fluid stream is mixed with a carbonaceous fuel stream to form a single fluid stream (or slurry if a pulverized solid fuel is used) that is below the auto-ignition temperature of the fuel and whose properties are adjusted to produce an adiabatic flame temperature (or other temperature range as described herein) of about 1,200 ℃ to 3,500 ℃;

mixing at least part of the recycled CO₂Circulating the fluid with the combustion products to form a mixed fluid stream (or other temperature range as described herein) at a temperature range of about 500 ℃ to 1,600 ℃;

generating a vortex discharge flow having a pressure (or other pressure range as described herein) of about 2MPa to about 7.3 MPa;

externally heating part of high pressure CO₂Circulating fluid flow using heat from low temperature O₂One or more air compressors (especially in adiabatic mode) and/or CO of the plant₂Heat of compression for compressor (especially in adiabatic mode) operation, heat being passed through a suitable heat transfer fluid (including CO)₂The fluid itself) is transferred;

heating one or more external fluid streams in a heat exchanger using an equivalent additional fuel combusted in the combustion chamber, wherein the one or more external fluid streams may include steam, which may be superheated in the heat exchanger;

externally heating a portion of the recycled CO using heat supplied from condensed steam provided from an external source₂Circulating a fluid stream;

cooling of CO-containing in a heat exchanger₂A stream (which exits the cold end of the heat exchanger) to provide heat for heating an externally provided fluid stream;

providing O₂Feed stream of O₂Is at least about 85% (or other concentration ranges as described herein);

operating the combustion chamber so that O₂A concentration in the total gas stream exiting the combustor (i.e., the combustion product stream) and entering the turbine of greater than about 0.1% mol;

performing a power generation process such that only one power generation turbine is used;

performing a power generation process such that the carbonaceous fuel input into the combustion chamber is substantially completely combusted using only one combustion chamber;

operating the combustion chamber so that O₂O in the inlet to the combustion chamber₂The amount in the stream is less than that described for stoichiometric combustion of the fuel stream entering the combustion chamber, thus resulting in the production of H in the combustion product stream₂And carbon monoxide (CO); and

the method is carried out using two or more turbines, each having a defined outlet pressure, where H₂And CO, either or both, are present in the exhaust stream exiting the first turbine (and subsequent turbines, except the last turbine in the turbine train, if applicable), and some or all of the H₂And CO by adding O before the second and subsequent turbine inlets₂Stream to be combusted to increase the operating temperature of each of the second or more turbines to a higher value such that there is an excess of O in the exit stream from the last turbine₂This excess is greater than about 0.1% mol.

In further embodiments, the present invention also provides one or more of the following steps;

heating CO in a heat exchange system by cooling a swirling exhaust stream₂Circulating the fluid such that the swirling exhaust stream is cooled below its water dew point;

cooling of turbine exhaust stream by ambient temperature cooling medium and condensation of water and fuel and combustion generated impurities including H₂SO₄、HNO₃HCl and other impurities such as Hg and other metals that form ionic compounds in solution;

in the first compressor, the purified CO is₂The circulating fluid is compressed above its critical pressure but below 10 MPa;

cooling the circulating fluid to a density of greater than 600kg/m³A point of (a);

high density CO injection in compressors₂Circulating fluid is compressed to overcome pressure drop in the system and recycle CO₂The pressure required for feeding the fluid into the combustion chamber;

removal of product CO₂A product stream comprising substantially all of the CO formed by the combustion of the carbon in the fuel stream₂The CO is₂A discharge stream flowing from the first compressor or the second compressor;

supplying an additional amount of heat to the CO at a temperature level above the water dew point of the cooling turbine exhaust stream₂Circulating fluids, either directly to heat exchangers or by heating containing part of the CO₂By-pass of circulating fluid to circulate CO at the hot end of the heat exchanger₂The temperature difference between the fluid and the turbine exhaust is less than 50 ℃;

using fuel containing carbonaceous fuel with O in an evaporatively cooled combustion chamber₂Partially oxidized non-combustible residue) to produce a residue containing H₂、CO、CH₄、H₂S、NH₃And a stream of incombustible residues, the combustor being fed with a partial recycle of CO₂A fluid to cool the partially oxidized combustion products to a temperature of 500 ℃ to 900 ℃, wherein ash is present as solid particles which can be completely removed from the outlet fluid stream by a filtration system;

providing cooling turbine exhaust stream and heating cycle CO₂Temperature difference between fluid streams at which bypass flow rate and separately heated circulating CO₂The fluid flow rate is remixed and it is between 10 ℃ and 50 ℃;

providing pressure of turbine exhaust stream exiting the cold end of the heat exchanger such that when the stream is cooled prior to water and contaminant separation, there is no liquidState CO₂Forming;

superheating a plurality of steam streams originating from a steam power system associated with a conventional boiler system and a nuclear reactor with at least a portion of the turbine exhaust stream;

recycle CO to steam at one or more pressure levels taken from an external steam source, such as a power plant₂The stream provides additional low level heat;

providing heat to at least a portion of the condensate exiting the steam condenser of the steam power generation system using the expanded exhaust stream exiting the cold end of the heat exchanger system;

circulating CO for hot exhaust gas from an open cycle gas turbine₂The stream provides additional low level heat;

adding CO to a partially oxidized coal derived gas₂As fuel to a second combustion chamber for complete combustion;

operating a single combustion chamber in which O₂The ratio of fuel to fuel being such that part of the fuel is oxidised to contain CO₂、H₂O and SO₂And the remaining fuel is oxidized to contain H₂CO and H₂A component of S;

operating the two turbines beyond a total desired pressure ratio, wherein O₂Injected into the exhaust stream of the first turbine to combust the reducing component to reheat it to a higher temperature before expansion through the second turbine at intermediate pressure.

Further embodiments are encompassed by the invention, as described with respect to the various figures and/or as disclosed in the further description of the invention provided herein.

Brief Description of Drawings

Having thus described the invention in general terms, reference will now be made to the accompanying drawings, which are not necessarily drawn to scale, and wherein:

FIG. 1 is a schematic illustration of an evaporatively cooled combustion apparatus that may be used in accordance with certain embodiments of the present disclosure;

FIG. 2 is an exemplary cross-sectional schematic view of an evaporation member wall in a combustion chamber that may be used in certain embodiments of the present disclosure;

FIGS. 3A and 3B schematically illustrate a thermal mating process of an evaporation component assembly of a combustion apparatus that may be used in certain embodiments of the present disclosure;

FIG. 4 schematically illustrates a combustion product contaminant removal device that may be used in accordance with certain embodiments of the present disclosure;

FIG. 5 is a flow chart illustrating a power cycle according to one embodiment of the present disclosure;

FIG. 6 is a schematic diagram illustrating a CO according to an embodiment of the present disclosure₂A flow diagram of a circulating fluid flowing through a separation unit;

FIG. 7 is a flow chart illustrating boosting with two or more compressors or pump trains in a booster unit according to one embodiment of the present disclosure;

FIG. 8 is a flow diagram illustrating a heat exchange unit in which three separate heat exchangers are employed in series, according to one embodiment of the present disclosure;

FIG. 9 is a flow diagram illustrating a turbine unit utilizing two turbines operating in series in a reduction mode (reducing mode) according to one embodiment of the present disclosure;

FIG. 10 is a flow diagram illustrating a system and method for generating electricity using two combustors in accordance with an embodiment of the present disclosure;

FIG. 11 is a flow diagram illustrating a specific example of a system and method for generating power according to one embodiment of the present disclosure; and

FIG. 12 is a flow diagram illustrating another example of a system and method for generating electricity in conjunction with a conventional coal-fired boiler, according to an embodiment of the present disclosure.

Detailed Description

The invention will now be described in more detail hereinafter with reference to various embodiments. These embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. Indeed, the invention may be embodied in many different forms and should not be construed as limited to the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements. As used in this specification and the appended claims, the singular forms "a", "an", and "the" include plural referents unless the content clearly dictates otherwise.

The present invention provides for the utilization of a high efficiency fuel combustor (such as an evaporatively cooled combustor) and associated circulating fluids (such as CO)₂Circulating fluid) to generate electricity. The circulating fluid is provided in the combustion chamber along with a suitable fuel, any necessary oxidant and any associated materials that can be used for efficient combustion. In particular embodiments, the method may be practiced using a combustor operating at very high temperatures (e.g., in the range of about 1,600 ℃ to about 3,300 ℃, or other temperature ranges as disclosed herein), and the presence of the circulating fluid may serve to moderate (moderate) the temperature of the fluid stream exiting the combustor so that the fluid stream may be used in energy transfer to generate electricity. Specifically, the combustion product stream may be expanded through at least one turbine to generate electricity. The expanded gas stream may be cooled to remove various components, such as water, from the stream, and the heat recovered from the expanded gas stream may be used to heat the CO₂The fluid is circulated. The cleaned circulating fluid stream may then be pressurized and heated for recirculation through the combustion chamber. If desired, a portion of the CO from the combustion product stream₂(i.e., derived from CO formed by combustion of a carbonaceous fuel in the presence of oxygen₂) Can be removed for sequestration or other treatment, such as transfer to CO₂A pipeline. The system and method canUtilizing specific process parameters and components to maximize the efficiency of the system and method, particularly while avoiding the release of CO to the atmosphere₂. The circulating fluid is formed by using CO, as described in detail herein₂As an example of a circulating fluid. Despite the utilization of CO₂Circulating fluid is an advantageous embodiment according to the present invention, but this disclosure should not be construed as necessarily limiting the scope of circulating fluid that may be used in the present invention unless otherwise stated.

In certain embodiments, power generation systems according to the present disclosure may utilize primarily CO₂The circulating fluid of (1). In other aspects, the chemistry of the circulating fluid to be immediately fed into the combustion chamber is such that the circulating fluid consists essentially of CO₂. In this sense, the word "predominantly" may mean that the fluid comprises at least about 90% molar, at least about 91% molar, at least about 92% molar, at least about 93% molar, at least about 94% molar, at least about 95% molar, at least about 96% molar, at least about 97% molar, at least about 98% molar, or at least about 99% molar CO₂. The circulating fluid to be fed immediately into the combustion chamber preferably comprises substantially only CO₂. In this sense, the phrase "substantially only" may refer to at least about 99.1% molar, at least about 99.25% molar, at least about 99.5% molar, at least about 99.75% molar, at least about 99.8% molar, or at least about 99.9% molar CO₂. In the combustion chamber, CO₂May be mixed with one or more other components which may be derived from the fuel, any oxidant and any derivative from the combustion of the fuel. Thus, the circulating fluid exiting the combustion chamber, which may be described herein as combustion products, may contain CO₂Together with lesser amounts of other substances, such as H₂O、O₂、N₂、Ar、SO₂、SO₃、NO、NO₂HCl, Hg, and trace amounts of other components that may originate from the combustion process (e.g., particulates such as ash or liquefied ash), including other combustibles. As described in more detail below, the combustion process may be controlled such that the properties of the fluid stream may be reduced or oxidized, whichMay provide the benefits specifically described.

The systems and methods of the present invention may incorporate one or more combustors for combusting a suitable fuel, as described herein. Preferably, at least one combustion chamber used according to the invention is an efficient combustion chamber capable of providing substantially complete combustion of fuel at relatively high temperatures. High temperature combustion is particularly useful for providing substantially complete combustion of the fuel and thus maximizing efficiency. In various embodiments, high temperature combustion may refer to combustion at a temperature of at least about 1,200 ℃, at least about 1,300 ℃, at least about 1,400 ℃, at least about 1,500 ℃, at least about 1,600 ℃, at least about 1,750 ℃, at least about 2,000 ℃, at least about 2,500 ℃, or at least about 3,000 ℃. In further embodiments, high temperature combustion may refer to combustion at a temperature of about 1,200 ℃ to about 5,000 ℃, about 1,500 ℃ to about 4,000 ℃, about 1,600 ℃ to about 3,500 ℃, about 1,700 ℃ to about 3,200 ℃, about 1,800 ℃ to about 3,100 ℃, about 1,900 ℃ to about 3,000 ℃, or about 2,000 ℃ to about 3,000 ℃.

In certain embodiments, high temperature combustion according to the present invention may be performed using an evaporatively cooled combustor. One example of an evaporatively cooled combustor that may be used in the present invention is described in U.S. patent application No. 12/714,074, filed on 26/2/2010, the disclosure of which is incorporated herein by reference in its entirety. In some embodiments, an evaporatively cooled combustor useful according to the present invention may include one or more heat exchange zones, one or more cooling fluids, and one or more evaporative fluids.

The use of an evaporatively cooled combustor according to the present invention is particularly advantageous over known techniques relating to combusting fuel to generate electricity. For example, the use of evaporative cooling may be used to prevent corrosion, fouling and erosion in the combustion chamber. This also allows the combustion chamber to be operated in a temperature range high enough to provide complete, or at least substantially complete, combustion of the fuel used. These and other advantages are further described herein.

In a particular aspect, an evaporatively cooled combustor useful according to the present invention may include a combustor at least partially defined by an evaporative component, wherein the evaporative component is at least partially surrounded by a pressure containment vessel. The combustion chamber may have an inlet portion and an opposite outlet portion. The inlet portion of the combustion chamber may be configured to receive a carbonaceous fuel that is combusted within the combustion chamber at a combustion temperature to form combustion products. The combustion chamber may be further configured to direct the combustion products toward the outlet portion. The vaporization member can be configured to direct vaporized material passing therethrough toward the combustion chamber to effect a buffering interaction between the combustion products and the vaporization member. Additionally, vaporized material may be introduced into the combustion chamber to achieve a desired combustion product outlet temperature. In particular embodiments, the evaporative substance may include, at least in part, a circulating fluid.

The walls of the combustion chamber may be lined with a layer of porous material, evaporating substances such as CO₂And/or H₂O is directed through the layer of porous material and flows.

In still further aspects, the inner evaporation member 2332 can extend from the inlet portion 222A to the outlet portion 222B of the evaporation member 230. In some cases, the inner evaporative member 2332 of perforated/porous structure may extend substantially completely from the inlet portion 222A to the (axial) outlet portion 222B such that the evaporative fluid 210 is introduced into substantially the entire length of the combustion chamber 222. That is, substantially all of inner evaporative members 2332 may be configured with a perforated/porous structure such that substantially the entire length of combustion chamber 222 is evaporatively cooled. More specifically, in some aspects, the cumulative perforated/porous region can be substantially equal to the surface area of the inner evaporative member 2332. In still other aspects, the perforations/holes can be spaced at a suitable density so as to achieve a substantially uniform distribution of vaporized material from the inner vaporization member 2332 into the combustion chamber 222 (i.e., no "dead space" in which there is a lack of flow or absence of vaporized material 210). In one example, a one-square foot inner vaporization member 2332 may include an array of perforations/holes in the order of 250 x 250 per square inch, providing about 62,500 holes/in 2 spaced about 0.004 inches (about 0.1mm) apart. The ratio of the pore area to the total wall area (% porosity) may be, for example, about 50%. The array of apertures can be varied over a wide range to accommodate other system design parameters, such as the desired pressure drop versus flow rate through the vaporization member. In some examples, an array size of about 10 x 10 to about 10,000 x 10,000 per inch may be utilized with a porosity of about 10% to about 80%.

The flow of vaporized material through the porous vaporization layer and optionally through other arrangements (provisions) may be configured such that a desired total outlet fluid temperature from the combustion chamber is achieved. In some embodiments, such temperatures may range from about 500 ℃ to about 2,000 ℃, as further described herein. Such flow may also be used to cool the evaporation component to a temperature below the maximum allowable operating temperature of the material forming the evaporation component. The vaporized material may also be used to prevent the effects of any liquid or solid ash material or other contaminants in the fuel that may corrode, foul, or otherwise damage the walls. In such a case, it may be desirable to utilize a material for the evaporation member that has a reasonable thermal conductivity so that the incidental radiant heat can be conducted radially outward through the porous evaporation member and then captured by convective heat transfer from the surface of the porous layer structure to the fluid passing radially inward through the evaporation layer. This configuration may allow the subsequent partial flow directed through the evaporation member to be heated to a temperature in a desired range, such as about 500 ℃ to about 1,000 ℃, while maintaining the temperature of the porous evaporation member substantially within the design range of the materials used therefor. Suitable materials for the porous evaporation member may include, for example, porous ceramics, refractory metal fibers, drilled cylindrical shapes (hole-drilled cylinder coatings), and/or sintered metal layers or sintered metal powders. A second function of the vaporizing element may be to ensure a substantially uniform radially inward flow of the vaporizing fluid and longitudinally along the combustion chamber to achieve good mixing between the vaporizing fluid flow and the combustion products while promoting a uniform axial flow along the length of the combustion chamber. A third function of the vaporization member may be to achieve a radially inward velocity of the dilution fluid to provide a buffer to prevent solid and/or liquid particles of ash or other contaminants within the combustion products from affecting the surface of the vaporization layer and causing clogging or other damage, or otherwise. Such factors may be important, for example, when a burning fuel such as coal has a residual inert noncombustible residue. The inner wall of the combustion chamber pressure vessel surrounding the vaporization member may also be insulated to isolate the high temperature vaporizing fluid flow within the combustion chamber.

One example of a combustor apparatus that can be used in accordance with the present invention is schematically illustrated in FIG. 1, the combustor apparatus being generally represented by the numeral 220. In this example, the combustion apparatus 220 may be configured to combust particulate solids, such as coal, to form combustion products, although any other suitable combustible carbonaceous material may be used as fuel as disclosed herein. The combustion chamber 222 may be defined by an evaporation member 230 configured to direct evaporative fluid passing therethrough into the combustion chamber 222 (i.e., to promote evaporative cooling and/or to buffer interaction between the combustion products and the evaporation member 230). It will be appreciated by those skilled in the art that the evaporation member 230 may be substantially cylindrical so as to define a substantially cylindrical combustion chamber 222 having an inlet portion 222A and an opposite outlet portion 222B. The vaporization component 230 may be at least partially surrounded by a pressure containment component 2338. The inlet portion 222A of the combustion chamber 222 may be configured to receive a fuel mixture from a mixing device, generally indicated by the numeral 250. In other embodiments, such mixing devices may not be present, and the one or more substances input into the combustion chamber may be added separately via separate inlets. According to a particular embodiment, the fuel mixture may be combusted in the combustion chamber 222 at a particular combustion temperature to form combustion products, wherein the combustion chamber 222 is further configured to direct the combustion products toward the outlet portion 222B. Heat rejection equipment 2350 (see, e.g., fig. 2) may be coupled to pressure containment component 2338 and configured to control its temperature. In particular instances, heat rejection apparatus 2350 may include a heat transfer jacket defined at least in part by a wall 2336 opposite pressure containment component 2338, wherein liquid may be circulated in a water circulation jacket 2337 defined therebetween. In one embodiment, the liquid being circulated may be water.

In a particular aspect, the porous inner evaporative member 2332 is thus configured to introduce an evaporative fluid into the combustion chamber 222 such that the evaporative substance 210 enters the combustion chamber 222 at a substantially right angle (90 °) relative to the inner surface of the inner evaporative member 2332. The introduction of the vaporized material 210 at a substantially right angle relative to the inner vaporization member 2332 may facilitate or otherwise enhance the effect of directing the swirling of the slag or solid droplets or other contaminants or hot combustion gases away from the inner surface of the inner vaporization member 2332, among other advantages. The lack of contact between slag or solid droplets can prevent the droplets from coalescing into large droplets or clumps, which is known in the art to occur when droplets or particles come into contact with a solid wall. The introduction of the vaporized material 210 at a substantially right angle relative to the inner vaporization member 2332 may facilitate or otherwise enhance the prevention of combustion product vortices having sufficient velocity from forming perpendicular to and adjacent to the inner vaporization member, which may affect and damage the inner vaporization member. In these cases, the outer vaporization member 2331, pressure containment member 2338, heat transfer jacket 2336, and/or thermal insulation layer 2339 may be configured, alone or in combination, to provide a "manifolding" action (i.e., to provide a substantially evenly distributed supply) for the transport of vaporized substance/fluid 210 through the inner vaporization member 2332 and into the combustion chamber 222. That is, a substantially uniform supply of vaporized material 210 (in terms of flow rate, pressure, or any other suitable and appropriate measure) into combustion chamber 222 may be achieved, and the vaporized material 210 may be specifically tailored and configured by configuring outer vaporization member 2331, pressure containment member 2338, heat transfer jacket 2336, and/or thermal insulation layer 2339 such that vaporized material 210 is uniformly supplied to inner vaporization member 2332, or vaporized material 210 is supplied around the outer surface of inner vaporization member 2332 such that a substantially uniform distribution of vaporized material 210 is achieved within combustion chamber 222. This substantially uniform distribution may inhibit the formation of hot combustion fluid vortices that otherwise would be formed by the interaction of the non-uniform vaporization flow with the combustion fluid flow, and which could affect and damage the inner vaporization components.

The mixing apparatus 250 (when present) may be configured to mix the carbonaceous fuel 254 with the enriched oxygen 242 and the recycle fluid 236 to form the fuel mixture 200. The carbonaceous fuel 254 may be provided in the form of a solid carbonaceous fuel, a liquid carbonaceous fuel, and/or a gaseous carbonaceous fuel. The enriched oxygen 242 may be oxygen at a molar concentration greater than 85%. The enriched oxygen 242 may be supplied, for example, by any air separation system/technique known in the art, such as, for example, mayA low temperature air separation process or a high temperature ion transport membrane oxygen separation process (from air) is performed. The recycle fluid 236 may be carbon dioxide as described herein. In the case where the carbonaceous fuel 254 is a particulate solid, such as pulverized coal 254A, the mixing apparatus 250 may be further configured to mix the particulate solid carbonaceous fuel 254A with the fluidizing substance 255. According to one aspect, the particulate solid carbonaceous fuel 254A may have an average particle size between about 50 microns and about 200 microns. According to yet another aspect, the fluidizing substance 255 may comprise water and/or liquid CO₂Having a density of about 450kg/m³To about 1100kg/m³In the meantime. More specifically, the fluidizing substance 255 can combine with the particulate solid carbonaceous fuel 254A to form a slurry 250A having, for example, from about 25wt% to about 55wt% of the particulate solid carbonaceous fuel 254A. Although the oxygen 242 is shown in fig. 1 as being mixed with the fuel 254 and the circulating fluid 236 prior to introduction into the combustion chamber 222, one skilled in the art will appreciate that in some instances, the oxygen 242 may be separately introduced into the combustion chamber 222 as necessary or desired.

The mixing apparatus 250, in some aspects, for example, can include an array of spaced apart injection nozzles (not shown) arrayed around the sidewall 223 of the vaporization member 230 associated with the inlet portion 222A of the cylindrical combustion chamber 222. Injecting the fuel/fuel mixture into the combustion chamber 222 in this manner may provide, for example, a larger surface area of the inlet flow of the injected fuel mixture, which in turn may facilitate rapid heat transfer to the inlet flow of the injected fuel mixture by radiation. The temperature of the injected fuel mixture may thus be rapidly increased to the ignition temperature of the fuel and may thus lead to compact combustion (compactcombustion). The injection velocity of the fuel mixture may range, for example, between about 10m/sec to about 40m/sec, although these values may depend on many factors, such as the configuration of the particular injection nozzle. Such an injection arrangement may take many different forms. For example, the injection arrangement may include an array of holes, for example, ranging between about 0.5mm to about 3mm in diameter, through which the injected fuel will be injected at a velocity of between about 10m/s to about 40 m/s.

As shown in more detail in fig. 2, the combustion chamber 222 may be defined by a vaporization component 230, which may be at least partially surrounded by a pressure containment component 2338. In some cases, the pressure containment component 2338 may further be at least partially surrounded by a heat transfer jacket 2336, wherein the heat transfer jacket 2336 may join the pressure containment component 2338, thereby defining one or more passages 2337 therebetween through which a low pressure water stream may be circulated. By an evaporation mechanism, circulating water can thus be used to control and/or maintain the selected temperature of pressure safety housing member 2338 in a range of, for example, about 100 ℃ to about 250 ℃. In some aspects, an insulating layer 2339 may be disposed between the evaporation component 230 and the pressure containment component 2338.

In some cases, the evaporation component 230 may include, for example, an outer evaporation component 2331 and an inner evaporation component 2332, the inner evaporation component 2332 being disposed opposite the outer evaporation component 2331 and defining the combustion chamber 222 as viewed from the pressure safety housing component 2338. The outer evaporation member 2331 may be composed of any suitable high temperature resistant material, such as, for example, steel and steel alloys, including stainless steel and nickel alloys. In some cases, outer evaporation member 2331 can be configured to define a first evaporation fluid supply channel 2333A that extends from its surface adjacent insulating layer 2339 to its surface adjacent inner evaporation member 2332. The first evaporative fluid supply channel 2333A may correspond in some cases to a second evaporative fluid supply channel 2333B defined by a pressure containment component 2338, a heat transfer jacket 2336, and/or an insulating layer 2339. The first and second evaporative fluid supply channels 2333A, 2333B can thus be configured to jointly direct evaporative fluid passing therethrough to the inner evaporative component 2332. In some cases, such as shown in fig. 1, the vaporizing fluid 210 may include a circulating fluid 236 and may be obtained from the same source to which it is connected. The first and second vaporizing fluid supply channels 2333A, 2333B may be insulated as necessary for delivering the vaporizing fluid 210 (i.e., CO) with sufficient supply and under sufficient pressure₂) Such that the vaporizing fluid 210 is directed through the inner vaporizing member 2332 and into the combustion chamber 222. As disclosed herein, such measures involving vaporizing component 230 and associated vaporizing fluid 210 may allow for combustion apparatus 220 to be at relatively high pressures and relatively high temperatures as otherwise disclosed hereinAnd (5) operating.

In this regard, the inner evaporation member 2332 may be comprised of, for example: porous ceramic materials, perforated materials, laminated materials, porous mats composed of fibers randomly oriented in two dimensions and ordered in a third dimension, or any other suitable material or combination thereof that exhibits the desired characteristics as disclosed herein (i.e., multiple flow channels or pores or other suitable openings 2335 for receiving and directing evaporative fluid through inner evaporative component 2332). Non-limiting examples of porous ceramics and other materials suitable for such evaporative-cooling systems include alumina, zirconia, phase change toughened zirconium (zirconium), copper, molybdenum, tungsten, copper-impregnated tungsten (copper-impregnated), molybdenum-coated tungsten (tungsten-coated), copper-coated tungsten (tungsten-coated), various high temperature nickel alloys, and rhenium-coated materials. Suitable material sources include, for example, CoorsTek, inc. (Golden, CO) (zirconium); ultrametaadvanced materials solutions (Pacoima, CA) (refractory metal coating); OrsamSylvania (Danvers, MA) (tungsten/copper); and markech international, Inc (PortTownsend, WA) (tungsten). Examples of suitable perforated materials for such evaporative-cooling systems include all of the above-mentioned materials and suppliers (wherein the perforated end structure may be obtained by perforating an initially non-porous material, for example, using methods known in the manufacturing art). Examples of suitable laminates include all of the above materials and suppliers (where laminated end structures may be obtained by laminating non-porous or partially porous structures in such a way as to obtain the desired end porosity, for example, using methods known in the manufacturing art).

Fig. 3A and 3B illustrate that in one aspect of the combustion apparatus 220, the structure defining the combustion chamber 222 may be formed by a "hot" interference fit between the evaporation component 230 and surrounding structure, such as a pressure containment component 2338 or a thermal insulation layer 2339 disposed between the evaporation component 230 and the pressure containment component 2338. For example, when relatively "cold," the evaporation component 230 may be made smaller in size radially and/or axially relative to the surrounding pressure containment component 2338. Likewise, when inserted into the pressure safety housing member 2338, there may be radial and/or axial gaps between them (see, e.g., fig. 3A). Of course, such a size difference may facilitate insertion of the evaporation component 230 into the pressure containment component 2338. However, when heated toward, for example, an operating temperature, the evaporation member 230 may be configured to expand radially and/or axially to reduce or eliminate the gap (see, e.g., fig. 3B). To do so, an interference axial and/or radial fit may be formed between the vaporizing component 230 and the pressure containment component 2338. In the case of evaporation members 230 having outer evaporation members 2331 and inner evaporation members 2332, such an interference fit may place the inner evaporation members 2332 under compression. Also, a suitable high temperature brittle material such as porous ceramic may be used to form the inner evaporation member 2332.

With inner evaporative component 2332 so configured, evaporative substance 210 may include, for example, carbon dioxide directed through inner evaporative component 2332 (i.e., from the same source as circulating fluid 236) such that evaporative substance 210 forms a buffer layer 231 (i.e., a "vapor wall") proximate inner evaporative component 2332 within combustion chamber 222, wherein buffer layer 231 may be configured to buffer the interaction between inner evaporative component 2332 and the heat associated with the liquefied non-combustible elements and the combustion products. That is, in some cases, vaporizing fluid 210 may be delivered through inner vaporizing component 2332, e.g., at least at a pressure within combustion chamber 222, where vaporizing fluid 210 (i.e., CO)₂Flow) into the combustion chamber 222 is sufficient for the vaporizing fluid 210 to mix with and cool the combustion products, thereby forming an outlet fluid mixture at a temperature sufficient relative to the inlet requirements of the subsequent downstream process (i.e., the turbine may require an inlet temperature of, for example, about 1,225 ℃), but wherein the outlet fluid mixture remains high enough to maintain slag droplets or other contaminants in the fuel in a fluid or liquid state. The liquid state of the non-combustible elements of the fuel may facilitate separation of these contaminants in liquid form, preferably in free-flowing low viscosity form, e.g., from the combustion products, with less likelihood of clogging or otherwise damaging any exhaust system that implements such separation. In practice, such requirements may depend on various factors, such as the type of solid carbonaceous fuel used (i.e., coal) and the specific characteristics of the slag formed during combustion. That is, the combustion chamber 222The combustion temperature within the carbonaceous fuel may be such that any non-combustible elements in the carbonaceous fuel are liquefied within the combustion products.

In a particular aspect, the porous inner evaporation members 2332 are thus configured to direct evaporation fluid radially inward and into the combustion chamber 222 so as to form a fluid barrier or buffer layer 231 (see, e.g., fig. 2) around the surface of the inner evaporation members 2332 defining the combustion chamber 222. The surface of the inner evaporation member 2332 is also heated by the combustion products. Also, the porous inner evaporation members 2332 may be configured to have a suitable thermal conductivity such that the evaporation fluid 210 passing through the inner evaporation members 2332 is heated while the porous inner evaporation members 2332 are simultaneously cooled, resulting in a temperature of the surface of the inner evaporation members 2332 defining the combustion chamber 222 in the region of highest combustion temperature of, for example, about 1,000 ℃. The fluid barrier or buffer layer 231 formed by the vaporizing fluid 210 in cooperation with the inner vaporizing elements 2332 thus buffers the interaction between the inner vaporizing elements 2332 and the high temperature combustion products and slag or other contaminant particles, and as such, the buffering of the inner vaporizing elements 2332 avoids contact, fouling or other damage. Further, the vaporizing fluid 210 may be introduced into the combustion chamber 222 via the inner vaporizing member 2332 in a manner such that the outlet mixture of the vaporizing fluid 210 and the combustion products surrounding the outlet portion 222B of the combustion chamber 222 is conditioned at the noted temperature (e.g., about 500 ℃ to about 2,000 ℃).

In particular embodiments, the combustion apparatus 220 may thus be configured as an efficient, evaporative-cooled combustion apparatus capable of providing relatively complete combustion of the fuel 254 at relatively high operating temperatures as described herein. Such a combustion device 220 may implement one or more cooling fluids and/or one or more vaporizing fluids 210 in some cases. Other components may also be implemented in connection with the combustion apparatus 220. For example, an air separation unit may be provided for separating N₂And O₂And the fuel injector means may be arranged to receive O from the air separation unit₂And mixing O₂With CO₂The circulating fluid is combined with a fuel stream comprising a gas, a liquid, a supercritical fluid, or at high density CO₂Slurrying in fluidsThe solid particulate fuel of (1).

In another aspect, the evaporative-cooled combustion apparatus 220 may include a fuel injector for injecting a pressurized fluid stream into the combustion chamber 222 of the combustion apparatus 220, wherein the fuel stream may include the treated carbonaceous fuel 254, the fluidizing medium 255 (which may include the circulating fluid 236, as discussed herein), and the oxygen 242. Oxygen (enriched) 242 and CO₂The circulating fluid 236 combines as a homogeneous supercritical mixture. The amount of oxygen present may be sufficient to combust the fuel and produce combustion products having a desired composition. The combustion apparatus 220 may also include a combustion chamber 222 configured as a high pressure, high temperature combustion volume for receiving a flow of steam entering the combustion volume through walls of the porous evaporation member 230 defining the combustion chamber 222 and the evaporated fluid 210. The feed rate of vaporizing fluid 210 may be used to control the combustor exit section/turbine inlet section temperature to a desired value and/or to cool vaporizing element 230 to a temperature compatible with the material forming vaporizing element 230. The evaporative fluid 210 directed through the evaporative components 230 provides a fluid/buffer layer at the surface of the evaporative components 230 defining the combustion chamber 222, wherein the fluid/buffer layer can inhibit particles of ash or liquid slag produced by the combustion of certain fuels from interacting with the exposed walls of the evaporative components 230.

The combustion chamber 222 may be further configured such that the flow of fuel (and the circulating fluid 236) may be injected or otherwise introduced into the combustion chamber 222 at a pressure greater than the pressure at which combustion occurs. The combustion apparatus 220 may include a pressure containment component 2338 at least partially surrounding the vaporization component 230 defining the combustion chamber 230, wherein an insulating component 2339 may be disposed between the pressure containment component 2338 and the vaporization component 230. In some cases, a heat rejection apparatus 2350, such as a jacketed water cooling system, defining a water circulation jacket 2337 may engage the pressure containment component 2338 (i.e., outside of the pressure containment component 2338, forming the "shell" of the combustion apparatus 220). The vaporizing fluid 210 implemented in connection with the vaporizing part 230 of the combustion device 220 may be, for example, mixed with a small amount of H₂O and/or inert gases such as N₂Or CO of argon₂. The evaporation member 230 may comprise, for example, porous metal, ceramicA composite matrix, a layered manifold, any other suitable structure, or combinations thereof. In some aspects, combustion within the combustion chamber 222 can produce a high pressure, high temperature combustion product stream, which can then be directed to a power generation device, such as a turbine, where expansion occurs, as more fully described herein.

By implementing a relatively high pressure as performed by the combustion apparatus as disclosed herein, it may act to concentrate the energy produced thereby to a relatively high intensity with a minimum volume, which in essence results in a relatively high energy density. This relatively high energy density allows downstream processing of this energy to be performed in a more efficient manner than processing at lower pressures and thus provides a technical feasibility factor. Aspects of the present disclosure may thus provide energy densities on the order of magnitude greater (i.e., 10-100 times) than existing power plants. Higher energy density increases process efficiency and, by reducing the size and mass of the equipment, and thus the cost of the equipment, the cost of the equipment required to perform the conversion of thermal energy to electricity can be reduced.

As discussed further herein, the combustion apparatus used in the methods and systems of the present invention can be used for the combustion of a variety of different carbonaceous fuel sources. In particular embodiments, the carbonaceous fuel may be substantially completely combusted such that no liquid or solid non-combustible materials are contained in the combustion product stream. However, in some embodiments, solid carbonaceous fuels (e.g., coal) that can be used in the present invention can result in the presence of non-combustible materials. In particular embodiments, the combustion device may include a device capable of achieving a combustion temperature that causes the non-combustible elements in the solid carbonaceous fuel to liquefy during combustion. In these cases, an arrangement for removing the liquefied incombustible element may be applied. Removal may be accomplished using, for example, a cyclone separator, an impingement separator, or a graded refractory pellet filter bed arranged in an annular configuration, or a combination thereof. In certain embodiments, the liquid droplets may be removed from the high temperature circulating fluid stream by a series of cyclonic separators, such as, for example, the separation device 2340 shown in fig. 4. In general, aspects of such cyclone separators practiced by the present disclosure may include a plurality of centrifugal separation devices 100 arranged in series, including an inlet centrifugal separation device 100A configured to receive the combustion product/outlet fluid stream and liquefied noncombustible elements associated therewith, and an outlet centrifugal separation device 100B configured to discharge the combustion product/outlet fluid stream from which the liquefied noncombustible elements are substantially removed. Each centrifugal separation device 100 comprises a plurality of centrifugal separation elements or cyclones 1 operably arranged in parallel around a central collection pipe 2, wherein each centrifugal separation element or cyclone 1 is configured to remove at least a portion of the liquefied non-combustible elements from the combustion products/outlet fluid stream and to direct the removed portion of the liquefied non-combustible elements to a sump 20. Such a separation apparatus 2340 may be configured to operate at elevated pressures and, as such, further include a pressure-containing housing 125 configured to house centrifugal separation equipment and a sump. In accordance with these aspects, the pressurized housing 125 may be an extension of the pressure containment block 2338 surrounding the combustion apparatus 220, or the pressurized housing 125 may be a separate block capable of engaging the pressure containment block 2338 attached to the combustion apparatus 220. In either case, due to the elevated temperature experienced by the separation device 2340 via the outlet fluid stream, the pressure-containing housing 125 may also include a heat dissipation system, such as a heat transfer jacket (not shown) having a circulating liquid therein, operatively engaged with the pressure-containing housing for removing heat therefrom. In some aspects, a heat recovery device (not shown) may be operably engaged with the heat transfer jacket, wherein the heat recovery device may be configured to receive a liquid circulating in the heat transfer jacket and recover thermal energy from the liquid.

In particular embodiments, the (slag removal) separation device 2340 illustrated in fig. 4 may be configured to be disposed in series with the combustion apparatus 220 about the outlet portion 222B of the combustion apparatus for receiving the outlet fluid stream/combustion products therefrom. The evaporatively cooled outlet fluid stream from the combustion apparatus 220, containing droplets of liquid slag (non-combustible elements), may be directed via a conical reducing pipe 10 into the central collection arrangement 2A of the inlet centrifugal separation device 100A. In one aspect, the separation apparatus 2340 may include three centrifugal separation devices 100A, 100B, 100C (although those skilled in the art will appreciate that such separation apparatus may include one, two, three, or more centrifugal separation devices, as necessary or desired). In this case, three centrifugal separation apparatus 100A, 100B, 100C in series operable arrangement provide a 3-stage cyclonic separation unit. Each centrifugal separation device comprises, for example, a plurality of centrifugal separation elements (cyclones 1) arranged around the circumference of a respective central collection tube 2. The central collection arrangement 2A and the central collection tube 2 of the inlet centrifugal separation device 100A and the intermediate centrifugal separation device 100C are each sealed at their outlet ends. In these cases, the outlet fluid flow is directed to the branch channel 11 corresponding to each centrifugal separation element (cyclone 1) of the respective centrifugal separation device 100. The branch channel 11 is configured to engage with the inlet end of each cyclone 1 to thereby form a tangential inlet (which may, for example, enable the outlet fluid flow entering the cyclone 1 to interact with the wall of the cyclone 1 in a spiral flow). The outlet channel 3 from each cyclone 1 is then routed into the inlet portion of the central collection tube 2 of the respective centrifugal separation apparatus 100. At the outlet centrifugal separation device 100B, the outlet fluid flow (from which the non-combustible elements are substantially separated) is conducted out of the central collection pipe of the outlet centrifugal separation device 100B and through the collection pipe 12 and the outlet nozzle 5, so that a "clean" outlet fluid flow can then be directed to a subsequent process, such as a device in connection with a phase change device. The exemplary three-stage cyclonic separation arrangement thus allows slag removal to reach below 5ppm by mass in the outlet fluid stream.

At each stage of the separating apparatus 2340, separated liquid slag is conducted from each cyclone 1 via an outlet pipe 4 extending towards a sump 20. The separated liquid slag is then directed into an outlet nozzle or pipe 14 extending from the sump 20 and pressure housing 125 for removal and/or recovery of components therefrom. In carrying out the slag removal, the liquid slag may be directed through a water cooling section 6 or otherwise through a section having a high pressure, cold water pipe connection, wherein interaction with the water causes the liquid slag to solidify and/or granulate. The mixture of solidified slag and water can then be separated in a vessel (collection arrangement) 7 into a slag/water fluid mixture which, in particular after depressurization, can be removed via a suitable valve 9, while any residual gas can be removed via a separation line 8. In some embodiments, a pair of vessels with associated systems operating sequentially may allow for continuous operation of the system.

Because the separation device 2340 may operate in conjunction with a relatively high temperature combustion product stream (i.e., a temperature sufficient to maintain the non-combustible elements in liquid form having a relatively low viscosity), in some instances it may be desirable that the surface of the separation device 2340 exposed to one of the combustion product/outlet fluid stream and the liquefied non-combustible elements associated therewith should be constructed of a material configured to have at least one of high temperature resistance, high corrosion resistance, and low thermal conductivity. Examples of such materials may include zirconia and alumina, although these examples are not intended to be limiting in any way. Also, in certain aspects, the separation device 2340 may be configured to substantially remove liquefied non-combustible elements from the combustion product/outlet fluid stream and maintain the non-combustible elements in a low viscosity liquid form, at least until they are removed from the sump 20. Of course, in embodiments where a non-solid fluid is used and the combustion product stream does not contain non-combustible materials, the addition of a slag separator may not be necessary.

In some embodiments, the separation apparatus 2340 may be used to separate particulate solid ash from the combustion of any fuel that produces non-combustible solid residues, such as coal. For example, coal may be ground to a desired size (e.g., such that less than 1wt% of the particles are pulverized coal including particles greater than 100 μm in size) and mixed with liquid CO₂And (4) pulping. In a specific embodiment, the liquid CO₂May be at a temperature of from about-40 c to about-18 c. The slurry may comprise from about 40% to about 60% by weight coal. The slurry can then be pressurized to the desired combustion pressure. Referring to fig. 1, the recirculation flow 236 may be divided for entry into the combustion chamber 220. The first portion (stream 236a) may be input to the combustor 220 via the mixing device 250, while the second portion (stream 236b) may be input to the combustor 220 by passing through the evaporative cooling layer 230. As described above, the following O can be used₂Operating the combustion chamber 220 at a fuel ratioTo form a reducing gas mixture (e.g. containing H)₂、CH₄、CO、H₂S and/or NH₃). The partial flow 236 through the evaporative cooling layer 230 into the combustor may be used to cool the combustion gases and CO₂The mixture of fluids is circulated to a temperature substantially below the solidification temperature of the ash (e.g., in the range of about 500 ℃ to about 900 ℃). The total gas stream 5 from separation device 2340 may be passed through a filtration unit that reduces the residual solid ash particle level to very low values (e.g., less than about 2mg/m of gas passing through the filter³). This clean gas is then combusted in a second combustion chamber where it can be diluted by another portion of the recirculated fluid stream 236. In these embodiments, the recirculated fluid flow 236 may be split between the two combustion chambers, if desired.

Any carbonaceous material may be used as fuel according to the invention. In particular, because of the high pressures and temperatures maintained by the oxy-combustion devices used in the methods and systems of the present invention, useful fuels include, but are not limited to, various grades and types of the following: coal, wood, oil, fuel oil, natural gas, coal-based fuel gas, tar from tar sands, bitumen, biomass, algae, fractionated combustible solid waste reuse, bitumen, secondary tires, diesel, gasoline, jet fuel (JP-5, JP-4), gas derived from gasification or pyrolysis of hydro-carbonaceous materials, ethanol, solid and liquid biofuels. This can be considered an important difference from prior art systems and methods. For example, known prior art systems for burning solid fuels such as coal require a very different design than systems that burn non-solid fuels such as natural gas.

The fuel may be suitably treated to enable injection into the combustion device at a sufficient velocity and at a pressure higher than the pressure within the combustion chamber. Such fuels may be in the form of a liquid, slurry, gel or paste, and have suitable fluidity and viscosity at ambient or elevated temperatures. For example, the fuel may be provided at a temperature of about 30 ℃ to about 500 ℃, about 40 ℃ to about 450 ℃, about 50 ℃ to about 425 ℃, or about 75 ℃ to about 400 ℃. Any solid fuel material may be suitably ground or shredded or otherwise processed to reduce particle size. Fluidizing or slurrying media may be added as necessary to achieve a suitable form and to meet the flow requirements of high pressure pumping. Of course, a fluidizing medium may not be necessary, depending on the form of the fuel (i.e., liquid or gas). Also, in some embodiments, the recycled circulating fluid that is circulated may be used as a fluidizing medium.

Suitable vaporizing fluids that may be used in the combustion chamber according to the present invention may include any fluid capable of flowing through the liner in sufficient quantities and pressures to form a vapor wall. In the present embodiment, CO₂It may be desirable to evaporate the fluid because the resulting vapor wall has excellent thermal insulation properties as well as visible and ultraviolet light absorbing properties. CO 2₂Can be used as the supercritical fluid. Other examples of evaporative fluids include H₂O, cooled combustion product gas recycled from downstream, oxygen, hydrogen, natural gas, methane, and other light hydrocarbons. The fuel may be used in particular as a vaporizing fluid during start-up of the combustion chamber in order to obtain a suitable operating temperature and pressure in the combustion chamber before injection of the main fuel source. The fuel may also be used as a vaporization fluid during switching between primary fuel sources to regulate the operating temperature and pressure of the combustion chamber, such as when switching coal to biomass as the primary fuel. In some embodiments, two or more vaporizing fluids may be used. Furthermore, different vaporizing fluids may be used at different locations along the combustion chamber. For example, a first vaporizing fluid may be used in a high temperature heat exchange zone and a second vaporizing fluid may be used in a low temperature heat exchange zone. The vaporizing fluid can be optimized for the temperature and pressure conditions of the combustion chamber, wherein the vaporizing fluid forms a vapor wall. In the present example, the vaporizing fluid is preheated recycle CO₂。

In one aspect, the present invention provides a method of generating electricity. In particular, the method utilizes CO₂A circulating fluid which is preferably recycled by the process, as described herein. The inventive method also utilizes a high efficiency combustor, such as an evaporatively cooled combustor as described above. In some embodiments, reference may generally be made to the flow chart shown in FIG. 5The method is described. As can be seen in this figure, a combustion chamber 220 is provided and various inputs are provided therein. Carbonaceous fuels 254 and O₂242 may be combined with the recycle fluid 236 (CO in this embodiment) if desired₂) Are introduced together into the combustion chamber 220. The optional presence of this component is indicated by the mixing device 250 indicated by the dashed line. In particular, two or all three substances (fuel, O)₂And CO₂Circulating fluid) may be combined in the mixing apparatus 250 prior to introduction into the combustion chamber 220.

In various embodiments, it may be desirable for the material entering the combustion chamber to exhibit specific physical characteristics that can promote the desired efficient power generation operation. For example, in certain embodiments, CO may be desired₂CO in the circulating fluid₂Is introduced into the combustion chamber at a defined pressure and/or temperature. In particular, CO introduced into the combustion chamber₂It can be beneficial to have a pressure of at least about 8 MPa. In further embodiments, the CO introduced into the combustion chamber₂May be at a pressure of at least about 10MPa, at least about 12MPa, at least about 14MPa, at least about 15MPa, at least about 16MPa, at least about 18MPa, at least about 20MPa, at least about 22MPa, at least about 24MPa, or at least about 25 MPa. In other embodiments, the pressure may be from about 8MPa to about 50MPa, from about 12MPa to about 50MPa, from about 15MPa to about 50MPa, from about 20MPa to about 50MPa, from about 22MPa to about 45MPa, from about 22MPa to about 40MPa, from about 25MPa to about 40MPa, or from about 25MPa to about 35 MPa. In addition, CO introduced into the combustion chamber₂It can be beneficial to have a temperature of at least about 200 ℃. In further embodiments, the CO introduced into the combustion chamber₂May be at a temperature of at least about 250 ℃, at least about 300 ℃, at least about 350 ℃, at least about 400 ℃, at least about 450 ℃, at least about 500 ℃, at least about 550 ℃, at least about 600 ℃, at least about 650 ℃, at least about 700 ℃, at least about 750 ℃, at least about 800 ℃, at least about 850 ℃ or at least about 900 ℃.

In some embodiments, it may be desirable for the fuel introduced into the combustion chamber to be provided under certain conditions. For example, in some embodiments, the first and second electrodes may,it may be desirable for the carbonaceous fuel to be introduced into the combustion chamber at a defined pressure and/or temperature. In some embodiments, the carbonaceous fuel may be mixed with CO₂The circulating fluid is introduced into the combustion chamber under the same or substantially similar conditions. The phrase "substantially similar conditions" can refer to a condition parameter (e.g., CO) that is within 5%, within 4%, within 3%, within 2%, or within 1% of the referenced condition parameter described herein₂Condition parameters of the circulating fluid). In certain embodiments, the carbonaceous fuel may be mixed with CO prior to introduction into the combustion chamber₂The circulating fluids are mixed. In these embodiments, carbonaceous fuels and CO are contemplated₂The circulating fluid will be under the same or substantially similar conditions (which may specifically include with respect to CO)₂The conditions described for circulating the fluid). In other embodiments, the carbonaceous fuel may be independent of CO₂A circulating fluid is introduced into the combustion chamber. In these cases, the carbonaceous fuel may still be associated with CO₂The circulating fluid is introduced under the pressure indicated. In some embodiments, the carbonaceous fuel is maintained at a different temperature than CO prior to introduction to the combustion chamber₂The temperature of the circulating fluid temperature may be useful. For example, the carbonaceous fuel may be introduced into the combustion chamber at a temperature of from about 30 ℃ to about 800 ℃, from about 35 ℃ to about 700 ℃, from about 40 ℃ to about 600 ℃, from about 45 ℃ to about 500 ℃, from about 50 ℃ to about 400 ℃, from about 55 ℃ to about 300 ℃, from about 60 ℃ to about 200 ℃, from about 65 ℃ to about 175 ℃, or from about 70 ℃ to about 150 ℃.

In other embodiments, it may be desirable for O to be introduced into the combustion chamber₂Provided under specific conditions. Such conditions may be the provision of O₂As attached to the method of (1). For example, it may be desirable to provide O at a particular pressure₂. In particular, O introduced into the combustion chamber₂It can be beneficial to have a pressure of at least about 8 MPa. In further embodiments, O introduced into the combustion chamber₂May be at a pressure of at least about 10MPa, at least about 12MPa, at least about 14MPa, at least about 15MPa, at least about 16MPa, at least about 18MPa, at least about 20MPa, at least about 22MPa, at least about 24MPa, at least about 25MPa, at least about 30MPa, at least about 35MPa, at least about 40MPa, at least about 45MPa, or at least about 50 MPa. O is₂May include utilizing an air compressor (or oxygen separator), such as cryogenic O₂Concentrator, O₂Transport separators or any similar devices, e.g. O₂Ion transport separator for separating O₂And ambient air. Alone or in combination therewith, O₂Can include feeding O₂Pressurized to achieve the desired pressure, as described above. This behavior may cause O₂Heating of (2). In some embodiments, O may be desired₂At a desired temperature that is different from the temperature achieved by pressurizing the other. For example, it may be desirable to subject O at a temperature of from 30 ℃ to about 900 ℃, from about 35 ℃ to about 800 ℃, from about 40 ℃ to about 700 ℃, from about 45 ℃ to about 600 ℃, from about 50 ℃ to about 500 ℃, from about 55 ℃ to about 400 ℃, from about 60 ℃ to about 300 ℃, from about 65 ℃ to about 250 ℃, or from about 70 ℃ to about 200 ℃₂To the combustion chamber. Further, in some embodiments, O₂Can be in contact with CO₂The circulating fluid and/or the carbonaceous fuel are introduced into the combustion chamber under the same or substantially similar conditions. This may result from mixing the various components prior to introduction into the combustion chamber, or may result from the production of O₂Produced in a specific way introduced into the combustion chamber. In a particular embodiment, O₂CO in an amount which is in molar proportion to a defined amount₂Are combined so that O₂Can be in contact with CO₂The circulating fluid stream is provided at the same temperature. For example, the combination may be carried out at a temperature below 100 ℃ while the CO is₂Under supercritical pressure. Due to CO₂By dilution, which eliminates the need to heat pure O alone₂Associated with the risk of burning. Such a mixture may be at a CO of about 1:2 to about 5:1, about 1:1 to about 4:1, or about 1:1 to about 3:1₂/O₂And (4) the ratio.

In some embodiments, O supplied to the combustion chamber₂Is substantially purified may be useful (i.e., O)₂Upgraded relative to the molar content of other components naturally present in the air). In certain embodiments, O₂May have greater than about 50mol%, greater than about 60mol%, greater than about 70mol%, greater than about 80mol%, greater than about 85mol%, greater than about 90mol%, greater than about 95mol%, greater thanAt a purity of about 96mol%, greater than about 97mol%, greater than about 98mol%, greater than about 99mol%, or greater than about 99.5 mol%. In other embodiments, O₂May have a molar concentration of about 85% to about 99.6mol%, about 85% to about 99mol%, about 90% to about 98mol%, or about 90% to about 97 mol%. Total CO from carbon in fuel₂Recovery facilitates the use of higher purity levels in the range of at least about 99.5 mol%.

CO₂The circulating fluid may be at the inlet of the combustion chamber and O₂Is introduced into the combustion chamber with a carbonaceous fuel. However, as described above with respect to the evaporatively cooled combustor, CO₂The circulating fluid may also be introduced into the evaporatively cooled combustion chamber as all or a portion of the evaporatively cooled cooling fluid introduced into the evaporative component through one or more evaporatively cooled fluid supply passages formed in the evaporatively cooled combustion chamber. In an embodiment according to the invention, CO₂The circulating fluid may be at the combustor inlet (i.e., along with O)₂And fuel) is introduced into the combustion chamber, and CO₂The circulating fluid may also be introduced into the combustion chamber as all or part of the evaporative cooling fluid via the evaporative component. In other embodiments, CO₂The circulating fluid may also be introduced into the combustion chamber as all or part of the evaporative cooling fluid only through the evaporative components (i.e., CO-free)₂Is introduced to contain O₂And a combustor inlet for fuel).

In some embodiments, the invention also features the proportions of the various components introduced into the combustion chamber. To achieve maximum combustion efficiency, it may be useful to combust carbonaceous fuels at high temperatures. However, the combustion temperature and the temperature of the combustion product stream exiting the combustion chamber may need to be controlled within defined parameters. In view of this, CO is provided in a specific ratio with respect to the fuel₂The circulating fluid may be useful so that the combustion temperature and/or turbine inlet temperature may be controlled within a desired range while also maximizing the amount of energy that may be converted to electricity. In particular embodiments, this may be achieved by adjusting the CO₂The ratio of the circulating fluid flow to the carbon in the fuel. The desired ratio may be influenced by the desired turbine inlet temperature and heat exchangeThe temperature differential between the inlet and outlet streams at the hot end of the exchanger, as described in more detail herein. The ratio is described in particular as CO₂CO in the circulating fluid₂To the carbon present in the carbonaceous fuel. For measuring CO introduced into the combustion chamber₂In some embodiments, CO supplied to the combustion chamber₂All contents of (i.e. at the inlet with fuel and O)₂Introduction of CO together₂And any CO used as evaporative cooling fluid₂) Is included in the calculation. However, in particular embodiments, the calculation may be based solely on the CO introduced at the combustor inlet₂Does not include CO used as an evaporative cooling fluid₂). In which CO is present₂In embodiments where the cooling fluid is introduced into the combustion chamber only as an evaporative cooling fluid, the calculation is based on CO introduced into the combustion chamber as an evaporative cooling fluid₂The amount of (c). Thus, the ratio can be described as CO input to the combustor inlet₂Compared to the carbon in the fuel fed to the combustion chamber. Alternatively, the ratio may be described as CO delivered to the combustor via an evaporative cooling fluid₂Compared to the carbon in the fuel fed to the combustion chamber.

In certain embodiments, the CO introduced into the combustion chamber₂The ratio of the recycle fluid to the carbon in the fuel may be from about 10 to about 50 on a molar basis (i.e., about 10 molCO)₂Carbon per mole of fuel to about 50molCO₂Per mole of carbon in the fuel). In further embodiments, the CO in the circulating fluid₂The ratio to carbon in the fuel may be about 15 to about 50, about 20 to about 50, about 25 to about 50, 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 30 to about 40. In other embodiments, the CO in the circulating fluid₂The ratio to carbon in the fuel may 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.

CO introduced into the combustion chamber₂The molar ratio to carbon present in the carbonaceous fuel can have a significant impact on the overall system thermal efficiency. Such asThe impact on efficiency may also be affected by the design and function of other components in the system, including the heat exchanger, water separator, and pressure boosting unit. The combination of various elements in the systems and methods described herein results in a particular CO that can be described herein₂High thermal efficiency is achieved at the/C ratio. Previously known systems and methods that do not include the various elements described herein generally require significantly less CO than is used in the present invention₂CO in the/C molar ratio₂the/C molar ratio in order to achieve efficiencies close to those achieved herein. However, the present invention has determined that CO is recycled₂To recycle CO₂Capable of exploiting CO that greatly surpasses those that can be used in the known art₂CO in the/C molar ratio₂The molar ratio of C to C. According to the invention, high CO is used₂the/C molar ratio is advantageously used to dilute impurities in the combustion stream. The corrosive or erosive effects of impurities (e.g., chloride and sulfur) on system components are thus greatly reduced. Current high chloride and/or high sulfur coals cannot be used in known systems because of the combustion products (which include HCl and H) from such coals₂SO₄) Are too corrosive and aggressive to power plant components to withstand. Many other impurities (e.g., solid ash particles and volatile matter containing elements such as lead, iodine, antimony, and mercury) can also cause severe internal damage to power plant components at high temperatures. Recycling CO₂Can greatly reduce or eliminate the deleterious effects of such impurities on power plant components. Then, to CO₂The choice of the/C molar ratio may involve complex considerations of efficiency and power plant erosion and corrosion effects, as well as CO₂Complex considerations for recirculation system component design and function. The invention enables the implementation of efficient CO₂Recycle and thus increased CO₂a/C molar ratio, which has a high thermal efficiency which is not to be expected in the known art. High CO content₂the/C molar ratio thus conveys at least the advantages mentioned above.

Similarly, O introduced into the combustion chamber is controlled₂The content of (c) can be useful. This may in particular depend on the operating properties of the combustion chamber. As described in more detail herein, the methods and systems of the present inventionThe system may allow operation in a fully oxidized mode, a fully reduced mode, or a variation of both. In the complete oxidation mode, O supplied to the combustion chamber₂Preferably at least in the stoichiometric amount necessary to achieve complete oxidation of the carbonaceous fuel. In certain embodiments, O is supplied₂Will exceed the stoichiometric amount by at least about 0.1mol%, at least about 0.25mol%, at least about 0.5mol%, at least about 1mol%, at least about 2mol%, at least about 3mol%, at least about 4mol%, or at least about 5 mol%. In other embodiments, O is supplied₂Will exceed the stoichiometric amount by about 0.1% to about 5mol%, about 0.25% to about 4mol%, or about 0.5% to about 3 mol%. In the fully reduced mode, O supplied to the combustion chamber₂Preferably, the carbonaceous fuel is converted into component H₂、CO、CH₄、H₂S and NH₃The desired stoichiometric amount plus more than at least about 0.1mol%, at least about 0.25mol%, at least about 0.5mol%, at least about 1mol%, at least about 2mol%, at least about 3mol%, at least about 4mol%, or at least about 5 mol%. In other embodiments, O is supplied₂Will exceed the stoichiometric amount by about 0.1% to about 5mol%, about 0.25% to about 4mol%, or about 0.5% to about 3 mol%.

In some embodiments, the method features of the invention may relate to CO₂Throughout the physical state of the various steps in the process. CO 2₂Are believed to exist in various states depending on the physical condition of the material. CO 2₂Has a triple point at 0.518MPa and-56.6 ℃, but CO₂Also has a critical pressure and temperature of 7.38MPa and 31.1 deg.C. Above this critical point, CO₂Exists as a supercritical fluid and the present invention has recognized that by circulating CO₂Maintaining at a specific point in a prescribed state can maximize the power generation efficiency. In a particular embodiment, the CO introduced into the combustion chamber₂Preferably in the form of a supercritical fluid.

Efficiency of a power generation system or method is generally understood to describe the ratio of the energy output of the system or method to the energy input into the system or method. In the case of power generation systems or methods, efficiency is typically measuredDescribed as the ratio of the power or power (e.g., in megawatts or Mw) output to the customer grid to the total low heating value thermal energy of the fuel burning the power (or power) generated. This ratio may then be referred to as net system or process efficiency (based on LHV). The efficiency may take into account all of the energy described by the internal system or process, including the production of purified oxygen (e.g., via an air separation unit), pressurized CO₂To be delivered to a pressurized pipeline and other systems or methods requiring energy input.

In various embodiments, the systems and methods of the present invention can utilize primarily CO in the cycle₂As a working fluid, wherein the carbonaceous fuel is in substantially pure O₂In excess of CO₂Combustion at a pressure of critical pressure (i.e., in the combustion chamber) produces a combustion product stream. The stream is turboexpanded and then passed through a recuperative heat exchanger. Turbine exhaust preheating of supercritical state recirculated CO in a heat exchanger₂The fluid is circulated. The preheated recycle CO₂The circulating fluid is fed into the combustion chamber where it mixes with the products from the combustion of the carbonaceous fuel, producing a total flow at a defined maximum turbine inlet temperature. The present invention may provide superior efficiency, at least in part due to the recognition of the benefits of minimizing the temperature difference at the hot end of the recuperative heat exchanger. This minimization can be achieved by utilizing a low temperature level heat source to heat a portion of the recycled CO prior to introduction into the combustion chamber₂To be implemented. At these low temperature levels, supercritical CO₂Is very high and this additional heating may allow the turbine exhaust stream to drive CO₂Preheating to a much higher temperature can significantly reduce the temperature difference at the hot end of the recuperative heat exchanger. In particular embodiments, useful cryogenic heat sources are air compressors used in adiabatically operated cryogenic air separation plants or hot exhaust streams from conventional gas turbines. In a particular embodiment of the invention, the temperature difference at the hot end of the recuperative heat exchanger is less than about 50 ℃, and preferably in the range of about 10 ℃ to about 30 ℃. The use of low pressure ratios (e.g., below about 12) is another factor that can increase efficiency. By using CO₂AsThe working fluid in combination with the low pressure ratio reduces the energy loss in raising the pressure of the cooled turbine exhaust to the recirculation pressure. A further advantage is the ability to obtain the conversion in the fuel as higher than CO at pipeline pressures (typically about 10MPa to about 20MPa)₂CO of high pressure fluid of supercritical pressure₂And has very little parasitic power consumption at about 100% carbon capture from fuel. Such system and method parameters are further described herein in more detail.

Returning to FIG. 5, carbonaceous fuel 254 introduced into combustion chamber 220 is combined with O₂242 and CO₂The recycled fluid 236 is combusted to produce the combustion products stream 40. In particular embodiments, combustor 220 is an evaporatively cooled combustor, such as described above. The combustion temperature may vary depending on the particular process conditions, e.g. the type of carbonaceous fuel used, the CO introduced into the combustion chamber₂The molar ratio to carbon in the fuel, and/or CO introduced into the combustion chamber₂And O₂In a molar ratio of (a). In particular embodiments, the combustion temperature is the temperature as described above with respect to the description of the evaporatively cooled combustor. In particularly preferred embodiments, combustion temperatures in excess of about 1,300 ℃ may be advantageous, as described herein.

It may also be useful to control the combustion temperature so that the flow of combustion products exiting the combustion chamber has a desired temperature. For example, for a stream of combustion products exiting a combustion chamber, it may be useful to have the following temperatures: a temperature of at least about 700 ℃, at least about 750 ℃, at least about 800 ℃, at least about 850 ℃, at least about 900 ℃, at least about 950 ℃, at least about 1,000 ℃, at least about 1,050 ℃, at least about 1,100 ℃, at least about 1,200 ℃, at least about 1,300 ℃, at least about 1,400 ℃, at least about 1,500 ℃, or at least about 1,600 ℃. In some embodiments, the combustion product stream may have a temperature of about 700 ℃ to about 1,600 ℃, about 800 ℃ to about 1,600 ℃, about 850 ℃ to about 1,500 ℃, about 900 ℃ to about 1,400 ℃, about 950 ℃ to about 1,350 ℃, or about 1,000 ℃ to about 1,300 ℃.

As mentioned above, CO₂Generating electricity in its entiretyThe pressure in the cycle may be a key parameter in maximizing the efficiency of the power cycle. While it may be important to have a particular defined pressure for the material introduced into the combustion chamber, it may likewise be important to have a defined pressure for the flow of combustion products. In particular, the pressure of the combustion product stream may be related to the CO introduced into the combustion chamber₂The pressure of the circulating fluid is related. In particular embodiments, the pressure of the combustion product stream may be CO introduced into the combustion chamber₂At least about 90% of the pressure-i.e., in the circulating fluid. In further embodiments, the pressure of the combustion product stream may be CO introduced into the combustion chamber₂At least about 91%, 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% of the pressure.

The chemical composition of the combustion product stream exiting the combustion chamber can vary depending on the type of carbonaceous fuel used. Importantly, the combustion product stream will include CO that is recycled and reintroduced into the combustion chamber or other cycle₂As described in more detail below. In addition, excess CO₂(including CO due to fuel combustion₂) Can be derived from CO₂Recycle fluid recovery (particularly where it is suitable for direct transfer to CO)₂The pressure of the pipeline) for isolation or other processing, which does not include release to the atmosphere. In further embodiments, the combustion product stream may include one or more of the following: steam, SO₂、SO₃、HCI、NO、NO₂Hg, excess O₂、N₂Ar and possibly other pollutants that may be present in the combusted fuel. The presence of these species in the combustion product stream may be consistently CO₂The fluid stream is recycled unless removed, such as by the methods described herein. CO removal₂Such substances present outside can be referred to as "minor components".

As seen in fig. 5, the combustion product stream 40 may be directed to a turbine 320 where the combustion product stream 40 is expanded to generate electricity (e.g., via a generator to generate electricity, which is not shown in the illustration). The turbine 320 may have a flow of combustion products 40And for releasing CO₂To the turbine exhaust stream 50. Although a single turbine 320 is shown in fig. 5, it should be understood that more than one turbine may be used, with multiple turbines connected in series or optionally separated by one or more other components, such as other combustion groups, separation components, and the like.

Again, in this step, the process parameters can be closely controlled to maximize cycle efficiency. Existing natural gas power plant efficiency is strictly dependent on turbine inlet temperature. For example, a great deal of work has been done to implement turbine technology at substantial cost, with inlet temperatures as high as about 1,350 ℃. The higher the turbine inlet temperature, the higher the plant efficiency, and the more expensive the turbine, and potentially, the shorter its life. Some utilities are hampered by paying higher prices and also risk shorter lifetimes. Although the present invention may utilize such turbines in some embodiments to increase efficiency even further, this is not required. In particular embodiments, the present systems and methods may achieve desired efficiencies while utilizing a much lower range of turbine inlet temperatures, as described above. Thus, to the extent that a particular efficiency is achieved, features of the invention may be as described herein while providing a flow of combustion products to the turbine inlet at a defined temperature, which, as described herein, may be significantly less than what is recognized in the art as being required to achieve the same efficiency with the same fuel.

As described above, the combustion product stream 40 exiting the combustor 220 preferably has CO with the CO entering the combustor 220₂The pressure of the circulating fluid 236 is closely approximated (closelyaligned). In particular embodiments, the combustion product stream 40 is thus at a level such that the CO present in the stream₂Temperature and pressure in the supercritical fluid state. As the combustion product stream 40 expands through the turbine 320, the pressure of the stream decreases. Preferably, this pressure drop is controlled such that the pressure of the combustion product stream 40 is at a defined ratio to the pressure of the turbine exhaust stream 50. In certain embodiments, the pressure ratio of the flow of combustion products at the turbine inlet to the turbine exhaust stream at the turbine outlet is less than about 12. This can be defined as the inlet pressure (I)_p) And outlet pressure (O)_p) Ratio (i.e., I)_p/O_p). In further embodiments, the pressure ratio may 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 turbine may have an inlet pressure to outlet pressure ratio of about 1.5 to about 12, about 2 to about 12, about 3 to about 12, about 4 to about 12, about 2 to about 11, about 2 to about 10, about 2 to about 9, about 2 to about 8, about 3 to about 11, about 3 to about 10, about 3 to about 9, about 4 to about 11, about 4 to about 10, about 4 to about 9, or about 4 to about 8.

In particular embodiments, the turbine exhaust stream may be expected to be under conditions such that the CO in the stream is₂Is no longer in the supercritical fluid state but is in the gaseous state. For example, supplying gaseous CO₂Can facilitate the removal of any minor components. In some embodiments, the turbine exhaust stream has a pressure lower than CO₂The pressure at which it will be in its supercritical state. Preferably, the turbine exhaust stream has a pressure less than about 7.3MPa, less than or equal to about 7MPa, less than or equal to about 6.5MPa, less than or equal to about 6MPa, less than or equal to about 5.5MPa, less than or equal to about 5MPa, less than or equal to about 4.5MPa, less than or equal to about 4MPa, less than or equal to about 3.5MPa, less than or equal to about 3MPa, less than or equal to about 2.5MPa, less than or equal to about 2MPa, or less than or equal to about 1.5 MPa. In other embodiments, the pressure of the turbine exhaust stream may be from about 1.5MPa to about 7MPa, from about 3MPa to about 7MPa, or from about 4MPa to about 7 MPa. Preferably, the pressure of the turbine exhaust stream is less than the CO at the cooling temperature encountered by the stream₂Condensing pressure (e.g., ambient cooling). Therefore, according to the present invention, it is preferred that the CO downstream of the turbine 320 (and preferably upstream of the booster unit 620) is₂Should be maintained in the gaseous state and not be allowed to reach a state where liquid CO can be formed₂The conditions of (1).

Although the passage of the combustion product stream through the turbine may result in a certain amount of temperature drop, the turbine exhaust stream typically has a temperature that may impede the removal of any minor components present in the combustion product stream. For example, the turbine exhaust stream may have a temperature of about 500 ℃ to about 1,000 ℃, about 600 ℃ to about 1,000 ℃, about 700 ℃ to about 1,000 ℃, or about 800 ℃ to about 1,000 ℃. Because the temperature of the combustion product stream is relatively high, it may be advantageous for the turbine to be made of a material capable of withstanding such high temperatures. For turbines, it may also be useful to include materials that provide excellent chemical resistance to the types of secondary species that may be present in the combustion product stream.

In some embodiments, it can therefore be useful to pass the turbine exhaust stream 50 through at least one heat exchanger 420 that cools the turbine exhaust stream 50 and provides CO at a temperature within a defined range₂Circulating fluid stream 60. In particular embodiments, the CO exiting heat exchanger 420 (or the last heat exchanger in the series when two or more heat exchangers are used)₂The circulating fluid 60 has a temperature of less than about 200 ℃, less than about 150 ℃, less than about 125 ℃, less than about 100 ℃, less than about 95 ℃, less than about 90 ℃, less than about 85 ℃, less than about 80 ℃, less than about 75 ℃, less than about 70 ℃, less than about 65 ℃, less than about 60 ℃, less than about 55 ℃, less than about 50 ℃, less than about 45 ℃ or less than about 40 ℃.

As mentioned above, it can be advantageous for the pressure of the turbine exhaust to have a pressure that is at a particular ratio to the pressure of the flow of combustion products. In particular embodiments, the turbine exhaust stream is passed directly through one or more heat exchangers described herein without passing through any other components of the system. Thus, the pressure ratio can also be described as the ratio of the pressure at which the combustion product stream exits the combustion chamber compared to the pressure at which the stream enters the warm end of the heat exchanger (or, when a series of heat exchangers is used, the first heat exchanger). Again, the pressure ratio is preferably less than about 12. In further embodiments, the pressure ratio of the combustion product stream to the stream entering the heat exchanger may 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 may be about 1.5 to about 10, about 2 to about 9, about 2 to about 8, about 3 to about 8, or about 4 to about 8.

While the use of an evaporatively cooled combustor allows for high heat combustion, the systems and methods of the present invention may be characterized by the ability to supply the turbine exhaust stream to a heat exchanger (or series of heat exchangers) at a temperature that is sufficiently low to reduce the costs associated with the system, increase the life of the heat exchanger(s), and improve the performance and reliability of the system. In specific embodiments, the hottest operating temperature in a system or method according to the invention is less than about 1,100 ℃, less than about 1,000 ℃, less than about 975 ℃, less than about 950 ℃, less than about 925 ℃, or less than about 900 ℃.

In certain embodiments, it can be particularly useful for the heat exchanger 420 to include at least two heat exchangers in series for receiving the turbine exhaust stream 50 and cooling it to a desired temperature. The type of heat exchanger used may vary depending on the conditions of entry into the heat exchanger. For example, the turbine exhaust stream 50 may be at a relatively high temperature as described above, and therefore, it may be beneficial for the heat exchanger directly receiving the turbine exhaust stream 50 to be made of high performance materials designed to withstand extreme conditions. For example, a first heat exchanger in a series of heat exchangers may compriseAlloys or similar materials. Preferably, the first heat exchanger in the series comprises a material capable of withstanding the following continuous operating temperatures: a temperature of at least about 700 ℃, at least about 750 ℃, at least about 800 ℃, at least about 850 ℃, at least about 900 ℃, at least about 950 ℃, at least about 1,000 ℃, at least about 1,100 ℃, or at least about 1,200 ℃. It may also be beneficial for the one or more heat exchangers to comprise a material having excellent chemical resistance to the type of secondary materials that may be present in the combustion product stream.Alloys are available from specialmetals corporation, and some embodiments may include austenitic nickel-chromium-based alloys. Examples of alloys that may be useful includeAn example of an advantageous heat exchanger design is a diffusion bonded compact plate heat exchanger with chemically milled fins in a plate made of a high temperature material such as one of the alloys mentioned above. Suitable heat exchangers may include those known under the trade name(from meggitusa, Houston, TX).

The first heat exchanger in the series is preferably capable of transferring sufficient heat from the turbine exhaust stream to enable one or more other heat exchangers present in the series to be made of more conventional materials such as stainless steel. In particular embodiments, at least two heat exchangers or at least three heat exchangers are used in series to cool the turbine exhaust stream to a desired temperature. In the following description heat transfer from turbine exhaust stream to CO₂The effectiveness of utilizing multiple heat exchangers in a series can be seen in the description of circulating fluid to reheat the circulating fluid prior to introduction into the combustion chamber.

In some embodiments, the methods and systems may be characterized as single stage combustion methods or systems. This can be achieved by utilizing a high efficiency combustor such as the above-described evaporatively cooled combustor. Basically, the fuel can be burned substantially completely in the single combustion chamber, so that it is not necessary to provide a series of combustion chambers to completely burn the fuel. Thus, in some embodiments, the present methods and systems may be described such that the evaporatively cooled combustor is the only combustor. In further embodiments, the methods and systems may be described such that combustion occurs only in a single evaporatively cooled combustor prior to passing the exhaust stream into the heat exchanger. In still other embodiments, the methods and systems may be described such that the turbine exhaust stream is delivered directly into the heat exchanger without passing through an additional combustor.

After cooling, the CO leaving the at least one heat exchanger 420₂The circulating fluid stream 60 may undergo other treatments to leave CO behind₂Any minor components in the circulating fluid stream 60 are separated from the combustion of the fuel. As shown in fig. 5, the circulating fluid stream 60 may be directed to one or more separation units 520. As discussed in more detail below, the present invention may be particularly characterized as being capable of providing combustion from carbonaceous fuels without atmospheric CO₂A method of releasing to generate electricity. This may be achieved, at least in part, by utilizing CO formed in the combustion of the carbonaceous fuel in the power generation cycle₂As a circulating fluid. Although, in some embodiments, the CO is₂Continuous combustion and recirculation as a circulating fluid may cause CO in the system₂And (4) accumulating. In this case, at least a portion of the CO is withdrawn from the circulating fluid₂(e.g., in an amount about equal to the amount of CO resulting from combustion of the carbonaceous fuel₂Amount) can be useful. This recovered CO₂May be treated by any suitable method. In a specific embodiment, CO₂May be directed to the pipeline for isolation or processed by suitable methods, as described below.

CO entering the pipeline₂Should be substantially free of water to prevent corrosion of the carbon steel for the pipe, which may be CO₂A requirement for the specifications of the piping system. Despite "wet" CO₂Can be directly input into stainless steel CO₂In pipelines, but this is not always possible and, in fact, it may be more desirable to utilize carbon steel pipelines due to cost issues. Thus, in certain embodiments, CO₂Water present in the recycle stream (e.g., water formed during the combustion of carbonaceous fuels and continuously present in the combustion product stream, turbine exhaust stream, and CO)₂In the circulating fluid stream) CO that can be cooled from the bulk as a liquid phase₂Removed from the circulating fluid stream. In particular embodiments, this may be achieved by providing CO at a pressure when the gaseous mixture is cooled to the lowest temperature reached by the ambient temperature cooling means₂By circulating fluid (e.g. in gaseous state), the pressure being less than the gas mixtureCO present in the matter₂The pressure at which it is liquefied. For example, in particular in the separation of secondary components therefrom, CO₂The circulating fluid may be provided at a pressure of less than 7.38 MPa. Even lower temperatures may be required if a cooling device is utilized that is at a temperature in a low ambient range or significantly below ambient. This allows the water to be separated as a liquid, and also minimizes the purified CO leaving the separation unit₂Contamination of recycle stream 65. This also limits the turbine exhaust pressure to a value less than the critical pressure of the turbine exhaust. The actual pressure may depend on the temperature of the available ambient cooling means. For example, if water separation occurs at 30 ℃, a pressure of 7MPa allows for CO to be separated₂The condensation pressure has a margin of 0.38 MPa. In some embodiments, the CO exiting the heat exchanger and entering the separation unit₂The circulating fluid may be provided at a pressure of from about 2MPa to about 7MPa, from about 2.25MPa to about 7MPa, from about 2.5MPa to about 7MPa, from about 2.75MPa to about 7MPa, from about 3MPa to about 7MPa, from about 3.5MPa to about 7MPa, from about 4MPa to about 7MPa, or from about 4MPa to about 6 MPa. In other embodiments, the pressure may be substantially the same as the pressure at the turbine outlet.

In a specific embodiment, purified CO₂The recycle stream 65 is free or substantially free of water vapor after water separation. In some embodiments, purified CO₂The recycle stream may be characterized as containing only the following amounts of water vapor: less than 1.5% by moles, less than 1.25% by moles, less than 1% by moles, less than 0.9% by moles or less than 0.8% by moles, less than 0.7% by moles, less than 0.6% by moles, less than 0.5% by moles, less than 0.4% by moles, less than 0.3% by moles, less than 0.2% by moles or less than 0.1% by moles. In some embodiments, purified CO₂The circulating fluid stream may contain only the following amounts of water vapor: from about 0.01% to about 1.5% by moles, from about 0.01% to about 1% by moles, from about 0.01% to about 0.75% by moles, from about 0.01% to about 0.5% by moles, from about 0.01% to about 0.25% by moles, from about 0.05% to about 0.5% by moles, or from about 0.05% to about 0.25% by moles.

Under the conditions of temperature and pressureSupply of CO₂It can be very advantageous to circulate a fluid to facilitate separation of secondary components, such as water. In other words, the present invention may specifically specify that CO is to be introduced₂The circulating fluid is maintained under desired conditions to maintain the CO₂CO in the circulating fluid₂And the water is in a desired state to facilitate separation prior to separation. By supplying CO at the pressure as described above₂Circulating a fluid, the temperature of which can be lowered to the point where the water in the stream will be in the liquid state and thus more readily removed from the gaseous CO₂To a separate point in (c).

In certain embodiments, it may be desirable to provide further drying conditions for the purified CO₂The circulating fluid is completely or substantially free of water. As described above, water is driven from CO based on phase differences in matter₂Separation in the circulating fluid may leave a smaller portion (i.e., a low concentration) of water remaining in the CO₂The fluid is circulated. In some embodiments, the CO containing a minor portion of the water remaining therein continues to be used₂A circulating fluid is acceptable. In other embodiments, the CO is reacted₂It can be useful for the circulating fluid to undergo other treatments to facilitate removal of all or a portion of the remaining water. For example, low concentrations of water may be removed by a desiccant dryer or other device that would be suitable according to the present invention.

Supplying CO to a separation unit at a defined pressure₂Circulating fluid can be particularly advantageous to again maximize the efficiency of the power cycle. In particular, CO is supplied at a defined pressure range₂The circulating fluid enables the purification of CO in the gas phase₂The circulating fluid is compressed to a high pressure with minimal overall power consumption. As described below, such pressurization may be necessary to partially purify the CO₂The circulating fluid can be recycled to the combustor and a portion can be supplied at a desired duct pressure (e.g., about 10MPa to about 20 MPa). This further illustrates the advantages of minimizing the inlet to outlet pressure ratio of the expansion turbine as described above. This serves to increase the overall cycle efficiency and also bring the discharge pressure from the turbine into the desired range described above for the removal of CO₂Separation of water from other minor components by the circulating fluid。

CO₂One embodiment of the circulating fluid flowing through the separation unit 520 is illustrated in FIG. 6. As can be seen in this figure, the CO from the heat exchanger can be made to flow from₂The circulating fluid stream 60 passes through a cold water heat exchanger 530 (or any similar functioning device) which further utilizes water from the CO₂Removing heat and discharging mixed phase CO from the recycle stream 60₂Circulating a fluid 61 in which CO₂Is still gas and CO₂The water in the circulating fluid is converted to the liquid phase. For example, by reacting CO₂The circulating fluid 60 can pass the CO through the cold water heat exchanger 530₂The circulating fluid is cooled to a temperature of less than about 50 ℃, less than about 55 ℃, less than about 40 ℃, less than about 45 ℃, less than about 40 ℃ or less than about 30 ℃. Preferably, CO passes through the cold water heat exchanger 530₂The pressure of the circulating fluid is substantially unchanged. Mixed phase CO₂The circulating fluid 61 is directed to a water separation unit 540 where a liquid water stream 62a is discharged from the separator 520. Also leaving the water separation unit 540 is enriched CO₂Circulating fluid stream 62 b. The enriched stream can be used as purified CO₂The circulating fluid stream 65 exits the separator 520 directly. In alternative embodiments (e.g., streams and assemblies as indicated by the dashed lines), the enriched CO₂The circulating fluid stream 62b may be directed to one or more additional separation units 550 to remove other secondary components, as described in more detail below. In a specific embodiment, CO₂Any other minor components of the recycled fluid may be removed after the water is removed. CO 2₂The recycle fluid is then used as purified CO₂The circulating fluid 65 exits the one or more additional separation units. However, in some embodiments, the mixed phase CO is removed before water removal₂The recycle stream 61 may be first directed to remove one or more minor components, while the partially purified stream may then be directed to a water separation unit 540. Various separator combinations that may be desired will occur to those skilled in the art of the present disclosure, and all such combinations are intended to be incorporated by the present invention.

As mentioned above, in addition to water, CO₂The circulating fluid may contain other minor components such as,such as fuel-derived impurities, combustion-derived impurities, and oxygen-derived impurities. Such minor components may also be separated from the cooled gaseous CO at the same or nearly the same time as the water is separated₂Removed from the circulating fluid. For example, minor components such as SO in addition to water vapor₂、SO₃、HCI、NO、NO₂Hg and excess O₂、N₂And Ar can also be removed. CO 2₂These minor components of the recycle stream, often considered as impurities or contaminants, can all be removed from the cooled CO using suitable methods (e.g., the methods described in U.S. patent application publication No. 2008/0226515 and european patent application nos. EP1952874 and EP1953486, which are incorporated herein by reference in their entirety)₂Removed from the circulating fluid. SO (SO)₂And SO₃Can be 100% converted into sulfuric acid>95% NO and NO₂Can be converted into nitric acid. CO 2₂Any excess O present in the circulating fluid₂May be separated as a rich stream for optional recycle to the combustor. Any inert gas present (e.g. N)₂And Ar) can be vented to atmosphere at low pressure. In certain embodiments, CO₂The circulating fluid can thus be purified so that the CO resulting from the combustion of carbon in the fuel₂Can ultimately be delivered as a high density purified stream. In a specific embodiment, purified CO₂The circulating fluid may comprise CO at a concentration of at least 98.5mol%, at least 99mol%, at least 99.5mol%, or at least 99.8mol%₂. In addition, CO₂The circulating fluid may be supplied at a desired pressure for direct input of CO₂In a conduit, for example, at least about 10MPa, at least about 15MPa, or at least about 20 MPa.

As summarized above, the carbonaceous fuel 254 is in O₂242 and CO₂Combustion in the presence of the circulating fluid 236 in the evaporatively cooled combustion chamber 220 can form a combustion products stream 40 having a relatively high temperature and pressure. Can make the carbon dioxide contain relatively large amount of CO₂The combustion product stream 40 is passed through a turbine 320 to expand the combustion product stream 40, thereby reducing the pressure of the stream and generating power. The turbine exhaust stream 50 exiting the outlet of the turbine 320 is at a reduced pressure, but still retains a relatively high temperature. Due to combustion productsContaminants and impurities are present in the stream, in the presence of CO₂It is advantageous to separate out these contaminants and impurities before the recycle fluid is recycled back into the system. To accomplish this separation, the turbine exhaust stream 50 is cooled by passing through one or more heat exchangers 420. Separation of the secondary products (e.g., water and any other contaminants and impurities) can be achieved as described above. To remove CO₂The recycle stream is recycled back to the combustor, necessitating reheating and repressurizing the CO₂The fluid is circulated. In certain embodiments, the invention may be particularly characterized by the implementation of specific method steps to maximize the efficiency of the power generation cycle while maximizing the prevention of contaminants (e.g., CO)₂) And is discharged to the atmosphere. This is particularly relevant in relation to cooled and purified CO leaving the separation unit₂As can be seen when the circulating fluid is reheated and repressurized.

As further illustrated in FIG. 5, the purified CO exiting the one or more separation units 520 may be made to exit₂Circulating fluid 65 through one or more pressure increasing units 620 (e.g., pumps, compressors, etc.) to increase the purified CO₂The pressure of the circulating fluid 65. In certain embodiments, CO is purified₂The circulating fluid 65 may be compressed to a pressure of at least about 7.5MPa or at least about 8 MPa. In some embodiments, the purified CO can be passed through a single pressure boost unit₂The pressure of the circulating fluid is increased to the desired pressure for introduction into the combustion chamber 220 as described herein.

In particular embodiments, the pressurization may be performed in pressurization unit 620 using a series of two or more compressors (e.g., pumps). One such embodiment is shown in FIG. 7, where CO is purified₂The recycle fluid 65 passes through a first compressor 630 to purify the CO₂The circulating fluid 65 is compressed to a first pressure (which preferably exceeds CO)₂Critical pressure) and thus stream 66. Stream 66 may be directed to a cold water heat exchanger 640 that recovers heat (e.g., heat formed by the pressurization activity of the first compressor) and forms stream 67, which is preferably at a temperature near ambient. Stream 67 may be directed to a second compressor 650 for CO utilization₂The circulating fluid is pressurized to a second pressure greater than the first pressureAnd (4) pressure. As described below, the second pressure may be substantially similar to CO₂The circulating fluid is fed (or recirculated) to the desired pressure in the combustion chamber.

In particular embodiments, first compressor 630 may be used to increase purified CO₂Pressure of the circulating fluid 65, so that the purified CO₂The circulating fluid is converted from a gaseous state to a supercritical fluid state. In a specific embodiment, CO is purified₂The recycle fluid may be pressurized at the first compressor 630 to a pressure of about 7.5MPa to about 20MPa, about 7.5MPa to about 15MPa, about 7.5MPa to about 12MPa, about 7.5MPa to about 10MPa, or about 8MPa to about 10 MPa. The stream 66 leaving the first compressor 630 (which is in a supercritical fluid state) is then passed through a cold water heat exchanger 640 (or any similar functional device) which can convert the CO₂The circulating fluid is cooled to a temperature sufficient to form a dense fluid that can be more efficiently pumped to even higher pressures. In view of the large volume of CO being recycled for use as a circulating fluid₂This can be significant. Pumping large volumes of CO in supercritical fluid state₂Can have significant energy consumption for the system. However, the present invention recognizes that an advantageous increase in efficiency can be achieved by making the CO₂Increasing density and thus reducing supercritical CO pumped back to the combustion chamber for recirculation₂To the total volume of the container. In a specific embodiment, CO₂The circulating fluid can be at least about 200kg/m after exiting the cold water heat exchanger 640 (and before being heated by the heat exchanger unit 420)³At least about 250kg/m³At least about 300kg/m³At least about 350kg/m³At least about 400kg/m³At least about 450kg/m³At least about 500kg/m³At least about 550kg/m³At least about 600kg/m³At least about 650kg/m³At least about 700kg/m³At least about 750kg/m³At least about 800kg/m³At least about 850kg/m³At least about 900kg/m³At least about 950kg/m³Or at least about 1,000kg/m³The density of (2). In other embodiments, the density may be about 150kg/m³To about 1,1,100kg/m³About 200kg/m³To about 1,000kg/m³About 400kg/m³To about 950kg/m³About 500kg/m³To about 900kg/m³Or about 500kg/m³To about 800kg/m³。

In particular embodiments, passing stream 66 through cold water heat exchanger 640 may introduce CO₂The circulating fluid is cooled to a temperature of less than about 60 ℃, less than about 50 ℃, less than about 40 ℃, or less than about 30 ℃. In other embodiments, the CO leaving cold water heat exchanger 640 as stream 67₂The temperature of the circulating fluid may be from about 15 ℃ to about 50 ℃, from about 20 ℃ to about 45 ℃, or from about 20 ℃ to about 40 ℃. CO in stream 67 entering second compressor 650₂The circulating fluid is in a position that facilitates energy efficient pumping of the stream to a means for CO as described herein₂The circulating fluid is introduced at a desired pressure in the combustion chamber. E.g. pressurized supercritical CO₂The circulating fluid stream 70 can be further pressurized to a pressure of at least about 12MPa, at least about 15MPa, at least about 16MPa, at least about 18MPa, at least about 20MPa, or at least about 25 MPa. In some embodiments, the pressurized supercritical CO₂The recycle fluid stream 70 may be further pressurized to a pressure of from about 15MPa to about 50MPa, from about 20MPa to about 45MPa, or from about 25MPa to about 40 MPa. Any type of compressor capable of operating at the temperatures and achieving the pressures described may be used, such as a high pressure multi-stage pump.

Pressurized CO exiting one or more pressurizing units 620₂The recycle fluid stream 70 may be directed back to the heat exchanger previously used to cool the turbine exhaust stream 50. As shown in FIG. 5, pressurized CO may be used₂The circulating fluid stream 70 first passes through a gas stream splitter 720, which forms CO₂Pipeline fluid stream 80 and CO₂Recycle fluid stream 85 (except for CO present in this stream)₂Actual amount of it with CO₂The circulating fluid flow 70 is substantially the same). Thus, in some embodiments, the CO has been pressurized₂At least a portion of the CO in the circulating fluid stream₂Is introduced into the pressurized conduit for isolation. From CO₂Circulating fluid stream removes and directs CO to pipeline (or other sequestration or treatment device)₂Depending on the amount of fuel introduced into the combustion chamberTo control the desired CO of the combustion temperature₂And the actual CO present in the combustion exhaust stream exiting the combustion chamber₂The amount of (c) is varied. In some embodiments, the CO recovered as described above₂May be substantially the amount of CO formed by combustion of a carbonaceous fuel in a combustion chamber₂The amount of (c).

To achieve efficient operation, the CO that will exit the pressurizing unit 620₂It can be advantageous to heat the circulating fluid to a temperature at which the supercritical fluid has a much lower specific heat. This amounts to providing a very large heat input in a relatively low temperature range. Partially recycling CO using an external heat source (e.g., a relatively low temperature heat source)₂The circulating fluid provides additional heating allowing the heat exchanger unit 420 to have the turbine exhaust stream 50 at the hot end of the heat exchanger unit 420 (or, when a series of two or more heat exchangers is used, the first heat exchanger) with the recirculated CO₂With a small temperature difference between the circulating fluid streams 236. In particular embodiments, the pressurized CO is₂Circulating a fluid through one or more heat exchangers may be used to pressurize the CO₂The circulating fluid stream is heated to a desired temperature for pressurizing the CO₂The circulating fluid stream enters the combustion chamber. In certain embodiments, the CO is introduced into the reaction vessel₂Pressurised CO before the circulating fluid stream is fed into the combustion chamber₂The circulating fluid stream is heated to a temperature of at least about 200 ℃, at least about 300 ℃, at least about 400 ℃, at least about 500 ℃, at least about 600 ℃, at least about 700 ℃, or at least about 800 ℃. In some embodiments, the heating may reach a temperature of about 500 ℃ to about 1,200 ℃, about 550 ℃ to about 1,000 ℃, or about 600 ℃ to about 950 ℃.

FIG. 8 illustrates an embodiment of a heat exchange unit 420 in which heat is recovered from the turbine exhaust stream 50 using three separate heat exchangers in series to provide CO at appropriate conditions₂Recycling the fluid stream 60 for removing the secondary components and, at the same time, CO₂Recycle fluid stream 236 is recycled to the pressurized supercritical CO prior to introduction into the combustion chamber₂The circulating fluid stream 70 (or 85) adds heat. As followsFurther described, the present systems and methods may be retrofitted from conventional power systems (e.g., coal-fired power plants) to increase their efficiency and/or output. In some embodiments, the heat exchange unit 420 described below may therefore be referred to as a primary heat exchange unit in such a retrofit, where a secondary heat exchange unit (as illustrated in fig. 12) is also used. The secondary heat exchange unit may thus be, for example, one or more heat exchangers for superheating a steam stream. The use of the terms primary and secondary heat exchange units should not be construed to limit the scope of the invention but merely to provide clarity in the description.

In the embodiment encompassed by fig. 8, the turbine exhaust stream 50 enters the heat exchanger train 420 by first passing through a first heat exchanger 430 to provide stream 52 having a lower temperature than the turbine exhaust stream 50. The first heat exchanger 430 may be described as a high temperature heat exchanger because it receives the hottest stream in the train, i.e., the turbine exhaust stream 50, and thus will transfer heat within the highest temperature range in the heat exchanger train 420. As described above, the first heat exchanger 430 receiving the relatively high temperature turbine exhaust stream 50 may comprise a special alloy or other material used to prepare a heat exchanger suitable to withstand the temperatures. By passing through the first heat exchanger 430 (which may also apply to other embodiments where less than three or more than three separate heat exchangers are utilized), the temperature of the turbine exhaust stream 50 may be significantly reduced. In certain embodiments, the temperature of the stream 52 exiting the first heat exchanger 430 may be at least about 100 ℃, at least about 200 ℃, at least about 300 ℃, at least about 400 ℃, at least about 450 ℃, at least about 500 ℃, at least about 550 ℃, at least about 575 ℃, or at least about 600 ℃ lower than the temperature of the turbine exhaust stream 50. In particular embodiments, the temperature of stream 52 may be from about 100 ℃ to about 800 ℃, from about 150 ℃ to about 600 ℃, or from about 200 ℃ to about 500 ℃. In a preferred embodiment, the pressure of stream 52 exiting first heat exchanger 430 is substantially similar to the pressure of turbine exhaust stream 50. Specifically, the pressure of stream 52 exiting first heat exchanger 430 can be at least 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% of the pressure of turbine exhaust stream 50.

Stream 52 exiting first heat exchanger 430 is passed through second heat exchanger 440, producing stream 56, which is at a temperature less than the temperature of stream 52 entering second heat exchanger 440. The second heat exchanger 440 may be described as an intermediate temperature heat exchanger because it transfers heat in an intermediate temperature range (i.e., the range is smaller than the first heat exchanger 430 but larger than the third heat exchanger 450). In some embodiments, the temperature difference between the first stream 52 and the second stream 56 may be significantly less than the temperature difference between the turbine exhaust 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 may be about 10 ℃ to about 200 ℃, about 20 ℃ to about 175 ℃, about 30 ℃ to about 150 ℃, or about 40 ℃ to about 140 ℃ lower than the temperature of the stream 56 entering the second heat exchanger 440. In particular embodiments, the temperature of stream 56 may be from about 75 ℃ to about 600 ℃, from about 100 ℃ to about 400 ℃, or from about 100 ℃ to about 300 ℃. Again, it may be preferred that the pressure of stream 56 exiting second heat exchanger 440 may be substantially similar to the pressure of stream 52 entering second heat exchanger 440. Specifically, the pressure of stream 56 exiting second heat exchanger 440 can be at least 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% of the pressure of stream 52 entering second heat exchanger 440.

Passing the stream 56 exiting the second heat exchanger 440 through a third heat exchanger 450 to produce CO₂A circulating fluid stream 60 having a temperature less than the temperature of stream 56 entering the third heat exchanger 450. The third heat exchanger 450 may be described as a cryogenic heat exchanger because it transfers heat in the lowest temperature range of the heat exchanger train 420. In some embodiments, the CO exiting third heat exchanger 450₂The temperature of the circulating fluid stream 60 may be about 10 ℃ to about 250 ℃, about 15 ℃ to about 200 ℃, about 20 ℃ to about 175 ℃, or about 25 ℃ to about 150 ℃ lower than the temperature of the stream 56 entering the third heat exchanger 450. In particular embodiments, the temperature of stream 60 may be from about 40 ℃ to about 200 ℃, from about 40 ℃ to about 100 ℃, or from about 40 ℃ to about 90 ℃. Again, it may be preferred to leave a third heat exchangeCO of vessel 450₂The pressure of the circulating fluid stream 60 may be substantially similar to the pressure of stream 56 of stream 52 entering the third heat exchanger 450. Specifically, the CO exiting the third heat exchanger 450₂The pressure of the circulating fluid stream 60 can be at least 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% of the pressure of the stream 56 entering the third heat exchanger 450.

CO leaving third Heat exchanger 450₂The circulating fluid stream 60 (and thus typically exiting the heat exchanger unit 420) may be introduced into one or more separation units 520, as described above. Also as described above, the CO₂The recycle fluid stream may be subjected to one or more types of separation to remove minor components from the stream, which stream is then pressurized as the recycle fluid (which optionally has a portion of the CO)₂Which is separated out to enter CO₂Piping or other isolation or treatment devices, without venting to the atmosphere).

Returning to FIG. 8, the CO has been pressurized₂The circulating fluid stream 70 (or 85 if it first passes through the separation device, as shown in FIG. 5) may be directed back through the same series of three heat exchangers so that the heat initially withdrawn through the heat exchangers may be used to impart heat to the pressurized CO₂The fluid stream 70 is circulated (before it enters the combustion chamber 220). Typically, the pressurized CO is imparted through three heat exchangers (450, 440, and 430)₂The heat of the circulating fluid stream 70 may be relatively proportional to the amount of heat withdrawn through the heat exchanger as described above.

In certain embodiments, the invention may be characterized by a temperature differential exiting and entering the cold end of the heat exchanger (or the last heat exchanger in the series). Referring to fig. 8, this may specifically involve a temperature difference between streams 60 and 70. The temperature difference of the stream at the cold end of the heat exchanger (or the last heat exchanger in the series) is specifically greater than zero and may range from about 2 ℃ to about 50 ℃, about 3 ℃ to about 40 ℃, about 4 ℃ to about 30 ℃, or about 5 ℃ to about 20 ℃.

In some embodiments, the pressurized CO may be used₂The circulating fluid stream 70 passes directly through the three heat exchangers in series. For example, pressurized CO₂The circulating fluid stream 70 (i.e., at a relatively low temperature) may be passed through the third heat exchanger 450 to form an increased temperature stream 71, may be passed directly through the second heat exchanger 440 to form an increased temperature stream 73, may be passed directly through the first heat exchanger 430 to form a high temperature, pressurized CO that may be directed to the combustor 220₂Circulating fluid stream 236.

However, in certain embodiments, the invention may be characterized by further increasing the recycled CO using an external heat source₂The temperature of the circulating fluid. For example, as illustrated in FIG. 8, after the pressurized CO is used₂After the circulating fluid stream 70 passes through the third heat exchanger 450, the resulting stream 71 is not passed directly to the second heat exchanger 440, but rather is passed through a flow splitting assembly 460 that splits the stream 71 into two streams 71b and 72 a. Stream 71b may be passed through a second heat exchanger 440, as described otherwise above. Stream 72a may be passed through a side heater 470, which may be used to impart additional amounts of heat to the pressurized CO beyond that imparted by the heat exchanger itself₂Circulating fluid stream 70.

Pressurized CO from stream 71 directed to second heat exchanger 440 and side heater 470₂The relative amount of circulating fluid depends on the operating conditions and the pressurized CO used to enter the combustion chamber 220₂The desired final temperature of the circulating fluid stream may vary. In certain embodiments, CO in stream 71b directed to second heat exchanger 440 and stream 72a directed to side heater 470₂The molar ratio can be about 1:2 to about 20:1 (i.e., about 1molCO in stream 71 b)₂2molCO in stream 72a₂About 20molCO in stream 71b₂1mol CO in stream 72a₂). In further embodiments, CO in stream 71b directed to the second heat exchanger 440 and stream 72a directed to the side heater 470₂The molar ratio may be about 1:1 to about 20:1, about 2:1 to about 16:1, about 2:1 to about 12:1, about 2:1 to about 10:1, about 2:1 to about 8:1, or about 4:1 to about 6: 1.

The side heater may comprise a heater for imparting heat to the CO₂Any device that circulates a fluid. In some embodiments, the energy (i.e., heat) provided by the side heater can be input into the system from an external source. However, in embodiments according to the invention, the efficiency of the cycle can be increased by using waste heat generated at one or more locations in the cycle. E.g. for O fed into the combustion chamber₂Can generate heat. Known air separation units can generate heat as a by-product of the separation process. Further, O is provided under increased pressure₂Can be useful, such as described above, and such pressurization of the gas can also generate heat as a byproduct. E.g. O₂Can be generated by operating a cryogenic air separation process in which oxygen is pressurized in the process by pumping liquid oxygen that has been effectively heated to maintain refrigerated ambient temperatures. Such a cryopumped oxygen plant may have two air compressors, both of which are capable of adiabatic operation, without intermediate stages of cooling, so that the hot charge air may be cooled to a temperature close to and/or greater than the temperature of the stream heated by the external source (e.g., stream 72a in fig. 8). In known technology settings, this heat is not utilized, or it may actually be a drain on the system, as a secondary cooling system is required to remove the byproduct heat. However, in the present invention, a coolant may be used to recover heat generated from the air separation process and supply the heat to the side heater illustrated in fig. 8. In other embodiments, the side heater itself may be an air separation unit (or related device), while the CO is₂The circulating fluid (e.g., stream 72a in fig. 8) itself may be circulated directly through a coolant system on or associated with the air separation unit to recover heat generated during the air separation process. More specifically, the heat added may be CO operated adiabatically₂Compressor and aftercooler heat transfer fluid for transferring heat of compression to heat part of high pressure CO₂Recycle fluid) to remove heat of compression, or by direct heat transfer to high pressure recycle CO₂Circulating the fluid stream to obtain (e.g., stream 72a in fig. 8). Furthermore, this addition of heat need not be limited to the bits described with respect to FIG. 8But may be in the separation of minor components from CO₂Any point after the circulating fluid is fed into the cycle (but preferably at CO)₂The circulating fluid passes directly before the heat exchanger upstream of the input into the combustion chamber). Of course, any similar method of utilizing waste generated in a power generation cycle would also be encompassed by the present disclosure, such as utilizing a flow supply at a suitable condensing temperature or hot exhaust gas from a conventional open cycle gas turbine.

The amount of heat given by the side heater 470 depends on the materials and equipment used and the CO used to enter the combustion chamber 220₂The final temperature reached by the circulating fluid stream 236. In some embodiments, the side heater 470 is effective to increase the temperature of the stream 72a by at least about 10 ℃, at least about 20 ℃, at least about 30 ℃, at least about 40 ℃, at least about 50 ℃, at least about 60 ℃, at least about 70 ℃, at least about 80 ℃, at least about 90 ℃ or at least about 100 ℃. In other embodiments, the side heater 470 effectively increases the temperature of the stream 72a by about 10 ℃ to about 200 ℃, about 50 ℃ to about 175 ℃, or about 75 ℃ to about 150 ℃. In particular embodiments, the side heater 470 increases the temperature of the stream 72a to within at least about 15 ℃, within at least about 12 ℃, within at least about 10 ℃, within at least about 7 ℃, or within at least about 5 ℃ of the temperature of the stream 73 exiting the heat exchanger 440.

With this addition of other heat sources, stream 71 exiting third heat exchanger 450 may be superheated, exceeding the total amount of CO if in the stream₂The available heat capacity of the heating stream 71 in the second heat exchanger 440 when directed through the second heat exchanger 440. By separating the streams, the heat available in the second heat exchanger 440 can be given to all of part of the content of CO in stream 71b₂The fluid is circulated and heat from the side heater 470 can be fully imparted to a portion of the content of CO in stream 72a₂The fluid is circulated. Thus, it can be seen that when utilizing the optional split stream approach, the temperature of the combined stream entering first heat exchanger 430 can be greater than when the entire amount of CO in stream 71 is present₂The circulating fluid is directed to second heat exchanger 440 rather than the temperature of stream 73 exiting second heat exchanger 440 when split and heated separately as described above. In some embodiments, the increased heat obtained by the split stream process may be significant enough to confine the CO₂Whether the circulating fluid flow 236 is sufficiently heated before entering the combustion chamber.

As seen in fig. 8, stream 71b exiting splitter 460 is passed through second heat exchanger 440 to form stream 73, which is directed to mixer 480, which contains stream 73 and stream 72b exiting from side heater 470. The combined stream 74 is then passed through a first heat exchanger 430 to convert the CO₂The circulating fluid is heated to a temperature substantially close to the turbine exhaust stream upon entering the first heat exchanger 430. This proximity to the fluid stream temperature at the hot end of the first heat exchanger may be applicable to other embodiments of the invention utilizing less than three or more heat exchangers, and may be applicable to CO₂The circulating fluid passes through a first heat exchanger therein after exiting the turbine. The ability to achieve this proximity to the temperature of the fluid stream at the hot end of the first heat exchanger can be a key feature of the present invention to achieve a desired level of efficiency. In certain embodiments, the temperature of the turbine exhaust stream entering the first heat exchanger in order from the turbine (i.e., after expansion in the turbine) is compared to the CO exiting the heat exchanger for recycle to the combustor₂The difference in temperature of the circulating fluid stream may be less than about 80 ℃, less than about 75 ℃, less than about 70 ℃, less than about 65 ℃, less than about 60 ℃, less than about 55 ℃, less than about 50 ℃, less than about 45 ℃, less than about 40 ℃, less than about 35 ℃, less than about 30 ℃, less than about 25 ℃, less than about 20 ℃ or less than about 15 ℃.

As can be seen from the above, by precisely controlling the turbine exhaust stream 50 and the recycle CO at the hot end of the heat exchanger 420 (or, alternatively, the first heat exchanger 430 in the series illustrated in FIG. 8)₂The temperature differential between the circulating fluid streams 236 may greatly facilitate the efficiency of the systems and methods of the present invention. In a preferred embodiment, the temperature difference is less than 50 ℃. While not wishing to be bound by theory, it has been found that, according to the present invention, the heat is used to recycle CO₂The heat available to the recycle fluid (e.g., heat withdrawn from the turbine exhaust stream in one or more heat exchangers) may not be suitable for adequately heating the recycle CO₂The total flow of the circulating fluid. The present invention has appreciated that this can be overcome by splitting stream 71 so that stream 71b enters heat exchanger 440 and stream 72a enters external heat source 470, which external heat source 470 provides an additional source of external heat that raises the temperature of stream 72b exiting external heat source 470 to substantially close to the temperature of stream 73 exiting heat exchanger 440, as already described above. Streams 72b and 73 are then combined to form stream 74. The flow rate of 71b (and also 72a) can be controlled by the temperature difference at the cold end of the flow heat exchanger 440. The amount of external heat required to overcome the thermal discomfort described above can be minimized by making the temperature of stream 56 as low as possible and then minimizing the cold end temperature difference of heat exchanger 440. The water vapor present in stream 56, which is produced from the combustion products, reaches its dew point at a temperature that depends on the composition of stream 56 and its pressure. Below this temperature, the condensation of water greatly increases the mCp of stream 56 to stream 60 and provides all of the heat required to heat the total recycle stream 70 to stream 71. The temperature of stream 56 exiting heat exchanger 440 preferably may be within about 5 ℃ of the dew point of stream 56. The temperature difference between streams 56 and 71 at the cold end of heat exchanger 440 may preferably be at least about 3 deg.C, at least about 6 deg.C, at least about 9 deg.C, at least about 12 deg.C, at least about 15 deg.C, at least about 18 deg.C, or at least about 20 deg.C.

Returning to FIG. 5, CO₂The recycle stream 236 is preheated before being recycled to the combustor 220, such as described with respect to the at least one heat exchanger 420, which at least one heat exchanger 420 receives the hot turbine exhaust stream 50 that passes through the expansion turbine 320. To maximize the efficiency of the cycle, it can be useful to operate the expansion turbine 320 at a high inlet temperature as consistent as possible with the available materials of construction of the hot gas inlet path and the highly pressurized turbine blades, and the maximum temperature allowed by the heat exchanger 420 consistent with the system operating pressure. The hot inlet path of the turbine inlet flow and the first row of turbine blades may be cooled by any useful means. In some embodiments, CO is recycled by using a portion of the high pressure₂Circulating fluid may maximize efficiency. In particular, low temperature CO₂The cycle fluid (e.g., in the range of about 50 ℃ to about 200 ℃) may be withdrawn from the cycle before the cold end of heat exchanger 420, or when a series of heat exchangers are utilizedMultiple heat exchanger units are withdrawn from an intermediate location in the heat exchanger 420 (e.g., from streams 71, 72a, 71b, 72b, 73, or 74 in fig. 8). The blade cooling fluid may be discharged from the holes of the turbine blades and introduced into the turbine flow between them.

Operation of a high efficiency combustor, such as the evaporatively cooled combustor described herein, can produce combustion gases that are oxidizing gases having an excess oxygen concentration, such as in the range of about 0.1% to about 5 mol%. Alternatively, the combustion chamber can be produced to contain a concentration of one or more H₂、CO、CH₄、H₂S and NH₃Combustion gas of the reducing gas of (1). This is particularly advantageous because, according to the invention, it is possible to utilize a power turbine having only one turbine unit or a series of turbine units (e.g. 2, 3 or more units). Advantageously, in certain embodiments utilizing a series of turbines, all units can operate at the same inlet temperature, and this may allow for maximum power output for a given first turbine feed pressure and total pressure ratio.

An example of a turbine unit 320 utilizing two turbines 330, 340 operating in series in a reduction mode is shown in fig. 9. As seen in this figure, the combustion products stream 40 is directed to a first turbine 330. In these embodiments, the combustion product stream 40 is designed (e.g., by controlling the fuel used, the O used₂In amounts and operating conditions of the combustion chamber) into a reducing gas containing one or more combustible components therein, as described above. The combustion product stream 40 is expanded through a first turbine 330 to generate electricity (such as in connection with an electrical generator, not shown in this illustration) and form a first exhaust stream 42. A predetermined amount of O may be introduced into the second turbine 340 prior to introduction₂To the first turbine exhaust stream 42 to combust combustible components present in the first turbine exhaust stream 42. This leaves excess oxygen while raising the inlet temperature of the second turbo unit 340 to substantially the same value as the inlet temperature of the first turbo unit 330. For example, the temperature of the exhaust stream 42 from the first turbo unit 330 may be in the range of about 500 ℃ to about 1,000 ℃. When in reduction mode, O is added at this temperature₂To the discharge flow42 may cause the gases in the stream to be heated by combustion of the excess fuel to a temperature in the range of about 700 c to about 1,600 c, which is substantially the same as the temperature range of the combustion product stream 40 exiting the combustor 220 into the first turbine unit 330. In other words, at the inlet of each of the two turbines, the operating temperature is substantially the same. In particular embodiments, the operating temperatures at the turbine inlet differ by no more than about 10%, no more than about 9%, no more than about 8%, no more than about 7%, or 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%. Similar reheating steps of other turbine units may also be implemented in the sense that residual fuel remains. If desired, combustion can be enhanced by utilizing a suitable catalyst in the oxygen transfer combustion space.

In certain embodiments, a power cycle as described herein may be used to retrofit existing power plants, such as by introducing a high pressure, high temperature heating fluid (e.g., a turbine exhaust stream as described herein) to the steam superheating cycle of a conventional rankine cycle power plant. It may be a coal-fired or nuclear power plant with a Boiling Water Reactor (BWR) or Pressurized Water Reactor (PWR) thermal cycle. This effectively increases the efficiency and power output of the steam rankine cycle power plant by superheating the steam to a much higher temperature than the maximum temperature of the superheated steam produced in prior systems. In the case of pulverized coal fired boilers, steam temperatures can currently reach about 600 ℃, whereas steam conditions for nuclear power plants are typically up to about 320 ℃. With superheating, which may be accompanied by heat exchange in the present system and method, the steam temperature may be raised above 700 ℃. This results in a direct conversion of thermal energy to additional shaft power, as the additional fuel that is burned to superheat the steam is converted to additional power in the steam-based power plant without increasing the amount of concentrated steam. This may be achieved by providing a secondary heat exchange unit. For example, the turbine exhaust stream described with respect to the inventive method and system may be directed through the secondary heat exchange unit before being passed through the primary heat exchange unit, as described otherwise herein. The heat obtained in the secondary heat exchange unit may be used to superheat steam from the boiler, as described above. The superheated steam may be directed to one or moreA turbine to generate electricity. The turbine exhaust stream after passing through the secondary heat exchange unit may then be directed to the primary heat exchange unit as described further herein. Such systems and methods are described in example 2 and illustrated in fig. 12. In addition, low pressure steam can be taken from the last steam turbine inlet and utilized to heat partially recycled CO₂Circulating the fluid as described above. In particular embodiments, condensate from a steam power plant may utilize CO prior to degassing₂The circulating fluid stream is heated to an intermediate temperature, the CO₂The circulating fluid stream exits the cold end of the heat exchanger unit (e.g., at a temperature of about 80 ℃ in some embodiments). This heating is typically done with bleed steam (bleedsteam) taken from the last LP steam turbine stage inlet, so that the current net effect of lack of side stream heating on the steam power plant is compensated for by preheating to conserve condensate of the bleed steam.

The above-outlined power generation method (i.e., power cycle) may be implemented in accordance with the present invention using a suitable power generation system as described herein. In general, a power generation system according to the present disclosure may include any of the components described herein in connection with the power generation method. For example, the power generation system may be included in O₂And CO₂A combustion chamber for combusting a carbonaceous fuel in the presence of a circulating fluid. However, in particular, the combustion chamber may be an evaporatively cooled combustion chamber as described herein; combustors capable of operating under the conditions otherwise described herein may also be used. In particular, the combustion chamber may be characterized in relation to the combustion conditions under which it operates, as well as the specific components of the combustion chamber itself. In some embodiments, the system may include one or more systems for providing carbonaceous fuel (and optionally fluidizing medium), O₂And CO₂An injector for circulating a fluid. The system may include an assembly for removing liquid slag. The combustor produces fuel gas at a temperature at which solid ash particles can be effectively filtered from the gas, and the gas can be mixed with quenching CO₂Mixed and combusted in the second combustion chamber. The combustion chamber may comprise at least one combustion stage in CO₂Combusting carbonaceous fuel in the presence of a circulating fluid to provide combustion at a pressure and temperature as described hereinFor containing CO₂The combustion product stream of (a).

The system may also include a power generating turbine in fluid communication with the combustion chamber. The turbine may have an inlet for receiving a flow of combustion products and for releasing a CO-containing gas₂To the turbine exhaust stream outlet. As the fluid flow expands, electricity may be generated, and the turbine is designed to maintain the fluid at a desired pressure ratio (I)_p/O_p) As described herein.

The system also includes at least one heat exchanger in fluid communication with the turbine for receiving the turbine exhaust stream and cooling the stream to form cooled CO₂The fluid stream is circulated. Also, the at least one heat exchanger may be used to heat CO input to the combustor₂The fluid is circulated. In particular, the heat exchanger may be characterized by the materials from which it is constructed, which allow for operation under certain conditions, as described herein.

The system may also include one or more CO for exiting the heat exchanger₂Separation of recycle fluid stream into CO₂And one or more devices for recovering or disposing of other components. Specifically, the system includes a controller for controlling the CO from₂Means for separating water (or other impurities as described herein) from the circulating fluid stream.

The system may further comprise one or more compression devices in fluid communication with the at least one heat exchanger (and/or with one or more separation devices) for compressing the purified CO₂A device for circulating a fluid (e.g., a compressor). Further, the system may include means for introducing CO₂Means for dividing the circulating fluid into two streams, one for defence against passage through the heat exchanger and into the combustion chamber, and the second for transport to the booster duct (or other means for sequestering and/or treating CO₂)。

In some embodiments, even more components may be included in the system. For example, the system may include O₂Separation unit for conveying O₂Into combustion chambers (or into injectors or the like for mixing O₂And one or moreVarious other substances). In some embodiments, the air separation unit may generate heat. Thus, it can be useful for the system to also include one or more heat transfer components that transfer heat from the air separation unit to the CO upstream of the combustion chamber₂The fluid stream is circulated. In further embodiments, a system according to the present disclosure may include any and all of the components described further herein with respect to the power generation cycle and the method of generating power.

In further embodiments, the invention includes systems and methods particularly for generating electricity using fuels that leave non-combustible residues when burned, such as coal. In certain embodiments, such non-combustible materials may be removed from the combustion product stream by utilizing a suitable device, such as the pollutant removal device illustrated in fig. 4. However, in other embodiments, it can be useful to treat non-combustible materials by utilizing a multi-combustion chamber system and method, as illustrated in fig. 10.

As shown in FIG. 10, the coal fuel 254 may be passed through a mill device 900 to provide pulverized coal. In other embodiments, the coal fuel 254 may be supplied under pelletized conditions. In particular embodiments, the coal may have an average particle size of from about 10 μm to about 500 μm, from about 25 μm to about 400 μm, or from about 50 μm to about 200 μm. In other embodiments, the coal may be described as having greater than 50%, 60%, 70%, 80%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%, 99%, or 99.5% of the coal particles having an average size of less than about 500 μm, 450 μm, 400 μm, 350 μm, 300 μm, 250 μm, 200 μm, 150 μm, or 100 μm. The pulverized coal crocodile fluidized matter is mixed to provide coal in the form of a slurry. In FIG. 10, pulverized coal is mixed with CO from recycle in mixer 910₂CO of the circulating fluid₂The side draw 68 is combined. In FIG. 10, CO₂Side draw 68 is taken from stream 67, which has been subjected to CO in order to provide a supercritical, high density state₂And (4) treating the circulating fluid. In particular embodiments, the CO used to form the coal slurry₂May have a density of about 450kg/m³To about 1,100kg/m³The density of (c). More specifically, CO₂The side draw 68 may be combined with the granular coal to formSlurry 255 containing, for example, from about 10wt% to about 75wt% or from about 25wt% to about 55wt% of particulate coal. In addition, CO from the side draw 68 used to form the slurry₂May be at a temperature of less than about 0 ℃, less than about-10 ℃, less than about-20 ℃, or less than about-30 ℃. In other embodiments, the CO from the side draw 68 used to form the slurry₂May be at a temperature of from about 0 ℃ to about-60 ℃, from about-10 ℃ to about-50 ℃, or from about-18 ℃ to about-40 ℃.

Mixing pulverized coal/CO₂Slurry 255 is transferred from mixer 910 to partial oxidation combustor 930 via pump 920. Formation of O using air separation unit 30₂A stream of air separation unit that separates air 241 into purified O₂As described herein. The O is₂The flow is split into O which is directed to a partial oxidation combustor 930₂Stream 243 and O directed to partial oxidation combustor 220₂Stream 242. In the embodiment of FIG. 10, CO₂Stream 86 is taken from the recycle CO₂The fluid stream 85 is recycled for cooling the partial oxidation combustor 930. In other embodiments, the CO used to cool the partial oxidation combustor 930₂May be taken from stream 236 instead of stream 86, or the CO₂May be taken from stream 86 and stream 236. Preferably, the CO taken₂In an amount sufficient to cool the temperature of stream 256 so that the ash is present in a solid form that can be safely removed. CO as described further herein₂Coal and O2 are supplied to the partial oxidation combustor 930 in a ratio such that the coal is only partially oxidized to produce a partially oxidized combustion product stream 256 comprising CO₂Together with H₂、CO、CH₄、H₂S and NH₃One or more of (a). CO 2₂Coal and O₂Is also introduced into the partial oxidation combustor 930 in the necessary proportion such that the temperature of the partially oxidized combustion product stream 256 is sufficiently low that all ash present in that stream 256 is in the form of solid particles that can be readily removed by one or more cyclones and/or filters. The embodiment of fig. 10 illustrates ash removal via filter 940. In particular embodiments, the temperature of the partial oxidation combustion stream 256 may be less than about 1,100 ℃, less than about 1,000 ℃, less than about 900 ℃, less than about 800 ℃, or less than about 700 ℃. In further embodiments, the temperature of the partial oxidation combustion stream 256 may be from about 300 ℃ to about 1,000 ℃, from about 400 ℃ to about 950 ℃, or from about 500 ℃ to about 900 ℃.

The filtered partial oxidation combustion stream 257 may be directly input into the second compressor 220, which may be an evaporatively cooled combustor, as described further herein. The input is in conjunction with O₂Stream 242 and recycle CO₂The circulating fluid streams 236 are supplied together. Combustion at this location may proceed similarly as otherwise described herein. Partial oxidation of combustible material in combustion stream 256 at O₂And CO₂In the presence of combustion in the combustion chamber 220, producing a combustion stream 40. The stream is expanded through turbine 320 to generate electricity (e.g., through generator 1209). The turbine exhaust stream 50 is passed through a heat exchanger unit 420 (which may be a series of heat exchangers, such as described with respect to fig. 8). Make CO₂Circulating fluid stream 60 passes through cold water heat exchanger 530 forming stream 61, which is passed to separator 540 to remove minor components (e.g., H) from stream 62₂O、SO₂、SO₄、NO₂、NO₃And Hg). Separator 540 may be substantially similar to column 1330 described below with respect to fig. 12. Preferably, separator 540 comprises a reactor that provides a contactor with sufficient residence time so that the impurities can react with water to form easily removable substances (e.g., acids). Subjecting the purified CO₂The circulating fluid stream 65 passes through a first compressor 630 to form stream 66, which is cooled with a cold water heat exchanger 640 to provide supercritical, high density CO₂Circulating fluid 67. As described above, a portion of stream 67 may be withdrawn as stream 68 for use as a fluidizing medium in mixer 910 to form coal slurry stream 255. The supercritical, high density CO₂The circulating fluid stream 67 is additionally further pressurized in compressor 650 to form a pressurized, supercritical, high density CO₂Circulating fluid stream 70. A portion of the CO in stream 70₂May be withdrawn at location 720, as described herein with respect to fig. 5 and 11, to supply stream 80 to the CO₂Pipes or other isolation devices. The remaining part of CO₂As pressurized, supercritical, high density CO₂Circulating fluidThe flow 85 continues and a portion thereof may be withdrawn as flow 86 for cooling the partial oxidation combustor 930, as described above. In addition, stream 85 is returned through heat exchanger 420 (or series of heat exchangers, as described with respect to FIG. 8) to heat the stream and ultimately form the recycle CO for input to combustor 220₂Circulating fluid stream 236. As described above, an external heat source may be used in conjunction with the heat exchanger unit 420 to provide the necessary efficiency. Likewise, other system and method parameters as otherwise described herein may be applied to the systems and methods described with respect to fig. 10, such as stream temperatures and pressures, and other operating conditions of the turbine unit 320, the heat exchanger unit 420, the separation unit 520, and the compressor unit 630.

Examples

Experiment of

The invention is further described below with reference to specific examples. The examples are provided to illustrate certain embodiments of the invention and should not be construed as limiting the invention.

Example 1 utilization of recycled CO₂System and method for power generation by combustion of a circulating fluid with methane

One particular embodiment of a system and method according to the present invention is illustrated in fig. 11. The following description describes the system for a particular recycle computer simulation under particular conditions.

In this model, a stream 254 of methane (CH4) fuel at a temperature of 134 ℃ and a pressure of 30.5MPa is mixed with recycle CO₂The circulating fluid stream 236 is combined in the mixer 252 at a temperature of 860 ℃ and a pressure of 30.3MPa (and thus it is in a supercritical fluid state) and then introduced into the evaporatively cooled combustion chamber 220. The air separation unit 30 is used to provide concentrated O at a temperature of 105 ℃ and a pressure of 30.5MPa₂242. The air separation unit also generates heat (Q), which is transferred for use in the process. O is₂242 in the combustion chamber 220 with methane fuel stream 254 and CO₂The recycled streams 236 combine and combustion occurs in the combustor, providing a combustion product stream 40 having a temperature of 1189 ℃ and a pressure of 30 MPa. CO 2₂、O₂And methane is supplied in a molar ratio of about 35:2:1 (i.e., lbmol/hr-moles per pound per hour). The combustion in this embodiment utilizes an energy input at a ratio of 344,935 Btu/hr (363,932 kJ/hr).

The combustion product stream 40 is expanded 320 to produce a turbine exhaust stream 50 (CO in the turbine exhaust stream 50) at a temperature of 885 ℃ and a pressure of 5MPa₂In the gaseous state). The expansion of the combustion product stream 40 through the turbine 320 generates electricity at a rate of 83.5 kilowatts per hour (kW/hr).

The turbine exhaust stream 50 is then passed through a series of three heat exchangers to continuously cool the stream to remove minor components. Passing through the first heat exchanger 430 produces a stream 52 having a temperature of 237 ℃ and a pressure of 5 MPa. Stream 52 is passed through a second heat exchanger 440 producing stream 56 at a temperature of 123 ℃ and a pressure of 5 MPa. Stream 56 is passed through a third heat exchanger 450, producing stream 60 at a temperature of 80 ℃ and a pressure of 5 MPa.

In recycling CO₂After the circulating fluid passes through the gift-washing heat exchanger, the stream 60 is further cooled by passing through a cold water heat exchanger 530. Circulating water (C) at a temperature of 24 ℃ through the cold water heat exchanger 530 to remove CO₂The circulating fluid stream 60 is cooled to a temperature of 27 ℃ and thus CO is caused to be present₂Any water present in the circulating fluid stream condenses. Then cooling the CO₂The circulating fluid stream 61 passes through a separation unit 540 such that liquid water is removed and discharged as stream 62 a. Mixing the "dried" CO₂The recycle fluid stream 65 was discharged from the water separation unit 540 at a temperature of 34 ℃ and a pressure of 3 MPa.

Next, the dried CO is allowed to stand₂The recycle fluid stream 65 (which is still in the liquid state) passes through the first compression unit 630 in a two-step pressurization scheme. CO 2₂The circulating fluid stream is pressurized to 8MPa, which also pressurizes the CO₂The temperature of the circulating fluid stream rose to 78 ℃. This required a power input of 5.22 kW/hr. Then make theSupercritical fluid CO₂The circulating fluid stream 66 passes through a second chilled water heat exchanger 640 where the supercritical fluid CO₂The circulating fluid stream 66 is cooled with water at a temperature of 24 ℃ to give a temperature of 27 ℃, a pressure of 8MPa and a density of 762kg/m³Cooling supercritical fluid CO of₂Circulating fluid stream 67. The stream is then passed through a second compression unit 650 to form pressurized CO at a temperature of 69 ℃ and a pressure of 30.5MPa₂Circulating fluid stream 70. This required a power input of 8.23 kW/hr. The flow is passed through a pipe splitter 720, whereby 1lbmolCO is passed₂Directed to the addition conduit via stream 80, and 34.1lbmolCO₂Is directed as stream 85 back through the series of three heat exchangers to reheat the CO before entering the combustor 220₂The fluid stream is circulated.

Make the pressurized CO₂The circulating fluid stream 85 passes through a third heat exchanger 450, forming stream 71 at a temperature of 114 ℃ and a pressure of 30.5 MPa. Stream 71 is passed through splitter 460 to yield 27.3lbmol CO₂Is directed to the second heat exchanger 440 as stream 71b, and 6.8lbmol of CO₂Is directed in stream 72a past side heater 470. Stream 71b and stream 72a each have a temperature of 114 ℃ and a pressure of 30.5 MPa. The side heater 470 utilizes heat (Q) from the separation unit 30 to the CO₂The circulating fluid stream provides additional heat. Stream 71b is passed through a second heat exchanger 440 producing stream 73 at a temperature of 224 ℃ and a pressure of 30.5 MPa. Stream 72a is passed through side heater 470 to form stream 72b, which is also at a temperature of 224 ℃ and a pressure of 30.4 MPa. Streams 73 and 72b are combined in mixer 480 to form stream 74 at a temperature of 224 ℃ and a pressure of 30.3 MPa. Stream 74 is then passed through a first heat exchanger 430 to provide recycled CO at a temperature of 860 ℃ and a pressure of 30.0MPa₂A circulating fluid stream 236 for input back into the combustion chamber 220.

The efficiency of the above simulated cycle is calculated based on the energy produced versus the LHV of the methane fuel and the additional energy input into the system, as described above. Under simulated conditions, an efficiency of about 53.9% was obtained. This is particularly surprising since any CO is prevented₂(particularly any C derived from combustion of a carbonaceous fuelO₂) While achieving such excellent efficiency.

Example 2 utilization of recycled CO₂System and method for refurbishing power generation with a circulating fluid by a pulverized coal power plant

Another embodiment of a system and method according to the present invention is illustrated in fig. 12. The following description describes the system with mathematical simulations for a particular cycle under particular conditions.

In this model, the ability to retrofit systems and methods as described herein to a conventional pulverized coal-fired power plant is illustrated.

Adding O with the pressure of 30.5MPa₂Stream 1056 along with carbonaceous fuel 1055 (e.g., coal-derived gas as illustrated by partial oxidation) at a pressure of 30.5MPa and CO at a pressure of 30.5MPa₂The circulating fluid stream 1053 is introduced into the evaporatively cooled combustor 220. The O is₂May be received from an air separator or similar device capable of generating heat (Q) that may be transferred for use in the system, such as generating steam for expansion or adding heat to cooled CO₂The fluid stream is circulated. The combustion of the fuel in the combustion chamber 220 produces a combustion product stream 1054 having a temperature of 1,150 ℃ and a pressure of 30.0 MPa. This flow is expanded through turbine 320 (which may be referred to as the main power turbine) to generate power by driving generator 1209. The expanded turbine exhaust stream 1001 at a temperature of 775 ℃ and a pressure of 3.0MPa is introduced into the warm end of the heat exchanger 1100 where the heat from the turbine exhaust stream 1001 is used to superheat the high pressure steam stream 1031 and intermediate pressure steam stream 1032 produced in the conventional pulverized coal-fired power plant 1800. Boiler feed water 1810 and coal 1810 are input to a power plant 1800 to produce steam streams 1031 and 1032 by combustion of the coal 1810. The heat transfer in the heat exchanger superheats the steam streams 1031 and 1032 from a temperature of about 550 ℃ to a temperature of about 750 ℃ to form steam streams 1033 and 1034, which are returned to the power generation plant as shown below. The process achieves very high steam temperatures without the need for conventional power generation by burning coal at near atmospheric conditionsExpensive high temperature alloys used in the large steam boilers of the plant. The steam streams 1033 and 1034 are expanded in a three-stage turbine 1200 (which is commonly referred to as a secondary power generation turbine) that drives a generator 1210. Steam 1035 exiting turbine 1200 is condensed in condenser 1220. Treated condensate 1036 is pumped to high pressure using feedwater pump 1230 and then vaporized and superheated in coal-fired boiler 1800 for discharge into heat exchanger 1100, as described above. The system is used to increase the power output and efficiency of existing coal-fired power plants.

Diffusion bonded compact plate heat exchanger with chemically milled fins in a plate made of a high temperature material such as one of the alloys mentioned above

The heat exchanger 100 is a Heatric type bonded plate heat exchanger with chemically milled channels typically constructed of a high temperature high nickel content alloy such as 617 alloy, which is capable of handling high pressures and temperatures, allowing significant steam superheating and operation under oxidizing conditions. The heat exchanger is a highly efficient heat transfer unit with a high heat transfer coefficient for all fluids.

The structure and operation of the remaining portions of the system and method illustrated in FIG. 12 are similar to the systems and methods otherwise described herein. Specifically, the expansion turbine exhaust stream 1001 is cooled in heat exchanger 1100 and exits the cold end of heat exchanger 1100 as exhaust stream 1037, which is at a temperature of 575 ℃. 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 2.9MPa to form stream 1038. This stream is further cooled in a third heat exchanger 1310 to a temperature of 40 c against a portion of condensate 1057 from the power plant condenser 1230, forming stream 1039, which is further cooled to a temperature of 27 c against cooling water in a cold water heat exchanger 1320, forming stream 1040 at a pressure of 2.87 MPa. The heat exchanger 1300 may be a Heatric310 stainless steel diffusion bonded unit.

The cooled stream 1040 at 30 ℃ is fed to the bottom of a packed column 1330 equipped with a circulation pump 1340 for providing a counter current weak acid circulation system between the incoming and scrubbed weak acidsTo generate counter-current contact. SO (SO)₂、SO₃NO and NO₂Is converted into HNO₃And H₂SO₄And absorbed by the liquid along with the condensed water and any other water soluble components. The net liquid product from column 1330 is removed in conduit 1042, the pressure is reduced to atmospheric pressure, and enters separator 1360. Dissolved CO₂Flashed in line 1043 and compressed to a pressure of 2.85MPa using pump 1350, exits as stream 1044 and is added to stream 1045 which exits the top of column 1330. These combined streams form CO to be recycled back into the combustion chamber₂The fluid is circulated. Diluted H in water₂SO₄And HNO₃Exits from the bottom of separator 1360 as stream 1046. The concentration depends on the fuel composition and the temperature in the contact column 1330. Note that nitric acid is preferably present in acid stream 1046 because nitric acid will react with any mercury present and completely remove the impurities.

Recycled CO into compressor 1380₂The circulating fluid stream is first dried in a desiccant dryer to a dew point of about-60 ℃ and then purified using a cryogenic separation scheme to remove O₂N2 and Ar, such as shown in european patent application EP1952874a1, which is incorporated herein by reference.

Compressed, recycled CO leaving compressor 1380 at a pressure of 8.5MPa₂The circulating fluid stream 1047 is cooled by means of cooling water at 27 ℃ in a cold water heat exchanger 1370 to form dense supercritical CO₂Fluid stream 1048, pumped to a pressure of 30.5MPa and a temperature of 74 ℃ in pump 1390, forming high pressure, recycled CO₂Circulating fluid stream 1050. A part of CO₂As CO₂Product stream 1049 is removed from stream 1050 for isolation or other treatment without venting to atmosphere. In this embodiment, the CO is introduced into the reactor₂Product stream 1049 pressure is reduced to the desired pipeline pressure of about 20MPa and delivered to CO₂In the pipeline.

The remaining part of the high pressure recycle CO₂The circulating fluid stream (now stream 1051) enters the cold end of heat exchanger 1300. The flow is a dense super-high of 74 DEG CA critical fluid, which must receive a significant amount of low grade heat, to convert it to a fluid with a much lower specific heat at a temperature of 237 ℃. In this embodiment, this lower heat passes through LP steam stream 1052 at a pressure of 0.65MPa and from the supply O₂Stream 1056 is provided by adiabatic compression heat from the air compressor in the cryogenic oxygen plant, and the LP steam stream is taken from the steam stream entering the low pressure steam turbine of a conventional power plant. The low pressure steam exits heat exchanger 1300 as stream 1301. Optionally, the total heat may be provided by utilizing a plurality of available steam streams from a coal-fired power plant at pressures up to 3.8 MPa. The energy may also be provided from the heat (Q) formed by the air separation unit, as described above. To partially recycle CO₂This side-stream heating of the stream provides most of the heat required at the cold end of the heat exchanger 1300 and allows only a small temperature differential of about 25 ℃ at the hot end of the heat exchanger 1300, which increases overall efficiency.

High pressure, high temperature, recycled CO₂The recycle fluid stream 1053 exits the heat exchanger 1300 at a temperature of 550 ℃ and enters the combustion chamber 220 where it is used to cool combustion gases derived from a natural gas stream 1055 (in this embodiment) containing 97mol% oxygen stream 1056 to produce a combustion product stream 1054, as described above. In this embodiment, the turbine thermal path and leading row turbine blades utilize CO taken from pump discharge flow 1050 at 74 deg.C₂Stream 1058.

If the system is used as a stand-alone power plant and utilizes pure CH₄Operating with simulated natural gas fuel, then recycling CO₂Stream 1053 enters the combustor at a temperature of about 750 deg.C, while turbine exhaust 1001 enters the heat exchanger 1300 at a temperature of about 775 deg.C.

The efficiency of the independent power system in the present embodiment is 53.9% (LHV). The number includes a low temperature O₂Plant and natural gas feed and CO₂Power consumption of the compressor. If the fuel is a simulated coal having a calorific value of 27.92 Mj/kg (e.g., partial oxidation, ash is removed in a first combustion chamber and filter unit, followed by combustion of the fuel gas and CO in a second combustion chamber₂Mixture) ofThe efficiency will be 54% (LHV). In both cases, virtually 100% of the CO originates from the carbon in the fuel₂Produced at a pipeline pressure of 20 MPa.

The system and method for utilizing coal fuel described above and illustrated in FIG. 12 may be characterized as being applicable to power plants having the following specific parameters. The effect of the power plant of the conversion-fired pulverized coal type according to the present invention is calculated as follows:

steam conditions HP steam: 16.6MPa, 565 ℃, flow rate: 47314kg/sec

LPsteam: 4.02MPa, 565 ℃, flow rate: 371.62kg/sec

Net power output: 493.7.Mw

Coal for existing equipment: 1256.1Mw

Net efficiency (LHV): 39.31 percent

CO₂Capture%: 0

A conversion plant retrofitted with existing equipment incorporating the presently disclosed systems and methods:

CO₂net power output of the power system: 371.7Mw

The net overpower of the existing equipment is as follows: 639.1Mw

Total net filtration: 1010.8Mw

CoalforCO₂Coal for power systems: 1053.6Mw

Coal for existing systems: 1256.1Mw

Net total efficiency (LHV): 43.76 percent

CO₂Capture%: 45.6%. The

Note that in this example, no CO was captured from the existing plant₂。

Many modifications and other embodiments of the invention will come to mind to one skilled in the art to which this invention pertains having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. Therefore, it is to be understood that the inventions are not to be limited to the specific embodiments disclosed and that 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 descriptive sense only and not for purposes of limitation.

Claims

1. A method of generating electricity, comprising:

mixing fuel and O₂And CO₂The circulating fluid being introduced into the combustion chamber, the CO₂Introduced at a pressure of at least 12MPa and a temperature of at least 400 ℃;

combusting the fuel to provide a fuel comprising CO₂The combustion product stream of (a), the combustion product stream having a temperature of at least 800 ℃;

expanding the combustion product stream through a turbine to generate electricity, the turbine having an inlet for receiving the combustion product stream and a turbine for releasing a gas comprising CO₂Wherein the pressure ratio of the combustion product stream at the inlet to the turbine exhaust stream at the outlet is less than 12;

recovering heat from the turbine exhaust stream by passing the turbine exhaust stream through a main heat exchange unit to provide a cooled turbine exhaust stream;

subjecting the supercritical CO₂The circulating fluid stream is cooled to a density of at least 200kg/m³The temperature of (a);

make supercritical, high density CO₂Circulating a fluid through a second compressor to cause the CO to₂Pressurizing the circulating fluid to the pressure required by the input of the combustion chamber;

make supercritical, high density and high pressure CO₂Circulating fluid through the same main heat exchange unit so that the heat withdrawn is used to augment the CO₂The temperature of the circulating fluid;

supplying an additional amount of heat to the supercritical, high density, high pressure CO₂Recycling fluid to re-elevate the CO₂Temperature of the circulating fluid to recycle CO leaving the main heat exchange unit for recycling back to the combustor₂The difference between the temperature of the circulating fluid and the temperature of the turbine exhaust stream is less than 50 ℃; and

2. The method of claim 1, wherein the recovering step cools the turbine exhaust stream to a temperature below its water dew point.

3. The method of claim 1, wherein the removing step comprises further cooling the turbine exhaust stream against an ambient temperature cooling medium.

4. The method of claim 3, wherein the further cooling condenses water along with the one or more minor components to form a composition comprising H₂SO₄、HNO₃A solution of one or more of HCl and mercury.

5. The method of claim 1, wherein the compressing with the first compressor pressurizes the cooled turbine discharge stream to a pressure of less than 12 MPa.

6. The process of claim 1, wherein the CO is recovered from supercritical, high density, high pressure CO prior to passing through the main heat exchange unit₂Product CO recovery in a circulating fluid stream₂And (4) streaming.

7. The method of claim 6, wherein the product CO₂The stream comprises substantially all of the CO formed by the combustion of carbon in the carbonaceous fuel₂。

8. The method of claim 6, wherein the product CO₂The stream being at and directly fed to the high-pressure CO₂Pressure compatible with the pipe.

9. The method of claim 1, wherein the combustion is conducted at a temperature of 1,200 ℃ to 5,000 ℃.

10. The method of claim 1, wherein the fuel comprises a partial combustion product stream.

11. The method of claim 10, comprising using O₂Combusting carbonaceous fuel, providing carbonaceous fuel, O₂And CO₂The proportion of circulating fluid being such as to contain carbonThe fuel is only partially oxidized to produce said partial combustion product stream, said stream comprising non-combustible components and H₂、CO、CH₄、H₂S and NH₃One or more of (a).

12. The method of claim 11, wherein the carbonaceous fuel, O₂And CO₂The recycle fluid is provided in a proportion such that the temperature of said partial combustion product stream is sufficiently low that substantially all of the non-combustible components in the stream are in the form of solid particles.

13. The method of claim 12, wherein the cooling fluid comprises CO₂。

14. The method of claim 12, wherein the noncombustible component includes ash.

15. The method of claim 12, wherein the temperature of the partial combustion product stream is from 500 ℃ to 900 ℃.

16. The method of claim 12, further comprising passing the partial combustion product stream through one or more filters.

17. The method of claim 16, the filter reducing the residual amount of noncombustible component to less than 2mg/m³Partial combustion products.

18. The method of claim 11, wherein the carbonaceous fuel comprises coal, lignite, or petroleum coke.

19. The method of claim 18, wherein the carbonaceous fuel is in particulate form and is present as CO-containing₂The slurry of (a) is provided.

20. The method of claim 19, wherein the particulate fuel is such that greater than 90% of the particles have an average size less than 500 μm.

21. The method of claim 1, wherein the CO is₂The circulating fluid is introduced at a pressure of at least 15 MPa.

22. The method of claim 1, wherein the CO is₂The circulating fluid is introduced at a temperature of at least 600 ℃.

23. The method of claim 1, wherein the CO is₂The circulating fluid is introduced at a temperature of at least 700 ℃.

24. The method of claim 1, wherein the combustion product stream has a temperature of at least 1,000 ℃.

25. The method of claim 1, wherein the combustion product stream has a pressure that is CO introduced into the combustion chamber₂At least 90% of the pressure of (a).

26. The method of claim 25, wherein the combustion product stream pressure is CO introduced into the combustion chamber₂At least 95% of the pressure of (a).

27. The method of claim 1, wherein the ratio of the pressure of the combustion product stream at the inlet to the pressure of the turbine exhaust stream at the outlet is 1.5 to 10.

28. The method of claim 27, wherein the ratio of the pressure of the combustion product stream at inlet to the pressure of the turbine exhaust stream at outlet is 2 to 8.

29. The method of claim 1, wherein the fuel is a carbonaceous fuel, and wherein the CO introduced into the combustion chamber₂CO in the circulating fluid₂In a molar ratio to carbon in the fuel of 10 to 50.

30. The method of claim 29, wherein the CO introduced into the combustion chamber₂CO in the circulating fluid₂And O₂In a molar ratio of 10 to 30.

31. The method of claim 1, wherein the CO in the turbine exhaust stream₂In the gaseous state.

32. The method of claim 31, wherein the turbine exhaust stream has a pressure less than or equal to 7 MPa.

33. The process of claim 1, wherein the main heat exchange unit comprises a series of at least three heat exchangers.

34. The method of claim 33, wherein a first heat exchanger in the series receives the turbine exhaust stream and reduces its temperature, the first heat exchanger being made of a high temperature alloy that withstands temperatures of at least 700 ℃.

35. The method of claim 33, wherein the recovering heat step comprises passing the turbine exhaust stream sequentially through a first heat exchanger, a second heat exchanger, and a third heat exchanger, and wherein the method comprises increasing the supercritical, high density, high pressure CO by₂Temperature of the circulating fluid, passing said high pressure CO₂Circulating the fluid through a third heat exchanger to form a first heated stream, splitting the first heated stream into a second heated stream and a third heated stream, passing the second heated stream through the second heat exchanger to form a second heated streamA fourth heating stream, passing the third heating stream through the side heater to provide an additional amount of heat and form an fifth heating stream, combining the fourth and fifth streams from the second heat exchanger and the side heater to obtain a sixth heating stream, passing the sixth heating stream through the first heat exchanger to provide a supercritical, high density, high pressure CO stream having a temperature₂A circulating fluid, the temperature being such that the difference between the temperature of the circulating fluid and the temperature of the turbine exhaust stream is less than 50 ℃.

36. The method of claim 35, wherein the CO in the second heating stream passing through the second heat exchanger and the third heating stream passing through the side heater₂Is 1:2 to 20: 1.

37. The method of claim 35, wherein the CO in the second heating stream passing through the second heat exchanger and the third heating stream passing through the side heater₂Is 2:1 to 16: 1.

38. The method of claim 35, wherein the CO in the second heating stream passing through the second heat exchanger and the third heating stream passing through the side heater₂Is 2:1 to 8: 1.

39. The method of claim 35, wherein the heat introduced by the side heater increases the temperature of the third heated stream by at least 10 ℃.

40. The method of claim 35, wherein the heat introduced by the side heater increases the temperature of the third heated stream by at least 20 ℃.

41. The method of claim 1, wherein the supercritical, high density CO after passing through the second compressor₂The circulating fluid stream has a pressure of at least 15 MPa.

42. The method of claim 41, wherein the supercritical, high density CO after passing through the second compressor₂The circulating fluid stream has a pressure of at least 25 MPa.

43. The method of claim 1, wherein the supercritical CO₂The circulating fluid stream is cooled to a density of at least 400kg/m³The temperature of (2).

44. The method of claim 1, wherein the additional amount of heat comprises from O₂Heat recovered by the separation unit.

45. The method of claim 1, wherein the additional amount of heat is directed to the CO after passing through the second compressor but before passing through the main heat exchange unit₂A circulating fluid is provided.

46. The method of claim 1, wherein the additional amount of heat is provided directly to a main heat exchange unit.

47. The process of claim 1, wherein the main heat exchange unit comprises a series of at least three heat exchangers, and wherein the portion of the CO is contained by heating₂A side stream of the circulating fluid, which side stream is present between the two heaters, thereby providing the additional amount of heat.

48. The method of claim 1, wherein said O₂Is provided in an amount such that a portion of the fuel is oxidized to comprise CO₂、H₂O and SO₂And the remaining part of the fuel is oxidized to one or more oxidation products selected from H₂、CO、CH₄、H₂S、NH₃Of (2) a combustible component of (a).

49. The method of claim 48, wherein the turbine comprises two units, each unit having an inlet and an outlet, and wherein the operating temperature at the inlet of each unit is substantially the same.

50. The method of claim 49, comprising adding an amount of O to the fluid flow at an outlet of the first turbine unit₂。

51. The method of claim 1, wherein the turbine exhaust stream is a stream containing excess O₂The oxidizing fluid of (1).

52. The method of claim 1, wherein the CO is₂Circulating fluid as a mixture with O₂And either or both of the fuel and the fuel are introduced into the combustion chamber.

53. The method of claim 1, wherein the combustion chamber comprises an evaporatively cooled combustion chamber.

54. The method of claim 53, wherein the CO is₂The circulating fluid is introduced into the evaporatively cooled combustion chamber as all or a portion of the evaporatively cooled fluid directed through one or more evaporatively cooled fluid supply passages formed therein.

55. The method of claim 1, wherein the combustion is conducted at a temperature of at least 1,200 ℃.

56. The method of claim 1, wherein said O₂As wherein O₂Is provided in a stream of at least 85% molar concentration.

57. The method of claim 56, whereinO₂Is 85% to 99.8%.

58. The method of claim 1, wherein the turbine exhaust stream is passed directly into the main heat exchange unit without passing through an additional combustor.

59. The method of claim 1, wherein the method provides a combustion efficiency of greater than 50%, calculated as the ratio of the net electrical power produced to the total low heating value thermal energy of the carbonaceous fuel combusted to generate electricity.

60. The method of claim 1, further comprising passing the combustion product stream through at least one device for removing solid or liquid contaminants between the combusting step and the expanding step.

61. The method of claim 1, further comprising passing the turbine exhaust stream through a secondary heat exchange unit between the expanding step and the withdrawing step.

62. The method of claim 61, wherein the secondary heat exchange unit utilizes heat from the turbine exhaust stream to heat one or more streams derived from a steam power system.

63. The method of claim 62, wherein the steam powered system comprises a conventional boiler system.

64. The method of claim 63, wherein the conventional boiler system comprises a coal-fired power plant.

65. The method of claim 62, wherein the steam power system comprises a nuclear reactor.

66. The method of claim 62, wherein the one or more heated streams are passed through one or more turbines to generate electricity.

67. A power generation system, comprising:

a combustion chamber configured for receiving fuel, O₂And CO₂Circulating a fluid stream and having at least one combustion stage in the CO₂Combusting the fuel in the presence of a circulating fluid and providing a CO-containing gas at a pressure of at least 8MPa and a temperature of at least 800 ℃₂The combustion product stream of (a);

a main power generation turbine in fluid communication with the combustor, the main power generation turbine having an inlet for receiving a flow of combustion products and an outlet for releasing a CO-containing gas₂The main power generating turbine is adapted to control the pressure drop such that the ratio of the flow of combustion products at the inlet to the pressure of the turbine exhaust stream at the outlet is less than 12;

a main heat exchange unit in fluid communication with the main power generating turbine for receiving a turbine exhaust stream and transferring heat from the turbine exhaust stream to CO₂Circulating a fluid stream;

a first compressor in flow communication with the main heat exchange unit adapted to compress the CO₂Circulating fluid stream compression above CO₂A pressure of a critical pressure;

a second compressor in flow communication with the first compressor and adapted to compress the cooled CO₂Compressing the circulating fluid flow to a pressure required for input to the combustion chamber; and

one or more heat transfer components adapted to transfer heat from an external source to the CO upstream of the combustion chamber and downstream of the second compressor₂The fluid is circulated.

68. The power generation system of claim 67 further comprising one or more separation devices disposed between the main heat exchange unit and the at least one compressor for removing CO removal₂Is externally present in the CO₂One or more times in the circulating fluidAnd (4) components.

69. The power generation system of claim 67 comprising a cooling device adapted to cool the CO exiting the first compressor₂Cooling the circulating fluid stream to a density of greater than 200kg/m³The temperature of (2).

70. The power generation system of claim 67 wherein the one or more heat transfer components are coupled to O₂The separation equipment is connected.

71. The power generation system of claim 67 wherein the combustion chamber is a first combustion chamber and further comprising a second combustion chamber located upstream of and in fluid communication with the first combustion chamber.

72. The power generation system of claim 71 further comprising one or more filters or separation devices located between the second combustion chamber and the first combustion chamber.

73. The power generation system of claim 71 further comprising a mixing device for forming a slurry of particulate fuel and fluidizing medium.

74. The power generation system of claim 71 further comprising a milling device for pelletizing the solid fuel.

75. The power generation system of claim 67 wherein the main heat exchange unit comprises a series of at least two heat exchangers.

76. The power generation system of claim 75 wherein the main heat exchange unit comprises a series of at least three heat exchangers.

77. The power generation system of claim 75 wherein the first heat exchanger in the series is adapted to receive the main power generating turbine exhaust stream and is made of a high temperature alloy that withstands temperatures of at least 700 ℃.

78. The power generation system of claim 67 wherein the main power generating turbine includes a series of at least two turbines.

79. The power generation system of claim 67 further comprising a secondary heat exchange unit located between and in fluid communication with the primary power generating turbine and the primary heat exchange unit.

80. The power generation system of claim 79 further comprising a boiler in fluid communication with the secondary heat exchange element via at least one steam stream.

81. The power generation system of claim 80 further comprising a secondary power generating turbine having an inlet for receiving at least one steam stream from the secondary heat exchange unit.