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    • 专利摘要:
    SYSTEM AND METHOD FOR HIGH EFFICIENCY ENERGY GENERATION USING NITROGEN GAS AS A WORKING FLUID. The present invention relates to a method for energy production, using a high pressure / low pressure ratio Brayton Energy cycle with predominantly N2 mixed with combustion products CO2 and H2O as a working fluid, is provided. The high pressure can be in the range of 8 Mpa to 50 Mpa (80 bar to 500 bar). The pressure ratio can be in the range of 1.5 to 10. The natural gas fuel can be burned in a first high-pressure combustor with an almost stoichiometric amount of pressurized preheated air, and the pure flue gas can be mixed with the heated high pressure recycling N2 + CO2 + H2O flow, which moderates the temperature of the mixed gas to the value required for the maximum inlet temperature for a first turbine producing shaft power.
    公开号:BR112013008661B1
    申请号:R112013008661-0
    申请日:2011-09-20
    公开日:2020-12-08
    发明作者:Rodney John Allam；Jeremy Eron Fetvedt；Miles R. Palmer
    申请人:Palmer Labs. Llc；8 Rivers Capital, Llc；
    IPC主号:
    专利说明:

    FIELD OF THE INVENTION
    [001] The present invention provides high efficiency methods for energy production using an N2 working fluid to burn fuel in air. BACKGROUND
    [002] As energy requirements continue to grow worldwide, there is an increasingly urgent need for additional processes for energy production. The current high-efficiency method for power generation using natural gas or distilled HC fuel is the combined natural gas cycle system (NGCC), which comprises a Brayton cycle gas turbine and a Rankine cycle steam system. The largest commercially available gas turbines produce energy in the NGCC system in the range of about 450 MW (Megawatt) to around 550 MW, with a lower heating value efficiency in the range of about 56% to about 60% in ISO conditions (from "International Organization for Standardization"). Current single train units available, employing a coal boiler plus a steam generator, can produce more than 1000 MW, with net efficiency of up to about 45%, based on the best steam conditions achievable with better boiler designs and available materials. Nuclear reactors available from a single steam boiler produce more than 1000 MW.
    [003] In addition to the above, Patent Publication No. 2011/0179799 describes a high pressure: low pressure energy cycle using a carbonaceous fuel or hydrocarbon fuel that is burned in the presence of a high concentration oxygen atmosphere, and, therefore, requires the provision of a source of highly pure oxygen. The combustion product is cooled by recycling a high temperature, high pressure, and highly purified CO2 stream, which is heated against a turbine exhaust stream in a heat exchanger.
    [004] As seen above, an existing and emerging technology in the field may require the use of multiple cycles and / or the provision of highly purified materials for combustion. Therefore, the need for energy systems that use natural gas and / or distillate fuels burned in air that produce up to 500 MW in a single train or more persists. SUMMARY OF THE INVENTION
    [005] The systems and methods presently described for energy production can be very useful to provide high efficiency energy production and have one or more of the following characteristics.
    [006] The systems and methods described can achieve a lower maximum turbine temperature than a conventional NGCC system, with efficiency comparable to a conventional NGCC system.
    [007] The systems and methods described can achieve with a turbine temperature equivalent to an NGCC system, with higher efficiency than a conventional NGCC system.
    [008] The systems and methods described can have a significantly lower cost of capital than a conventional NGCC system.
    [009] The systems and methods described can use a single working fluid.
    [0010] The systems and methods described can use different means of a steam system to drive the turbine (s).
    [0011] The systems and methods described can be significantly more compact than a conventional NGCC system.
    [0012] The systems and methods described can have a significantly higher concentration of CO2 in the exhaust gas than the concentration of approximately 3% in the NGCC exhaust, so that CO2 is more easily captured using a suitable removal system.
    [0013] The systems and methods described above can use air as a low cost oxidant source, instead of requiring highly pure oxygen.
    [0014] The systems and methods described above can provide an almost stoichiometric combustion condition, in order to provide a production of excess inert gases, which can be ventilated to the atmosphere.
    [0015] The systems and methods described can use a high pressure flow comprising inert gases for the production of energy, expanding the flow through one or more turbines.
    [0016] The systems and methods described can provide a method to operate an energy production process, in which a fossil fuel is burned with a high pressure with air, in an almost stoichiometric condition in a closed cycle, with a high pressure ratio: low enough pressure, so that the excess pressurized inert gases remaining after consumption of oxygen in the combustion are expanded to atmospheric pressure with a maximum production of additional energy.
    [0017] In addition to that described above, in one embodiment, the present invention provides an energy production system. The energy production system can comprise a first combustion configured to burn a first flow of fuel and a first flow of air in the presence of a first flow of recycling, to produce a first flow of combustion, a first turbine configured to expand the first combustion flow, and a first heat exchanger configured to receive at least a portion of a first discharge flow from the first turbine. The first heat exchanger can be configured to employ the first discharge stream portion to heat the first air flow and at least a portion of the first recycle stream, which is produced from the first discharge flow. The energy production system can also include a second compound configured to burn a second fuel stream and a second air stream in the presence of a second recycling stream produced from the first discharge stream, to produce a second combustion stream , a second turbine configured to expand the second combustion flow, and a second heat exchanger configured to heat the second air flow and the second recycling flow.
    [0018] In some embodiments, the second heat exchanger can be configured to employ a second discharge flow from the second turbine to heat the second air flow and the second recycling flow. The second heat exchanger can be additionally configured to heat a second portion of the first recycle stream. The energy production system can additionally comprise a third combustion configured to burn a third fuel flow and a third air flow in the presence of a second discharge flow received from the second turbine to produce a third combustion flow, and a third turbine configured to expand the third combustion flow. The second heat exchanger can be configured to employ a third discharge stream from the third turbine to heat the second air stream and the second recycle stream. The second heat exchanger can be additionally configured to heat the third air flow. The second heat exchanger can be additionally configured to heat a second portion of the first recycle stream.
    [0019] In some embodiments, a recycling compressor can be configured to compress the first recycling stream. A second portion of the second discharge stream can be directed to the second combustion. The energy production system may additionally comprise a purifier configured to receive a cooled discharge flow from the second heat exchanger. The purifier may comprise a CO2 adsorption system.
    [0020] In some embodiments, the energy production system may additionally comprise an air compressor system configured to compress a supply air flow to produce the first air flow and the second air flow. The air compressor system may comprise a first air compressor configured to compress the first air flow and a second air compressor to compress the second air flow. The second air compressor can be further configured to compress the first air flow, before the first air compressor compresses the first air flow. The energy production system can be configured to control the flow rate of the first air flow and flow rate of the second air flow to provide a substantially stoichiometric combustion in the first combustion and second combustion. For example, the energy production system can be configured to control the flow rate of the first air flow and the flow rate of the second air flow resulting in up to 5% excess O2 in combustion in the first combustion and second combustion .
    [0021] In some embodiments, the first fuel stream and the second fuel stream may comprise a compressed hydrocarbon gas. The compressed hydrocarbon gas can comprise methane. The first air flow and the second air flow can comprise compressed ambient air. The first recycling stream and the second recycling stream can be greater than 50% N2 on a molar basis. The power generation system may additionally comprise a separator configured to remove a liquid stream from the portion of the first discharge stream directed through the first heat exchanger. In addition, the power generation system can be configured to operate with net electricity generation efficiency based on a lower heating value of at least about 60% when operating at a turbine temperature of around 1300 ° C at about 1500 ° C.
    [0022] In another modality, a method is provided to produce energy. The method may comprise burning a first flow of fuel and a first flow of air in a first combustion in the presence of a first flow of recycling, to produce a first flow of combustion, expanding the first flow of combustion in a first turbine to rotate the first turbine and produce power, direct at least a portion of a first discharge stream from the first turbine to a first heat exchanger, and employ the portion of the first discharge stream to heat the first air flow and at least a portion of the first recycling stream produced from the first discharge stream with the first heat exchanger. The method may additionally comprise burning a second fuel stream and a second air stream in a second combustion in the presence of a second recycling stream that is produced from the first discharge stream to produce a second combustion stream, expanding the stream combustion in a second turbine to turn the second turbine and produce power, direct the second air flow and the second recycling flow to a second heat exchanger, and heat the second air flow and the second recycling flow with the second heat exchanger.
    [0023] In some embodiments, heating the second air flow and the second recycling flow with the second heat exchanger may comprise employing a second discharge flow from the second turbine to heat the second air and the second recycling flow. The method may further comprise also heating a second portion of the first recycling stream with the second heat exchanger. The method may also include burning a third fuel stream and a third air stream in a third combustion in the presence of a second exhaust stream received from the second turbine to produce a third combustion stream and expand the third combustion stream in a third turbine to produce power. Heating the second air flow and the second recycling flow with the second heat exchanger may comprise employing a third discharge flow from the third turbine to heat the second air flow and the second recycling flow. The method may additionally include heating the third air flow with the second heat exchanger. Also, the method may include heating a second portion of the first recycle stream with the second heat exchanger.
    [0024] In some embodiments, the method may additionally comprise compressing the first recycling stream with a recycling compressor. The method may also include directing a second portion of the first exhaust stream to a second combustion. In addition, the method may include directing a cooled discharge flow from the second heat exchanger to a purifier. The purifier may comprise a CO2 adsorption system.
    [0025] In some embodiments, the method may additionally comprise compressing a supply air flow with an air compressor to produce the first air flow and the second air flow. Compressing a supply air flow with an air compressor system may comprise compressing the first air flow with a first air compressor and compressing the second air flow with a second air compressor. Compressing the supply air flow with an air compressor system may comprise compressing the first air flow with the second air compressor before compressing the first air flow with the first air compressor. In addition, the method may include controlling the flow rate of the first air flow and flow rate of the second air flow with the air compressor system to provide substantially stoichiometric combustion in the first combustion and second combustion. For example, the method may include controlling the flow rate of the first air flow and the flow rate of the second air flow with the air compressor system resulting in up to about 5% excess O2 in combustion in the first combustion and second combustor.
    [0026] In some embodiments, the first fuel stream and the second fuel stream may comprise compressed hydrocarbon gas. The compressed hydrocarbon gas can comprise methane. The first air flow and the second air flow can comprise compressed ambient air. The first recycling stream and the second recycling stream can be greater than 50% N2 on a molar basis. The method may also include removing a liquid stream from the portion of the first discharge stream directed through the first heat exchanger with a separator. Additionally, energy can be produced at a net electricity generation efficiency based on a lower heating value of at least about 60%, when operating at a turbine temperature of about 1300 ° C to about 1500 ° Ç.
    [0027] An additional modality of an energy production system is provided. The energy production system may comprise an air source configured to supply an air flow, a fuel source configured to supply a fuel flow, and a combustor configured to burn the fuel flow and air flow in the presence of a recycling flow to produce a combustion flow greater than 50% N2 on a molar basis. The air source and the fuel source can be configured to supply an air flow and fuel flow within a ratio configured to provide a substantially stoichiometric combustion of up to about 5% excess O2 in the combustion. The energy production system may additionally comprise a turbine configured to expand the combustion flow and a heat exchanger configured to receive at least a portion of a turbine discharge flow. The heat exchanger can be configured to employ the discharge flow portion to heat the air flow and at least a portion of the recycling flow produced from the discharge flow.
    [0028] In some embodiments, the energy production system may additionally comprise a second combustor configured to burn a second fuel stream and a second air stream in the presence of a second recycling stream that is produced from the discharge stream for producing a second combustion stream, a second turbine configured to expand the second combustion stream, and a second heat exchanger configured to heat the second air stream and the second recycle stream.
    [0029] An additional modality of a method for producing energy is provided. The method can comprise burning a fuel stream and an air stream in a combustor in the presence of a recycling stream to produce a combustion stream, which is greater than 50% N2 on a molar basis, where the ratio of the fuel stream in The air flow is controlled to provide a substantially stoichiometric combustion in a turbine to rotate the turbine and produce power. The method may additionally comprise expanding the combustion flow in a turbine to rotate the turbine and produce power; directing at least a portion of a discharge stream from the turbine to the heat exchanger; and employing the discharge flow portion to heat the air flow and at least a portion of the recycling flow, which is produced from the discharge flow with the heat exchanger.
    [0030] In some embodiments, the method may additionally comprise burning a second stream of fuel and a second stream of air in a second combustion in the presence of a second stream of recycling, which is produced from the discharge stream to produce a second stream combustion, expand the second combustion flow in a second turbine to rotate the second turbine and produce power; directing the second air flow and the second recycling flow to a second heat exchanger; and heating the second air flow and the second recycling flow with the second heat exchanger. BRIEF DESCRIPTION OF THE DRAWINGS
    [0031] To help understand the modalities of the present invention, reference is made to the attached drawings, which are not necessarily to scale. The drawings are merely exemplary and have not been construed as limiting with respect to the present invention.
    [0032] FIG 1 provides a flow diagram illustrating an energy production system including three turbines and method of operation thereof, according to an embodiment of the present invention; and
    [0033] FIG 2 provides a flow diagram illustrating an energy production system including two turbines and method of operation thereof, according to another embodiment of the present invention. DETAILED DESCRIPTION
    [0034] The present invention will now be described more widely, with reference to various modalities. Such modalities are provided so that the present invention is meticulous and complete, and transmits its scope to those skilled in the art. In fact, the present invention can be configured in many different ways, and should not be taken to be limited to the modalities shown; instead, such modalities are provided so that they meet the legal requirements. As used in this and the appended claims, the singular forms of the indefinite articles "UM" and "UMA" and definite articles "O" and "A" include their plural counterparts, unless expressed differently in context.
    [0035] In certain embodiments, the present invention comprises methods and systems that provide distinct advantages over known energy production systems. For example, in various embodiments, the present invention can provide one or more of the following: • generation of electrical energy using gaseous fuels without ash (such as, for example, natural gas) or liquid fuels without ash (such as, for example, distillate fuels) in a Brayton cycle, which burns the fuel with air, and in which the predominant component is Nitrogen; • absence of a Rankine steam cycle to achieve high efficiency; • production of electricity in a net efficiency based on a lower heating value, equal (or better) than the best current combined gas turbine cycle systems; • high pressures that allow the system to define a relatively compact form factor at a relatively low cost; • the systems can be customized to provide single train units for powers greater than 500 MW, in relatively compact units; • facilitating the capture of CO2 from the ventilation gas, where the concentration of CO2 is in the range of 10% to 12 mol% using an almost stoichiometric combustion in the preheated compressed air flows; and • achieve low levels of NOx in the exhaust gas in the range of 10% to 12 mol%, using an almost stoichiometric fuel combustion with preheated compressed air flow; and
    [0036] temperatures that are moderated by recycling flows in N2.
    [0037] In specific embodiments, the present invention can provide a Brayton cycle fuel / air power system operation without a steam or oxygen cycle installation at a lower cost of capital than current combined cycle units with a concentration of CO2 in the exhaust of, for example, about 10 mol% or more. In some embodiments, the system can remove additional CO2 from the exhaust gas vented to the atmosphere, using an amine CO2 purifier system.
    [0038] The present invention will now be described with reference to the modality of the system illustrated in FIG 1, which is not intended to limit the description and which, instead, is provided to show exemplary modalities. In general terms, FIG 1 illustrates a modality of a Rankine cycle configured to produce energy. The system can include first combustor 3, a second combustor 4, and a third combustor 34. Each of these combustors can receive and burn a fuel stream (first, second, and third fuel streams 26, 24, 37) respectively with a heated compressed air flow (first, second, and third heated compressed air flows 51, 21, 38) to produce the respective combustion flows (first, second, and third combustion flows 27, 23, 36). The combustion flows 27, 23, 36 are supplied to the first, second and third turbines 5,6, 35 respectively, which expand the combustion flows to generate a rotation that can be converted into energy. For example, turbines 5,6, 35 can be directly or indirectly coupled to the electric generator 45.
    [0039] To increase efficiency the system can include first heat exchanger 2 and second heat exchanger 1. A portion 58 of a discharge stream 28 from the first turbine 5 can be directed through the first heat exchanger to heat a first compressed air flow 30, and with that forming the first heated compressed air flow 51. The first heat exchanger 2 can also heat a first recycling stream 57 which is provided for the first combustor 3. The first recycling stream 57 can work to reduce the temperature in the first combustion 3 to thereby reduce NOx production in the combustion of the first fuel stream 26 with the first air flow 51. The first recycle stream 57 can also work to reduce the flow temperature combustion 27, which leaves the first combustion 3 at a temperature equal to or greater than the maximum inlet temperature of the first turbine 5. The first recycling stream 57 can be cooled portion 58 of the discharge stream 28 of the first turbine 5 in the first heat exchanger 2 and a chiller 8, separating a liquid stream 31 in a separator 9, compressing a portion 59 of the separate stream 15 in a recycling compressor 53 and directing a portion 50 of the separate compressed stream 49 back through the first heat exchanger. The first recycle stream 57 may also include the remainder of the compressed separate stream 49 which has been heated in the second heat exchanger 1 to form a heated separate compressed stream 50.
    [0040] The second heat exchanger 1 can be heated by the discharge flow 39 from the third turbine 35. In particular, the discharge flow 18 from the second turbine 6 can be directed through the third combustion 34 and the combustion flow 36 from the third combustion can be supplied to the third turbine 35. The discharge stream 18 from the second turbine 6 thus can be heated and combined with the flue gases to form the third flue stream 36, which can be at a relatively higher temperature than the discharge flow from the second turbine 6, and then the third turbine 35 can operate with a higher efficiency than that in which it receives the discharge flow from the second turbine directly. The discharge stream 39 from the third turbine 35 is then directed to the second heat exchanger 1 and the cooled discharge stream 19 can then be discharged into the atmosphere. Alternatively, as illustrated, the cooled discharge stream 19 can be directed through a purifier 97 (i.e., a CO2 adsorption system) configured to remove CO2 and / or other gases, before directing a gas 99 into the atmosphere.
    [0041] The second heat exchanger 1 can be employed to heat the remaining portion 16 of the compressed separate stream 49 to form the heated compressed separate stream 50 which can be combined with the other portion 60 of the compressed separate stream 49 which is heated in the first exchanger heat 2 to form the first recycle stream 57, which is directed through the first combustion 3. The second heat exchanger 1 can also be employed to heat the remaining portion 17 of the separate stream 15 to form a second recycle stream 40, which is directed through the second combustion 4. The second recycle stream 40 can work to reduce the temperature in the second combustion 4 to thereby reduce the NOx production in combustion of the second fuel stream 24 with the second air stream 21 The second recycle stream 40 can also function to reduce the temperature of the combustion stream 23 leaving the second combustion 4 to a higher temperature or i at the maximum inlet temperature of the second turbine 6. In some embodiments, a remaining portion 22 of the discharge stream 28 from the first turbine 5 can also be recycled through the second combustion 4 without first being cooled, heated, or otherwise processed after leaving the first turbine. The remaining portion 22 of the discharge stream 28 serves to allow nitrogen, argon, and other non-combustible inert components from the combustion air streams and fuel streams, together with most of the CO2 and part of the water produced as combustion product or air or fuel flows are vented into the atmosphere as flow 99, and prevent their accumulation in the system. The first turbine 5 can operate with a high inlet pressure and a low pressure ratio producing a high discharge pressure. The purpose of the second turbine 6 and the third turbine 35 with their associated combustors 4, 34 and the second heat exchanger 1 is to allow the pressure energy in the remaining portion 22 of the discharge stream 28 to be efficiently used to increase energy production overall efficiency of the process. The second heat exchanger 1 can also provide heat for the second and third air flows 21, 38 which are respectively directed to the second and third combusters 4, 34.
    [0042] In addition to referring to the compressed heated air flows 51, 21, 38 supplied to combustors 3, 4, 34, the system may include an air compressor system including first and second and third air compressors 10, 11, 42, which can be driven by an electric motor 54, in some modalities, or mechanically coupled to one or more of the turbines 5, 6, 35. The third air compressor 42 can receive a supply air flow (ie ambient air) and compress the supply air flow. A first portion 48 of the supply air flow 12 compressed by the third air compressor 42 can be directed through the second heat exchanger 1 to form the flow of heated compressed air 38 supplied to the third combustion 34. A second portion 47 of the flow of air compressed supply 12 by the third air compressor 34 can be directed to the second air compressor 11. A first portion 20 of the air flow 47 compressed by the second air compressor 11 can be directed through the second heat exchanger 1 to form the flow heated compressed air 21, which is supplied to the second combustion 4. A second portion 14 of the compressed air flow 47 by the second air compressor 11 can be received by the first air compressor 10. The compressed air flow 30 by the first air compressor air 10 can be directed through the first heat exchanger 2 to form the first air flow 51, which is supplied to the first combustion 3.
    [0043] Due to this serial compressor mode, in which the third combustion 34 receives a flow of compressed air 38 through the third air compressor 42, the second combustion 4 receives a flow of compressed air 21 through both the third and second air compressors 42 11, and the first combustion 3 receives a flow of compressed air 51 through the third, second, and first air compressors 42, 11, 10, the air source for the combustion may vary. In particular, the airflow rate for the combustors can be the highest in the first combustion 34 and the lowest in the third combustor 34, and an intermediate airflow rate in the second combustion 4. Additionally, the fuel flows 26 , 24, respectively received by the first and second combustors 3, 4, can be at a relatively high pressure, due to the compression of a fuel flow 25 by a fuel compressor 7, which can be driven by an electric motor 77, in comparison with the fuel flow 37 supplied by the fuel compressor. Therefore, the rates of fuel flows 26, 24, 37 and compressed air 51, 21, 38 can be controlled to provide the desired air: fuel ratios. For example, flow rates can be configured to provide substantially stoichiometric combustion. The flow rates of each of the fuel streams 26, 24, 37 for each of the 3, 4, 34 combustors are separately controlled to provide a sufficient amount of heat, when burned in an almost stoichiometric condition and mixed with the streams. recycling, to provide the required inlet temperature for each of the turbines 5, 6, 35. Air flows 51, 21, 38 are separately controlled at one or more locations (ie flows 48, 20 30) to provide combustion almost stoichiometric of the fuel in fuel streams 26, 24, 37 in combustors 3, 4, 34. The flow rates of recycling streams 57, 40 are separately controlled at one or more locations (ie in streams 60, 16, 17) to provide the required flow rate for combustion flows 27, 23, 36 provided for turbines 5, 6, 35. Thus, the air source (ie one or more components configured to supply air flows 51,21, 38 for combustors 3, 4, 34) and / or fuel source (ie one or more components configured to supply the fuel flows 26, 24, 37 for each of the combustors 3, 4, 34) can be configured to supply the air flow and fuel flow at a rate configured to provide a substantially stoichiometric combustion in the combustor (ie with up to about 5% excess O2). In that regard, employing a substantially stoichiometric combustion of air flows comprising ambient air, excess inert gases (i.e. N2 and Ar) from combustion can be removed from the closed system and vented to the atmosphere. For example, the flow 36 leaving the third combustion 34 and entering the third turbine 35 can have high pressure (i.e. 20 Bar (2MPa) at 6 Mpa (60 Bar)) and high temperature, and include a major concentration of inert gases. After expansion, flow 39 and flow 19 may each have low pressure or approach atmospheric pressure. Consequently, the flow is expanded through one or more turbines to produce energy and reduce pressure before venting inert gases into the atmosphere, as described above. A further description of the operation of the system of FIG 1 will be provided below. However, it must be understood that temperatures, pressures, fuels, gases, etc., are provided for the purpose of example. Therefore, the operation of the system may differ in one or more aspects from the examples provided in some modalities.
    [0044] The system of FIG 1 can use heat exchangers 2, 1 (ie economizers) in a cycle of Brayton Energy in a ratio of high pressure: low pressure, which can use predominantly N2 mixed with combustion products CO2 and H2O as working fluid, which is provided to the combustors through a plurality of recycling streams 57,40,22, 18. Nitrogen can be the primary component in one or more of the recycling streams 57, 40, 22 18 (ie more than 50 % N2 and on a molar basis). The high pressure in combustor 3 can be greater than about 6 Mpa (60 Bar), greater than about 8 Mpa (80 Bar), or greater than about 12 Mpa (120 Bar) or can be in the range of about 8 Mpa (80 Bar) at about 50 Mpa (500 Bar), from about 10 Mpa (100 Bar) to about 45 Mpa (450 Bar), or from about 20 Mpa (200 Bar) to about 40 Mpa (400 Pub). The pressure ratio in each of the 5, 6, 35 turbines can be in the range of about 4 to about 12, about 5 to about 11, or about 7 to about 10. The fuel flow 26 comprising hydrocarbon can be burned in a first high pressure combustor 3 with an almost stoichiometric amount of oxygen from a first flow of heated compressed air. The fuel stream 26 preferably comprises a hydrocarbon that is gaseous under ambient conditions, such as methane (i.e. natural gas). Other hydrocarbons, such as liquefied petroleum gas (LPG), can be used. The fuel stream, therefore, can comprise a compressed hydrocarbon gas (i.e. any combination of C1 to C4 hydrocarbon gases). Additionally, distilled fuels can also be used. Specifically, any liquid fuel obtained from the distillation of petroleum can be used, such as gasoline, diesel, kerosene, heating oil, and "Jet Fuel" (jet fuel). More generally, a suitable liquid can be a petroleum distillate comprising C5-C7o, C6-C5o, C7-C30, or C8C20. The pure flue gas can be mixed with the recycling stream 57, which moderates the temperature of the combustion stream 27 to a temperature equal to or less than the maximum inlet temperature of the first turbine 5. A portion 60 of the first recycling stream 57 can be preheated in a first heat exchanger 2, using heat from portion 58 of the discharge stream 28 received from the first turbine 5. The high inlet pressure, the inlet temperature, and the low pressure ratio of the turbines 5, 6, 35 mean that discharge temperatures can be relatively high, typically in the range of 400 ° C to 800 ° C. The heat present in the discharge streams 28, 18 and 39 can be recovered in heat exchangers 1, 2, to achieve high efficiency, and to maximize energy production.
    [0045] The combustion flow temperature 27 received by the first turbine 5 can be at least about 500 ° C, at least about 700 ° C, or at least about 900 ° C, or it can be in the range of about 900 ° C to about 1600 ° C, from about 1000 ° C to about 1500 ° C, or from about 1100 ° C to about 1400 ° C. The use of a high pressure to low pressure ratio of about 4 to about 12, about 5 to about 11, or about 7 to about 10 in the first turbine 5 can provide a flow discharge pressure discharge 28 in the range of about 0.67 Mpa (6.7 Bar) to about 12.5 Mpa (125 Bar), from about 1.2 Mpa (12 Bar) to about 10 Mpa (100 Bar) , from about 15 Mpa (1.5 Bar) to about 7.5 Mpa (75 Bar), or from about 2 Mpa (20 Bar) to about 5.7 Mpa (57 Bar). A portion of the combustion stream 27 from the first combustion 3 comprising N2 + CO2 + H2O, can, in the end, be discharged to the atmosphere. At least a portion of the combustion stream 27 from the first combustion 3 can be expanded in a second turbine 6, after reheating in a second combustion 4, with temperature moderation by the second recycling stream 40. The second recycling stream 40 and the second air stream 21 can be heated by the discharge stream 39 from the third turbine 35 in the second heat exchanger 1 to about 200 ° C to about 800 ° C, from about 300 ° C to about 600 ° C, or from about 450 ° C to about 550 ° C.
    [0046] Optionally, to achieve high efficiency, the combustion flux 23 coming from the second combustion 4 can pass through the third turbine 35, the third combustion 34 being disposed between the second turbine 6 and the third turbine 35 to maximize the power from the combustion flow, while it is expanded to atmospheric pressure. The second turbine 6 and the third turbine 35 can use substantially equal pressure ratios. Each of the combustion streams 27, 23, 36 can be at a temperature of about 500 ° C to about 1800 ° C, from about 900 ° C to about 1600 ° C, or from about 1100 ° C to about 1400 ° C. The second recycling stream 40 provided for the second combustion 3, and optionally for the third combustion 34 and the heated compressed air streams 21, 38 for the second and third combusters, are preheated against the discharge stream 39 coming from the third turbine 35 in the second heat exchanger 1. The discharge stream 39 from the third turbine 35 can be cooled to less than 100 ° C in the second heat exchanger 1 before being discharged as a cooled exhaust stream 19. The exhaust stream 19 preferably it can be more than about 5%, more than 8%, or more than about 10% molar CO2. In that regard, with the exhaust stream 19 having a relatively high CO2 content, the use of a purifier 97 can be facilitated. As used in this, a purifier can encompass any device or system configured to remove a certain component from a stream, more specifically remove a pollutant, such as CO2, SOx, and NOx. In particular, any CO2 adsorption / removal system can be used as a purifier. Non-limiting examples of solvent-based systems that can be used include alkaline carbonates, as in the BENFIELDTM Process (UOP, LLC), alcohol amines, as in the ECONAMINE FG_PLUS process (Fluor Corporation), and alcohols, diols, and ethers, as in the Process RECTISOL® (Lurgi, GMBH) and SELEXOLTM solvent (The Dow Chemical Company). Other systems, such as membrane-based systems, or adsorption systems could also be used. Therefore, the purifier 97 can reduce the CO2 content and direct the gas 99 into the atmosphere. The removed CO2 can be captured for sequestration or for use in other methods. In other embodiments, the exhaust gas 19 can be directed to the atmosphere, without directing the exhaust flow through a purification system.
    [0047] The amount of air from the heated compressed air streams 51, 21, 38 supplied to each of the 3, 4, 34 combustors can be limited to an almost stoichiometric O2 concentration with a net excess of O2 concentration less than about 5%, less than about 3%, or less than about 2%, or within the range of about 0.1% to about 5%, from about 0.15% to about 4%, or from about 0.25% to about 3%, compared to the stoichiometric amount required to complete fuel combustion 26,24,37. By employing such stoichiometric concentrations with respect to the air supplied by the heated compressed air streams 51, 21, 38 to combustors 3, 4, 34 and recycling the exhausted O2 combustion product streams, the described cycles are distinguished from a gas turbine system conventional used in NGCC installations. A conventional gas turbine can use a compressed air flow to dilute combustion gases produced in the combustion, to achieve the required temperature at the turbine inlet. Typically, about 2/3 of the total compressed air deviates from combustion in the combustors, typically resulting in a concentration of about 14% O2 and about 3% CO2 in the exhaust. In contrast, the systems according to the present invention, can provide a separate flow 15 produced by combustion in the first combustion 3 and expansion in the first turbine 3, after cooling in the first heat exchanger 2 and chiller 8, and removing the flow of condensed water 31 having a CO2 content typically in the range of about 6% to about 15%, from about 8% to about 14%, or from about 10% to about 12 mol%, compared to about from 2% to about 4% of a typical gas turbine system.
    [0048] Advantageously, to remove CO2, the separate compressed flow 49 from the discharge flow 28 from the first turbine 5 is available in a preferred pressure range of about 0.5 Mpa (5 Bar) to about 15 Mpa ( 150 Bar) or from about 0.65 Mpa (6.5 Bar) to about 12.4 Mpa (124 Bar), and at an almost atmospheric temperature, following the cooling in the first heat exchanger 2, removing water in a separator 9, and compression on the recycling compressor 53. This high partial pressure of CO2 lowers the capital cost with respect to CO2 removal and provides greater removal efficiency. For example, from about 50% to about 80%, from about 55% to about 75%, or from about 60% to about 70% of the total CO2 stream produced by the combustion of fuel can be available in that stream separate tablet 49 comprising (N2 + Ar), CO2, excess O2 and residual water in the vapor phase preferably preferably about 15 Mpa (1.5 Bar) to about 10 Mpa (100 Bar) and at an almost ambient temperature . The remaining fraction of the total CO2 flow is available in the remaining portion 17 of the separated flow 15 at atmospheric pressure in a dry basis molar concentration in the range of about 7% to about 15%, from about 8% to about 14% , or from about 10% to about 12%, which can comprise the same compressed separate flow components 49.
    [0049] The described system may comprise an arm multi-stage compressor (comprising first 10, second 11, and third air compressor 42) supplying air at two or three pressure levels for combustors 3, 4, 34 and a separate recycling compressor high pressure ratio: low pressure 53 that can circulate one or more of the recycling streams 57, 40, 22, 18 to one or more of the 3, 4, 34 combustors. The air compressors 10, 11, 42 can be electrically driven (ie by an electric motor) or driven at least in part from the turbine shaft 5, 6, 35.The air compressors 10, 11, 42 and the recycling compressor 53 can optionally be connected in a single system , driven by a single drive system. Alternatively, air compressors 10, 11, 42 and / or recycling compressor 53 can be separated and driven independently.
    [0050] The first heat exchanger 2 can be configured to provide cooling for the discharge flow of high pressure turbine 28, which leaves the first turbine 5 and enters the first heat exchanger, at a temperature in the range of about 400 ° About 1200 ° C, about 500 ° C to about 1000 ° C, or about 600 ° C to about 800 ° C. The heat released by the discharge stream 28 from the first turbine 5 can be used to heat at least a portion 60 of the first recycle stream 57. The high efficiency in the overall system is strongly influenced by the achievement of a relatively small temperature differential between the temperature of the discharge stream 28 leaving the first turbine 5 and the first heated recycling stream 57. The specific heat of the compressed separate stream 49 can be significantly higher than that of the discharge stream 28 coming from the first turbine 5, although the rate of flow of the discharge stream is higher than the flow rate of the compressed separate stream (due to the removal of condensation stream 31 and the remaining portion 17 of the separate stream 15), and there may be insufficient discharge stream to provide a relatively differential temperature through the first heat exchanger 2.
    [0051] To overcome this problem, a portion 16 of the compressed separate flow 49 can be preheated in the second heat exchanger 1 against the discharge flow 39 coming from the third turbine 35. The flow rate 16 of the separate compressed flow 49 can be configured to provide a temperature differential less than about 40 ° C, less than about 30 ° C, or less than about 10 ° C in relation to the initial discharge flow temperature 39 from the third turbine 35 in the second heat exchanger 1 By which the flow rate of the portion 60 of the compressed separate stream, which is directed through the first heat exchanger 2, can be further reduced in relation to the flow rate of the discharge stream 28 coming from the first turbine 5, and a relatively small temperature differential can also be achieved between the first recycle stream 57 and the discharge stream from the first turbine. The portion 16 of the compressed separate stream 49, preheated in the second heat exchanger 1 to form a heated stream 50, can be combined with the portion 60 of the compressed separate stream 49, preheated by the second heat exchanger 2, to form the first stream of heat. heated recycle 57. Although illustrated in combination with portion 60 of the separate compressed stream 49 downstream of the first heat exchanger 2, the heated stream 50, instead, can combine with that portion upstream of the first heat exchanger or in the heat exchanger heat at a point where the two flows have substantially the same temperature.
    [0052] The remaining portion 17 of the separate flow 15 can bypass the recycling compressor 53 and pass through the second heat exchanger 1 and proceed to the second combustion 4, as the second recycling flow 40. The modality described above can provide a differential of temperature between the stream leaving the first heat exchanger 2 (and at least partially forming the first heated recycle stream 57) and the exhaust of turbine 28 from the first turbine 5 in the range of about 10 ° C to about 40 ° C ° C. The heat exchangers 2, 1 can be a multichannel diffusion connected heat exchanger (ie from Heatric Division of Meggit PLC) using a blade plate heat exchanger or a high nickel alloy heat exchanger (such as the alloy 617) or vacuum brazed stainless steel (ie from Chart Industries or Sumitomo Precision Products) in some embodiments. Other suitable exchangers can also be used.
    [0053] In a preferred system, a portion 17 of the cooled separator stream 15 coming from the discharge stream 28; a portion 16 of the cooled, separate, and pressurized stream 49, formed from that of the discharge stream 28; and air flows 21, 38 for the second and third fuels 3, 34 are heated in the second heat exchanger 1 against the discharge flow 39 from the third turbine 35. The second recycling flow 40 (ie the remaining portion 17 of the separate flow cooled 15 after heating in the second heat exchanger 1) enters the second combustion 4 with fuel flow 24, compressed heated air flow 21 (ie air flow 20 after heating) and a recycled portion 22 of the discharge flow turbine flow 28. The fuel flow 24 can be compressed by the fuel compressor 7 to a pressure substantially equal to the pressure of the second recycling flow 40. The second combustion flow 23 is discharged to the second combustion 4 at a temperature suitable for the flow of inlet to second turbine 6 (ie in a range of about 900 ° C to about 1600 ° C).
    [0054] A portion 58 of the turbine discharge stream 28 from the first turbine 5 can be directed to the first heat exchanger 2 to provide heat to the first recycle stream 57 and air flow 51 supplied to the first combustion 3. The flow of air 51 and the first recycling stream 57 can be heated to about 400 ° C to about 900 ° C and preferably to a range of about 600 ° C to about 800 ° C. After passing through the first heat exchanger 2, the discharge stream 28 forms a cooled stream 33 at a temperature that can be below 100 ° C. The cooled stream 33 can be further cooled by the cooler 8 to form a cooled stream 32 having a temperature substantially equal to the average ambient temperature, to cause the liquids to condense from the stream, which can be removed as a liquid stream31 by the separator 9.
    [0055] The discharge flow 18 from the second turbine 6 is optionally reheated in the third combustion 34, where the third fuel flow 37 is burned with the third flow of heated compressed air 38. Reheat the discharge flow 18 leaving the second turbine 6 can provide an inlet temperature for the third turbine 35 in the range of about 600 ° C to about 1800 ° C, from about 700 ° C to about 1700 ° C, or from about 900 ° C to about 1600 ° C, which increases the efficiency of the cycle, providing the third turbine with a working fluid that is at least at a higher temperature than the discharge flow that leaves the second turbine. The temperature of the discharge stream 39 leaving the third turbine 35 can increase to a range of about 200 ° C to about 900 ° C, limited by the maximum design temperature of the second heat exchanger 1. In modalities that employ a portion 58 of the discharge stream 28 coming from the first turbine 5 to heat the first heat exchanger 2, the third combustion 34 and the second turbine 6 can be used to guarantee an adequate pressure ratio through the third turbine 35. In general, the third turbine 35 may have a higher pressure ratio than the second turbine 6 and a lower outlet temperature. The inlet temperature of the third turbine 35 should be as high as possible - i.e. in the range of about 1000 ° C to about 1600 ° C, limited by the maximum inlet temperature.
    [0056] Heat exchangers 2, 1 can be a vacuum-brazed stainless steel plate-plate heat exchanger or high-nickel high-pressure heat exchanger connected by diffusion, depending on the design temperature and pressure combination . Such units are manufactured, for example, by Sumitomo Precision Products, Chart Industries, or Heatric. Optionally, one or both of the heat exchangers 1, 2 can also be used to preheat part or all of the fuel feed flow fed to the system. In some embodiments, heat exchangers 2, 1 can be configured to employ portion 58 of the discharge stream 28 from the first turbine 5 and the discharge stream 28 from the third turbine 35 respectively, to heat each of the other fluids received. in heat exchangers respectively from a temperature below about 100 ° C to a temperature in the range of about 300 ° C to about 900 ° C, and preferably from about 450 ° C to about 800 ° C. Optionally, two or more turbines 5, 6, 35, can be coupled to a single electric generator 45, via a common drive shaft or gearbox, to allow different rotational speeds for each turbine, and, therefore, the operation of each turbine at its respective optimal speed. Therefore, the system can be used to generate electricity in some modalities.
    [0057] Tables 1 to 4 below illustrate exemplary operational parameters in various flows 12, 28, 22, 23, 58, 51, 18, 24, 19, 27, 33, 32, 31, 15, 26, and 25 and the second combustion 4 during operation of the system illustrated in FIG 1. The operating parameters are based on operation with a pure methane fuel flow of 0.4536 kmol / kg in ISO condition assuming a turbine efficiency of 88.37% and efficiency of 85% compressor. Some compressors shown diagrammatically have been calculated as multistage units with intercooling. No other auxiliary power demand being included. The net efficiency of the LHV-based system is estimated to be around 60%. TABLE 1
    [0058] Exemplary operational parameters in flows 12, 28, 22,23, 58

    TABLE 2
    [0059] Exemplary operational parameters in flows 51, 18, 24 and 19.

    TABLE 3
    [0060] Exemplary operational parameters in flows 27, 3.3 32 and fuel
    TABLE 4
    [0061] Exemplary operational parameters in flows 31.15, 26.25


    [0062] The systems described here can be particularly advantageous in that the efficiencies are comparable to or greater than the efficiencies that can be achieved in NGCC systems, using significantly lower turbine temperatures. Thus, the systems of the present invention can use significantly lower maximum turbine temperatures (ie the maximum fluid temperature through any of the turbines) than the current technique, and still achieve a net efficiency of electricity generation comparable to or greater than the efficiency in known NGCC systems. In some embodiments, systems and methods can be described providing higher efficiency than NGCC for all turbine temperatures.
    [0063] So far, to achieve greater efficiency, it has been necessary to significantly increase the operating temperature of the turbine. For example, conventional NGCC systems have employed maximum turbine temperature temperatures of around 1500 ° C to achieve a net efficiency of around 59% based on LHV. To achieve efficiency as high as 64%, the known technique requires the use of gas turbines of super-high temperatures, operating in the range of 1700 ° C. In comparison, the present systems detected in this can achieve a net efficiency of about 60% based on LHV, employing a turbine temperature of about 1279 ° C. Additional comparisons between the efficiency of the systems of the invention and of existing NGCC systems are illustrated in Table 5, for various turbine operating temperatures. TABLE 5
    [0064] Comparison of net efficiency between Present Invention Systems and NGCC Systems

    [0065] Thus, in one embodiment, the systems described can achieve efficiencies comparable to or greater than those of conventional NGCC systems, using lower maximum turbine temperatures. As noted above, it may be desirable to reduce the temperatures of the turbine, to reduce the costs of the turbine, thereby reducing the need to use more expensive materials configured to withstand high temperatures. Alternatively, the systems described therein can operate at the same maximum temperatures as conventional NGCC systems, but with relatively higher efficiency. For example, in one embodiment, a system or method presently described can operate with net electricity generation efficiency based on a lower heating value of at least about 60%, operating with a turbine temperature in the range of about 1300 ° C to about 1500 ° C. In other embodiments, a system or method, according to the invention, can operate with a net electricity generation efficiency based on a lower heating value, according to any of the following: at least about 55% at a temperature of around 1100 ° C; at least 58% at a temperature of about 1200 ° C, at least 63% at a temperature of around 1400 ° C, at about 65% at a temperature of around 1500 ° C; or at least about 68% at a temperature of about 1700 ° C. In specific embodiments, a system or method, according to the present invention, can operate with a net electricity generation efficiency based on a lower heating value that is at least about 60% operating at a turbine temperature less than about 1500 ° C, less than about 1400 ° C, or less than about 1300 ° C. In still other embodiments, a system or method, according to the invention, can operate with a net efficiency of electrical generation based on a heating value less than at least about 55% at a turbine temperature in the range of about 1100 ° C to about 1300 ° C.
    [0066] As noted above, the third turbine 35 and the third fuel 34 are optional in some modalities. In that regard, FIG 2 illustrates an embodiment of the system that does not include a third combustion, a third turbine, or a third air compressor. The system can be substantially similar to the system of FIG 1, except with respect to the noted differences. As illustrated, the discharge flow 18 'from the second turbine 6 can be directed to the second heat exchanger 1' without having to pass through the third combustion and third turbine first. In these embodiments, the discharge flow 18 'can be at a pressure above atmospheric pressure, equal to the pressure drop through the second heat exchanger 1 (and any piping or interconnecting equipment) between the second turbine 6 and the atmosphere . It should be noted that, in this modality, a purifier is not employed. Thus, the cooled discharge stream 19 'can be discharged into the atmosphere, without first having to pass through the purifier. However, a purifying system can also be employed in this embodiment, for example, as in the system embodiment of FIG 1.
    [0067] Since a third turbine is not used, a third combustor may not be present, as well as the associated air and fuel flows. Therefore, the air compressor system may not employ a third air compressor, and the second heat exchanger 1 'may not heat a third air flow. Thus, the supply air flow 12 'can be provided directly to the second air compressor 12', instead of being compressed by a third air compressor first. With respect to other aspects, the system of FIG 2 can be substantially similar to the system of FIG 1.
    [0068] The use of a first turbine with a high pressure: low pressure ratio, and the combustion products of the same being expanded in one or more coupled energy turbine stages, with an almost stoichiometric combustion using pressurized preheated air with air flows. recycling to moderate turbine inlet temperatures, can provide a system with efficiency in the range of about 55% to about 65%. High pressures in the system can allow the installation to define a relatively compact form factor at a relatively low cost of capital. The system can be designed to produce more than 500 MW for power generation from base load. The system can also be used in low power applications, such as ship propulsion units, using a distilled fuel with a low sulfur content, where thermal efficiencies greater than 50% based on LHV are achieved.,
    [0069] Many modifications and other modalities of the present invention, as established in this one, may come to the minds of those skilled in the technique to which the present invention belongs, enjoying the benefit of the teachings contained in the description. Therefore, it should be understood that the present invention is not limited to the specific modalities described above, and that many modifications and other modalities may be included in the scope of the appended claims. Although specific terms have been used, such terms are used in a generic sense and are purely descriptive, without any limiting purpose.
    权利要求:
    Claims (28)
    [0001]
    1. An energy production system comprising: a first combustor (3) configured to burn a first fuel stream (26) and a first air stream (51), in the presence of a first recycling stream (57) to produce a first combustion flow (27); a first turbine (5) configured to expand the first combustion flow (27); a first heat exchanger (2) configured to receive at least a portion of a first discharge stream (28) from the first turbine (5); characterized by the fact that the first heat exchanger (2) is configured to employ the portion (58) of the first discharge flow (28) to heat the first air flow (51) and at least a portion (60) of the first recycling stream (57), which is produced from the first discharge stream (28); a second combustion (4) configured to burn a second fuel stream (24) and a second air stream (21) in the presence of a second recycling stream (40), which is produced from the first discharge stream (28 ), to produce a second combustion flow (23); a second turbine (6) configured to expand the second combustion flow (23); and a second heat exchanger (1) configured to heat the second air flow (21) and the second recycle flow (40).
    [0002]
    2. Energy production system according to claim 1, characterized in that the second heat exchanger (1) is configured to employ a second discharge flow (18) from the second turbine (6) to heat the second air flow (21) and the second recycling flow (40); or the second heat exchanger (1) is additionally configured to heat a second portion (16) of the first recycling stream (57); or wherein a second portion (22) of the first discharge stream (28) is directed to the second combustion (4); or wherein the first air flow (51) and the second air flow (21) comprise compressed ambient air; or where the first recycling stream (57) and the second recycling stream (40) are greater than 50% N2 on a molar basis; or or where the power generation system is configured to operate with a net electric generation efficiency based on a heating value lower than at least about 60%, when operating at a turbine temperature of around 1300 ° At about 1500 ° C.
    [0003]
    3. Energy production system according to claim 1, characterized by the fact that it additionally comprises a third combustor (34) configured to burn a third fuel flow (37) and a third air flow (38) in the presence of a second discharge stream (18) received from the second turbine (6) to produce a third combustion stream (36); and a third turbine (35) configured to expand the third combustion flow (36).
    [0004]
    4. Energy production system according to claim 3 characterized by the fact that the second heat exchanger (1) is configured to employ a third discharge flow (39) from the third turbine (35), to heat the second air flow (21) and the second recycling flow (40).
    [0005]
    5. Energy production system according to claim 4, characterized in that the second heat exchanger (1) is additionally configured to heat the third air flow (38); or wherein the second heat exchanger (1) is additionally configured to heat a second portion (16) of the first recycling stream (57).
    [0006]
    The energy production system according to claim 1, characterized by the fact that it additionally comprises: a recycling compressor (53) configured to compress the first recycling flow (57); or a separator (9) configured to remove the liquid stream (31) from the portion (60) of the first discharge stream (57) directed through the first heat exchanger (2).
    [0007]
    The energy production system according to claim 1, characterized in that it additionally comprises a purifier (97) configured to receive a cooled discharge flow (19) from the second heat exchanger (1), optionally in which the purifier (97) comprises a CO2 absorption system.
    [0008]
    8. Energy production system according to claim 1, characterized in that it additionally comprises an air compressor system (10, 11, 42) configured to compress the supply air flow (12) to produce the first flow air (51) and second air flow (21).
    [0009]
    9. Energy production system according to claim 8, characterized in that the air compressor system comprises a first air compressor (10) configured to compress the first air flow (51) and a second air compressor (11) configured to compress the second air flow (21).
    [0010]
    An energy production system according to claim 9, characterized in that the second air compressor (11) is additionally configured to compress the first air flow (51) before the first air compressor (10) compress the first air flow (51).
    [0011]
    11. Energy production system according to claim 9, characterized in that the air compressor system (10, 11, 42) is configured to control a flow rate of the first air flow (51) and a rate flow rate of the second air flow (21) to provide substantially stoichiometric combustion in the first combustion (3) and the second combustion (4).
    [0012]
    12. Energy production system according to claim 11, characterized in that the air compressor system (10, 11, 42) is configured to control the flow rate of the first air flow (51) and the rate flow rate of the second air flow (21) to provide an excess of up to about 5% O2 in combustion in the first combustion (3) and second combustion (4).
    [0013]
    13. Energy production system according to claim 1, characterized in that the first fuel stream (26) and the second fuel stream (24) comprise a compressed hydrocarbon gas, optionally wherein the compressed hydrocarbon gas comprises methane.
    [0014]
    14. Energy production system according to claim 1, characterized by the fact that it still comprises an air source configured to supply the first air flow (51) and a fuel source configured to supply the first fuel flow (26 ); wherein the first combustion flow (27) is greater than 50% N2 on a molar basis; and the air source and fuel source are configured to supply the first air flow (51) and the first fuel flow (26) with a ratio configured to provide a substantially stoichiometric combustion in the first combustion having an excess of O2 of up to about 5%.
    [0015]
    15. Method for producing energy characterized by the fact that it comprises: burning a first flow of fuel (26) and a first air flow (51) in a first combustion (3) in the presence of a first recycling flow (57) for producing a first combustion flow (27); expanding the first combustion flow (27) in a first turbine (5) to rotate the first turbine (5) and produce energy; directing at least a portion of the first discharge stream (28) from the first turbine (5) to a first heat exchanger (2); employ the portion of the first discharge stream (28) to heat the first air stream (51) and at least a portion of the first recycle stream (57), which is produced from the first discharge stream (28) with the first heat exchanger (2); burning a second stream of fuel and a second stream of air (21) in a second combustion (4) in the presence of a second recycle stream (40) that is produced from the first discharge stream (28) to produce a second combustion flow; expanding the second combustion stream (23) in a second turbine to rotate the second turbine to produce energy; directing the second air flow (21) and second recycling flow (40) to a second heat exchanger (1); and heating the second air flow (21) and the second recycling flow (40) with the second heat exchanger (1).
    [0016]
    16. Method according to claim 15, characterized by the fact that heating the second air flow (21) and the second recycling flow (40) with the second heat exchanger (1) comprises employing a second discharge flow ( 18) from the second turbine to heat said air flow and said recycling flow (40); or wherein the first air flow (51) and the second air flow (21) comprise compressed ambient air; or where the first recycling stream (57) and the second recycling stream (40) are greater than 50% N2 on a molar basis; or or in which energy is produced with a net electric generation efficiency based on a heating value lower than at least about 60%, when operating at a turbine temperature of about 1300 ° C to about 1500 ° C .
    [0017]
    17. Method according to claim 15, characterized in that it additionally comprises heating a second portion of the first recycling stream (40) with the second heat exchanger (1); or additionally comprises compressing the first recycling stream (57) with the recycling compressor (53); or additionally comprises directing a second portion of the first discharge stream (28) to the second combustion (4); or additionally it comprises removing a liquid stream from the portion of the first discharge stream (28) through the first heat exchanger (2) with a separator (9).
    [0018]
    18. Method according to claim 15, characterized by the fact that it additionally comprises burning a third flow of fuel and a third flow of air in a third combustion in the presence of a second recycling flow (40) received from the second turbine for produce a third combustion flow; expand the third combustion flow in a third turbine to rotate the third turbine to produce energy.
    [0019]
    19. Method according to claim 18, characterized by the fact that heating the second air flow (21) and the second recycling flow (40) with the second heat exchanger (1) comprises employing a third discharge flow from the third turbine (35) to heat the second air flow (21) and the second recycling flow (40).
    [0020]
    20. Method according to claim 19, characterized by the fact that it additionally comprises heating the third air flow with the second heat exchanger (1); or additionally comprises heating a second portion of the first recycling stream (57) with the second heat exchanger (1).
    [0021]
    21. Method according to claim 15, characterized by the fact that it additionally comprises directing a cooled discharge flow from the second heat exchanger (1) to a purifier, optionally in which the purifier is a CO2 adsorption system.
    [0022]
    Method according to claim 15, characterized in that it additionally comprises compressing a supply air flow with an air compressor system to produce the first air flow (51) and the second air flow (21).
    [0023]
    23. Method according to claim 22, characterized in that compressing the supply air flow with the air compressor system comprises compressing the first air flow (51) with a first air compressor and compressing the second air flow (21) with a second air compressor (11).
    [0024]
    24. Method according to claim 23, characterized in that compressing the supply air flow with the air compressor system comprises compressing the first air flow (51) with the second air compressor (11) before compressing the first air flow (51) with the first air compressor (10).
    [0025]
    25. Method according to claim 23, characterized in that it additionally comprises controlling the flow rate of the first air flow (51) and the flow rate of the second air flow (21) with the air compressor system to provide substantially stoichiometric combustion in the first combustion (3) and second combustion (4).
    [0026]
    26. Method according to claim 25, characterized in that it additionally comprises controlling the flow rate of the first air flow (51) and flow rate of the second air flow (21) with the air compressor system to provide an excess of up to 5% of O2 in the combustion in the first combustion (3) and second combustion (4).
    [0027]
    27. Method according to claim 15, characterized in that the first fuel stream (26) and the second fuel stream comprise compressed hydrocarbon gas, optionally wherein the compressed hydrocarbon gas comprises methane.
    [0028]
    28. Method according to claim 15, characterized by the fact that the first combustion flow is greater than 50% N2 on a molar basis, and in which the ratio of the first fuel flow to the air flow is controlled in a way to provide a substantially stoichiometric combustion with an excess of O2 of up to about 5%.
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    EA023988B1|2016-08-31|
    EA201300386A1|2013-11-29|
    HK1187968A1|2014-04-17|
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    法律状态:
    2018-12-26| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2019-11-26| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2020-09-08| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2020-12-08| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 20/09/2011, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US38504210P| true| 2010-09-21|2010-09-21|
    US61/385,042|2010-09-21|
    PCT/US2011/052342|WO2012040195A2|2010-09-21|2011-09-20|System and method for high efficiency power generation using a nitrogen gas working fluid|
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