Systems and methods for low-pressure OXY-fuel combustion with carbon capture

Abstract

The present disclosure provides systems and methods for generating power from hydrocarbon feedstocks (e.g., natural gas, biogas, propane, biomass-derived VOCs) while facilitating carbon dioxide (CO₂) capture at relatively moderate pressures. In some embodiments, the oxygen-rich gas has an O₂ concentration of at least about 30%—including near-pure O₂—to yield exhaust gases with CO₂ concentrations often exceeding 90% by volume. The exhaust gas may be expanded in a turbine to produce power and then compressed (e.g., often to pressures below about 10 bar) for CO₂ sequestration, storage, or utilization.

Description

SYSTEMS AND METHODS FOR LOW-PRESSURE OXY-FUEL COMBUSTIONWITH CARBON CAPTURECROSS-REFERENCE

[0001] This application claims priority to U.S. Provisional Application No. 63 / 626495 filed on January 29, 2024, which is incorporated by reference herein in its entirety.BACKGROUND

[0002] Carbon capture incentives may help offset power generation costs as CO2 reduction grows more urgent. Some industrial processes generate excess oxygen and require high heat, such as for steam or SOEC pre-heating. Pressurized Brayton Cycle systems often need fuel boosters for gaseous fuels, with higher firing temperatures requiring advanced materials. Smaller, faster systems reduce hardware size but rely on specialized components to deliver grid-level power. CO2 capture may involve energy-intensive Air Separation Units. Biomass approaches — from refined biofuels to direct combustion — vary in carbon by-products and may not fully utilize available heat for feedstock processing.SUMMARY

[0003] The present disclosure provides systems and methods for generating power from hydrocarbon feedstocks (e.g., natural gas, biogas, propane, biomass-derived VOCs) while facilitating carbon dioxide (CO2) capture at relatively moderate pressures. In some embodiments, the oxygen-rich gas has an O2 concentration of at least about 30% — including near-pure O2 — to yield exhaust gases with CO2 concentrations often exceeding 90% by volume. The exhaust gas may be expanded in a turbine to produce power and then compressed (often to pressures below about 10 bar) for CO2 sequestration, storage, or utilization.

[0004] Recognized herein is a need for more efficient methods of producing on-demand power while capturing CO2 in a semi-closed or partially closed cycle. Embodiments described include controlling combustion stoichiometry (e.g., near- or fully stoichiometric) to minimize nitrogen oxides (NOx), sulfur oxides (SOx), carbon monoxide (CO), and unburned hydrocarbons. Various approaches detail: (i) using industrial by-product oxygen (e.g., from ammonia or ethanol production) to reduce costs; (ii) recirculating CO2 to moderate combustion temperature and enhance CO2 capture purity; (iii) employing multi-stage heat exchangers to preheat reactants, improving thermal efficiency; and (iv) operating sub-atmospheric or modest-pressure combustors and turbines configured from standard-grade alloys.

[0005] Additionally, some embodiments address biomass conversion (e.g., pyrolysis of lignocellulosic feedstock) to produce VOCs and stable char, providing negative-carbon or low-carbon power generation with integrated CO2 capture. The combination of precise oxygen control, moderate compression, and direct or semi-closed Brayton cycle operation ensures high CO2 purity suitable for sequestration, enhanced oil recovery, or industrial uses. By utilizing at least a portion of the turbine-generated power to drive CO2 compression, the disclosed systems and methods provide a scalable pathway for efficient power generation with reduced carbon emissions.

[0006] The present disclosure provides systems and methods for power generation. The method comprises: (a) providing a gas comprising oxygen (02); (b) combusting a hydrocarbon feedstock with the gas comprising oxygen, thereby obtaining an exhaust gas comprising carbon dioxide (CO2); (c) expanding the exhaust gas in a turbine, thereby producing power; (d) compressing at least a portion of the exhaust gas using at least a portion of the power produced in (c), thereby obtaining compressed CO2 at a pressure no greater than 73.9 bar; and (e) combining at least a portion of the compressed CO2 with additional oxygen, thereby obtaining a combined gas.

[0007] In some embodiments, the gas comprising oxygen comprises a concentration of O2 from about 30% to about 100% by volume. In some embodiments, the gas comprising oxygen comprises a concentration of O2 greater than 90% by volume. In some embodiments, the gas comprising oxygen is an output of an industrial process. In some embodiments, the industrial process comprises ammonia production, hydrogen production, ethanol production, chemical looping, water electrolysis, or other industrial processes, or any combination thereof. In some embodiments, the gas comprising oxygen comprises at least about 30% O2 by volume.

[0008] In some embodiments, the exhaust gas comprises a concentration of CO2 of greater than 90% by volume. In some embodiments, the exhaust gas comprises a concentration of CO2 of greater than 95% by volume. In some embodiments, a concentration of unreacted hydrocarbon feedstock in the exhaust gas is less than 1% by volume. In some embodiments, a concentration of sulfur oxides (SOx) in the exhaust gas is less than 1% by volume. In some embodiments, a concentration of nitrogen oxides (NOx) in the exhaust gas is less than 1% byvolume. In some embodiments, a concentration of carbon monoxide (CO) in the exhaust gas is less than 1% by volume. In some embodiments, the exhaust gas further comprises water (H2O).

[0009] In some embodiments, at least a portion of the water is removed from the exhaust gas prior to the compressing in (d). In some embodiments, a concentration of H2O in the exhaust gas prior to the compression in (d) is less than 10% by volume.

[0010] In some embodiments, (b) occurs in a combustor, and the gas comprising oxygen is fed to the combustor in a stoichiometric amount to fully combust the hydrocarbon feedstock. In some embodiments, at least about 99% of O2 in the gas comprising oxygen is consumed during the combusting in (b). In some embodiments, the combusting in (b) comprises stoichiometric combustion of the hydrocarbon feedstock.

[0011] In some embodiments, a concentration of CO2 in the compressed CO2 stream is greater than about 90% by volume. In some embodiments, the concentration of CO2 in the compressed CO2 stream is greater than about 95% by volume. In some embodiments, the concentration of CO2 in the compressed CO2 stream is greater than about 99% by volume.

[0012] In some embodiments, the combined gas comprises a concentration of O2 less than about 30% by volume. In some embodiments, the combined gas comprises a concentration of CO2 greater than about 50% by volume.

[0013] In some embodiments, prior to (b), the gas comprising oxygen is preheated in a heat exchanger. In some embodiments, an additional portion of the compressed CO2 is not combined with the additional oxygen. In some embodiments, the additional portion of the compressed CO2 is directed to a carbon sequestration unit, a purification unit, a storage unit, or a carbon utilization unit, or any combination thereof, without passing through an air separation unit. In some embodiments, the additional portion of the compressed CO2 is passed through a first heat exchanger to preheat the additional oxygen prior to the combining in (e). In some embodiments, the first heat exchanger comprises a gas exchange recuperator. In some embodiments, a temperature of the additional oxygen after exiting the first heat exchanger is at least about 26 °C. In some embodiments, a temperature of the additional oxygen after exiting the first heat exchanger is at least about 600 °C. In some embodiments, a temperature of the additional oxygen prior to entering the first heat exchanger is less than about 400 °C. In some embodiments, a temperature of the additional oxygen increases by atleast about 10 °C in the first heat exchanger. In some embodiments, a temperature of the additional oxygen increases by at least about 100 °C in the first heat exchanger.

[0014] In some embodiments, the gas comprising oxygen is directed through a second heat exchanger prior to (b). In some embodiments, subsequent to (e), the combined gas is directed through a second heat exchanger. In some embodiments, a temperature of the combined gas or the gas comprising oxygen after exiting the second heat exchanger is at least about 200 °C. In some embodiments, that temperature is at least about 600 °C. In some embodiments, a temperature of the combined gas or the gas comprising oxygen prior to entering the second heat exchanger is at least about 500 °C. In some embodiments, the combined gas or the gas comprising oxygen is optionally passed through a second heat exchanger to increase its temperature prior to combustion. In some embodiments, a temperature of the combined gas or the gas comprising oxygen increases by at least 200 °C in the second heat exchanger. In some embodiments, after exiting the second heat exchanger, the combined gas is combusted with additional hydrocarbon feedstock, thereby obtaining additional exhaust gas comprising CO2. In some embodiments, the additional exhaust gas is directed through the second heat exchanger such that heat is transferred from the additional exhaust gas to the combined gas. In some embodiments, the second heat exchanger is optionally bypassed or operated at reduced capacity, so that the temperature of the additional exhaust gas after exiting the second heat exchanger is at most about 300 °C (if in use) or remains substantially unchanged (if not in use).

[0015] In some embodiments, the combined gas is combusted with additional hydrocarbon feedstock, thereby obtaining additional exhaust gas comprising CO2. In some embodiments, the additional exhaust gas is expanded, thereby producing additional power. In some embodiments, at least a portion of the additional exhaust gas is compressed, thereby obtaining additional compressed CO2 at a pressure no greater than 10 bar.

[0016] In some embodiments, the combusting in (b) occurs in a combustor. In some embodiments, a pressure in the combustor is less than about 1.6 bar. In some embodiments, a pressure in the combustor is less than atmospheric pressure. In some embodiments, the temperature of the exhaust gas leaving the combustor during the combusting in (b) is less than about 1500 °C. In some embodiments, that temperature is less than about 1000 °C.

[0017] In some embodiments, the hydrocarbon feedstock comprises natural gas, biogas, propane, methane, kerosene, jet fuel, or diesel, or any combination thereof. In someembodiments, the hydrocarbon feedstock comprises biomass or a derivative thereof. In some embodiments, the hydrocarbon feedstock comprises one or more volatile organic compounds (VOCs). In some embodiments, the one or more VOCs are obtained by drying and pyrolyzing a biomass feedstock. In some embodiments, the drying or the pyrolyzing of the biomass feedstock is at least partially facilitated by heat from the exhaust gas. In some embodiments, the drying or the pyrolyzing of the biomass feedstock produces a carbon-rich char or stable solid pyrolysis product in addition to the one or more VOCs. In some embodiments, the carbon-rich char or stable solid pyrolysis product is stored in a manner that prevents its oxidation.

[0018] In some embodiments, a flow rate of the gas comprising oxygen into the combustor is controlled, thereby controlling, or modifying a composition of the exhaust gas. In some embodiments, a rate of injection of the hydrocarbon feedstock into the combustor is controlled, thereby controlling, or modifying a composition of the exhaust gas. In some embodiments, the combustor is partitioned into an oxygen-rich combustion zone and a CO2 dilution zone. In some embodiments, the hydrocarbon feedstock is introduced into the combustor without the use of a resolute fuel booster or separate fuel compressor. In some embodiments, a flow rate of the hydrocarbon feedstock and a flow rate of the gas comprising oxygen are dynamically controlled based on real-time demand for the power produced in (c). In some embodiments, the combusting in (b) is performed without a separate air separation unit. In some embodiments, in (b), a stoichiometric ratio of the hydrocarbon feedstock and the gas comprising oxygen is maintained, thereby reducing formation of incomplete combustion products in the exhaust gas.

[0019] In some embodiments, the expanding in (c) occurs in a turbine. In some embodiments, the turbine and components thereof are manufactured from standard-grade alloys. In some embodiments, a temperature of the exhaust gas entering the turbine is less than 1000 °C. In some embodiments, that temperature is less than 900 °C. In some embodiments, the turbine is directly coupled to an electrical generator at a synchronous or otherwise compatible speed, thereby eliminating the need for a gearbox or additional power electronics. In some embodiments, a dimensionless specific speed (Ns) of the exhaust gas through the turbine is adjustable between about 0.21 and about 2.0.

[0020] In some embodiments, an expansion ratio of the turbine is from about 1.5 to about 10.0. In some embodiments, a rotational speed of the turbine is between about 1800 rpm and about 10,000 rpm. In some embodiments, the compatible speed comprises at least one of3000 RPM, 3600 RPM, 6000 RPM, or 7200 RPM. In some embodiments, a turbine stress management (TSM) component is used to reduce mechanical stress on the turbine or components thereof, and a pressure at an inlet of the TSM is no less than about 10 bar. In some embodiments, the pressure at the inlet of the TSM is from about 0.1 bar to about 1.6 bar. In some embodiments, a pressure at an inlet of the turbine is from about 0.1 bar to about 1.5 bar. In some embodiments, a pressure at an outlet of the turbine is less than about 0.5 bar. In some embodiments, that pressure is from about 0.1 bar to about 0.5 bar. In some embodiments, the power output from the turbine is from about 2000 kilowatts electrical (kWe) to about 20,000 kWe.

[0021] In some embodiments, an overall net electrical efficiency of the power generation system is between about 10% and about 60%. In some embodiments, a polytropic efficiency of the turbine is from about 46% to about 100%. In some embodiments, an isentropic efficiency of the turbine is from about 46% to about 100%. In some embodiments, the compressed CO2 obtained from the compressor is at a pressure of no greater than 8 bar. In some embodiments, that pressure is no greater than 5 bar. In some embodiments, that pressure is no greater than 3 bar. In some embodiments, the compressed CO2 obtained from the compressor is at a pressure less than atmospheric pressure.

[0022] In some embodiments, the compressing in (d) occurs in a compressor. In some embodiments, the compressor is mechanically coupled to the turbine on a common shaft. In some embodiments, at least one intercooling stage is included in the compressor. In some embodiments, the cycle working fluid is drawn into the compressor passively. In some embodiments, the compressor has a polytropic efficiency from about 40% to about 90%. In some embodiments, a flow rate of the cycle working fluid through the compressor is adjustable based on real-time demand for compression or CO2 sequestration. In some embodiments, the compressor comprises one or more axial, radial (centrifugal), or multistage compressors. In some embodiments, a shaft speed of the compressor is from about 1800 rpm to about 7200 rpm.

[0023] In some embodiments, at least a portion of the compressed CO2 is routed to a carbon capture or sequestration unit. In some embodiments, the compressed CO2 is utilized for oil recovery or for any industrial processes requiring CO2 injection. In some embodiments, the method is a semi-closed Brayton Cycle. In some embodiments, the method utilizes a CO2 working fluid, and a mass flow rate of the working fluid is from about 14 kg / s to about 100 kg / s.

[0024] In some embodiments, at least one of (a), (b), (c), (d), or (e) is performed at sub- atmospheric pressure. In some embodiments, (a), (b), (c), (d), and (e) are performed at sub- atmospheric pressure. In some embodiments, a second portion of the power produced in (c) that is not used in the compressing in (d) is used in an industrial process. In some embodiments, the industrial process produces the gas comprising oxygen. In some embodiments, the power produced in (c) is usable for at least one of: (i) generating electricity, (ii) directly driving a mechanical device or system, or (iii) providing other useful work output. In some embodiments, the turbine is operated at an inlet temperature exceeding about 1000 °C by employing advanced high-temperature alloys or thermal barrier coatings on turbine components, thereby providing higher-temperature combustion while maintaining material integrity.

[0025] Another aspect includes a non-transitory computer-readable media comprising executable instructions that, when executed, cause at least one computer processor to perform any of the methods described herein.

[0026] Another aspect is a computer system comprising a memory storing computer-readable instructions and at least one processor configured to execute the computer-readable instructions that are configured to perform the method of any of the methods described herein.INCORPORATION BY REFERENCE

[0027] All publications, patents, and patent applications mentioned in this specification are herein incorporated by reference to the same extent as if each individual publication, patent, or patent application was specifically and individually indicated to be incorporated by reference. To the extent publications and patents or patent applications incorporated by reference contradict the disclosure contained in the specification, the specification is intended to supersede and / or take precedence over any such contradictory material.BRIEF DESCRIPTION OF THE DRAWINGS

[0028] The novel features of the invention are set forth with particularity in the appended claims. A better understanding of the features and advantages of In some embodiments, the systems and methods disclosed herein will be obtained by reference to the following detailed description that sets forth illustrative embodiments, in which the principles of the invention are utilized, and the accompanying drawings (also “Figure” and “FIG.” herein), of which:

[0029] FIG. 1 shows an example of a power generation system configured for carbon capture, in accordance with some embodiments.

[0030] FIG. 2 shows an example of a single-shaft power generation system configured for natural gas fueling and capable of delivering electric power at a selected efficiency, in accordance with some embodiments.

[0031] FIG. 3 shows an example of a semi-closed biomass-fueled sub-atmospheric Brayton power system featuring integrated pyrolysis and carbon capture, in accordance with some embodiments.

[0032] FIG. 4 shows an example of a temperature-time diagram illustrating fast and slow pyrolysis profiles for biochar formation, in accordance with some embodiments.

[0033] FIG. 5 shows an example of a semi-closed biomass-fueled sub-atmospheric Brayton power system configured to dry and pyrolyze feedstock while generating electrical power, in accordance with some embodiments.

[0034] FIG. 6 shows an example of an un-recuperated semi-closed sub-atmospheric Brayton power system arrayed to maximize heat recovery for applications such as steam generation, in accordance with some embodiments.

[0035] FIG. 7 shows an example of a natural gas-fueled un-recuperated semi-closed sub- atmospheric Brayton power system configured for enhanced heat recovery and carbon capture, in accordance with some embodiments.

[0036] FIG. 8 shows an example of a system workflow diagram illustrating a sub- atmospheric oxy-fuel combustion turbine with options for heat output, power generation, and carbon sequestration, in accordance with some embodiments.

[0037] FIG. 9 shows an example of an integrated system that combines oxy-fuel combustion, heat recovery, and carbon dioxide capture in a closed-loop process, in accordance with some embodiments.

[0038] FIG. 10 shows an example of a closed loop bioenergy system where biomass is converted into syngas for power generation, with captured carbon dioxide directed to utilization or sequestration, in accordance with some embodiments.

[0039] FIG. 11 shows an example of a biomass-based power system integrating direct air capture and rock injection for long-term carbon dioxide storage, in accordance with some embodiments.

[0040] FIG. 12 shows an example of a computer system, in accordance with some embodiments.

[0041] FIG. 13 shows an example of a Brayton power system close-coupled to an abundant oxygen source, in accordance with some embodiments.

[0042] FIG. 14 shows an example of a natural gas-based power generation system configured for carbon capture, in accordance with some embodiments.

[0043] FIG. 15 shows an example of a biogenic gas power generation system configured for carbon capture, in accordance with some embodiments.

[0044] FIG. 16 shows an example of a power generation system configured for geological carbon sequestration, in accordance with some embodiments.

[0045] FIG. 17 shows an example of a power generation system configured for enhanced oil recovery (EOR), in accordance with some embodiments.

[0046] FIG. 18 shows an example of a power generation system configured for carbon dioxide mineralization, in accordance with some embodiments.

[0047] FIG. 19 shows an example of a power generation system configured for chemical and fuel production, in accordance with some embodiments.

[0048] FIG. 20 shows an example of a methanol production system that integrates biomass conversion, electrolysis, and captured carbon dioxide, in accordance with some embodiments.

[0049] FIG. 21 shows an example of a power generation system integrated with hydrogen production via electrolysis, in accordance with some embodiments.

[0050] FIG. 22 shows an example of a carbon dioxide removal system combining biomass- to-syngas conversion, direct air capture, and rock injection, in accordance with some embodiments.

[0051] FIG. 23 shows an example of a companion integration for direct air capture with a sub-atmospheric oxy-fuel combustion system, in accordance with some embodiments.DETAILED DESCRIPTION

[0052] While various embodiments have been shown and described herein, it will be obvious to those skilled in the art that such embodiments are provided by way of example only.Numerous variations, changes, and substitutions may occur to those skilled in the art withoutdeparting from the present disclosure. It may be understood that various alternatives to the embodiments described herein may be employed.

[0053] Whenever the term “at least,” “greater than,” or “greater than or equal to” precedes the first numerical value in a series of two or more numerical values, the term “at least,” “greater than” or “greater than or equal to” applies to each of the numerical values in that series of numerical values. For example, greater than or equal to 1, 2, or 3 is equivalent to greater than or equal to 1, greater than or equal to 2, or greater than or equal to 3.

[0054] Whenever the term “no more than,” “less than,” or “less than or equal to” precedes the first numerical value in a series of two or more numerical values, the term “no more than,” “less than,” or “less than or equal to” applies to each of the numerical values in that series of numerical values. For example, less than or equal to 3, 2, or 1 is equivalent to less than or equal to 3, less than or equal to 2, or less than or equal to 1.

[0055] The term “real time” or “real-time,” as used interchangeably herein, generally refers to an event (e.g., an operation, a process, a method, a technique, a computation, a calculation, an analysis, a visualization, an improved, etc.) that is performed using recently obtained (e.g., collected or received) data. In some cases, a real time event may be performed almost immediately or within a short enough time span, such as within at least 0.0001 millisecond (ms), 0.0005 ms, 0.001 ms, 0.005 ms, 0.01 ms, 0.05 ms, 0.1 ms, 0.5 ms, 1 ms, 5 ms, 0.01 seconds, 0.05 seconds, 0.1 seconds, 0.5 seconds, 1 second, or more. In some cases, a real time event may be performed almost immediately or within a short enough time span, such as within at most 1 second, 0.5 seconds, 0.1 seconds, 0.05 seconds, 0.01 seconds, 5 ms, 1 ms, 0.5 ms, 0.1 ms, 0.05 ms, 0.01 ms, 0.005 ms, 0.001 ms, 0.0005 ms, 0.0001 ms, or less.

[0056] The term “hydrocarbon feedstock” (also referred to herein as “hydrocarbon fuel,” “fuel,” or “fuel source”) generally refers to any carbon-containing material that may be combusted, reformed, partially oxidized, or otherwise thermally or chemically processed to yield carbon dioxide (CO2), water (H2O), and optionally solid or liquid byproducts (e.g., char, tars, bio-oil). Such feedstocks may be fossil-based (e.g., natural gas, propane, diesel, heavy oils, coal) or biogenic / renewable (e.g., lignocellulosic biomass, biogas, pyrolysis vapors, biooils) and may exist in gaseous, liquid, or solid forms. These materials release energy or chemical intermediates upon heating or partial oxidation and may include waste-derived sources (e.g., landfill gas, syngas from gasification, or refined biomass liquids). Furthermore, the “x” may encompass synthetic fuels, hydrogen-rich carbonaceous materials, and blendedor hybrid feedstocks that combine fossil and renewable inputs, provided they yield energy or intermediates through thermal or chemical processing.

[0057] The term “unit,” as used herein, generally refers to a unit operation or subsystem within a broader power generation and carbon capture process. Unit operations may include, for example, combustors (reacting fuel and oxidant), compressors (raising or lowering fluid pressure), turbines (expanding hot gases to extract work), heat exchangers (e.g., recuperators), pyrolysis reactors, anaerobic digesters (AD) for biogas production, gasification reactors, carbon mineralization or carbonation units (e.g., for concrete curing or rock injection), CO2 compression or injection subsystems (e.g., for enhanced oil recovery or geological sequestration), char-processing modules, separators, condensers, and any other chemical or physical processing stage. A given process may incorporate one, or a plurality of, such unit operations to generate, capture, or utilize carbon dioxide from one or more hydrocarbon feedstocks.

[0058] The term “carbon-containing material,” as used herein, generally refers to a substance having at least one carbon atom. In some examples, the carbon-containing material comprises gaseous CO2 or CO. In other examples, the carbon-containing material may be a stable solid carbon residue formed via pyrolysis (e.g., char) or mineralized forms of carbon (e.g., carbonates). Such materials may be derived from hydrocarbon feedstocks (including biomass-based or fossil-based sources) through processes such as anaerobic digestion, gasification, pyrolysis, or partial oxidation. A carbon-containing material may also be a CO2- derived product, for instance when near-pure CO2 is sequestered, converted into another compound (e.g., synthetic fuels, chemicals), mineralized into solid form, or stored as a stable carbon intermediate. In some instances, char may be sequestered (e.g., in soil) or further utilized as biochar and / or activated carbon, and mineralized carbonates may be incorporated into construction or other industrial applications.

[0059] The term “combustion unit,” as used herein, generally refers to any unit operation or subsystem used to oxidize a hydrocarbon feedstock and produce an exhaust stream containing CO2, H2O, and, in some configurations, nitrogen or other inert gases. In oxy-fuel embodiments, this unit may exclusively receive oxygen or oxygen-enriched oxidant, thereby generating a predominantly CO2- and water-rich exhaust. In some instances, the combustion unit may operate sub-atmospherically and / or include CO2 recirculation to moderate flame temperature and reduce NOXformation. Depending on the system design, the combustion unit may be arrayed to run stoichiometric or partial-oxidation conditions, and it may interfacewith pyrolysis, gasification, or other upstream / downstream processes to accommodate a variety of hydrocarbon feedstocks (including biogenic or fossil-based sources).

[0060] The term "power," as used herein, generally refers to any useful work output derived from the expansion of gases through a turbine or similar device. In some embodiments, power may comprise electrical power, generally measured in kilowatts electrical (kWe). In some instances, power may comprise mechanical power, such as shaft work directly driving compressors, pumps, or other mechanical devices. In some cases, power may comprise rotational power transferred through a common shaft operating at synchronous or variable speeds. For example, the power output may be used for grid-compatible electricity generation, mechanical drive applications, or combinations thereof. In some embodiments, the term "power" may also encompass energy recovery in various forms, including but not limited to thermal energy recovery from exhaust streams. The power output may be controlled based on real-time demand signals, with a portion used internally (e.g., for compression or auxiliary systems) and excess power available for export to external processes or the electrical grid.

[0061] The term “semi-closed Brayton cycle” (also sometimes referred to as a “partially closed Brayton cycle”) as used herein generally refers to a thermodynamic cycle in which a working fluid — often including CO2 — is compressed, heated (e.g., via fuel combustion in an oxy-fuel or enriched-oxidant environment), expanded in a turbine to produce work, and then partially recirculated rather than fully vented. In such an arrangement, some fraction of the exhaust gas is reintroduced to the compressor inlet (or an intermediate stage), while the remaining portion — containing CO2 and other byproducts — may be captured, sequestered, or otherwise directed to a utilization pathway. By recycling a substantial share of the working fluid, a semi-closed Brayton cycle may maintain high CO2 concentrations, simplify carbon capture, moderate combustion temperatures (via CO2 dilution), and reduce or eliminate the need for external nitrogen. Depending on embodiment details, the cycle may operate sub- atmospherically, near atmospheric, or slightly above atmospheric pressure; it may be integrated with heat exchangers, recovering thermal energy at multiple stages, and may also incorporate pyrolysis reactors, anaerobic digesters, or gasification units to process various hydrocarbon feedstocks.

[0062] Unless otherwise specified, pressures given herein may be expressed in atmospheres (atm) or bar (with 1 bar ~ 14.5 psi and 1 atm ~ 1.01325 bar). Temperatures are provided in degrees Celsius (°C) or Kelvin (K). Flow rates, feedstock quantities, and other parametersmay also be reported using SI units or other recognized measurement systems. It will be understood by those skilled in the art that any suitable system of units and corresponding conversions (e.g., atm, psi, °F, SCFM) may be employed without departing from the scope or spirit of the present disclosure. As used herein, the term “sub-atmospheric” generally indicates a pressure below about 1 atm (e.g., 0.5-0.9 atm), “near-atmospheric” indicates a pressure close to 1 atm (e.g., about 0.8-1.2 atm), “atmospheric” refers to nominally 1 atm, and “above-atmospheric” indicates pressures exceeding about 1 atm (e.g., 1.1-2 bar or higher). These ranges are approximate and may vary depending on the specific embodiment or measurement reference.I. SYSTEM

[0063] The present disclosure provides systems and methods for generating power and capturing carbon dioxide using a sub-atmospheric Brayton cycle. In some embodiments, the systems and methods utilize a close-coupled source of oxygen to provide carbon dioxide capture without requiring an air separation unit. In some cases, the systems and methods disclosed herein may provide integrated heat recovery capabilities while maintaining carbon capture functionality. In some instances, these systems and methods capture CO2 from both natural gas and biomass-derived fuel sources, thus offering flexibility across various fuel types.

[0064] Provided herein are systems, devices, and methods for capturing or concentrating CO2 from hydrocarbon combustion processes, particularly through sub-atmospheric oxy-fuel cycles or pyrolysis-integrated cycles. In some embodiments, the systems and methods disclosed herein may include an integrated approach that avoids or minimizes the use of traditional air separation units.

[0065] In some embodiments, the systems and methods disclosed herein comprise an integrated carbon capture approach yielding a near-pure CO2 product stream. In some cases, a fuel stream that includes methane, natural gas, biogas, or biomass-derived volatiles may be introduced into a combustor operating at or near stoichiometric oxygen conditions. In some instances, the resulting exhaust stream comprises primarily CO2 and H2O, thereby simplifying the downstream process of carbon dioxide capture. For example, the captured CO2 may be sequestered, utilized for enhanced oil recovery (EOR), or converted into other carbon-based products.

[0066] In some embodiments, the systems and methods disclosed herein are configured to contact a hydrocarbon feedstock with an oxygen source (e.g., pure O2 or Ch-enriched gas) at controlled flow rates, thereby generating a flue gas with high CO2 concentration. In some embodiments, the process may include an integrated sub-atmospheric compressor-turbine system, where the working fluid is predominantly CO2. In some cases, operating under relatively low pressures and moderate temperatures may reduce or eliminate the need for advanced alloys and high-pressure fuel boosters, thereby minimizing both capital and operating costs.

[0067] An input fuel stream may comprise hydrocarbons at various concentrations or compositions. For instance, the input fuel may be a natural gas pipeline feed, having a methane concentration of at least about 70%, 80%, 90%, or 95%. Alternatively, the fuel stream may derive from biogas or pyrolysis vapors comprising mixed Ci to C4 hydrocarbons, tars, or other organics. In some embodiments, the process is tolerant of lesser amounts of sulfur or inert gases in the fuel. In some embodiments, pre-treatment or sulfur scrubbing may be employed to ensure minimal contamination of the captured CO2.

[0068] The captured CO2 stream may be directed to utilization (e.g., CCh-based chemical synthesis, green methanol production, or EOR) or sequestration (e.g., geological storage, mineralization). In some embodiments, the CO2 partial pressure within the system may be between about 0.1 bar to about 2 bar, providing direct compression or liquefaction steps without the complexity of conventional post-combustion capture. In some embodiments, compression to pipeline specifications (e.g., 100 bar) is readily achieved downstream of the sub-atmospheric cycle.

[0069] Carbon capture rates or efficiencies may vary depending on reactor configuration, operating conditions, and the purity of oxygen supply. In some embodiments, the system captures at least about 70%, 80%, 90%, 95%, or 99% of the carbon introduced in the fuel stream as CO2 in a single pass. In some embodiments, multi-stage or recycled pass configurations increase overall carbon capture, achieving near-complete capture rates above 99%. The captured CO2 may also be partially purified or dried to remove condensed water or trace impurities.

[0070] Sub-atmospheric oxy-fuel systems described herein may exhibit selectivity for CO2 production of about 95-99% relative to other carbon-containing combustion byproducts. In some instances, minor fractions of CO or unbumed hydrocarbons may be present buttypically remain below about 1-5%. If desired, these minor byproducts may be oxidized or reformed into additional CO2 to enhance capture rates.

[0071] A power generation system using the disclosed combustion approaches may include turbines, compressors, heat exchangers, and generators configured to produce power alongside near-pure CO2. In embodiments that incorporate biomass pyrolysis, a stable solid carbon char may also be produced, providing negative emissions benefits if the char is sequestered or used in soil amendment.

[0072] The sub-atmospheric cycles described herein may be compact or modular, containing essential components (e.g., combustor, compressor, turbine, heat recovery) in a single housing or skid. Alternatively, the system may comprise multiple linked unit operations across larger industrial sites, including a pyrolysis reactor, steam generation, or multiple turbines arrayed in series or parallel configurations. Each approach is intended to maximize CO2 purity, minimize operational costs, and harness the chemical energy of hydrocarbon feedstocks.

[0073] A power or heat generation system configured according to the present disclosure may include various materials of construction suitable for the expected temperature ranges and CCE-rich environments, such as steels, superalloys, ceramics, or coatings that resist corrosion. The system housing may be single-walled or double-walled, with internal coatings to prevent reaction with hot CO2 or other trace species.

[0074] The system may include one or more chambers or compartments, wherein sub- atmospheric combustion occurs, and a separate condensation or cooling chamber where water is removed, further concentrating CO2. In some embodiments, a pyrolysis chamber may be enclosed separately to dry and pyrolyze biomass before introducing its volatile fraction into the combustor.

[0075] The present disclosure provides a Semi-Closed Sub-Atmospheric Brayton Power System that utilizes a close-coupled abundant source of oxygen to deliver near-pure CO2 in the exhaust stream, providing carbon capture and sequestration without ancillary equipment. In some embodiments, the system comprises a natural gas-fueled power system. In some cases, the system comprises a sub-atmospheric cycle that eliminates fuel boosting. In some instances, the system comprises a low-pressure, low-temperature cycle that eliminates highgrade alloys, gearbox or power electronics, and fuel booster to minimize capital cost.

[0076] In some embodiments, the present disclosure provides a biomass-fueled variant comprising an integrated fuel treatment system that uses turbine exit conditions to dry and pyrolyze inlet biomass feedstock. In some cases, the system comprises a variant that does not utilize an abundant source of oxygen, where the exhaust stream is no longer near-pure CO2 and therefore not sequestration-ready, but retains its ability to store carbon in a stable solid form. In some instances, the system comprises un-recuperated variants that maximize heat recovery.

[0077] Described herein are various CO2 capture products resulting from the combustion or gasification of hydrocarbon feedstocks. Such products may include pipeline-grade CO2, liquefied CO2 for industrial usage, or carbonates formed by mineralizing CO2. These products may be partially purified, dried, or otherwise upgraded to meet commercial or regulatory standards. In embodiments utilizing biomass, the carbon fraction in the product CO2 may include a distinct isotopic signature reflective of the feedstock’s biological origin, whereas fossil-sourced feeds may yield a signature consistent with petrochemicals.

[0078] In some embodiments, the systems and methods disclosed herein may operate at temperatures from about 500°C to about 1200°C and at sub-atmospheric pressures of about 0.1 bar to about 0.8 bar in the combustor or turbine inlet, with higher pressures maintained downstream for CO2 compression. In some cases, factors such as fuel composition, oxygen purity, and system configuration may be optimized to balance efficiency, throughput, and carbon capture rate. In some instances, deployment across various industrial settings, including remote gas fields, bioenergy facilities, or integrated chemical plants aiming to reduce carbon emissions — or even achieve net-negative emissions.II. Pressure Parameters

[0079] The present disclosure provides systems and methods configured to perform one or more unit operations. In some embodiments, the one or more unit operations may comprise an oxygen supply operation, a fuel supply operation, a combustion operation, a turbine (expansion) operation, a compressor operation, a heat exchange or recuperation operation, a condensation or knock-out operation, a CO2 compression or sequestration operation, a biomass pyrolysis operation, a feedstock drying operation, a flow or pressure control operation, a cleaning or scrubbing operation, a char collection operation, a generator coupling operation, and / or an intermediate transport or conveyance operation. Additional unit operations may include a gasification operation, a water-gas shift operation, a Fischer-Tropsch synthesis operation, a chemical looping operation, a catalytic cracking operation, a membrane separation operation, an adsorption or desorption operation, an electrolysis operation, a thermal oxidation operation, a particle filtration operation, a solvent extraction operation, a distillation or fractionation operation, a polymerization operation, a solid-liquid separation operation, a fluidized bed operation, a rotary kiln operation, a mixing or blending operation, an ultrafiltration or reverse osmosis operation, a crystallization operation, a leaching operation, a pH adjustment operation, and / or a chemical reaction operation.

[0080] The input and / or output to the one or more unit operations may include oxygen, fuel, combustion products, compressed gases, heat, steam, liquid water, condensate, CO2, biomass, dried feedstock, syngas, purified gases, cleaned liquids, captured particulates, char, electrical energy, thermal energy, chemical products, intermediates, solvents, filtrates, permeates, chemical precursors, polymeric materials, solid residues, reaction byproducts, flue gas, waste streams, purified water, crystallized solids, pH-adjusted solutions, and / or reaction components. For example, an oxygen supply operation may provide oxygen as an input to a combustion operation, and the output may include combustion products such as heat and flue gas. Similarly, a gasification operation may receive biomass as an input and produce syngas and char as outputs. The specific inputs and outputs may vary depending on the type and configuration of the unit operations within the system.

[0081] In some cases, the one or more unit operations may operate under a pressure of about 0 atm to about 1.1 atm. In some cases, the one or more unit operations may operate under a pressure of about 0 atm to about 0.1 atm, about 0 atm to about 0.2 atm, about 0 atm to about 0.3 atm, about 0 atm to about 0.4 atm, about 0 atm to about 0.5 atm, about 0 atm to about 0.6 atm, about 0 atm to about 0.7 atm, about 0 atm to about 0.8 atm, about 0 atm to about 0.9 atm, about 0 atm to about 1 atm, about 0 atm to about 1.1 atm, about 0.1 atm to about 0.2 atm, about 0.1 atm to about 0.3 atm, about 0.1 atm to about 0.4 atm, about 0.1 atm to about 0.5 atm, about 0.1 atm to about 0.6 atm, about 0.1 atm to about 0.7 atm, about 0.1 atm to about 0.8 atm, about 0.1 atm to about 0.9 atm, about 0.1 atm to about 1 atm, about 0.1 atm to about 1.1 atm, about 0.2 atm to about 0.3 atm, about 0.2 atm to about 0.4 atm, about 0.2 atm to about 0.5 atm, about 0.2 atm to about 0.6 atm, about 0.2 atm to about 0.7 atm, about 0.2 atm to about 0.8 atm, about 0.2 atm to about 0.9 atm, about 0.2 atm to about 1 atm, about 0.2 atm to about 1.1 atm, about 0.3 atm to about 0.4 atm, about 0.3 atm to about 0.5 atm, about 0.3 atm to about 0.6 atm, about 0.3 atm to about 0.7 atm, about 0.3 atm to about 0.8 atm, about 0.3 atm to about 0.9 atm, about 0.3 atm to about 1 atm, about 0.3 atm to about 1.1 atm,about 0.4 atm to about 0.5 atm, about 0.4 atm to about 0.6 atm, about 0.4 atm to about 0.7 atm, about 0.4 atm to about 0.8 atm, about 0.4 atm to about 0.9 atm, about 0.4 atm to about 1 atm, about 0.4 atm to about 1.1 atm, about 0.5 atm to about 0.6 atm, about 0.5 atm to about 0.7 atm, about 0.5 atm to about 0.8 atm, about 0.5 atm to about 0.9 atm, about 0.5 atm to about 1 atm, about 0.5 atm to about 1.1 atm, about 0.6 atm to about 0.7 atm, about 0.6 atm to about 0.8 atm, about 0.6 atm to about 0.9 atm, about 0.6 atm to about 1 atm, about 0.6 atm to about 1.1 atm, about 0.7 atm to about 0.8 atm, about 0.7 atm to about 0.9 atm, about 0.7 atm to about 1 atm, about 0.7 atm to about 1.1 atm, about 0.8 atm to about 0.9 atm, about 0.8 atm to about 1 atm, about 0.8 atm to about 1.1 atm, about 0.9 atm to about 1 atm, about 0.9 atm to about 1.1 atm, or about 1 atm to about 1.1 atm. In some cases, the one or more unit operations may operate under a pressure of about 0 atm, about 0.1 atm, about 0.2 atm, about 0.3 atm, about 0.4 atm, about 0.5 atm, about 0.6 atm, about 0.7 atm, about 0.8 atm, about 0.9 atm, about 1 atm, or about 1.1 atm. In some cases, the one or more unit operations may operate under a pressure of at least about 0 atm, about 0.1 atm, about 0.2 atm, about 0.3 atm, about 0.4 atm, about 0.5 atm, about 0.6 atm, about 0.7 atm, about 0.8 atm, about 0.9 atm, or about 1 atm. In some cases, the one or more unit operations may operate under a pressure of at most about 0.1 atm, about 0.2 atm, about 0.3 atm, about 0.4 atm, about 0.5 atm, about 0.6 atm, about 0.7 atm, about 0.8 atm, about 0.9 atm, about 1 atm, or about 1.1 atm.

[0082] In some cases, the one or more unit operations may operate under a pressure of about1.1 atm to about 2.2 atm. In some cases, the one or more unit operations may operate under a pressure of about 1.1 atm to about 1.2 atm, about 1.1 atm to about 1.3 atm, about 1.1 atm to about 1.4 atm, about 1.1 atm to about 1.5 atm, about 1.1 atm to about 1.6 atm, about 1.1 atm to about 1.7 atm, about 1.1 atm to about 1.8 atm, about 1.1 atm to about 1.9 atm, about 1.1 atm to about 2 atm, about 1.1 atm to about 2.1 atm, about 1.1 atm to about 2.2 atm, about 1.2 atm to about 1.3 atm, about 1.2 atm to about 1.4 atm, about 1.2 atm to about 1.5 atm, about1.2 atm to about 1.6 atm, about 1.2 atm to about 1.7 atm, about 1.2 atm to about 1.8 atm, about 1.2 atm to about 1.9 atm, about 1.2 atm to about 2 atm, about 1.2 atm to about 2.1 atm, about 1.2 atm to about 2.2 atm, about 1.3 atm to about 1.4 atm, about 1.3 atm to about 1.5 atm, about 1.3 atm to about 1.6 atm, about 1.3 atm to about 1.7 atm, about 1.3 atm to about 1.8 atm, about 1.3 atm to about 1.9 atm, about 1.3 atm to about 2 atm, about 1.3 atm to about 2.1 atm, about 1.3 atm to about 2.2 atm, about 1.4 atm to about 1.5 atm, about 1.4 atm to about 1.6 atm, about 1.4 atm to about 1.7 atm, about 1.4 atm to about 1.8 atm, about 1.4 atm to about 1.9 atm, about 1.4 atm to about 2 atm, about 1.4 atm to about 2.1 atm, about 1.4 atmto about 2.2 atm, about 1.5 atm to about 1.6 atm, about 1.5 atm to about 1.7 atm, about 1.5 atm to about 1.8 atm, about 1.5 atm to about 1.9 atm, about 1.5 atm to about 2 atm, about 1.5 atm to about 2.1 atm, about 1.5 atm to about 2.2 atm, about 1.6 atm to about 1.7 atm, about 1.6 atm to about 1.8 atm, about 1.6 atm to about 1.9 atm, about 1.6 atm to about 2 atm, about 1.6 atm to about 2.1 atm, about 1.6 atm to about 2.2 atm, about 1.7 atm to about 1.8 atm, about 1.7 atm to about 1.9 atm, about 1.7 atm to about 2 atm, about 1.7 atm to about 2.1 atm, about 1.7 atm to about 2.2 atm, about 1.8 atm to about 1.9 atm, about 1.8 atm to about 2 atm, about 1.8 atm to about 2.1 atm, about 1.8 atm to about 2.2 atm, about 1.9 atm to about 2 atm, about 1.9 atm to about 2.1 atm, about 1.9 atm to about 2.2 atm, about 2 atm to about 2.1 atm, about 2 atm to about 2.2 atm, or about 2.1 atm to about 2.2 atm. In some cases, the one or more unit operations may operate under a pressure of about 1.1 atm, about 1.2 atm, about 1.3 atm, about 1.4 atm, about 1.5 atm, about 1.6 atm, about 1.7 atm, about 1.8 atm, about 1.9 atm, about 2 atm, about 2.1 atm, or about 2.2 atm. In some cases, the one or more unit operations may operate under a pressure of at least about 1.1 atm, about 1.2 atm, about 1.3 atm, about 1.4 atm, about 1.5 atm, about 1.6 atm, about 1.7 atm, about 1.8 atm, about 1.9 atm, about 2 atm, or about 2.1 atm. In some cases, the one or more unit operations may operate under a pressure of at most about 1.2 atm, about 1.3 atm, about 1.4 atm, about 1.5 atm, about 1.6 atm, about 1.7 atm, about 1.8 atm, about 1.9 atm, about 2 atm, about 2.1 atm, or about 2.2 atm.

[0083] In some cases, the one or more unit operations may operate under a pressure of aboutI atm to about 12 atm. In some cases, the one or more unit operations may operate under a pressure of about 1 atm to about 2 atm, about 1 atm to about 3 atm, about 1 atm to about 4 atm, about 1 atm to about 5 atm, about 1 atm to about 6 atm, about 1 atm to about 7 atm, about 1 atm to about 8 atm, about 1 atm to about 9 atm, about 1 atm to about 10 atm, about 1 atm to about 11 atm, about 1 atm to about 12 atm, about 2 atm to about 3 atm, about 2 atm to about 4 atm, about 2 atm to about 5 atm, about 2 atm to about 6 atm, about 2 atm to about 7 atm, about 2 atm to about 8 atm, about 2 atm to about 9 atm, about 2 atm to about 10 atm, about 2 atm to about 11 atm, about 2 atm to about 12 atm, about 3 atm to about 4 atm, about 3 atm to about 5 atm, about 3 atm to about 6 atm, about 3 atm to about 7 atm, about 3 atm to about 8 atm, about 3 atm to about 9 atm, about 3 atm to about 10 atm, about 3 atm to aboutI I atm, about 3 atm to about 12 atm, about 4 atm to about 5 atm, about 4 atm to about 6 atm, about 4 atm to about 7 atm, about 4 atm to about 8 atm, about 4 atm to about 9 atm, about 4 atm to about 10 atm, about 4 atm to about 11 atm, about 4 atm to about 12 atm, about 5 atm to about 6 atm, about 5 atm to about 7 atm, about 5 atm to about 8 atm, about 5 atm to about9 atm, about 5 atm to about 10 atm, about 5 atm to about 11 atm, about 5 atm to about 12 atm, about 6 atm to about 7 atm, about 6 atm to about 8 atm, about 6 atm to about 9 atm, about 6 atm to about 10 atm, about 6 atm to about 11 atm, about 6 atm to about 12 atm, about 7 atm to about 8 atm, about 7 atm to about 9 atm, about 7 atm to about 10 atm, about 7 atm to about 11 atm, about 7 atm to about 12 atm, about 8 atm to about 9 atm, about 8 atm to about10 atm, about 8 atm to about 11 atm, about 8 atm to about 12 atm, about 9 atm to about 10 atm, about 9 atm to about 11 atm, about 9 atm to about 12 atm, about 10 atm to about 11 atm, about 10 atm to about 12 atm, or about 11 atm to about 12 atm. In some cases, the one or more unit operations may operate under a pressure of about 1 atm, about 2 atm, about 3 atm, about 4 atm, about 5 atm, about 6 atm, about 7 atm, about 8 atm, about 9 atm, about 10 atm, about 11 atm, or about 12 atm. In some cases, the one or more unit operations may operate under a pressure of at least about 1 atm, about 2 atm, about 3 atm, about 4 atm, about 5 atm, about 6 atm, about 7 atm, about 8 atm, about 9 atm, about 10 atm, or about 11 atm. In some cases, the one or more unit operations may operate under a pressure of at most about 2 atm, about 3 atm, about 4 atm, about 5 atm, about 6 atm, about 7 atm, about 8 atm, about 9 atm, about 10 atm, about 11 atm, or about 12 atm.

[0084] In some cases, the one or more unit operations may operate under a pressure of about 10 atm to about 120 atm. In some cases, the one or more unit operations may operate under a pressure of about 10 atm to about 20 atm, about 10 atm to about 30 atm, about 10 atm to about 40 atm, about 10 atm to about 50 atm, about 10 atm to about 60 atm, about 10 atm to about 70 atm, about 10 atm to about 80 atm, about 10 atm to about 90 atm, about 10 atm to about 100 atm, about 10 atm to about 110 atm, about 10 atm to about 120 atm, about 20 atm to about 30 atm, about 20 atm to about 40 atm, about 20 atm to about 50 atm, about 20 atm to about 60 atm, about 20 atm to about 70 atm, about 20 atm to about 80 atm, about 20 atm to about 90 atm, about 20 atm to about 100 atm, about 20 atm to about 110 atm, about 20 atm to about 120 atm, about 30 atm to about 40 atm, about 30 atm to about 50 atm, about 30 atm to about 60 atm, about 30 atm to about 70 atm, about 30 atm to about 80 atm, about 30 atm to about 90 atm, about 30 atm to about 100 atm, about 30 atm to about 110 atm, about 30 atm to about 120 atm, about 40 atm to about 50 atm, about 40 atm to about 60 atm, about 40 atm to about 70 atm, about 40 atm to about 80 atm, about 40 atm to about 90 atm, about 40 atm to about 100 atm, about 40 atm to about 110 atm, about 40 atm to about 120 atm, about 50 atm to about 60 atm, about 50 atm to about 70 atm, about 50 atm to about 80 atm, about 50 atm to about 90 atm, about 50 atm to about 100 atm, about 50 atm to about 110 atm, about 50 atm toabout 120 atm, about 60 atm to about 70 atm, about 60 atm to about 80 atm, about 60 atm to about 90 atm, about 60 atm to about 100 atm, about 60 atm to about 110 atm, about 60 atm to about 120 atm, about 70 atm to about 80 atm, about 70 atm to about 90 atm, about 70 atm to about 100 atm, about 70 atm to about 110 atm, about 70 atm to about 120 atm, about 80 atm to about 90 atm, about 80 atm to about 100 atm, about 80 atm to about 110 atm, about 80 atm to about 120 atm, about 90 atm to about 100 atm, about 90 atm to about 110 atm, about 90 atm to about 120 atm, about 100 atm to about 110 atm, about 100 atm to about 120 atm, or about 110 atm to about 120 atm. In some cases, the one or more unit operations may operate under a pressure of about 10 atm, about 20 atm, about 30 atm, about 40 atm, about 50 atm, about 60 atm, about 70 atm, about 80 atm, about 90 atm, about 100 atm, about 110 atm, or about 120 atm. In some cases, the one or more unit operations may operate under a pressure of at least about 10 atm, about 20 atm, about 30 atm, about 40 atm, about 50 atm, about 60 atm, about 70 atm, about 80 atm, about 90 atm, about 100 atm, or about 110 atm. In some cases, the one or more unit operations may operate under a pressure of at most about 20 atm, about 30 atm, about 40 atm, about 50 atm, about 60 atm, about 70 atm, about 80 atm, about 90 atm, about 100 atm, about 110 atm, or about 120 atm.

[0085] In some cases, the one or more unit operations may operate under a pressure of about 100 atm to about 210 atm. In some cases, the one or more unit operations may operate under a pressure of about 100 atm to about 110 atm, about 100 atm to about 120 atm, about 100 atm to about 130 atm, about 100 atm to about 140 atm, about 100 atm to about 150 atm, about 100 atm to about 160 atm, about 100 atm to about 170 atm, about 100 atm to about 180 atm, about 100 atm to about 190 atm, about 100 atm to about 200 atm, about 100 atm to about 210 atm, about 110 atm to about 120 atm, about 110 atm to about 130 atm, about 110 atm to about 140 atm, about 110 atm to about 150 atm, about 110 atm to about 160 atm, about 110 atm to about 170 atm, about 110 atm to about 180 atm, about 110 atm to about 190 atm, about 110 atm to about 200 atm, about 110 atm to about 210 atm, about 120 atm to about 130 atm, about 120 atm to about 140 atm, about 120 atm to about 150 atm, about 120 atm to about 160 atm, about 120 atm to about 170 atm, about 120 atm to about 180 atm, about 120 atm to about 190 atm, about 120 atm to about 200 atm, about 120 atm to about 210 atm, about 130 atm to about 140 atm, about 130 atm to about 150 atm, about 130 atm to about 160 atm, about 130 atm to about 170 atm, about 130 atm to about 180 atm, about 130 atm to about 190 atm, about 130 atm to about 200 atm, about 130 atm to about 210 atm, about 140 atm to about 150 atm, about 140 atm to about 160 atm, about 140 atm to about 170 atm,about 140 atm to about 180 atm, about 140 atm to about 190 atm, about 140 atm to about 200 atm, about 140 atm to about 210 atm, about 150 atm to about 160 atm, about 150 atm to about 170 atm, about 150 atm to about 180 atm, about 150 atm to about 190 atm, about 150 atm to about 200 atm, about 150 atm to about 210 atm, about 160 atm to about 170 atm, about 160 atm to about 180 atm, about 160 atm to about 190 atm, about 160 atm to about 200 atm, about 160 atm to about 210 atm, about 170 atm to about 180 atm, about 170 atm to about 190 atm, about 170 atm to about 200 atm, about 170 atm to about 210 atm, about 180 atm to about 190 atm, about 180 atm to about 200 atm, about 180 atm to about 210 atm, about 190 atm to about 200 atm, about 190 atm to about 210 atm, or about 200 atm to about 210 atm. In some cases, the one or more unit operations may operate under a pressure of about 100 atm, about 110 atm, about 120 atm, about 130 atm, about 140 atm, about 150 atm, about 160 atm, about 170 atm, about 180 atm, about 190 atm, about 200 atm, or about 210 atm. In some cases, the one or more unit operations may operate under a pressure of at least about 100 atm, about 110 atm, about 120 atm, about 130 atm, about 140 atm, about 150 atm, about 160 atm, about 170 atm, about 180 atm, about 190 atm, or about 200 atm. In some cases, the one or more unit operations may operate under a pressure of at most about 110 atm, about 120 atm, about 130 atm, about 140 atm, about 150 atm, about 160 atm, about 170 atm, about 180 atm, about 190 atm, about 200 atm, or about 210 atm.

[0086] In some cases, the one or more unit operations may operate under a pressure of about 200 atm to about 2,500 atm. In some cases, the one or more unit operations may operate under a pressure of about 200 atm to about 300 atm, about 200 atm to about 400 atm, about 200 atm to about 500 atm, about 200 atm to about 600 atm, about 200 atm to about 700 atm, about 200 atm to about 800 atm, about 200 atm to about 900 atm, about 200 atm to about 1,000 atm, about 200 atm to about 1,500 atm, about 200 atm to about 2,000 atm, about 200 atm to about 2,500 atm, about 300 atm to about 400 atm, about 300 atm to about 500 atm, about 300 atm to about 600 atm, about 300 atm to about 700 atm, about 300 atm to about 800 atm, about 300 atm to about 900 atm, about 300 atm to about 1,000 atm, about 300 atm to about 1,500 atm, about 300 atm to about 2,000 atm, about 300 atm to about 2,500 atm, about 400 atm to about 500 atm, about 400 atm to about 600 atm, about 400 atm to about 700 atm, about 400 atm to about 800 atm, about 400 atm to about 900 atm, about 400 atm to about 1,000 atm, about 400 atm to about 1,500 atm, about 400 atm to about 2,000 atm, about 400 atm to about 2,500 atm, about 500 atm to about 600 atm, about 500 atm to about 700 atm, about 500 atm to about 800 atm, about 500 atm to about 900 atm, about 500 atm to about1,000 atm, about 500 atm to about 1,500 atm, about 500 atm to about 2,000 atm, about 500 atm to about 2,500 atm, about 600 atm to about 700 atm, about 600 atm to about 800 atm, about 600 atm to about 900 atm, about 600 atm to about 1,000 atm, about 600 atm to about1.500 atm, about 600 atm to about 2,000 atm, about 600 atm to about 2,500 atm, about 700 atm to about 800 atm, about 700 atm to about 900 atm, about 700 atm to about 1,000 atm, about 700 atm to about 1,500 atm, about 700 atm to about 2,000 atm, about 700 atm to about2.500 atm, about 800 atm to about 900 atm, about 800 atm to about 1,000 atm, about 800 atm to about 1,500 atm, about 800 atm to about 2,000 atm, about 800 atm to about 2,500 atm, about 900 atm to about 1,000 atm, about 900 atm to about 1,500 atm, about 900 atm to about 2,000 atm, about 900 atm to about 2,500 atm, about 1,000 atm to about 1,500 atm, about 1,000 atm to about 2,000 atm, about 1,000 atm to about 2,500 atm, about 1,500 atm to about 2,000 atm, about 1,500 atm to about 2,500 atm, or about 2,000 atm to about 2,500 atm. In some cases, the one or more unit operations may operate under a pressure of about 200 atm, about 300 atm, about 400 atm, about 500 atm, about 600 atm, about 700 atm, about 800 atm, about 900 atm, about 1,000 atm, about 1,500 atm, about 2,000 atm, or about 2,500 atm. In some cases, the one or more unit operations may operate under a pressure of at least about 200 atm, about 300 atm, about 400 atm, about 500 atm, about 600 atm, about 700 atm, about 800 atm, about 900 atm, about 1,000 atm, about 1,500 atm, or about 2,000 atm. In some cases, the one or more unit operations may operate under a pressure of at most about 300 atm, about 400 atm, about 500 atm, about 600 atm, about 700 atm, about 800 atm, about 900 atm, about 1,000 atm, about 1,500 atm, about 2,000 atm, or about 2,500 atm.

[0087] In some embodiments, the operating pressure may range from sub-atmospheric (e.g., about 0.1 bar) up to about 70 bar or about 72.8 bar, thereby maintaining moderate or subcritical conditions. In some cases, preferred implementations operate below the supercritical pressure of approximately 73 bar to align with a sub- or low-pressure configuration. In some embodiments, the systems and methods disclosed herein may employ higher pressures if advanced materials or alternative configuration considerations permit.

[0088] In some embodiments, the system comprises at least one pressure ratio control feature. In some cases, the at least one pressure ratio control feature comprises variable guide vanes or flow control valves in the compressor to maintain a desired pressure ratio from about 2.5 to about 4.5, although other suitable ranges may be used. In some instances, the at least one pressure ratio control feature comprises sub-atmospheric inlet pressures (pi < 1 bar) to facilitate carbon capture. In some cases, the at least one pressure ratio control featurecomprises adapting to near-atmospheric or slightly above atmospheric pressures at the turbine inlet (e.g., about 0.4 bar to about 1.5 bar). In some instances, the at least one pressure ratio control feature comprises adjusting the expansion ratio in the turbine to maintain stable operation across varying loads. For example, the system may be configured to target a nominal expansion ratio of about 3.2. As an example, the pressure ratio control feature may coordinate with temperature control logic to avoid compressor surge or turbine overexpansion.

[0089] In some cases, a compressor inlet pressure may comprise about 0.1 atm, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.1, 2.2, 2.3, 2.4, 2.5,2.6, 2.7, 2.8, 2.9, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 4.0, 4.1, 4.2, 4.3, 4.4, 4.5, 4.6,4.7, 4.8, 4.9, 5.0, 5.1, 5.2, 5.3, 5.4, 5.5, 5.6, 5.7, 5.8, 5.9, 6.0, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7,6.8, 6.9, 7.0, 7.1, 7.2, 7.3, 7.4, 7.5, 7.6, 7.7, 7.8, 7.9, 8.0, 8.1, 8.2, 8.3, 8.4, 8.5, 8.6, 8.7, 8.8,8.9, 9.0, 9.1, 9.2, 9.3, 9.4, 9.5, 9.6, 9.7, 9.8, 9.9, or 10.0 atm, or any value in between. In some cases, a compressor outlet pressure may comprise similar values, ranging from about 0.1 atm to about 10.0 atm or greater.

[0090] In some cases, a pressure ratio is defined as the ratio of a compressor inlet pressure to a compressor outlet pressure. In some instances, the at least one compressor comprises a pressure ratio of 0.1, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7,1.8, 1.9, 2.0, 2.1, 2.2, 2.3, 2.4, 2.5, 2.6, 2.7, 2.8, 2.9, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8,3.9, 4.0, 4.1, 4.2, 4.3, 4.4, 4.5, 4.6, 4.7, 4.8, 4.9, 5.0, 5.1, 5.2, 5.3, 5.4, 5.5, 5.6, 5.7, 5.8, 5.9,6.0, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 6.8, 6.9, 7.0, 7.1, 7.2, 7.3, 7.4, 7.5, 7.6, 7.7, 7.8, 7.9, 8.0,8.1, 8.2, 8.3, 8.4, 8.5, 8.6, 8.7, 8.8, 8.9, 9.0, 9.1, 9.2, 9.3, 9.4, 9.5, 9.6, 9.7, 9.8, 9.9, or 10.0, or any value in between.

[0091] In some cases, a combustor inlet pressure may comprise about 0.1 atm, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.1, 2.2, 2.3, 2.4, 2.5,2.6, 2.7, 2.8, 2.9, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 4.0, 4.1, 4.2, 4.3, 4.4, 4.5, 4.6,4.7, 4.8, 4.9, 5.0, 5.1, 5.2, 5.3, 5.4, 5.5, 5.6, 5.7, 5.8, 5.9, 6.0, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7,6.8, 6.9, 7.0, 7.1, 7.2, 7.3, 7.4, 7.5, 7.6, 7.7, 7.8, 7.9, 8.0, 8.1, 8.2, 8.3, 8.4, 8.5, 8.6, 8.7, 8.8,8.9, 9.0, 9.1, 9.2, 9.3, 9.4, 9.5, 9.6, 9.7, 9.8, 9.9, or 10.0 atm, or any value in between. In some cases, a combustor outlet pressure may comprise similar values, ranging from about 0.1 atm to about 10.0 atm or greater.

[0092] In some cases, a pressure ratio is defined as the ratio of a combustor inlet pressure to a combustor outlet pressure. In some instances, the at least one combustor comprises a pressure ratio of 0.1, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.1, 2.2, 2.3, 2.4, 2.5, 2.6, 2.7, 2.8, 2.9, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 4.0,4.1, 4.2, 4.3, 4.4, 4.5, 4.6, 4.7, 4.8, 4.9, 5.0, 5.1, 5.2, 5.3, 5.4, 5.5, 5.6, 5.7, 5.8, 5.9, 6.0, 6.1,6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 6.8, 6.9, 7.0, 7.1, 7.2, 7.3, 7.4, 7.5, 7.6, 7.7, 7.8, 7.9, 8.0, 8.1, 8.2,8.3, 8.4, 8.5, 8.6, 8.7, 8.8, 8.9, 9.0, 9.1, 9.2, 9.3, 9.4, 9.5, 9.6, 9.7, 9.8, 9.9, or 10.0, or any value in between.

[0093] In some cases, a turbine inlet pressure may comprise about 0.1 atm, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.1, 2.2, 2.3, 2.4, 2.5, 2.6,2.7, 2.8, 2.9, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 4.0, 4.1, 4.2, 4.3, 4.4, 4.5, 4.6, 4.7,4.8, 4.9, 5.0, 5.1, 5.2, 5.3, 5.4, 5.5, 5.6, 5.7, 5.8, 5.9, 6.0, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 6.8,6.9, 7.0, 7.1, 7.2, 7.3, 7.4, 7.5, 7.6, 7.7, 7.8, 7.9, 8.0, 8.1, 8.2, 8.3, 8.4, 8.5, 8.6, 8.7, 8.8, 8.9,9.0, 9.1, 9.2, 9.3, 9.4, 9.5, 9.6, 9.7, 9.8, 9.9, or 10.0 atm, or any value in between. In some cases, a turbine outlet pressure may comprise similar values, ranging from about 0.1 atm to about 10.0 atm or greater.

[0094] In some cases, a pressure ratio is defined as the ratio of a turbine inlet pressure to a turbine outlet pressure. In some instances, the at least one turbine comprises a pressure ratio of 0.1, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.1,2.2, 2.3, 2.4, 2.5, 2.6, 2.7, 2.8, 2.9, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 4.0, 4.1, 4.2,4.3, 4.4, 4.5, 4.6, 4.7, 4.8, 4.9, 5.0, 5.1, 5.2, 5.3, 5.4, 5.5, 5.6, 5.7, 5.8, 5.9, 6.0, 6.1, 6.2, 6.3,6.4, 6.5, 6.6, 6.7, 6.8, 6.9, 7.0, 7.1, 7.2, 7.3, 7.4, 7.5, 7.6, 7.7, 7.8, 7.9, 8.0, 8.1, 8.2, 8.3, 8.4,8.5, 8.6, 8.7, 8.8, 8.9, 9.0, 9.1, 9.2, 9.3, 9.4, 9.5, 9.6, 9.7, 9.8, 9.9, or 10.0, or any value in between.III. Temperature Parameters

[0095] In some cases, the one or more unit operations may operate under a temperature of about 0 K to about 1,100 K. In some cases, the one or more unit operations may operate under a temperature of about 0 K to about 100 K, about 0 K to about 200 K, about 0 K to about 300 K, about 0 K to about 400 K, about 0 K to about 500 K, about 0 K to about 600 K, about 0 K to about 700 K, about 0 K to about 800 K, about 0 K to about 900 K, about 0 K to about 1,000 K, about 0 K to about 1,100 K, about 100 K to about 200 K, about 100 K to about 300 K, about 100 K to about 400 K, about 100 K to about 500 K, about 100 K to about600 K, about 100 K to about 700 K, about 100 K to about 800 K, about 100 K to about 900 K, about 100 K to about 1,000 K, about 100 K to about 1,100 K, about 200 K to about 300 K, about 200 K to about 400 K, about 200 K to about 500 K, about 200 K to about 600 K, about 200 K to about 700 K, about 200 K to about 800 K, about 200 K to about 900 K, about 200 K to about 1,000 K, about 200 K to about 1,100 K, about 300 K to about 400 K, about 300 K to about 500 K, about 300 K to about 600 K, about 300 K to about 700 K, about 300 K to about 800 K, about 300 K to about 900 K, about 300 K to about 1,000 K, about 300 K to about 1, 100 K, about 400 K to about 500 K, about 400 K to about 600 K, about 400 K to about 700 K, about 400 K to about 800 K, about 400 K to about 900 K, about 400 K to about 1,000 K, about 400 K to about 1,100 K, about 500 K to about 600 K, about 500 K to about 700 K, about 500 K to about 800 K, about 500 K to about 900 K, about 500 K to about 1,000 K, about 500 K to about 1,100 K, about 600 K to about 700 K, about 600 K to about 800 K, about 600 K to about 900 K, about 600 K to about 1,000 K, about 600 K to about 1,100 K, about 700 K to about 800 K, about 700 K to about 900 K, about 700 K to about 1,000 K, about 700 K to about 1,100 K, about 800 K to about 900 K, about 800 K to about 1,000 K, about 800 K to about 1,100 K, about 900 K to about 1,000 K, about 900 K to about 1,100 K, or about 1,000 K to about 1,100 K. In some cases, the one or more unit operations may operate under a temperature of about 0 K, about 100 K, about 200 K, about 300 K, about 400 K, about 500 K, about 600 K, about 700 K, about 800 K, about 900 K, about 1,000 K, or about 1,100 K. In some cases, the one or more unit operations may operate under a temperature of about at least about 0 K, about 100 K, about 200 K, about 300 K, about 400 K, about 500 K, about 600 K, about 700 K, about 800 K, about 900 K, or about 1,000 K. In some cases, the one or more unit operations may operate under a temperature of about at most about 100 K, about 200 K, about 300 K, about 400 K, about 500 K, about 600 K, about 700 K, about 800 K, about 900 K, about 1,000 K, or about 1,100 K.

[0096] In some cases, the one or more unit operations may operate under a temperature of about 1,000 K to about 2,500 K. In some cases, the one or more unit operations may operate under a temperature of about 1,000 K to about 1,100 K, about 1,000 K to about 1,200 K, about 1,000 K to about 1,300 K, about 1,000 K to about 1,400 K, about 1,000 K to about 1,500 K, about 1,000 K to about 1,600 K, about 1,000 K to about 1,700 K, about 1,000 K to about 1,800 K, about 1,000 K to about 1,900 K, about 1,000 K to about 2,000 K, about 1,000 K to about 2,500 K, about 1,100 K to about 1,200 K, about 1,100 K to about 1,300 K, about 1,100 K to about 1,400 K, about 1,100 K to about 1,500 K, about 1,100 K to about 1,600 K,about 1,100 K to about 1,700 K, about 1,100 K to about 1,800 K, about 1,100 K to about 1,900 K, about 1,100 K to about 2,000 K, about 1,100 K to about 2,500 K, about 1,200 K to about 1,300 K, about 1,200 K to about 1,400 K, about 1,200 K to about 1,500 K, about 1,200 K to about 1,600 K, about 1,200 K to about 1,700 K, about 1,200 K to about 1,800 K, about 1,200 K to about 1,900 K, about 1,200 K to about 2,000 K, about 1,200 K to about 2,500 K, about 1,300 K to about 1,400 K, about 1,300 K to about 1,500 K, about 1,300 K to about 1,600 K, about 1,300 K to about 1,700 K, about 1,300 K to about 1,800 K, about 1,300 K to about 1,900 K, about 1,300 K to about 2,000 K, about 1,300 K to about 2,500 K, about 1,400 K to about 1,500 K, about 1,400 K to about 1,600 K, about 1,400 K to about 1,700 K, about 1,400 K to about 1,800 K, about 1,400 K to about 1,900 K, about 1,400 K to about 2,000 K, about 1,400 K to about 2,500 K, about 1,500 K to about 1,600 K, about 1,500 K to about 1,700 K, about 1,500 K to about 1,800 K, about 1,500 K to about 1,900 K, about 1,500 K to about 2,000 K, about 1,500 K to about 2,500 K, about 1,600 K to about 1,700 K, about 1,600 K to about 1,800 K, about 1,600 K to about 1,900 K, about 1,600 K to about 2,000 K, about 1,600 K to about 2,500 K, about 1,700 K to about 1,800 K, about 1,700 K to about 1,900 K, about 1,700 K to about 2,000 K, about 1,700 K to about 2,500 K, about 1,800 K to about 1,900 K, about 1,800 K to about 2,000 K, about 1,800 K to about 2,500 K, about 1,900 K to about 2,000 K, about 1,900 K to about 2,500 K, or about 2,000 K to about 2,500 K. In some cases, the one or more unit operations may operate under a temperature of about 1,000 K, about 1,100 K, about 1,200 K, about 1,300 K, about 1,400 K, about 1,500 K, about 1,600 K, about 1,700 K, about 1,800 K, about 1,900 K, about 2,000 K, or about 2,500 K. In some cases, the one or more unit operations may operate under a temperature of about at least about 1,000 K, about 1,100 K, about 1,200 K, about 1,300 K, about 1,400 K, about 1,500 K, about 1,600 K, about 1,700 K, about 1,800 K, about 1,900 K, or about 2,000 K. In some cases, the one or more unit operations may operate under a temperature of about at most about 1,100 K, about 1,200 K, about 1,300 K, about 1,400 K, about 1,500 K, about 1,600 K, about 1,700 K, about 1,800 K, about 1,900 K, about 2,000 K, or about 2,500 K.

[0097] In some embodiments, the combustion and turbine inlet temperature remain below about 1000 °C, thereby allowing the use of standard-grade alloys. In some cases, the systems and methods disclosed herein may employ higher temperatures if advanced materials or alternative design considerations permit.

[0098] In some cases, the input and / or output fluids or gases associated with the one or more unit operations (e.g., oxygen supply, fuel supply, combustion, turbine expansion,compression, heat exchange, condensation, CO2 compression or sequestration, biomass pyrolysis, feedstock drying, flow or pressure control, cleaning or scrubbing, char collection, generator coupling, and / or intermediate transport or conveyance) may be handled at flow rates of about 1 kg / s, 2 kg / s, 3 kg / s, 4 kg / s, 5 kg / s, 6 kg / s, 7 kg / s, 8 kg / s, 9 kg / s, 10 kg / s, 11 kg / s, 12 kg / s, 13 kg / s, 14 kg / s, 15 kg / s, 16 kg / s, 17 kg / s, 18 kg / s, 19 kg / s, 20 kg / s, 21 kg / s, 22 kg / s, 23 kg / s, 24 kg / s, 25 kg / s, 26 kg / s, 27 kg / s, 28 kg / s, 29 kg / s, 30 kg / s, 31 kg / s, 32 kg / s, 33 kg / s, 34 kg / s, 35 kg / s, 36 kg / s, 37 kg / s, 38 kg / s, 39 kg / s, 40 kg / s, 100 kg / s, 42 kg / s, 43 kg / s, 44 kg / s, 45 kg / s, 46 kg / s, 47 kg / s, 48 kg / s, 49 kg / s, 50 kg / s, 51 kg / s, 52 kg / s, 53 kg / s, 54 kg / s,55 kg / s, 56 kg / s, 57 kg / s, 58 kg / s, 59 kg / s, 60 kg / s, 61 kg / s, 62 kg / s, 63 kg / s, 64 kg / s, 65 kg / s,66 kg / s, 67 kg / s, 68 kg / s, 69 kg / s, 70 kg / s, 71 kg / s, 72 kg / s, 73 kg / s, 74 kg / s, 75 kg / s, 76 kg / s,77 kg / s, 78 kg / s, 79 kg / s, 80 kg / s, 81 kg / s, 82 kg / s, 83 kg / s, 84 kg / s, 85 kg / s, 86 kg / s, 87 kg / s,88 kg / s, 89 kg / s, 90 kg / s, 91 kg / s, 92 kg / s, 93 kg / s, 94 kg / s, 95 kg / s, 96 kg / s, 97 kg / s, 98 kg / s,99 kg / s, or 100 kg / s, or greater than 100 kg / s, or any value in between.

[0099] In some embodiments, a pressure ratio may apply to one or more unit operations, where the pressure at one or more unit operation inlets is compared to the pressure at one or more unit operation outlets. These unit operations may include compressors, turbines (expansion operations), heat exchangers, gasification systems, chemical reactors, separation systems, condensation or knock-out systems, biomass pyrolysis systems, and / or membrane operations. The at least one unit operation may include a pressure ratio of 0.1, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.1, 2.2, 2.3, 2.4, 2.5,2.6, 2.7, 2.8, 2.9, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 4.0, 4.1, 4.2, 4.3, 4.4, 4.5, 4.6,4.7, 4.8, 4.9, 5.0, 5.1, 5.2, 5.3, 5.4, 5.5, 5.6, 5.7, 5.8, 5.9, 6.0, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7,6.8, 6.9, 7.0, 7.1, 7.2, 7.3, 7.4, 7.5, 7.6, 7.7, 7.8, 7.9, 8.0, 8.1, 8.2, 8.3, 8.4, 8.5, 8.6, 8.7, 8.8,8.9, 9.0, 9.1, 9.2, 9.3, 9.4, 9.5, 9.6, 9.7, 9.8, 9.9, or 10.0, or greater than 10.0, or any value in between.

[0100] The one or more unit operation inlets may include streams such as an oxygen-rich gas (e.g., 30-100% O2), nitrogen, fuel, biomass, chemical reactants, water, steam, syngas, or mixed gases, while the one or more unit operation outlets may include streams such as compressed gases, expanded gases, exhaust gases, purified or separated products, condensed liquids, reaction byproducts, or energy outputs (e.g., thermal, or mechanical energy). For example, a compressor may have gas as an inlet and produce compressed gas as an outlet, while a turbine may have high-pressure gas as an inlet and expanded gas along with mechanical or electrical energy as outlets. A heat exchanger may have separate inlets andoutlets for hot and cold streams, with the pressure ratios determining the operational efficiency. Similarly, a chemical reactor may include reactants entering through inlets and products or byproducts exiting through outlets, where the pressure ratios at the inlets and outlets are dictated by reaction conditions and system configuration.

[0101] In some embodiments, the system comprises at least one set of efficiency metrics. In some cases, the at least one set of efficiency metrics comprises an overall electrical efficiency ranging from about 20% to about 60%. In some instances, the at least one set of efficiency metrics comprises a second law (exergetic) efficiency from about 35% to about 75%. In some cases, the at least one set of efficiency metrics comprises a relationship given by:^overall (Wnet) / (Qin), (equation (1))

[0102] where Wnet is net work (turbine work minus compressor work), and Qin is heat input from fuel.

[0103] In some instances, the at least one set of efficiency metrics comprises a second law efficiency calculated asHex = (Wnet) / (Ein) (equation (2))

[0104] For example, the at least one set of efficiency metrics may be monitored under different load conditions, such as from about 50% to about 100% of configuration capacity. As an example, the system may maintain efficiencies within about 5 percentage points of nominal values across this load range. As an example, some embodiments may prioritize cost minimization and heat recovery over maximizing electrical efficiency. In some cases, the net work (Wnet) of the system may comprise multiple components, including turbine shaft work output (Wt), compressor work input (Wc), and auxiliary equipment work (Waux). The turbine shaft work output (Wt) may range from about 2000 kWe to about 12,000 kWe, with incremental values such as about 2000 kWe, about 2200 kWe, about 2400 kWe, about 2600 kWe, about 2800 kWe, about 3000 kWe, about 3200 kWe, about 3400 kWe, about 3600 kWe, about 3800 kWe, about 4000 kWe, about 4200 kWe, about 4400 kWe, about 4600 kWe, about 4800 kWe, about 5000 kWe, about 5200 kWe, about 5400 kWe, about 5600 kWe, about 5800 kWe, about 6000 kWe, about 6600 kWe, about 7200 kWe, about 7800 kWe, about 8400 kWe, about 9000 kWe, about 9600 kWe, about 10,200 kWe, about 11,400 kWe, or about 12,000 kWe. Similarly, the compressor work input (Wc) may range fromabout 800 kWe to about 4800 kWe, with examples including about 800 kWe, about 880 kWe, about 960 kWe, about 1040 kWe, about 1120 kWe, about 1200 kWe, about 1280 kWe, about 1360 kWe, about 1440 kWe, about 1520 kWe, about 1600 kWe, about 1680 kWe, about 1760 kWe, about 1840 kWe, about 1220 kWe, about 2000 kWe, about 2080 kWe, about 2160 kWe, about 2240 kWe, about 2320 kWe, about 2400 kWe, about 2640 kWe, about 2880 kWe, about 3120 kWe, about 3360 kWe, about 3600 kWe, about 3840 kWe, about 4080 kWe, about 4320 kWe, about 4560 kWe, or about 4800 kWe. The auxiliary equipment work (Waux) may range from about 50 kWe to about 400 kWe, with values such as about 50 kWe, about 55 kWe, about 60 kWe, about 65 kWe, about 70 kWe, about 75 kWe, about 80 kWe, about 85 kWe, about 90 kWe, about 95 kWe, about 100 kWe, about 110 kWe, about 120 kWe, about 130 kWe, about 140 kWe, about 150 kWe, about 160 kWe, about 170 kWe, about 180 kWe, about 190 kWe, about 200 kWe, about 220 kWe, about 240 kWe, about 260 kWe, about 280 kWe, about 300 kWe, about 320 kWe, about 340 kWe, about 360 kWe, about 380 kWe, or about 400 kWe.

[0105] In some cases, the input exergy (Ein) of the system may also include multiple components such as the chemical exergy of fuel input (Ex fuel), the physical exergy of the oxygen stream (Ex_o2), and the exergy of the waste heat stream (Ex waste). The chemical exergy of fuel input (Ex_fuel) may range from about 4000 kW to about 24,000 kW, with incremental values including about 4000 kW, about 4400 kW, about 4800 kW, about 5200 kW, about 5600 kW, about 6000 kW, about 6400 kW, about 6800 kW, about 7200 kW, about 7600 kW, about 8000 kW, about 8400 kW, about 8800 kW, about 9200 kW, about 9600 kW, about 10,000 kW, about 10,400 kW, about 10,800 kW, about 11,200 kW, about 11,600 kW, about 12,000 kW, about 13,200 kW, about 14,400 kW, about 15,600 kW, about 16,800 kW, about 18,000 kW, about 19,200 kW, about 20,400 kW, about 21,600 kW, about 22,800 kW, or about 24,000 kW. The physical exergy of the oxygen stream (Ex_o2) may range from about 100 kW to about 1000 kW, with values including about 100 kW, about 110 kW, about 120 kW, about 130 kW, about 140 kW, about 150 kW, about 160 kW, about 170 kW, about 180 kW, about 190 kW, about 200 kW, about 220 kW, about 240 kW, about 260 kW, about 280 kW, about 300 kW, about 350 kW, about 400 kW, about 450 kW, about 500 kW, about 600 kW, about 700 kW, about 800 kW, about 900 kW, or about 1000 kW. The exergy of the waste heat stream (Ex_waste) may range from about 200 kW to about 2000 kW, with examples including about 200 kW, about 220 kW, about 240 kW, about 260 kW, about 280 kW, about 300 kW, about 320 kW, about 340 kW, about 360 kW, about 380 kW, about 400kW, about 450 kW, about 500 kW, about 550 kW, about 600 kW, about 700 kW, about 800 kW, about 900 kW, about 1000 kW, about 1200 kW, about 1400 kW, about 1600 kW, about 1800 kW, or about 2000 kW.

[0106] In some cases, the heat input from fuel (Qin) may comprise a range of values extending from about 5000 kW to about 30,000 kW. Example values include about 5000 kW, about 5500 kW, about 6000 kW, about 6500 kW, about 7000 kW, about 7500 kW, about 8000 kW, about 8500 kW, about 9000 kW, about 9500 kW, about 10,000 kW, about 10,500 kW, about 11,000 kW, about 11,500 kW, about 12,000 kW, about 12,500 kW, about 13,000 kW, about 13,500 kW, about 14,000 kW, about 15,000 kW, about 16,000 kW, about 17,000 kW, about 18,000 kW, about 19,000 kW, about 20,000 kW, about 21,000 kW, about 22,000 kW, about 23,000 kW, about 24,000 kW, about 25,000 kW, about 26,000 kW, about 27,000 kW, about 28,000 kW, about 29,000 kW, or about 30,000 kW.

[0107] In some cases, component efficiencies for any system component may vary significantly depending on the configuration and operating conditions. The polytropic efficiency of a component, such as a turbine or compressor, may range from about 46% to about 200%. Example values include about 46%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80%, about 85%, about 90%, about 95%, about 100%, about 110%, about 120%, about 130%, about 140%, about 150%, about 160%, about 170%, about 180%, about 190%, or about 200%. Similarly, the isentropic efficiency of any component may range from about 46% to about 200%, with incremental values including about 46%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80%, about 85%, about 90%, about 95%, about 100%, about 110%, about 120%, about 130%, about 140%, about 150%, about 160%, about 170%, about 180%, about 190%, or about 200%.

[0108] The polytropic efficiency of any component may range from about 40% to about 180%. Example values include about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80%, about 85%, about 90%, about 100%, about 110%, about 120%, about 130%, about 140%, about 150%, about 160%, or about 180%. Additionally, the heat exchanger effectiveness for any component in the system may range from about 70% to about 100%, with values such as about 70%, about 75%, about 80%, about 85%, about 90%, about 95%, or about 100%.V. INPUT GAS

[0109] In some embodiments, the system comprises at least one combustion gas input subsystem. In some cases, the at least one combustion gas input subsystem comprises at least one primary oxygen source. In some instances, the at least one primary oxygen source comprises an industrial by-product stream from processes that produce or use O2 / CO2. For example, the processes may comprise one or more of the following: ammonia production, hydrogen production, ethanol facilities, water electrolysis, chlor-alkali operations, basic oxygen steelmaking or other industrial processes that produce or use O2 / CO2.

[0110] In some cases, the at least one combustion gas input subsystem comprises at least one auxiliary oxygen source. In some instances, the at least one auxiliary oxygen source comprises a cryogenic air separation unit (ASU) or a pressure swing adsorption (PSA) facility. For example, the at least one combustion gas input subsystem may be configured to deliver oxygen in purities ranging from about 30% to about 100% by volume or at any suitable purity range. As an example, near-pure oxygen from an external facility may be introduced into the combustor to facilitate oxy -fuel combustion and produce a predominantly CO2 working fluid.

[0111] In some embodiments, the system comprises materials selection for low-cost operation. In some cases, the sub-atmospheric pressure operation provides use of standardgrade alloys. In some instances, the system eliminates need for expensive high-grade materials in high-temperature zones.

[0112] In some embodiments, the system comprises at least one oxygen pre-treatment unit. In some cases, the at least one oxygen pre-treatment unit comprises at least one heat exchanger. In some instances, the at least one heat exchanger comprises a plate-fin or shell-and-tube configuration. In some cases, the at least one oxygen pre-treatment unit comprises at least one gas filtration or moisture removal device. In some instances, the at least one gas filtration or moisture removal device comprises a desiccant-based filter. For example, the at least one oxygen pre-treatment unit may be configured to raise incoming oxygen temperature by at least about 50°C and up to about 500°C or higher. As an example, a heat exchanger may draw thermal energy from a high-temperature CO2 stream to improve overall cycle efficiency before introducing oxygen into the combustor.

[0113] In some embodiments, the system comprises industrial integration capabilities. In some cases, the industrial integration comprises coupling with one or more industrial facilities to utilize excess oxygen. In some instances, the industrial integration provides heatrecovery for steam generation in ethanol plants or other heat-using industrial facilities. In some instances, the one or more industrial facilities may comprise one or more of the following: ammonia production, hydrogen production, ethanol facilities, water electrolysis, chlor-alkali operations, basic oxygen steelmaking or other industrial processes that produce or use O2 / CO2.

[0114] In some embodiments, the system comprises at least one oxygen mixing subsystem. In some cases, the at least one oxygen mixing subsystem comprises at least one static mixer. In some instances, the at least one static mixer comprises an internal vane configuration that promotes uniform blending of oxygen with recirculated CO2. In some cases, the at least one oxygen mixing subsystem comprises at least one dynamic mixing chamber. In some instances, the at least one dynamic mixing chamber comprises a swirl -based injector that further homogenizes the feed. For example, the at least one oxygen mixing subsystem may be configured to produce a blended stream containing up to about 30% O2 by volume. As an example, combining about 60% CO2 and about 40% O2 helps regulate combustion temperature and limit NOXformation.

[0115] In some embodiments, the system comprises a multi-sourced oxygen module equipped with a source selector manifold and buffer storage vessel to accept oxygen from multiple industrial processes. In some cases, the system comprises a partitioned combustor with an oxygen-rich zone and a CO2 dilution zone operating at sub-atmospheric pressure to moderate flame temperature. In some instances, an oxygen-supply arrangement may provide high-purity feeds (e.g., from a cryogenic pipeline or local ASU) alongside adjustable ambient air, while an oxygen-based process heat integration subsystem — featuring primary and secondary heat exchangers — preheats incoming oxygen (up to about 500°C). In some instances, a recirculation stream control subsystem may maintain a preferred CCh-to-Ch flow ratio (e.g., around 6: 1) using a return line and gas purity sensor. For example, an oxygen consumption monitoring subsystem, which may include mass flow sensors and exhaust analyzers, verifies usage efficiency up to about 99.9%.

[0116] In some embodiments, the system comprises at least one stoichiometric control subsystem. In some cases, the at least one stoichiometric control subsystem comprises at least one real-time oxygen-to-fuel ratio controller. In some instances, the at least one real-time oxygen-to-fuel ratio controller comprises an inline gas analyzer measuring CO2, O2, and CO levels in the exhaust. In some cases, the at least one stoichiometric control subsystem comprises at least one automated flow regulator. In some instances, the at least oneautomated flow regulator comprises a PID, or advanced process control module interfaced with the fuel supply. For example, the at least one stoichiometric control subsystem may be configured to maintain an excess oxygen factor from about 0.05 up to about 2.00 or greater. As an example, when the system operates across multiple hydrocarbon feedstocks, the at least one stoichiometric control subsystem may be configured to regulate an Ch-to-fuel molar ratio from about 0.1 up to about 5.0 or greater.

[0117] In some embodiments, the system comprises at least one stoichiometric control subsystem. In some cases, the at least one stoichiometric control subsystem comprises at least one real-time oxygen-to-fuel ratio controller. In some instances, the at least one real-time oxygen-to-fuel ratio controller comprises an inline gas analyzer measuring CO2, O2, and CO levels in the exhaust. In some cases, the at least one stoichiometric control subsystem comprises at least one automated flow regulator. In some instances, the at least one automated flow regulator comprises a PID, or advanced process control module interfaced with the fuel supply. For example, the at least one stoichiometric control subsystem may be configured to maintain an excess oxygen factor from about 0.05 up to about 2.00 or greater. As an example, when the system operates across multiple hydrocarbon feedstocks, the at least one stoichiometric control subsystem may be configured to regulate an Ch-to-fuel molar ratio from about 0.1 up to about 5.0 or greater.

[0118] In some embodiments, a stoichiometric ratio may comprise a ratio of oxygen to fuel. In some cases, the stoichiometric ratio may comprise about 0.1, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7,0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.1, 2.2, 2.3, 2.4, 2.5, 2.6, 2.7, 2.8,2.9, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 4.0, 4.1, 4.2, 4.3, 4.4, 4.5, 4.6, 4.7, 4.8, 4.9,5.0, 5.1, 5.2, 5.3, 5.4, 5.5, 5.6, 5.7, 5.8, 5.9, or 6.0, or any value in between. For example, a stoichiometric ratio of 1.0 may represent complete combustion with no excess oxygen, while a ratio greater than 1.0 may represent an excess oxygen condition. In some cases, the stoichiometric ratio may vary depending on the hydrocarbon feedstock, which may include methane, propane, butane, ethane, gasoline, diesel, kerosene, or biofuels.

[0119] In some embodiments, the at least one stoichiometric control subsystem may dynamically adjust the ratio of oxygen to fuel based on real-time feedback from sensors such as temperature sensors, gas composition analyzers, flow meters, and / or pressure transducers. For instance, the system may optimize the stoichiometric ratio to minimize NOXemissions, maximize thermal efficiency, or accommodate varying load conditions in the system. In some embodiments, the system comprises at least one modular power-generation unit. In somecases, the at least one modular power-generation unit comprises at least one sub-atmospheric oxy-fuel combustor. In some instances, the at least one sub-atmospheric oxy -fuel combustor comprises a combustion chamber configured for lower-pressure operation. In some cases, the at least one modular power-generation unit comprises at least one daisy-chain scaling interface. In some instances, the at least one daisy-chain scaling interface comprises interconnection points that provide parallel operation of multiple ~4 MWe modules. For example, the at least one modular power-generation unit may be configured to share heatrecovery components with other parallel units. As an example, each module may maintain sub-atmospheric conditions while collectively increasing total output.

[0120] In some embodiments, the system comprises at least one feedstock inlet. In some cases, the at least one feedstock inlet comprises at least one biomass inlet. In some instances, the at least one biomass inlet is configured for both aerobic and anaerobic biomass feedstocks (e.g., manure, wastewater sludge, pyrolysis, or gasification feedstock). In some cases, the at least one feedstock inlet comprises at least one waste-heat integration pathway. In some instances, the at least one waste-heat integration pathway comprises conduits for drying or preheating biomass. For example, the at least one biomass inlet may be configured to circulate hot exhaust gases for moisture reduction. As an example, waste-heat recovery may boost overall thermal efficiency in the range of about 20% to about 60%.

[0121] In some embodiments, the system comprises at least one oxygen supply interface. In some cases, the at least one oxygen supply interface comprises at least one electrolyzer feed connection. In some instances, the at least one electrolyzer feed connection comprises piping configured to receive waste O2 from a water electrolysis process. In some cases, the at least one oxygen supply interface comprises at least one standardized coupling. In some instances, the at least one standardized coupling comprises a heat-exchange port or manifold for combining oxygen supply lines with the system’s combustion chamber. For example, the system may be configured to use electrolyzer-derived waste O2 to support sub-atmospheric combustion. As an example, this integration may reduce external oxygen production costs while providing power or heat to the electrolyzer facility.

[0122] In some embodiments, the system comprises at least one heat-integration subsystem. In some cases, the at least one heat-integration subsystem comprises at least one waste-heat recovery unit. In some instances, the at least one waste-heat recovery unit comprises a recuperator or heat exchanger that captures exhaust heat for process steam generation. In some cases, the at least one heat-integration subsystem comprises at least one multi-stagethermal loop. In some instances, the at least one multi-stage thermal loop comprises piping or ducting to transfer heat between the combustor, feedstock preheater, and CO2 capture unit. For example, the at least one heat-integration subsystem may be configured to preheat fuel or dry biomass prior to combustion or gasification. As an example, sub-atmospheric operation combined with multi-stage heat recovery may improve overall system efficiency toward the higher end of about 20% to about 60%.

[0123] In some embodiments, the system comprises at least one carbon-capture assembly. In some cases, the at least one carbon-capture assembly comprises at least one CO2 separation unit (e.g., a condenser or scrubber). In some instances, the at least one CO2 separation unit comprises a cooling loop to liquefy or purify CO2. In some cases, the at least one carbon- capture assembly comprises at least one CO2 utilization interface. In some instances, the at least one CO2 utilization interface comprises connectors for enhanced oil recovery, mineralization, or e-fuels production. For example, the system may be configured to feed purified CO2 into a methanol synthesis reactor. As an example, CO2 may also be routed for mineralization in rock-injection processes or stored geologically for permanent sequestration. In some instances, CO2 may be directed to mineralization (e.g., concrete curing), enhanced oil recovery, hydrocarbon-fuel production, or stored via rock-injection.

[0124] In some embodiments, the system comprises at least one modular power-generation unit. In some cases, the at least one modular power-generation unit comprises at least one sub-atmospheric oxy-fuel combustor. In some instances, the at least one sub-atmospheric oxy-fuel combustor comprises a combustion chamber configured for lower-pressure operation. In some cases, the at least one modular power-generation unit comprises at least one daisy-chain scaling interface. In some instances, the at least one daisy-chain scaling interface comprises interconnection points that provide parallel operation of multiple ~4 MWe modules. For example, the at least one modular power-generation unit may be configured to share heat-recovery components with other parallel units. As an example, each module may maintain sub-atmospheric conditions while collectively increasing total output.

[0125] In some embodiments, the system comprises at least one feedstock inlet. In some cases, the at least one feedstock inlet comprises at least one biomass inlet. In some instances, the at least one biomass inlet is configured for both aerobic and anaerobic biomass feedstocks (e.g., manure, wastewater sludge, pyrolysis, or gasification feedstock). In some cases, the at least one feedstock inlet comprises at least one waste-heat integration pathway. In some instances, the at least one waste-heat integration pathway comprises conduits for drying orpreheating biomass. For example, the at least one biomass inlet may be configured to circulate hot exhaust gases for moisture reduction. As an example, waste-heat recovery may boost overall thermal efficiency in the range of about 20% to about 60%.

[0126] In some embodiments, the system comprises at least one oxygen supply interface. In some cases, the at least one oxygen supply interface comprises at least one electrolyzer feed connection. In some instances, the at least one electrolyzer feed connection comprises piping configured to receive waste O2 from a water electrolysis process. In some cases, the at least one oxygen supply interface comprises at least one standardized coupling. In some instances, the at least one standardized coupling comprises a heat-exchange port or manifold for combining oxygen supply lines with the system’s combustion chamber. For example, the system may be configured to use electrolyzer-derived waste O2 to support sub-atmospheric combustion. As an example, this integration may reduce external oxygen production costs while providing power or heat to the electrolyzer facility.

[0127] In some embodiments, the system comprises at least one heat-integration subsystem. In some cases, the at least one heat-integration subsystem comprises at least one waste-heat recovery unit. In some instances, the at least one waste-heat recovery unit comprises a recuperator or heat exchanger that captures exhaust heat for process steam generation. In some cases, the at least one heat-integration subsystem comprises at least one multi-stage thermal loop. In some instances, the at least one multi-stage thermal loop comprises piping or ducting to transfer heat between the combustor, feedstock preheater, and CO2 capture unit. For example, the at least one heat-integration subsystem may be configured to preheat fuel or dry biomass prior to combustion or gasification. As an example, sub-atmospheric operation combined with multi-stage heat recovery may improve overall system efficiency toward the higher end of about 20% to about 60%.

[0128] In some embodiments, the system comprises at least one carbon-capture assembly. In some cases, the at least one carbon-capture assembly comprises at least one CO2 separation unit (e.g., a condenser or scrubber). In some instances, the at least one CO2 separation unit comprises a cooling loop to liquefy or purify CO2. In some cases, the at least one carbon- capture assembly comprises at least one CO2 utilization interface. In some instances, the at least one CO2 utilization interface comprises connectors for enhanced oil recovery, mineralization, or e-fuels production. For example, the system may be configured to feed purified CO2 into a methanol synthesis reactor. As an example, CO2 may also be routed for mineralization in rock-injection processes or stored geologically for permanent sequestration.VI. GAS RECUPERATOR

[0129] In some embodiments, the system comprises at least one cycle recuperation arrangement. In some cases, the at least one cycle recuperation arrangement comprises at least one recuperation operation input. In some instances, the at least one recuperation operation input comprises a high-temperature CO2 flow exiting the turbine. In some cases, the at least one cycle recuperation arrangement comprises at least one recuperation operation output. In some instances, the at least one recuperation operation output comprises a preheated stream directed toward the combustor. For example, the at least one cycle recuperation arrangement may be configured to reclaim heat from the turbine exhaust and transfer it to a lower-temperature segment of the working fluid, thereby reducing the energy input otherwise required for heating. As an example, this approach may lower overall fuel consumption and promote thermally efficient power generation.

[0130] In some embodiments, the system comprises at least one gas exchange recuperator. In some cases, the at least one gas exchange recuperator comprises at least one gas exchange operation input. In some instances, the at least one gas exchange operation input comprises a slipstream of hot CO2 from the compressor discharge. In some cases, the at least one gas exchange recuperator comprises at least one gas exchange operation output. In some instances, the at least one gas exchange operation output comprises a preheated O2 supply entering the combustor. For example, the at least one gas exchange recuperator may be configured to transfer heat from hot CO2 to the incoming oxygen, thereby elevating the O2 temperature before combustion. As an example, this preheating may reduce thermal losses and lower combustor fuel demand.

[0131] In some embodiments, the system comprises at least one heat exchanger configured to recover thermal energy from the turbine exhaust stream. In some cases, the at least one heat exchanger comprises at least one recuperator for transferring heat from the turbine exhaust to the combustor inlet stream. In some instances, the at least one heat exchanger further comprises additional exchangers for generating steam or other process heat. For example, the at least one heat exchanger may be configured to provide both electrical power and useful thermal energy. As an example, a single facility may integrate power production with additional heating demands such as steam generation.

[0132] In some embodiments, the system comprises at least one recuperator configured to transfer heat between the turbine exhaust stream and the combustor inlet stream. In somecases, the at least one recuperator comprises at least one gas-to-gas heat exchanger with a high-pressure side and a low-pressure side. In some instances, the high-pressure side comprises a stream of CO2 and oxygen from a compressor discharge, while the low-pressure side comprises the turbine exhaust at a lower pressure. For example, the at least one recuperator may be configured to operate between about 0.3 bar and about 1 bar on the low- pressure side, although other suitable pressures may be used. As an example, the system may incorporate a bypass pathway to regulate the degree of heat recovery and balance the tradeoff between high-temperature heat extraction and cycle efficiency.

[0133] In some embodiments, the system comprises at least one recuperator system configured to manage heat transfer among multiple streams. In some cases, the at least one recuperator system comprises at least one recuperator outlet where the working fluid temperature may be about 508.4 K, although other suitable values may be used. In some instances, the at least one recuperator system is capable of producing outlet temperatures between about 450 K and about 550 K or, in other cases, about 400 K to about 600 K. For example, the at least one recuperator system may be configured to fine-tune these temperature ranges based on configuration priorities and operating conditions. As an example, downstream equipment requirements may dictate the improved balance between power generation and process heat demands.

[0134] In some embodiments, the system comprises at least one gas recuperator selected from a group consisting of plate-fin, shell-and-tube, spiral, microchannel, or brazed-plate configurations. In some cases, the at least one gas recuperator comprises at least one plate-fin device. In some instances, the plate-fin device comprises high-effectiveness fins for compact construction and enhanced heat transfer. In some cases, the at least one gas recuperator comprises at least one shell-and-tube configuration. In some instances, the shell-and-tube configuration comprises a robust mechanical configuration suited for higher differential pressures. For example, the at least one gas recuperator may be configured to balance cost, performance, and maintainability. As an example, a plate-fin configuration may be used for cycle recuperation, while a shell-and-tube device may be employed for gas exchange operations.

[0135] In some embodiments, the system comprises at least one gas recuperator constructed from materials suitable for high-temperature operation. In some cases, these materials comprise at least one nickel-based superalloy. In some instances, the nickel-based superalloy comprises Inconel or Hastelloy capable of sustaining elevated operating temperatures, such asabout 900 K or higher, although other temperature ranges may be used. In some cases, the system comprises at least one lower-temperature section of the recuperator constructed from carbon steels or aluminum alloys when operating below about 500 K. For example, advanced ceramics or ceramic-coated alloys may be employed where temperatures reach about 1000 K or more. As an example, specific material selections may vary depending on corrosion resistance and mechanical strength requirements.

[0136] In some embodiments, the system comprises at least one recuperator. In some cases, the at least one recuperator comprises at least one sub-atmospheric pressure side operating at pressures between about 0.1 atm and about 0.9 atm. In some instances, specific values may comprise about 0.1 atm, about 0.2 atm, about 0.3 atm, about 0.4 atm, about 0.5 atm, about 0.6 atm, about 0.7 atm, about 0.8 atm, and about 0.9 atm. In some instances, the at least one recuperator may comprise at least one near-atmospheric or slightly elevated pressure side operating at pressures between about 1 atm and about 2 atm. For example, the elevated side may include about 1 atm, about 1.1 atm, about 1.2 atm, about 1.3 atm, about 1.4 atm, about 1.5 atm, about 1.6 atm, about 1.7 atm, about 1.8 atm, about 1.9 atm, and about 2 atm.

[0137] In some embodiments, the system comprises at least one mechanism for managing temperature differentials between hot and cold streams. In some cases, the temperature differentials may comprise between about 100 K and about 2500 K. In some instances, the temperature differentials may comprise about 100 K, about 150 K, about 200 K, about 250 K, about 300 K, about 350 K, about 400 K, about 450 K, about 500 K, about 550 K, about 600 K, about 750 K, about 1000 K, about 1250 K, about 1500 K, about 1750 K, about 2000 K, about 2250 K, and about 2500 K.

[0138] In some embodiments, at least one stream may comprise a temperature between about 0 K and about 2500 K. In some instances, the temperature may comprise about 0 K, about 100 K, about 300 K, about 500 K, about 750 K, about 1000 K, about 1250 K, about 1500 K, about 1750 K, about 2000 K, about 2250 K, and about 2500 K. In some cases, the at least one stream may comprise one or more of CO2, O2, H2, and N2. For example, the system may be configured to facilitate heat exchange or energy recovery involving these gases at specified temperature ranges.VII. COMPRESSOR

[0139] In some embodiments, the system comprises at least one compressor. In some cases, the at least one compressor comprises at least one multi-stage compressor. In some instances,the at least one multi-stage compressor comprises at least one sub-atmospheric inlet stage. In some instances, the at least one sub-atmospheric inlet stage comprises a radial compressor stage formed from materials such as aerospace-grade aluminum alloys or conventional stainless steels. In some cases, the at least one multi-stage compressor comprises at least one axial compressor stage. In some instances, the at least one axial compressor stage comprises multiple rows of rotating and stationary blades formed from materials such as titanium alloys, carbon steels, or advanced composites. For example, the at least one multi-stage compressor may be configured to operate at rotational speeds such as about 3600 RPM or about 5000 RPM to elevate working fluids like CO2 from pressures as low as about 0.1 atm to pressures as high as about 2.0 atm. As an example, the multi-stage compressor may achieve discharge temperatures between about 300 K and about 500 K, depending on system requirements and operating conditions.

[0140] In some embodiments, the system comprises at least one mechanical coupling. In some cases, the at least one mechanical coupling comprises at least one common shaft. In some instances, the at least one common shaft comprises a direct mechanical connection between a turbine and a multi-stage compressor. In some cases, the at least one mechanical coupling comprises at least one rotational speed control element. In some instances, the at least one rotational speed control element comprises a gearbox or variable-speed drive. For example, the at least one mechanical coupling may be configured to operate at about 3600 rpm. As an example, the system may transfer turbine power directly to drive the multi-stage compressor without requiring separate electric motors.

[0141] In some embodiments, the system comprises at least one intercooling arrangement. In some cases, the at least one intercooling arrangement comprises at least one heat exchanger. In some instances, the at least one heat exchanger comprises a device configured to remove heat from partially compressed CO2. In some cases, the at least one intercooling arrangement comprises at least one moisture separator. In some instances, the at least one moisture separator comprises a device configured to prevent water accumulation in downstream stages. For example, the at least one intercooling arrangement may be configured to reduce the temperature of CO2 by about 20-60 K between compression stages. As an example, the intercooling arrangement may maintain a final outlet temperature of about 400-500 K.

[0142] In some embodiments, the system comprises at least one dedicated CO2 compression assembly. In some cases, the at least one dedicated CO2 compression assembly comprises at least one multi-stage configuration with moisture removal. In some instances, the at least onemulti-stage configuration comprises polishing and drying steps to ensure high-purity CO2. In some cases, the at least one dedicated CO2 compression assembly comprises at least one final booster stage. In some instances, the at least one final booster stage comprises a positivedisplacement compressor capable of reaching pressures above about 40 bar. For example, the at least one dedicated CO2 compression assembly may be configured to supply CO2 at about 3-10 bar for transport. As an example, the assembly may manage sub-atmospheric inlet pressures of about 0.25 atm without requiring separate fuel boosters.

[0143] In some cases, the compressor comprises at least one alloy material. In some instances, the at least one alloy material comprises austenitic stainless steel. In some cases, the at least one austenitic stainless steel comprises materials such as 80Ni-20Cr. In some instances, the at least one alloy material comprises a conventional nickel-based alloy. In some cases, the at least one conventional nickel-based alloy comprises readily sourced materials suitable for simplifying component fabrication and maintenance. In some instances, the compressor may comprise at least one heat-resistant material. In some cases, the at least one heat-resistant material comprises alloys such as Inconel 625 or Inconel 718 for improved durability under elevated temperatures. For example, 80Ni-20Cr alloy may be used when the temperature is about 500-700 K, while conventional nickel-based alloys may be used when the temperature is below about 800 K.

[0144] In some instances, the compressor may comprise at least one multi-stage assembly. In some cases, the at least one multi-stage assembly comprises at least one adjustable vane mechanism. In some instances, the at least one adjustable vane mechanism comprises components configured to regulate inlet flow to each stage. For example, the at least one multi-stage assembly may be configured to boost sub-atmospheric CO2 from about 0.3 bar to about 1 bar. As an example, interstage streams may transfer heat to ancillary processes, enhancing plant efficiency.

[0145] In some cases, the at least one compressor may be configured to handle working fluid flows (e.g, such as CO2) of about 1 kg / s, 2 kg / s, 3 kg / s, 4 kg / s, 5 kg / s, 6 kg / s, 7 kg / s, 8 kg / s, 9 kg / s, 10 kg / s, 11 kg / s, 12 kg / s, 13 kg / s, 14 kg / s, 15 kg / s, 16 kg / s, 17 kg / s, 18 kg / s, 19 kg / s, 20 kg / s, 21 kg / s, 22 kg / s, 23 kg / s, 24 kg / s, 25 kg / s, 26 kg / s, 27 kg / s, 28 kg / s, 29 kg / s, 30 kg / s, 31 kg / s, 32 kg / s, 33 kg / s, 34 kg / s, 35 kg / s, 36 kg / s, 37 kg / s, 38 kg / s, 39 kg / s, 40 kg / s, 100 kg / s, 42 kg / s, 43 kg / s, 44 kg / s, 45 kg / s, 46 kg / s, 47 kg / s, 48 kg / s, 49 kg / s, 50 kg / s, 51 kg / s, 52 kg / s, 53 kg / s, 54 kg / s, 55 kg / s, 56 kg / s, 57 kg / s, 58 kg / s, 59 kg / s, 60 kg / s, 61 kg / s, 62 kg / s, 63 kg / s, 64 kg / s, 65 kg / s, 66 kg / s, 67 kg / s, 68 kg / s, 69 kg / s, 70 kg / s, 71 kg / s, 72 kg / s, 73 kg / s, 74 kg / s,75 kg / s, 76 kg / s, 77 kg / s, 78 kg / s, 79 kg / s, 80 kg / s, 81 kg / s, 82 kg / s, 83 kg / s, 84 kg / s, 85 kg / s,86 kg / s, 87 kg / s, 88 kg / s, 89 kg / s, 90 kg / s, 91 kg / s, 92 kg / s, 93 kg / s, 94 kg / s, 95 kg / s, 96 kg / s,97 kg / s, 98 kg / s, 99 kg / s, or 100 kg / s, or any value in between.

[0146] As an example, the polytropic efficiency may be calculated as: r|p= (ln(p2 / pi)) / (ln(T2 / Ti)) x ((k - 1) / k), (equation (3))

[0147] where p2 / pi is the pressure ratio, T2 / T1 is the temperature ratio, and k is the specific heat ratio.

[0148] In some embodiments, the system comprises at least one compressor. In some cases, the at least one compressor comprises a polytropic efficiency that may comprise about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, 20%, 30%, 22%, 23%, 24%, 25%, 26%, 27%, 28%, 29%, 30%, 31%, 32%, 33%, 34%,35%, 36%, 37%, 38%, 39%, 40%, 41%, 42%, 43%, 44%, 45%, 46%, 47%, 48%, 49%, 50%,51%, 52%, 53%, 54%, 55%, 56%, 57%, 58%, 59%, 60%, 61%, 62%, 63%, 64%, 65%, 66%,67%, 68%, 69%, 70%, 71%, 72%, 73%, 74%, 75%, 76%, 77%, 78%, 79%, 80%, 81%, 82%,83%, 84%, 85%, 86%, 87%, 88%, 89%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%, or 99%, or any percentage in between.

[0149] In some instances, the pi may comprise about 0.33 bar. In some embodiments, pi may be between about 0.2 bar and about 0.5 bar, such as 0.2 bar, 0.21 bar, 0.22 bar, 0.23 bar, 0.24 bar, 0.25 bar, 0.26 bar, 0.27 bar, 0.28 bar, 0.29 bar, 0.3 bar, 0.31 bar, 0.32 bar, 0.33 bar, 0.34 bar, 0.35 bar, 0.36 bar, 0.37 bar, 0.38 bar, 0.39 bar, 0.4 bar, 0.41 bar, 0.42 bar, 0.43 bar, 0.44 bar, 0.45 bar, 0.46 bar, 0.47 bar, 0.48 bar, 0.49 bar, or 0.5 bar, or any value in between. In some cases, pi may be at least about 0.2 bar. In other instances, pi may be at most about 0.5 bar. The variable pi represents the pressure at the compressor inlet. In some instances, this may be the pressure of the CO2 working fluid entering the compressor after being cooled by the heat rejection heat exchanger. In some cases, this sub-atmospheric pressure results in a high specific volume for the CO2 working fluid.

[0150] In some instances, the p2 may comprise about 1.0 bar. In some embodiments, p2 may be between about 0.8 bar and about 1.6 bar, such as 0.8 bar, 0.81 bar, 0.82 bar, 0.83 bar, 0.84 bar, 0.85 bar, 0.86 bar, 0.87 bar, 0.88 bar, 0.89 bar, 0.9 bar, 0.91 bar, 0.92 bar, 0.93 bar, 0.94 bar, 0.95 bar, 0.96 bar, 0.97 bar, 0.98 bar, 0.99 bar, 1.0 bar, 1.01 bar, 1.02 bar, 1.03 bar, 1.04 bar, 1.05 bar, 1.06 bar, 1.07 bar, 1.08 bar, 1.09 bar, 1.1 bar, 1.11 bar, 1.12 bar, 1.13 bar, 1.14bar, 1.15 bar, 1.16 bar, 1.17 bar, 1.18 bar, 1.19 bar, 1.2 bar, 1.21 bar, 1.22 bar, 1.23 bar, 1.24 bar, 1.25 bar, 1.26 bar, 1.27 bar, 1.28 bar, 1.29 bar, 1.3 bar, 1.31 bar, 1.32 bar, 1.33 bar, 1.34 bar, 1.35 bar, 1.36 bar, 1.37 bar, 1.38 bar, 1.39 bar, 1.4 bar, 1.41 bar, 1.42 bar, 1.43 bar, 1.44 bar, 1.45 bar, 1.46 bar, 1.47 bar, 1.48 bar, 1.49 bar, or 1.6 bar, or any value in between. In some cases, p? may be at least about 0.8 bar. In other instances, p? may be at most about 1.6 bar. The variable p? represents the pressure at the compressor discharge or outlet. In some instances, this may be the pressure of the CO2 working fluid after work has been performed on it within the compressor to increase its pressure to approximately atmospheric pressure.

[0151] In some instances, the Ti may comprise about 306 K. In some embodiments, Ti may be between about 280 K and about 330 K, such as 280 K, 281 K, 282 K, 283 K, 284 K, 285 K, 286 K, 287 K, 288 K, 289 K, 290 K, 291 K, 292 K, 293 K, 294 K, 295 K, 296 K, 297 K, 298 K, 299 K, 300 K, 301 K, 302 K, 303 K, 304 K, 305 K, 306 K, 307 K, 308 K, 309 K, 310 K, 311 K, 312 K, 313 K, 314 K, 315 K, 316 K, 317 K, 318 K, 319 K, 320 K, 321 K, 322 K, 323 K, 324 K, 325 K, 326 K, 327 K, 328 K, 329 K, or 330 K, or any value in between. In some cases, Ti may be at least about 280 K. In some instances, Ti may be at most about 330 K. In some instances, variable Ti represents the temperature at the compressor inlet. In some instances, this may be the temperature of the CO2 working fluid entering the compressor, having been cooled to slightly above ambient temperature (approximately 20-30 K above ambient) by the heat rejection heat exchanger upstream.

[0152] In some instances, the T2 may comprise about 447.5 K. In some embodiments, T2 may be between about 400 K and about 500 K, such as 400 K, 401 K, 402 K, 403 K, 404 K, 405 K, 406 K, 407 K, 408 K, 409 K, 410 K, 411 K, 412 K, 413 K, 414 K, 415 K, 416 K, 417 K, 418 K, 419 K, 420 K, 421 K, 422 K, 423 K, 424 K, 425 K, 426 K, 427 K, 428 K, 429 K, 430 K, 431 K, 432 K, 433 K, 434 K, 435 K, 436 K, 437 K, 438 K, 439 K, 440 K, 441 K, 442 K, 443 K, 444 K, 445 K, 446 K, 447 K, 448 K, 449 K, 450 K, 451 K, 452 K, 453 K, 454 K, 455 K, 456 K, 457 K, 458 K, 459 K, 460 K, 461 K, 462 K, 463 K, 464 K, 465 K, 466 K, 467 K, 468 K, 469 K, 470 K, 471 K, 472 K, 473 K, 474 K, 475 K, 476 K, 477 K, 478 K, 479 K, 480 K, 481 K, 482 K, 483 K, 484 K, 485 K, 486 K, 487 K, 488 K, 489 K, 490 K, 491 K, 492 K, 493 K, 494 K, 495 K, 496 K, 497 K, 498 K, 499 K, or 500 K, or any value in between. In some cases, T2 may be at least about 400 K. In other instances, T2 may be at most about 500 K. The variable T2 represents the temperature at the compressor discharge or outlet. In some instances, this may be the temperature of the CO2 working fluid after the work of compression raises its temperature.

[0153] The variable k may represent the specific heat ratio (cp / cv) for CO2 under the operating conditions. This is also known as the adiabatic index or ratio of specific heats. In some instances, this value describes how the temperature and pressure of the CO2 working fluid relate during compression.

[0154] The variable r|pmay represents the polytropic efficiency, which characterizes how efficiently the compressor performs work on the CO2 working fluid to increase its pressure. In some instances, this efficiency metric accounts for the real gas behavior and irreversibilities during the compression process.VIII. COMBUSTOR

[0155] In some embodiments, the system comprises at least one combustor subsystem. In some cases, the at least one combustor subsystem comprises at least one fuel supply interface. In some instances, the at least one fuel supply interface comprises an inlet manifold that delivers hydrocarbon or bio-derived fuel (e.g., natural gas, biogas, propane, or syngas). In some cases, the at least one combustor subsystem comprises at least one oxidant delivery assembly. In some instances, the at least one oxidant delivery assembly comprises an oxygen- enriched stream containing about 50% to about 100% O2 by volume. For example, the at least one combustor subsystem may be configured to reduce nitrogen dilution by positioning the combustor downstream of a CO2 / O2 compressor discharge. As an example, this arrangement may limit volumetric flow in downstream equipment.

[0156] In some embodiments, the system comprises at least one combustion arrangement. In some cases, the at least one combustion arrangement comprises at least one pressure management component. In some instances, the at least one pressure management component comprises a regulated combustion chamber configured to operate near atmospheric or sub- atmospheric pressure (e.g., about 0.8 to about 1.2 bar). In some cases, the at least one combustion arrangement comprises at least one oxygen-to-fuel ratio controller. In some instances, the at least one oxygen-to-fuel ratio controller comprises near-stoichiometric injection controls maintaining an excess oxygen factor of about 0.95 to about 1.05. For example, the at least one combustion arrangement may be configured to generate a predominantly CO2 exhaust stream, permitting high-purity carbon capture. As an example, the exhaust may exceed about 90% CO2 by volume upon water removal.

[0157] In some embodiments, the system comprises fuel flexibility for various hydrocarbon sources. In some cases, the system processes natural gas, biogas, biogas, volatile organiccompounds, or synthesis gas. In some instances, the fuel flexibility provides operation with both fossil and renewable feedstocks.

[0158] In some embodiments, the system comprises at least one combustor module. In some cases, the at least one combustor module comprises at least one swirl-stabilized subsection. In some instances, the at least one swirl-stabilized subsection comprises vortex-generating vanes set at angles of about 30° to about 60°. In some cases, the at least one combustor module comprises at least one diffusion flame subsection. In some instances, the at least one diffusion flame subsection comprises a direct fuel-oxidant mixing zone that may operate near or below atmospheric pressure. For example, the at least one combustor module may be configured to enhance flame stability under varying loads. As an example, an annular swirl-stabilized combustor may be used to reduce emissions at sub-atmospheric pressures.

[0159] In some embodiments, the system comprises at least one combustion efficiency control subsystem. In some cases, the at least one combustion efficiency control subsystem comprises at least one exhaust gas analyzer. In some instances, the at least one exhaust gas analyzer comprises an infrared or paramagnetic sensor measuring CO, O2, and unburned hydrocarbons. In some cases, the at least one combustion efficiency control subsystem comprises at least one residence time management component. In some instances, the at least one residence time management component comprises a combustor geometry that permits thorough mixing for a combustion efficiency of about 90% to about 99.9%. For example, the at least one combustion efficiency control subsystem may be configured to achieve nearcomplete oxidation with unburned hydrocarbons under about 10 ppm. As an example, typical operation may target at least about 99% fuel conversion for a cleaner exhaust stream.In some embodiments, the system comprises at least one combustor inlet / outlet framework. In some cases, the at least one combustor inlet / outlet framework comprises at least one oxidant inlet line. In some instances, the at least one oxidant inlet line comprises a near-pure O2 stream or a CCh-diluted O2 mixture at about 10% to about 50% CO2. In some cases, the at least one combustor inlet / outlet framework comprises at least one exhaust outlet line. In some instances, the at least one exhaust outlet line comprises a CO2- and ILO-rich stream at about 900 K to about 1300 K. For example, the at least one combustor inlet / outlet framework may be configured to route the exhaust directly to a turbine or a recuperator for partial heat extraction. As an example, precise stoichiometric control may minimize residual CO and unburned hydrocarbons.

[0160] In some embodiments, the system comprises at least one pressure-temperature management subsystem. In some cases, the at least one pressure-temperature management subsystem comprises at least one combustor pressure control assembly. In some instances, the at least one combustor pressure control assembly comprises a valve or orifice configuration operating near 1.0 bar or up to about 2 bar. In some cases, the at least one pressure-temperature management subsystem comprises at least one flame temperature control unit. In some instances, the at least one flame temperature control unit comprises CO2 dilution lines that maintain flame temperatures between about 1500 K and about 2200 K. For example, the at least one pressure-temperature management subsystem may be configured to manage bulk exhaust temperature to about 900-1200 K for turbine inlet conditions. As an example, advanced liner cooling may keep combustor metal temperatures within safe limits.

[0161] In some embodiments, the system comprises at least one combustor flow control subsystem. In some cases, the at least one combustor flow control subsystem comprises at least one pressure ratio regulator. In some instances, the at least one pressure ratio regulator comprises an adjustable bypass line to achieve a combustor pressure ratio of about 1.0 to about 1.2 for near-atmospheric configurations. In some cases, the at least one combustor flow control subsystem comprises at least one stoichiometric control loop. In some instances, the at least one stoichiometric control loop comprises real-time valve adjustments to maintain oxygen levels within about 0.95 to about 1.05 of stoichiometric. For example, the at least one combustor flow control subsystem may be configured to reduce NOx formation through precise oxygen and fuel metering. As an example, an orifice plate may limit pressure drop while preserving stable flow.

[0162] In some embodiments, the system comprises at least one combustion enhancement module. In some cases, the at least one combustion enhancement module comprises at least one swirl vane assembly. In some instances, the at least one swirl vane assembly comprises vane angles producing swirl numbers from about 0.6 to about 1.5. In some cases, the at least one combustion enhancement module comprises at least one premix injector. In some instances, the at least one premix injector comprises a multi-nozzle configuration that uniformly disperses fuel and oxygen. For example, the at least one combustion enhancement module may be configured to utilize swirl-stabilized bluff bodies to anchor the flame. As an example, catalytic inserts may be introduced if lower ignition temperatures are desired.

[0163] In some embodiments, the system comprises at least one thermal management and emissions control assembly. In some cases, the at least one thermal management andemissions control assembly comprises at least one dilution subsystem. In some instances, the at least one dilution subsystem comprises recirculated CO2 lines that moderate peak flame temperatures by about 100-300 K. In some cases, the at least one thermal management and emissions control assembly comprises at least one low-NOx configuration. In some instances, the at least one low-NOx configuration comprises lean-premix zones keeping equivalence ratios below about 1.0. For example, the at least one thermal management and emissions control assembly may be configured to achieve near-zero NOx with high oxygen purity and adequate CO2 dilution. As an example, swirl-stabilized flames may yield uniform temperature profiles with fewer hotspots.IX. TURBINE

[0164] In some embodiments, the system comprises at least one turbine operation configured to convert thermal energy in hot combustion gases into shaft power. In some cases, the at least one turbine operation comprises at least one sub-atmospheric expansion stage. In some instances, the at least one sub-atmospheric expansion stage comprises an expansion pathway that lowers pressure from about 1 atm to about 0.3 atm, although other suitable ranges may be used. In some cases, the at least one turbine operation comprises at least one shaft power transfer subsystem. In some instances, the at least one shaft power transfer subsystem comprises mechanical linkages providing direct coupling to a compressor or generator. For example, the at least one turbine operation may be configured to deliver net electrical outputs around 4 MWe under some configuration conditions. As an example, sub-atmospheric power generation may permit moderate turbine inlet temperatures (e.g., about 900-1173 K), balancing efficiency with standard alloy requirements.

[0165] In some embodiments, the system comprises at least one mechanical coupling arrangement for the turbine. In some cases, the at least one mechanical coupling arrangement comprises at least one common shaft. In some instances, the at least one common shaft comprises a direct-drive interface operating at about 3600 RPM, although other speeds (e.g., 3000 RPM) may be used. In some cases, the at least one mechanical coupling arrangement comprises at least one integrated generator connection. In some instances, the at least one integrated generator connection comprises a synchronous linkage aligned with typical electrical frequencies (50 Hz or 60 Hz). For example, the at least one mechanical coupling arrangement may be configured to reduce complexity by eliminating separate gearboxes. As an example, blade sizing and shaft dimensions may account for higher specific volumes of CO2 at sub-atmospheric pressures.

[0166] In some embodiments, the system comprises at least one pressure management subsystem associated with the turbine. In some cases, the at least one pressure management subsystem comprises at least one inlet pressure regulator. In some instances, the at least one inlet pressure regulator comprises valves and piping that supply the turbine at about 1 atm, or between about 0.4 bar and about 1.6 bar. In some cases, the at least one pressure management subsystem comprises at least one expansion ratio module. In some instances, the at least one expansion ratio module comprises adjustable nozzle guide vanes that permit pressure drops from about 1.5 to about 30 in expansion ratio. In some instances, the at least one expansion ratio module comprises adjustable nozzle guide vanes that permit pressure drops from about 20 to about 30 in expansion ratio. For example, the system may be configured to maintain a pressure drop ratio (Ap / p) optimized for low-pressure operation, without imposing specific numerical constraints. As an example, the system may facilitate a pressure drop suitable for low-pressure regimes, such as expanding from approximately 1.0 atm to 0.2 atm, resulting in a Ap / p of around 80%. As an example, controlling the expansion ratio helps balance efficiency gains with hardware stress levels.

[0167] In some embodiments, the system comprises at least one turbine temperature control assembly. In some cases, the at least one turbine temperature control assembly comprises at least one high-temperature inlet section. In some instances, the at least one high-temperature inlet section comprises an operational window between about 900 K and about 1173 K, although temperatures up to about 1300-1400 K may be used if advanced alloys are employed. In some cases, the at least one turbine temperature control assembly comprises at least one material selection subsystem. In some instances, the at least one material selection subsystem comprises nickel-based superalloys (e.g., Inconel) or stainless steels suitable for sub-atmospheric operation. For example, the turbine blades may be configured to withstand outlet temperatures of about 950 K or anywhere between about 700 K and about 1200 K. As an example, quenching or CO2 dilution may be used to moderate combustion-gas temperature and extend component longevity.

[0168] In some embodiments, the system comprises at least one turbine performance module. In some cases, the at least one turbine performance module comprises at least one efficiency control section. In some instances, the at least one efficiency control section comprises aerodynamically optimized blades achieving isentropic or polytropic efficiencies from about 60% to about 90%, although other ranges may be used. In some cases, the at least one turbine performance module comprises at least one power output regulator. In some instances, the atleast one power output regulator comprises flow rate adjustments that accommodate mass flows from about 14 kg / s to about 100 kg / s, corresponding to net electrical outputs from about 2000 kWe to about 6000 kWe. For example, the system may be configured to produce overall cycle efficiencies from about 20% to about 60%. As an example, part-load operation (about 50% to about 100% load) may maintain stable turbine function without compromising efficiency.

[0169] In some embodiments, the system comprises at least one turbine heat recovery interface. In some cases, the at least one turbine heat recovery interface comprises at least one recuperated configuration. In some instances, the at least one recuperated configuration comprises a hot exhaust outlet at about 0.3 atm and about 950 K, routed to a heat exchanger for preheating compressor discharge flows. In some cases, the at least one turbine heat recovery interface comprises at least one unrecuperated configuration. In some instances, the at least one unrecuperated configuration permits direct exhaust at about 900-1100 K for external heat usage (e.g., biomass drying). For example, the system may be configured to switch between recuperated and unrecuperated modes depending on power-generation or heat-demand priorities. As an example, a controller may limit turbine inlet temperature to about 900 °C in some configurations to preserve component life.

[0170] In some embodiments, the system comprises at least one turbine load management subsystem. In some cases, the at least one turbine load management subsystem comprises at least one real-time ramp rate controller. In some instances, the at least one real-time ramp rate controller comprises fuel and oxygen flow controls permitting power output changes at about 0.5% to about 15% per minute. In some cases, the at least one turbine load management subsystem comprises at least one partial bypass assembly. In some instances, the at least one partial bypass assembly comprises anti-surge features to maintain stability through rapid transients. For example, the system may manage transitions from minimum to maximum load in about 5 to about 60 minutes. As an example, the exhaust management system may divert expanded CO2 to recirculation or carbon capture without requiring additional compression post-expansion.

[0171] In some embodiments, the system comprises at least one multistage turbine arrangement. In some cases, the at least one multistage turbine arrangement comprises at least one series expansion scheme. In some instances, the at least one series expansion scheme comprises two or more turbine stages extracting power at moderate inlet temperatures and pressures. In some cases, the at least one multistage turbine arrangement comprises atleast one parallel configuration. In some instances, the at least one parallel configuration includes multiple ~4 MWe units operating in a daisy-chain arrangement to scale total output. For example, the system may be configured to achieve higher net efficiency by distributing expansion across multiple stages while retaining sub-atmospheric benefits. As an example, standard-grade alloys may be used in each stage, reducing capital costs relative to exotic superalloys.

[0172] In some cases, the at least one turbine comprises at least one inlet operating point at about 1173 K and about 1 atm, with discharge near 0.3 atm. In some instances, the at least one inlet operating point comprises multi-stage rotors with Inconel blades to accommodate sub-atmospheric volumetric flows. In some cases, the at least one turbine example configuration comprises at least one durability subsystem. In some instances, the at least one durability subsystem comprises thermal stress management that limits gradients to about 10- 50 K / cm, permitting up to about 100-10,000 thermal cycles before major overhauls. For example, the system may be configured for service intervals of about 8,000-40,000 hours with continuous mechanical and thermal monitoring. As an example, balancing temperature, pressure, and expansion ratio may minimize lifecycle costs while promoting reliable carbon capture.

[0173] In some cases, the at least one turbine comprises at least one standard Inconel alloy (e.g., Inconel 625 or Inconel 718) for rotor and stator components. In some instances, the at least one standard Inconel alloy comprises good weldability and corrosion resistance at temperatures below about 900°C. In some cases, the at least one turbine also comprises at least one conventional nickel-based alloy in cooler sections. In some instances, the at least one conventional nickel-based alloy comprises an economical alternative for sub-atmospheric or low-pressure stages. For example, the at least one turbine may be configured to operate under sub-atmospheric inlet conditions, reducing stress requirements. As an example, the use of Inconel 625 or 718 may provide a balance between cost and high-temperature strength.

[0174] In some cases, the at least one turbine comprises a polytropic efficiency from about 46% to about 100%, although other suitable ranges may be used. In some instances, the at least one turbine comprises an isentropic efficiency from about 46% to about 100%. In some cases, the at least one turbine comprises an expansion ratio of about 3.2. In some instances, the at least one turbine comprises an inlet temperature from about 900°C (1173K) to about 1100°C or 1250K, depending on the embodiment. For example, the at least one turbine may be configured to drive an electrical generator, eliminating the need for a gearbox by directcoupling at synchronous speeds. As an example, the polytropic efficiency (r|p) for the turbine may be calculated as:T|p= (ln(Ts / T4)) / (ln(ps / p4)) x (k / (k - 1)), (equation (4))

[0175] where T3 / T4 is the temperature ratio and ps / p4 is the pressure ratio.

[0176] In some embodiments, the system comprises at least one turbine configured to expand an exhaust gas comprising CO2, thereby producing power. In some cases, the at least one turbine comprises a polytropic efficiency that may comprise about 46%, 47%, 48%, 49%, 50%, 51%, 52%, 53%, 54%, 55%, 56%, 57%, 58%, 59%, 60%, 61%, 62%, 63%, 64%, 65%,66%, 67%, 68%, 69%, 70%, 71%, 72%, 73%, 74%, 75%, 76%, 77%, 78%, 79%, 80%, 81%,82%, 83%, 84%, 85%, 86%, 87%, 88%, 89%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%,98%, 99%, or 100%, or any percentage in between.

[0177] In some instances, the ps may comprise about 1.0 bar. In some embodiments, ps may be between about 0.8 bar and about 1.6 bar, such as 0.8 bar, 0.85 bar, 0.9 bar, 0.95 bar, 1.0 bar, 1.05 bar, 1.1 bar, 1.15 bar, 1.2 bar, 1.25 bar, 1.3 bar, 1.35 bar, 1.4 bar, 1.45 bar, 1.5 bar, 1.55 bar, or 1.6 bar, or any value in between. In some cases, ps may be at least about 0.8 bar. In other instances, ps may be at most about 1.6 bar. The variable ps represents the pressure at the turbine inlet. In some instances, this may be the pressure of the exhaust gas entering the turbine after combustion.

[0178] In some instances, the p4 may comprise about 0.33 bar. In some embodiments, p4 may be between about 0.1 bar and about 0.5 bar, such as 0.1 bar, 0.15 bar, 0.2 bar, 0.25 bar, 0.3 bar, 0.35 bar, 0.4 bar, 0.45 bar, or 0.5 bar, or any value in between. In some cases, p4 may be at least about 0.1 bar. In other instances, p4 may be at most about 0.5 bar. The variable p4 represents the pressure at the turbine outlet. In some instances, this may be the pressure of the exhaust gas after expansion in the turbine.

[0179] In some instances, the T3 may comprise about 1173 K. In some embodiments, T3 may be between about 1073 K and about 1273 K, such as 1073 K, 1098 K, 1123 K, 1148 K, 1173 K, 1198 K, 1223 K, 1248 K, or 1273 K, or any value in between. In some cases, T3 may be at least about 1073 K. In some instances, T3 may be at most about 1273 K. The variable T3 represents the temperature at the turbine inlet. In some instances, this moderate turbine inlet temperature may permit the use of standard-grade alloys for the static and rotating parts in the turbine.

[0180] In some instances, the T4 may comprise about 950 K. In some embodiments, T4 may be between about 850 K and about 1050 K, such as 850 K, 875 K, 900 K, 925 K, 950 K, 975 K, 1000 K, 1025 K, or 1050 K, or any value in between. In some cases, T4 may be at least about 850 K. In other instances, T4 may be at most about 1050 K. The variable T4 represents the temperature at the turbine outlet. In some instances, this may be the temperature of the exhaust gas after expansion in the turbine has generated power.

[0181] The variable k may represent the specific heat ratio (cp / cv) for the exhaust gas under the operating conditions. This is also known as the adiabatic index or ratio of specific heats. In some instances, this value describes how the temperature and pressure of the exhaust gas relate during expansion.

[0182] The variable r|pmay represent the polytropic efficiency, which characterizes how efficiently the turbine extracts work from the exhaust gas during expansion. In some instances, this efficiency metric accounts for the real gas behavior and irreversibilities during the expansion process.

[0183] In some embodiments, the turbine may be coupled directly to an electrical generator at a synchronous speed. In some cases, this configuration eliminates the need for a gearbox or additional power electronics. For example, the turbine and generator may operate at about 3600 RPM on a single shaft.

[0184] In some cases, the at least one turbine may be configured to handle working fluid flows (e.g, such as CO2) of about 1 kg / s, 2 kg / s, 3 kg / s, 4 kg / s, 5 kg / s, 6 kg / s, 7 kg / s, 8 kg / s, 9 kg / s, 10 kg / s, 11 kg / s, 12 kg / s, 13 kg / s, 14 kg / s, 15 kg / s, 16 kg / s, 17 kg / s, 18 kg / s, 19 kg / s, 20 kg / s, 21 kg / s, 22 kg / s, 23 kg / s, 24 kg / s, 25 kg / s, 26 kg / s, 27 kg / s, 28 kg / s, 29 kg / s, 30 kg / s, 31 kg / s, 32 kg / s, 33 kg / s, 34 kg / s, 35 kg / s, 36 kg / s, 37 kg / s, 38 kg / s, 39 kg / s, 40 kg / s, 100 kg / s, 42 kg / s, 43 kg / s, 44 kg / s, 45 kg / s, 46 kg / s, 47 kg / s, 48 kg / s, 49 kg / s, 50 kg / s, 51 kg / s, 52 kg / s,53 kg / s, 54 kg / s, 55 kg / s, 56 kg / s, 57 kg / s, 58 kg / s, 59 kg / s, 60 kg / s, 61 kg / s, 62 kg / s, 63 kg / s,64 kg / s, 65 kg / s, 66 kg / s, 67 kg / s, 68 kg / s, 69 kg / s, 70 kg / s, 71 kg / s, 72 kg / s, 73 kg / s, 74 kg / s,75 kg / s, 76 kg / s, 77 kg / s, 78 kg / s, 79 kg / s, 80 kg / s, 81 kg / s, 82 kg / s, 83 kg / s, 84 kg / s, 85 kg / s,86 kg / s, 87 kg / s, 88 kg / s, 89 kg / s, 90 kg / s, 91 kg / s, 92 kg / s, 93 kg / s, 94 kg / s, 95 kg / s, 96 kg / s,97 kg / s, 98 kg / s, 99 kg / s, or 100 kg / s, or any value in between.

[0185] In some embodiments, the system comprises at least one turbine configured with specific mechanical configuration features. In some cases, the at least one turbine comprises a multi-stage arrangement rotating on a shaft speed from about 1800 rpm to about 7200 rpm,although about 3600 rpm may be typical for direct generator coupling. In some instances, the at least one turbine comprises a relatively large geometry resulting from sub-atmospheric inlet pressures ranging from about 0.4 bar to about 1.5 bar and outlet pressures from about 0.1 bar to about 0.5 bar. In some cases, the at least one turbine comprises standard Inconel alloys for both rotating and static parts, permitting operation at elevated temperatures (e.g., about 900°C to about 1100°C) without requiring exotic materials. In some instances, the at least one turbine comprises low blade stresses due to moderate expansion ratios and lower rotational speeds. For example, the at least one turbine may be configured to maintain a dimensionless specific speed (Ns) from about 0.21 to about 0.63. In some instances, the turbine may be configured to accommodate higher specific speeds, such as up to about 1.5 or more, to cover a broader range of operational scenarios, including those calculated for 4 MWe units.

[0186] As an example, the pressure drop ratio (Ap / p) may be between about 2.5% to about 7.5%, further illustrating moderate flow conditions. As an example, the pressure drop ratio (Ap / p) may represent a significant change, such as expanding from approximately 1.0 atm to 0.2 atm, resulting in a Ap / p of around 80%, further illustrating low-pressure flow conditions.X. HEAT RECOVERY

[0187] In some embodiments, the system comprises at least one heat management system. In some cases, the at least one heat management system may be configured to balance the system’s heat rejection and heat recovery to improve overall thermodynamic efficiency. As an example, the heat management system may operate in either a recuperated or unrecuperated mode, depending on real-time process demands.

[0188] In some embodiments, the system comprises at least one heat rejection subsystem. In some instances, the at least one air cooler comprises a configuration configured to reduce the working fluid temperature to about 15-35 K above ambient (e.g., about 306 K), although other suitable values may be used. As an example, the at least one heat rejection subsystem may produce a CO2 stream having a purity of greater than about 90% by volume after condensation and water removal.

[0189] In some embodiments, the system comprises at least one heat recovery subsystem. In some cases, the at least one recuperator comprises a high-temperature assembly configured to capture thermal energy from a turbine exhaust stream at about 950 K. As an example, thesystem may switch to an unrecuperated mode to supply higher exhaust temperatures (e.g., up to about 900 K) for external processes.

[0190] In some embodiments, the system comprises at least one oxygen preheating arrangement. In some cases, the at least one oxygen preheating arrangement comprises at least one heat exchanger configured to preheat incoming oxygen using waste heat from a combustor or turbine outlet. As an example, the system may improve combustion efficiency by introducing hotter reactants into the combustor.

[0191] In some embodiments, the system comprises at least one multi-stage heat exchanger arrangement for the combined flow of oxygen and CO2. In some cases, the at least one multistage heat exchanger arrangement comprises a first heat exchanger configured to raise the temperature of oxygen prior to mixing with compressed CO2. As an example, the at least one multi-stage heat exchanger arrangement may ensure the combined gas reaches at least about 500-600 °C before entering the combustor.

[0192] In some embodiments, the system comprises at least one steam generation system. In some instances, the at least one heat recovery heat exchanger comprises high-efficiency tubes arrayed in a counterflow configuration to transfer heat from the turbine exhaust to water. As an example, the steam generation system may facilitate industrial processes or district heating, while lowering exhaust temperatures prior to final heat rejection.

[0193] In some embodiments, the system comprises at least one control system. In some instances, the at least one control system comprises software or hardware that transitions the system between recuperated and unrecuperated operations based on heat demand or power generation priorities. As an example, the system may prioritize steam production during peak industrial demand and revert to recuperated mode at other times.

[0194] In some embodiments, the system comprises at least one heat exchanger that may be constructed from various materials. In some cases, the at least one heat exchanger comprises at least one nickel -based superalloy or ceramic, suitable for temperatures up to about 1000 °C or higher. As an example, the system may use copper-based or aluminum alloys in cooler, low-temperature sections to enhance thermal conductivity.

[0195] In some embodiments, the system comprises at least one heat exchanger configuration suitable for approach temperatures of about 15-35 K above ambient, although other suitable approach temperatures may be used. As an example, this configuration may allow gravity -based water condensation and a near-pure CO2 stream after sufficient cooling.

[0196] In some embodiments, the system comprises at least one heat recovery configuration. In some cases, the at least one heat recovery configuration comprises a recuperated mode with a first heat exchanger transferring thermal energy from the turbine exhaust to the compressor outlet stream. For example, the system may optimize steam generation, district heating, or other industrial requirements.

[0197] In some embodiments, the system comprises at least one heat recovery configuration. In some cases, the at least one heat recovery configuration comprises a recuperated mode with a first heat exchanger transferring thermal energy from the turbine exhaust to the compressor outlet stream. In some instances, the at least one heat recovery configuration comprises an unrecuperated mode in which the full exhaust temperature (approximately 900K to lOOOK) is directed to downstream processes. In some cases, the at least one heat recovery configuration comprises a recuperator effectiveness from about 85% to about 95%.

[0198] In some instances, the at least one heat recovery configuration comprises a thermal efficiency (qthermai) calculated by:T thermal (QreCovered) / (Qm), (equation (5))

[0199] where QrecOvered is useful heat recovered for external processes and Qin is the total heat input.

[0200] In some embodiments, the Qrecovered may comprise heat transferred from the system to external processes. In some cases, the Qrecovered may comprise heat utilized for steam generation in industrial processes. In some instances, the Qrecovered may comprise heat captured through the recuperator for preheating the compressor outlet stream to temperatures from about 800 K to about 1000 K. For example, the Qrecovered may comprise heat utilized for biomass drying and pyrolysis in biomass-fueled configurations of the system. As an example, the Qrecovered may comprise heat utilized for water condensate removal downstream of the heat rejection heat exchanger. In some cases, the Qrecovered may comprise heat recovered for district heating applications.

[0201] In some embodiments, the Qin may comprise heat input to the system from one or more sources. In some cases, the Qin may comprise heat generated from combustion of the hydrocarbon feedstock with oxygen in the combustor. In some instances, the Qin may comprise heat from the stoichiometric reaction of fuel with oxygen wherein the oxygen is provided at a stoichiometric ratio configured to achieve complete combustion. For example,the Qin may comprise heat input from the preheated oxygen stream after passing through the gas exchange recuperator. As an example, the Qin may comprise heat from the recirculated CO2 working fluid which comprises the bulk of the combustor inlet flow. In some cases, the Qin may comprise heat input from auxiliary heating sources configured to supplement the primary combustion heat input.

[0202] For example, the thermal efficiency may be about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, 20%, 30%, 22%, 23%, 24%, 25%, 26%, 27%, 28%, 29%, 30%, 31%, 32%, 33%, 34%, 35%, 36%, 37%, 38%, 39%, 40%,41%, 42%, 43%, 44%, 45%, 46%, 47%, 48%, 49%, 50%, 51%, 52%, 53%, 54%, 55%, 56%,57%, 58%, 59%, 60%, 61%, 62%, 63%, 64%, 65%, 66%, 67%, 68%, 69%, 70%, 71%, 72%,73%, 74%, 75%, 76%, 77%, 78%, 79%, 80%, 81%, 82%, 83%, 84%, 85%, 86%, 87%, 88%,89%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%, or 99%, or any percentage in between.

[0203] For example, the at least one heat recovery configuration may be configured to optimize steam generation, district heating, or other industrial requirements. As an example, some embodiments may sacrifice a portion of electrical efficiency to maximize heat recovery.

[0204] In some embodiments, the system comprises at least one heat recovery configuration. In some cases, the at least one heat recovery configuration comprises at least one recuperator. In some instances, the at least one recuperator comprises heat recovery ranging from about 500 kW to about 15,000 kW. In some cases, the at least one heat recovery configuration comprises at least one heat rejection heat exchanger. In some instances, the at least one heat rejection heat exchanger comprises heat recovered for water condensate removal ranging from about 500 kW to about 5000 kW. For example, the at least one recuperator may be configured to preheat streams to temperatures ranging from about 800 K to about 1200 K. As an example, the at least one heat rejection heat exchanger may transfer heat for industrial processes or steam generation ranging from about 1000 kW to about 10,000 kW.

[0205] In some embodiments, the system comprises at least one auxiliary heat recovery system. In some cases, the at least one auxiliary heat recovery system comprises heat utilized for biomass drying or pyrolysis. In some instances, the at least one auxiliary heat recovery system comprises heat recovery ranging from about 2000 kW to about 8000 kW. In some cases, the at least one auxiliary heat recovery system comprises heat recovered for district heating applications. In some instances, the heat recovered for district heating comprisesvalues ranging from about 2000 kW to about 12,000 kW. For example, the at least one auxiliary heat recovery system may be configured to transfer heat to downstream processes, such as industrial drying or district heating, with heat recovery rates of up to about 12,000 kW.

[0206] In some embodiments, the system comprises at least one additional heat recovery integration element. In some cases, the at least one additional heat recovery integration element comprises directing turbine exhaust heat to secondary industrial processes, such as steam generation. In some instances, the at least one additional heat recovery integration element comprises a heat recovery ratio (HRR) from about 70% to about 95%, although other suitable values may be implemented. In some cases, the at least one additional heat recovery integration element comprises real-time monitoring of available heat (Qavailable) versus recovered heat (Qrecovered). In some instances, the at least one additional heat recovery integration element comprises controls to maintain the turbine outlet temperature for efficient downstream utilization. For example, the at least one additional heat recovery integration element may be configured to prioritize thermal output in unrecuperated mode, trading off a portion of electrical efficiency. As an example, the system may be integrated with industrial sites needing reliable sources of medium- to high-temperature heat.XI. CARBON SEQUESTRATION

[0207] In some embodiments, the system comprises at least one CO2 outlet arrangement. In some cases, the at least one CO2 outlet arrangement comprises at least one sub-atmospheric discharge pathway. In some instances, the at least one sub-atmospheric discharge pathway comprises a cooled and dewatered CO2 stream prepared for pipeline-quality specification. In some cases, the at least one CO2 outlet arrangement comprises at least one compression interface. In some instances, the at least one compression interface comprises pumping or multi-stage compression configured to elevate CO2 pressure to about 80-100 bar. For example, the at least one CO2 outlet arrangement may be configured to deliver near-pure CO2 directly to a pipeline or injection site. As an example, a pipeline-quality CO2 stream may exceed about 95% purity by volume.

[0208] In some embodiments, the system comprises at least one CO2 product stream. In some cases, the at least one CO2 product stream comprises at least one medium-purity configuration exceeding about 90% CO2 by volume after water removal. In some instances, the at least one medium-purity configuration comprises a high-purity specification exceedingabout 99% by volume. In some cases, the at least one CO2 product stream comprises at least one ultra-high purity option greater than about 99.99% CO2 by volume. In some instances, the at least one ultra-high purity option comprises real-time analyzers confirming final composition. For example, the at least one CO2 product stream may be configured to offer multiple purity tiers suitable for industrial, food-grade, or pipeline applications. As an example, real-time monitoring may verify compliance with targeted standards prior to transport or sequestration.

[0209] In some embodiments, the system comprises at least one impurity control system. In some cases, the at least one impurity control system comprises at least one water removal unit. In some instances, the at least one water removal unit comprises condensation and gravity separation to reduce moisture content to below about 10% by volume. In some cases, the at least one impurity control system comprises at least one polishing stage. In some instances, the at least one polishing stage comprises filters or catalytic reactors configured to keep SOx, NOx, CO, and unreacted hydrocarbons each below about 1% by volume. For example, the at least one impurity control system may be configured to meet pipeline or foodgrade CO2 requirements. As an example, further scrubbing or sorbent materials may be added if more stringent emission limits (e.g., <100 ppm) are desired.

[0210] In some embodiments, the system comprises at least one downstream application interface. In some cases, the at least one downstream application interface comprises at least one enhanced oil recovery (EOR) connection system. In some instances, the at least one enhanced oil recovery connection system comprises injection lines delivering CO2 at purities of at least about 95% and pressures around 15-30 MPa. In some cases, the at least one downstream application interface comprises at least one chemical synthesis connection system. In some instances, the at least one chemical synthesis connection system comprises reactor inlets for methanol production at about 50-100 bar. For example, the at least one downstream application interface may be configured to allocate CO2 to multiple industrial processes without requiring separate gas-purification steps. As an example, flow-splitting may route CO2 to both EOR and methanol synthesis off-takers simultaneously.

[0211] In some embodiments, the system comprises at least one food-grade CO2 production configuration. In some cases, the at least one food-grade CO2 production configuration comprises at least one ultra-purification module. In some instances, the at least one ultrapurification module comprises adsorption beds or membrane filters configured to remove trace gases and odors, ensuring CO2 purity above about 99.9% by volume. In some cases, theat least one food-grade CO2 production configuration comprises at least one quality control subsystem. In some instances, the at least one quality control subsystem comprises real-time sensors verifying compliance with international beverage standards. For example, the at least one food-grade CO2 production configuration may be configured for carbonation, cryogenic freezing, or modified-atmosphere packaging. As an example, final dew points may be kept sufficiently low to avoid condensation in cold-chain logistics.

[0212] In some embodiments, the system comprises at least one construction materials interface. In some cases, the at least one construction materials interface comprises at least one green concrete production system. In some instances, the at least one green concrete production system comprises a curing chamber configured to operate at about 20-50 °C. In some cases, the at least one construction materials interface comprises at least one carbon mineralization unit. In some instances, the at least one carbon mineralization unit comprises an injection or mixing method that permanently locks CO2 into the concrete matrix, enhancing strength by about 5-15%. For example, the at least one construction materials interface may be configured to reduce overall cement requirements by mineralizing captured CO2. As an example, a portion of the CO2 stream may be diverted to curing lines.

[0213] In some embodiments, the system comprises enhanced rock weathering capabilities. In some cases, the weathering process injects CO2 into suitable geological formations. In some instances, the process provides permanent carbon sequestration with lifetimes exceeding 1000 years.

[0214] In some cases, a carbon sequestration efficiency may comprise a ratio of carbon retained or sequestered relative to the total carbon present in the input fuel. In some instances, the carbon sequestration efficiency may be defined as the percentage of carbon in the input fuel that is captured and stored, compared to the carbon released in the output gas. In some instances, the carbon sequestration efficiency may comprise about 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19%, 20%, 30%, 22%, 23%, 24%, 25%, 26%, 27%, 28%, 29%, 30%, 31%, 32%, 33%, 34%, 35%, 36%, 37%, 38%,39%, 40%, 41%, 42%, 43%, 44%, 45%, 46%, 47%, 48%, 49%, 50%, 51%, 52%, 53%, 54%,55%, 56%, 57%, 58%, 59%, 60%, 61%, 62%, 63%, 64%, 65%, 66%, 67%, 68%, 69%, 70%,71%, 72%, 73%, 74%, 75%, 76%, 77%, 78%, 79%, 80%, 81%, 82%, 83%, 84%, 85%, 86%,87%, 88%, 89%, 90%, 91%, 92%, 93%, 94%, 95%, 96%, 97%, 98%, or 99%, or any percentage in between.

[0215] In some embodiments, the system comprises at least one water management system. In some cases, the at least one water management system comprises at least one heat rejection heat exchanger. In some instances, the at least one heat rejection heat exchanger comprises an air cooler configured to cool exhaust gas to a temperature below the water vapor saturation point, often to about 20-30 K above ambient temperature. For example, the at least one heat rejection heat exchanger may be configured to reject excess heat to the ambient environment.

[0216] In some embodiments, the system comprises at least one water condensation or removal component. In some cases, the at least one water condensation or removal component comprises a mechanism for cooling and condensing H2O from a CCh-rich exhaust stream. In some instances, the at least one mechanism comprises gravity separators or demisters. For example, the at least one water condensation or removal component may be combined with the at least one heat rejection heat exchanger to produce near-pure CO2 at ambient temperature.

[0217] In some embodiments, the system comprises at least one water separation subsystem. In some cases, the at least one water separation subsystem comprises a gravity drainage mechanism configured to remove condensed water. In some instances, the at least one gravity drainage mechanism may operate downstream of the at least one heat rejection heat exchanger, where water vapor condensation occurs due to reduced temperatures. For example, the at least one water separation subsystem may remove the majority of water vapor generated during the combustion process, permitting the efficient handling of the CCh-rich stream.

[0218] In some embodiments, the system comprises at least one condensate collection system. In some cases, the at least one condensate collection system comprises gravity-driven drainage pathways configured to remove condensed water. In some instances, the at least one gravity-driven drainage pathway may operate under sub-atmospheric pressure to maintain system pressure integrity. For example, the at least one condensate collection system may allow effective water removal from the CCh-rich stream during processing.

[0219] In some embodiments, the system comprises at least one water content monitoring system. In some cases, the at least one water content monitoring system is configured to verify water removal levels prior to CO2 compression. In some instances, the at least one water content monitoring system may ensure that water concentrations in the CCh-rich stream remain less than about 10% by volume. For example, the at least one water contentmonitoring system may support downstream CO2 utilization applications by maintaining appropriate water removal thresholds.

[0220] In some embodiments, the system comprises at least one biomass pyrolysis subsystem. In some cases, the at least one biomass pyrolysis subsystem comprises at least one pyrolysis reactor. In some instances, the at least one pyrolysis reactor comprises a controllable temperature and residence time module. In some cases, the at least one biomass pyrolysis subsystem comprises at least one feedstock processing arrangement. In some instances, the at least one feedstock processing arrangement comprises a slow or fast pyrolysis selection mechanism, which may be chosen based on feedstock characteristics. For example, the at least one biomass pyrolysis subsystem may be configured to refine or filter volatile organic compounds (VOCs) prior to combustion. As an example, the at least one biomass pyrolysis subsystem may permit a biomass-to-energy route that aligns with a CO2 capture cycle.

[0221] In some embodiments, the system comprises biomass processing capabilities for wet feedstocks. In some cases, the wet feedstock processing comprises dairy manure processing, wastewater treatment, organic sludge processing, and palm oil effluent treatment. In some instances, the anaerobic digestion produces biogas with higher purity compared to pyrolysis gas.

[0222] In some embodiments, the system comprises at least one integrated heat-recovery arrangement. In some cases, the at least one integrated heat-recovery arrangement comprises at least one heat exchanger or rotary drum. In some instances, the at least one heat exchanger or rotary drum comprises a path for routing hot exhaust gas. In some cases, the at least one integrated heat-recovery arrangement comprises at least one biomass preheating module. In some instances, the at least one biomass preheating module comprises a process for reducing moisture content in the feedstock. For example, the at least one integrated heat-recovery arrangement may be configured to use recovered sensible heat for biomass drying or pyrolysis. As an example, the at least one integrated heat-recovery arrangement may allow increased pyrolysis efficiency by reusing otherwise wasted thermal energy.

[0223] In some embodiments, the system comprises at least one pyrolysis product management component. In some cases, the at least one pyrolysis product management component comprises at least one separation subsystem. In some instances, the at least one separation subsystem comprises a mechanism to isolate carbon-rich char or stable solidpyrolysis products from the volatile fraction. In some cases, the at least one pyrolysis product management component comprises at least one analysis module. In some instances, the at least one analysis module comprises a system that characterizes the char’s properties for soil amendment or industrial applications. For example, the at least one pyrolysis product management component may be configured to tailor pyrolysis conditions to obtain desired char composition. As an example, the at least one pyrolysis product management component may permit a multi-product approach that captures carbon in a solid form while generating gaseous fuels.

[0224] In some embodiments, the system comprises at least one char-storage arrangement. In some cases, the at least one char-storage arrangement comprises at least one inert container or controlled enclosure. In some instances, the at least one inert container or controlled enclosure comprises a seal that reduces exposure to air or moisture. In some cases, the at least one char-storage arrangement comprises at least one long-term sequestration module. In some instances, the at least one long-term sequestration module comprises a process for converting char into biochar for soil application. For example, the at least one char-storage arrangement may be configured to maintain carbon stability over extended periods. As an example, the at least one char-storage arrangement may allow negative-carbon or carbon-neutral operations by tracking lifecycle carbon benefits of stable char storage.

[0225] In some embodiments, the system comprises at least one biomass-compatible combustion setup. In some cases, the at least one biomass-compatible combustion setup comprises at least one combustor adapted to manage particulate-laden or vaporized biofuel streams. In some instances, the at least one combustor adapted to manage particulate-laden or vaporized biofuel streams comprises a burner geometry that may cope with ash or tars. In some cases, the at least one biomass-compatible combustion setup comprises at least one mixing mechanism for co-firing biomass-derived fuel with standard hydrocarbons. In some instances, the at least one mixing mechanism comprises a control system that maintains consistent combustion. For example, the at least one biomass-compatible combustion setup may be configured to provide a renewable or lower-carbon-intensity energy source. As an example, the at least one biomass-compatible combustion setup may use biomass or a derivative thereof as a hydrocarbon feedstock.XIV. CONTROL SYSTEMS

[0226] In some embodiments, the system comprises control systems configured to maintain improved operating conditions. Sensors and actuators manage working fluid composition, temperatures, and pressures. Logic coordinates fuel and oxygen input with power demand. For example, stoichiometric combustion conditions may be maintained while responding to load variations.

[0227] In some embodiments, the system comprises a real-time oxygen flow control mechanism to control a flow rate of the oxygen-rich gas into the combustor and modify the exhaust gas composition. In some cases, the system implements automated valves or flow controllers. In some instances, the system adjusts oxygen flow based on CO2 or CO sensor feedback. For example, the system uses advanced control algorithms to maintain target combustion efficiency. As an example, the system ramps oxygen flow when higher power is demanded, ensuring responsive tuning of exhaust quality and power output.

[0228] In some embodiments, the system comprises a hydrocarbon-feed control mechanism to control a rate of injection of the hydrocarbon feedstock into the combustor, thereby modifying exhaust gas composition. In some cases, the system synchronizes fuel injection with oxygen supply for balanced combustion. In some instances, the system responds to fluctuations in demand or feedstock availability. For example, the system may ramp fuel injection up or down to follow a load setpoint. As an example, the system avoids incomplete combustion by preventing excess fuel relative to oxygen, optimizing performance and emissions.

[0229] In some embodiments, the system comprises a load-following control strategy that dynamically controls the flow rates of both the hydrocarbon feedstock and the oxygen-rich gas based on real-time power demand. In some cases, the system monitors grid load or industrial process requirements. In some instances, the system ramps up or down oxygen and fuel to match desired power output. For example, the system may employ a control system receiving demand signals, modulating valves accordingly. As an example, the system ensures stable combustion under varying load, providing flexible on-demand power generation.

[0230] In some embodiments, the system comprises a stoichiometric-control module that maintains a stoichiometric ratio of hydrocarbon feedstock to the oxygen-rich gas , thereby reducing incomplete combustion products in the exhaust. In some cases, the system matches fuel and oxygen flows to meet theoretical combustion demand. In some instances, the system uses real-time sensors for CO and residual oxygen to confirm stoichiometry. For example, thesystem verifies minimal CO or unburned hydrocarbons in the exhaust. As an example, the system adjusts flow controllers to keep a near-perfect ratio, optimizing efficiency and exhaust purity.

[0231] In some embodiments, the system comprises a power allocation mechanism that uses a second portion of the power produced by expansion for an industrial process. In some cases, the system allocates surplus power from the turbine-generator output to drive ancillary equipment or to export power to a nearby facility. In some instances, the system matches real-time power output to an industrial load. For example, the system may supply power for electrolysis, synthesis, or other manufacturing tasks. As an example, the system improves overall resource utilization by coupling power generation with direct industrial consumption.

[0232] In some embodiments, the system comprises at least one water-in-exhaust management component. In some cases, the system includes at least one steam control unit that allows the combustion reaction to form water (H2O) as a natural by-product. In some instances, the system further comprises at least one humidity regulator to monitor exhaust gas dew point for improved condensation. For example, the system may collect water vapor for potential reuse. As an example, the system utilizes the steam content for energy recovery or cooling.

[0233] In some embodiments, the system comprises at least one exhaust-conditioning assembly. In some cases, the system includes at least one moisture-removal unit configured to remove at least a portion of water from the exhaust gas prior to compression. In some instances, the system further comprises at least one condenser or moisture separator to reduce water content and improve compression efficiency. For example, the system may lower dew point through intercooling or other conditioning. As an example, the system minimizes compressor corrosion and power load by reducing water content.

[0234] In some embodiments, the system comprises at least one water-content control module. In some cases, the system includes at least one moisture sensor to ensure the concentration of H2O in the exhaust gas prior to compression is less than about 10% by volume. In some instances, the system also comprises at least one cooling stage configured to meet the target water fraction. For example, the system may employ multi-stage condensation to reduce moisture. As an example, the system protects downstream equipment and improves CO2 processing by controlling residual water.XV. EXAMPLE EMBODIMENTS

[0235] In some embodiments, the system integrates the compressor module with the turbine module on a common shaft, providing direct mechanical power transfer. In such cases, power from the turbine may drive the compressor at sub-atmospheric inlet conditions. In some instances, a feedback mechanism routes compressed CO2 from the compressor directly into the oxy -fuel combustor, which combines the CO2 with a controlled flow of oxygen for near- stoichiometric combustion and near-pure CO2 exhaust. Hot gases from the combustor then drive the turbine for expansion and power generation. For example, the final exhaust may be cooled to condense water vapor, yielding a CCh-rich stream suitable for sequestration or utilization. In some cases, the system includes a heat recovery assembly placed downstream of the turbine module to harness residual thermal energy for steam generation or other industrial processes. This arrangement may improve overall efficiency or generate additional revenue through cogeneration applications. In some embodiments, the system comprises at least one sub-atmospheric Brayton cycle operating at a compressor inlet pressure significantly below standard atmospheric conditions. In some cases, this cycle employs CO2 as the working fluid, providing near-pure CO2 exhaust. In some instances, the sub- atmospheric configuration avoids the need for fuel-boosting equipment by passively drawing fuel into the combustor. For example, the compressor inlet may operate at about one-third of atmospheric pressure (-0.3 bar), reducing both capital cost and operational complexity.

[0236] In some embodiments, the system comprises at least one natural gas-fueled power block similar to a baseline configuration. In some cases, this power block employs an oxyfuel combustor receiving a stoichiometric flow of oxygen from a nearby O2 source (e.g., an ammonia or electrolysis facility). In some instances, near-pure CO2 exhaust is captured without requiring an air separation unit. For example, natural gas may be passively drawn into the combustor, eliminating the need for a high-pressure fuel booster, and simplifying overall operations.

[0237] In some embodiments, the system comprises at least one biomass-fueled sub- atmospheric Brayton cycle. In some cases, this biomass-fueled embodiment includes an integrated pyrolysis reactor that converts feedstock into volatile organic compounds (VOCs) and a stable carbon byproduct (char). In some instances, near-pure CO2 is captured when the combustor is supplied with oxygen from a close-coupled source. For example, the system may simultaneously dry and pyrolyze feedstock using turbine exit heat, producing char for long-term carbon storage and VOC gas for immediate power generation. In further cases, the system offers net-carbon-negative operation by sequestering char.

[0238] In some embodiments, the system comprises an unrecuperated sub-atmospheric Brayton cycle configured to maximize high-temperature heat availability at the turbine outlet. In some cases, omitting a recuperator allows higher-grade heat to be used for process steam or other industrial needs. In some instances, operating temperatures at the turbine exit may reach about 900 K, making the exhaust suitable for applications requiring substantial thermal input (e.g., ethanol refineries). For example, prioritizing heat recovery over electrical efficiency may be advantageous if industrial steam or other high-temperature processes provide significant revenue or efficiency gains.

[0239] In some embodiments, the system comprises at least one partitioned combustor capable of handling diverse fuels. In some cases, this combustor introduces fresh air or oxygen into a primary combustion zone and recirculates CCh-rich exhaust to a dilution section. In some instances, the partitioned configuration provides reliable combustion of natural gas, biogas, biogas, syngas, or diesel with minimal hardware changes. For example, maintaining a stoichiometric match between fuel and oxygen reduces NOXformation and yields a near-pure CO2 exhaust suitable for capture or sequestration.

[0240] In some embodiments, the system comprises at least one pyrolysis subsystem with a feedstock dryer and reactor. In some cases, the subsystem uses turbine exit heat to convert incoming biomass into volatile fuels and stable char. In some instances, long-term char storage facilitates net-negative carbon emissions. For example, operators may sell or sequester the char as a soil amendment while combusting the volatile gases in the Brayton cycle, effectively removing carbon dioxide from the atmosphere at scale.

[0241] In some embodiments, the system comprises at least one CO2 output stream configured for near-pure CO2 capture. In some cases, the stream is compressed and injected into geologic formations for long-term storage, potentially qualifying for credits such as 45Q. In other instances, the CO2 may be diverted to merchant markets, used for enhanced oil recovery, or integrated into low-carbon fuel production (e.g., green methanol). For example, the system may utilize oxygen from water electrolysis while selling captured CO2 to local industrial partners. As an example, routing electrolyzer-derived oxygen into the combustor reduces the need for an external oxygen supply and further improves the carbon intensity of the overall process.

[0242] In some embodiments, the system comprises sustainable aviation fuel (SAF) production integration. In some cases, the SAF production utilizes captured CO2 and greenhydrogen. In some instances, the integration provides carbon intensity reduction for aviation fuels.

[0243] In some embodiments, the system comprises at least one compressor. In some cases, the compressor is a multi-stage assembly with rotor blades formed from an Inconel alloy. In some instances, the compressor includes an inlet flow regulator with adjustable vanes configured to manage sub-atmospheric pressures (e.g., about 0.3 bar at the inlet). For example, the compressor may raise CO2 pressure to approximately 1 bar. In further examples, compression may heat the CO2 to about 447 K, suitable for introduction into an oxy-fuel combustor.

[0244] In some embodiments, the system comprises at least one oxy-fuel combustor. In some cases, the combustor has a thermal-barrier-lined chamber with a mixing manifold for stoichiometric injection of oxygen and fuel. In some instances, flow-control valves or orifices are sized to maintain the desired oxygen-fuel ratio. For example, the combustor may operate at about 1173 K, minimizing NOXby excluding atmospheric nitrogen. In further examples, exhaust gases consist primarily of CO2 and H2O, providing water condensation downstream for near-pure CO2 capture.

[0245] In some embodiments, the system comprises at least one turbine, which may include a multi-stage turbine rotor. In some cases, the rotor is configured for moderate inlet temperatures (up to about 1173 K). In some instances, the turbine shaft is directly coupled to a generator that may operate at around 3600 RPM without a gearbox. For example, the turbine may expand gases from roughly 1 bar to 0.3 bar, producing enough shaft power to drive the compressor and generate about 4 megawatts of power. In further examples, the turbine exhaust temperature may be near 950 K, suitable for downstream heat recovery.

[0246] In some embodiments, the system comprises at least one heat recovery assembly with a secondary heat exchanger. In some cases, this assembly uses high-efficiency counterflow tubes to extract thermal energy from the turbine exhaust. In some instances, a bypass manifold with flow-control valves diverts hot exhaust to an industrial process. For example, the heat recovery assembly may produce steam at about 435 K, boosting total system efficiency or providing cogeneration capabilities. In further examples, residual heat extraction before final cooling helps separate water, leaving near-pure CO2 ready for sequestration.

[0247] In some embodiments, the system is adapted to operate with various fuel types, including natural gas or syngas, over a combustor temperature range of about 900 K to 1173K. In some cases, the cycle is unrecuperated to maximize heat recovery at the turbine exhaust, though a partial recuperator may be employed to preheat the working fluid if higher combustion efficiency is desired. For example, net simple-cycle efficiency may be between about 30-40%, increasing to about 50-60% with full heat recovery. In further examples, carbon purity in the exhaust may exceed 90% by volume due to oxy-fuel operation. As an example, the system may be scaled up by adding additional compressor and turbine stages without major hardware reconfigurations.

[0248] In some embodiments, components are included for processing biomass-derived fuels, such as dryers or pyrolysis reactors that utilize recovered heat. Other modifications allow operation without a close-coupled oxygen source if necessary. For example, the system may still achieve carbon storage benefits by producing and sequestering biochar, even if full oxy- fuel conditions are temporarily unavailable.

[0249] In some embodiments, the system comprises at least one power generation system operating at sub-atmospheric pressure. In some cases, the at least one power generation system comprises at least one compressor, at least one combustor, at least one turbine, and at least one heat exchanger, arrayed in a semi-closed Brayton cycle utilizing carbon dioxide as a working fluid. In some instances, the compressor may compress an exhaust gas comprising CO2 to a pressure no greater than about 73.9 bar. For example, compression may occur between about 0.4 bar and about 1.6 bar. In some embodiments, the system comprises at least one oxy-fuel combustor configured to operate at a pressure less than about 1.6 bar and a temperature less than about 1000°C.

[0250] In some embodiments, the system comprises a multi-stage turbine configured to expand an exhaust gas comprising CO2. In some cases, the turbine may operate with an inlet temperature less than about 900°C, at an expansion ratio between about 1.5 and about 4.8. In further instances, the turbine may be mechanically coupled to the compressor on a common shaft. In some embodiments, at least one heat exchanger may be a recuperator transferring heat between the high-pressure and low-pressure sides of the system, potentially preheating incoming oxygen using extracted CO2.

[0251] In some embodiments, the system comprises at least one generator that may operate at about 3600 rpm without a gearbox and produce between about 2000 kWe and about 6000 kWe of electrical power. In further examples, a carbon dioxide extraction system may remove a portion of compressed CO2 with purity above about 90% by volume, directing it toa sequestration or utilization unit. In some cases, the system may receive an oxygen stream from an industrial process, such as ammonia production or water electrolysis, with O2 levels above about 90%.

[0252] In some embodiments, the system may process biomass feedstock in an integrated pyrolysis system, producing VOCs for combustion and stable carbon char byproduct. A control system may maintain stoichiometric combustion conditions, and a heat recovery system may capture thermal energy from the turbine exhaust to generate steam at about 435 K. Water management may remove condensed moisture to keep water concentration below about 10% by volume in the recycled CO2 stream. In some cases, a fuel delivery system may inject hydrocarbon feedstock (natural gas, biogas, propane, methane, diesel, or pyrolyzed VOCs) at sub-atmospheric pressure without a resolute booster.

[0253] In some embodiments, an efficiency optimization system may maintain polytropic or isentropic efficiencies in the turbine and compressor between about 40% and about 100%. The system may also include a CO2 processing unit to refine CO2 purity to above 99% for enhanced oil recovery, green concrete production, or methanol synthesis. Biomass-specific configurations may incorporate dryers and pyrolyzers utilizing turbine exhaust heat to create net-negative emissions through stable char production.

[0254] FIG. 1 shows an example a system 100 for power generation with carbon capture. The system 100 may comprise a compressor 102, a turbine 103, a generator 107, a combustor 104, a cycle recuperator 101, and a heat rejection heat exchanger 105. In some embodiments, ambient conditions for the system 100 may comprise a pressure of about 101.3 kPa and a temperature of about 298.2 K. The heat rejection heat exchanger 105 may be configured to remove water (H2O) from the working fluid.

[0255] In some embodiments, the working fluid at state point (1) entering the compressor 102 may be at a pressure of about 19.1 kPa and a temperature of about 306.2 K. The compressor discharge at state point (2) may operate at increased pressure and temperature. In some embodiments, the pressure may be about 101.3 kPa. In some cases, the temperature may be about 447.4 K. A gas exchange recuperator 106 may be configured to extract CO2 and add O2. The O2 input 111 may be configured to provide oxygen to the system 100. In some instances, at the CO2 extraction point (state point 3), the pressure may be about 10.8 kPa and the temperature may be about 447.4 K. The extracted CO2 may be directed to a CO2 output 108.

[0256] The cycle recuperator 101 may heat the working fluid prior to combustion. At state point (4) leading to the combustor 104, in some embodiments, the pressure may be about 99.8 kPa and the temperature may be about 899.7 K. The combustor 104 may receive natural gas via input 109. At state points (5, 6) between the combustor 104 and turbine 103, in some cases, the pressure may be between about 94.3 kPa and about 99.3 kPa. In some instances, the temperature may be between about 899.7 K and about 1,173.2 K. The turbine discharge at state points (7, 8) may operate at reduced pressure and temperature. In some embodiments, the pressure may be about 20.6-20.7 kPa. In some cases, the temperature may be about 950.0 K. At state point (9), in some instances, the pressure may be about 19.6 kPa and the temperature may be about 508.4 K.

[0257] The system 100 may be configured to generate about 4 MWe of electrical power through the generator 107. In some embodiments, the compressor 102, turbine 103, and generator 107 may be arrayed on a common shaft operating at synchronous speed, thereby eliminating the need for a gearbox or power electronics. The system 100 may be configured to operate as a semi-closed cycle using CO2 as a working fluid while providing carbon capture without requiring an air separation unit.

[0258] FIG. 2 shows an example schematic diagram of a power generation system 200 comprising a single-shaft configuration for a natural gas-fueled variant. In some embodiments, the system 200 may comprise a power output between about 2000 kWe and about 6000 kWe, for example, about 4000 kWe, with an engine electrical efficiency between about 20% and about 60%, for example, about 40.1%.

[0259] The system 200 may comprise a recuperator (RECUP) 201 configured to transfer heat between working fluid streams. In some instances, the recuperator 201 may be characterized by a cold-side pressure drop ratio (Ap / p) between about 2.5% and about 7.5%, for example, about 5.0%, and a hot-side pressure drop ratio between about 1.25% and about 3.75%, for example, about 2.5%. The recuperator inlet temperature may be between about 450 K and about 1350 K, for example, about 900 K, with an effectiveness between about 45% and about 99%, for example, about 90.0%. In some instances, the recuperator 201 may be characterized by a cold-side pressure drop ratio (Ap / p) optimized for the system's specific operating conditions, such as a Ap / p resulting from a pressure drop from approximately 1.0 atm to 0.2 atm, which corresponds to a significant change, for example, around 80%.

[0260] The system 200 may comprise a cold end pump (CMP) 206 and a turbine expander block (TRB) 204. The compressor may be characterized by a polytropic efficiency between about 45% and about 99%, for example, about 90.5%, and an isentropic efficiency between about 44% and about 99%, for example, about 88.6%. The turbine may be characterized by a polytropic efficiency between about 46% and about 99%, for example, about 92.0%, and an isentropic efficiency between about 47% and about 99%, for example, about 93.0%. In some embodiments, both the compressor and turbine may operate at a rotational speed between about 1800 rpm and about 7200 rpm, for example, about 3600 rpm.

[0261] A thermal storage module (TSM) 202 may be provided with a pressure drop ratio (Ap / p) between about 2.5% and about 7.5%, for example, about 5.0%. Alternatively, the TSM may be characterized by a pressure drop ratio optimized for specific system operating conditions, such as a Ap / p resulting from a pressure drop from approximately 1.0 atm to 0.2 atm, corresponding to a significant change, for example, around 80%. The system may include a precooler with a pressure drop ratio between about 1.25% and about 3.75%, for example, about 2.5%, and an approach temperature difference between about 4 K and about 12 K, for example, about 8.0 K. Alternatively, the precooler may also be characterized by an approach temperature and heat duty tailored to the system’s specific requirements. The precooler may have a heat duty between about 2800 kW and about 8500 kW, for example, about 5666 kW.

[0262] Multiple flow control valves may be positioned throughout the system 200, wherein said valves may be configured to have pressure drop ratios between about 0.25% and about 0.75%, for example, about 0.5%. The system may include a blower (BLR) 207 operatively coupled to a motor 208, which may be connected to a generator (GEN) 205 via an electrical connection 210.

[0263] In some embodiments, the working fluid mass flow rate may be between about 14 kg / s and about 100 kg / s (e.g., at 15-20 Mwe), for example, about 27 kg / s. The system may operate with a pressure ratio between about 1.8 and about 5.5, for example, about 3.69, and a turbine expansion ratio between about 1.6 and about 4.8, for example, about 3.17.

[0264] The generator 205 may experience alternator / bearing losses, wherein the inboard losses may be between about 3.2 kW and about 9.6 kW, for example, about 6.4 kW, and the outboard losses may be between about 2.4 kW and about 7.1 kW, for example, about 4.7 kW. The alternator electrical and power conversion efficiencies may be between about 2% andabout 6%, for example, about 4.0% and 3.0% respectively. For example, the working fluid may flow through the RECUP 201 where heat exchange occurs, then through the CMP 206 where pressure may be modified, and subsequently through the TRB 204 where expansion may generate mechanical energy for conversion to electrical power via the GEN 205. The RCIR 203 and TSM 202 may be configured to provide additional thermal management capabilities to optimize system performance.

[0265] In some embodiments, the compressor may be characterized by a dimensionless specific speed between about 0.25 and about 0.74, for example, about 0.49. The turbine may be characterized by a dimensionless specific speed between about 0.21 and about 0.63, for example, about 0.42. The turbine inlet temperature may be between about 590 K and about 1760 K, for example, about 1173 K.

[0266] FIG. 3 shows an example schematic diagram of a semi-closed biomass-fueled sub- atmospheric Brayton power system 300. The system 300 may comprise a cycle recuperator (CYCLE RECUP) 301 configured to transfer heat between working fluid streams and manage thermal energy recovery within the system.

[0267] In some embodiments, the system 300 may comprise a compressor (COMP) 302 fluidly coupled to a turbine expander block (TURB) 313, wherein said compressor 302 and turbine 313 may be configured to operate at sub-atmospheric pressure. A generator (GEN) 307 may be coupled to the compressor 302, wherein the generator 307 may be configured to convert mechanical energy to electrical power.

[0268] The system 300 may comprise a biomass feedstock unit 311 configured to supply feedstock to a biomass dryer 312. In some instances, the biomass dryer 312 may be thermally coupled to a pyrolysis reactor 313, wherein waste heat from the turbine 313 may be utilized to dry and pyrolyze the incoming feedstock. The pyrolysis reactor 313 may be configured to convert the biomass feedstock into volatile organic compounds (VOCs) and a stable solid pyrolysis product 314.

[0269] In some embodiments, the system 300 may comprise a combustor (COMB) 304 configured to receive the VOCs from the pyrolysis process. The system may further comprise a gas exchange recuperator 306 configured to manage oxygen (O2) input via port 310 and carbon dioxide (CO2) output via port 308. The system 300 may further comprise a heat rejection heat exchanger 305 configured to manage thermal conditions within the system. A water separator 309 may be provided to remove water (H2O) from the working fluid stream.

[0270] For example, the feedstock may be dried and pyrolyzed using turbine exit heat, wherein the pyrolyzed feedstock may be converted into volatile organic compounds for fueling the power cycle and a solid stable carbon byproduct for carbon sequestration.

[0271] In some instances, the CO2 captured in the power cycle may also be directed to various carbon utilization pathways — such as mineralization (e.g., concrete curing), enhanced oil recovery, hydrocarbon-fuel production, or chemical synthesis — or stored via geological or rock-injection methods. For example, by recirculating heat from the turbine exhaust, this integrated pyrolysis approach utilizes otherwise wasted thermal energy to process biomass while concurrently generating power and capturing or repurposing carbon. Biomass may be processed by a gasifier, pyrolyzer, or anaerobic digester (AD).

[0272] In some instances, the volatized fuel may be passively ingested due to the sub- atmospheric cycle pressure, thereby eliminating the need for a resolute fuel booster. The system 300 may be configured to operate in a semi-closed cycle wherein the working fluid may be recirculated through the various components while maintaining sub-atmospheric operating conditions throughout the cycle. Multiple fluid pathways, indicated by numbered connection points (l)-(8), may be provided to direct and control the flow of working fluid, volatile organic compounds, oxygen, and carbon dioxide throughout the system.

[0273] FIG. 4 shows an example of a temperature-time diagram 400 that may illustrate pyrolysis integration characteristics of the system. The system may comprise a temperature axis 401 and a time axis 402, wherein the time axis 402 may extend from seconds to months. In some embodiments, The system 400 may comprise multiple regions demarcated by temperature profiles 403, 404.

[0274] In some instances, a first temperature profile 405 may indicate fast pyrolysis conditions, which may occur within seconds or minutes at temperatures approaching 900°C. A second region 406 may comprise a slow pyrolysis zone, which may occur over longer time periods of hours to days. A third region 407 may indicate conditions for biochar formation above a particular temperature threshold.

[0275] In some embodiments, The system 400 may illustrate how turbine exit conditions may be configured to match pyrolysis requirements. For example, the heat from turbine outlet temperatures may be utilized to dry and pyrolyze incoming feedstock within seconds or minutes. In some instances, this configuration may provide a continuous and self-sustaining pretreatment / fueling process.

[0276] The system 400 may further comprise regions indicating conditions for biochar activation or gasification with steam and air, which may occur at temperatures approaching 900°C. In some embodiments, the temperature-time relationships illustrated in FIG. 4 may be configured to optimize the formation of biochar while maintaining efficient system operation. The torrefaction region may be indicated below the slow pyrolysis zone, occurring at lower temperatures over extended time periods.

[0277] FIG. 5 shows an example of a semi-closed biomass-fueled sub-atmospheric Brayton power system 500. The system 500 may comprise a cycle recuperator 501 configured to exchange heat between various streams within the system.

[0278] In some instances, the system 500 may comprise a compressor 502 configured to compress gas streams. The compressor 502 may be mechanically coupled to a generator 507, which may be configured to generate about 4 MW of electrical power in some embodiments.

[0279] The system 500 may further comprise a turbine 503 configured to expand gas streams to generate mechanical power. In some instances, the turbine 503 may be configured to provide waste heat for biomass processing.

[0280] In some cases, the system 500 may comprise a combustor 504 configured to combust volatile organic compounds (VOCs) generated from biomass processing. The combustor 504 may be configured to operate with a feedstock dryer 510 and a pyrolysis reactor 511, wherein the feedstock dryer 510 may be configured to receive biomass feedstock and the pyrolysis reactor 511 may be configured to convert dried biomass into VOCs and solid pyrolysis product.

[0281] The system 500 may comprise several heat exchangers, including a heat rejection heat exchanger 505 and a gas exchange recuperator 506. These heat exchangers may be configured to manage thermal energy within the system. In some instances, an ILO removal unit 508 may be configured to remove water from the gas streams.

[0282] Additionally, the system 500 may comprise an air inlet 509 configured to provide oxygen for combustion. The system may be configured such that volatized fuel is passively ingested due to sub-atmospheric cycle pressure, which may eliminate the need for a resolute fuel booster.

[0283] In some embodiments, the pyrolysis reactor 511 may be configured to generate two primary products: VOCs that may be used to fuel the power cycle, and a solid stable carbonbyproduct 513. The VOCs may be directed to the combustor 504, while the solid pyrolysis product 513 may be collected separately.

[0284] The numbered flow paths (1-8) shown in FIG. 5 may indicate the movement of various process streams through the system components. For example, flow path (7) may direct VOCs from the pyrolysis reactor 511 to the combustor 504, while flow path (5) may direct exhaust gases from the turbine 503.

[0285] In this way, the system 500 may integrate the compressor 502, turbine 503, combustor 504, and various heat exchangers with biomass processing equipment to create a self- sustaining power generation cycle that may also produce stable carbon byproducts. The sub- atmospheric operation may provide passive fuel ingestion while the waste heat integration may support efficient biomass processing operations.

[0286] FIG. 6 shows an example of an un-recuperated semi-closed sub-atmospheric Brayton power system 600. In some instances, the system 600 may be configured to maximize heat recovery for applications such as steam boiling.

[0287] The system 600 may comprise a compressor 601 configured to compress gas streams. In some cases, the compressor 601 may be mechanically coupled to a generator 606, which may be configured to generate about 4 MW of electrical power.

[0288] In some instances, the system 600 may comprise a turbine 602 configured to expand gas streams to generate mechanical power. The turbine 602 may be configured to provide waste heat that may be utilized for biomass processing and other heat recovery applications.

[0289] The system 600 may further comprise a combustor 603 configured to combust volatile organic compounds (VOCs) generated from biomass processing. In some embodiments, the system may comprise a heat recovery system 604 configured to capture and utilize waste heat from the process streams. The heat recovery system 604 may be configured to maximize heat recovery by eliminating the need for a recuperator.

[0290] In some cases, the system 600 may comprise a gas exchange recuperator 605 configured to manage thermal energy exchange between process streams. The system may further comprise an H2O removal unit 608 configured to remove water from the gas streams, and an oxygen (O2) inlet 609 configured to provide oxygen for combustion.

[0291] The system 600 may comprise a feedstock dryer 610 configured to receive and dry biomass feedstock, and a pyrolysis reactor 611 configured to convert the dried biomass intoVOCs and solid pyrolysis product. In some instances, the pyrolysis reactor 611 may be configured to generate two primary products: VOCs that may be used to fuel the power cycle, and a solid stable carbon byproduct 613.

[0292] Additionally, the system 600 may comprise a CO2 collection system 607 configured to capture and process CO2 from the exhaust stream. The numbered flow paths (1-8) shown in FIG. 6 may indicate the movement of various process streams through the system components. For example, flow path (7) may direct VOCs from the pyrolysis reactor 611 to the combustor 603.

[0293] In this way, the system 600 may integrate the compressor 601, turbine 602, combustor 603, and heat recovery system 604 to create an efficient power generation cycle that may maximize heat recovery for applications such as steam generation. The elimination of the recuperator may allow for enhanced heat recovery capabilities while maintaining the benefits of sub-atmospheric operation, such as passive fuel ingestion and efficient biomass processing.

[0294] FIG. 7 shows an example of a natural gas-fueled un-recuperated semi-closed sub- atmospheric Brayton power system 700. The system 700 may be configured to maximize heat recovery while utilizing natural gas as a primary fuel source.

[0295] In some instances, the system 700 may comprise a compressor 701 configured to compress gas streams. The compressor 701 may be mechanically coupled to a generator 706, which may be configured to generate about 4 MW of electrical power.

[0296] The system 700 may comprise a turbine 702 configured to expand gas streams to generate mechanical power. In some cases, the turbine 702 may be configured to provide exhaust heat that may be captured for heat recovery applications such as steam generation.

[0297] In some embodiments, the system 700 may comprise a combustor 703 configured to combust natural gas (Nat Gas) in the presence of oxygen. The system may further comprise a heat recovery system 704 configured to capture and utilize waste heat from the process streams. The heat recovery system 704 may be configured to maximize heat recovery by operating without a recuperator.

[0298] The system 700 may comprise a gas exchange recuperator 705 configured to manage thermal energy exchange between process streams. Additionally, the system may comprise an H2O removal unit 708 configured to remove water from the gas streams, and an oxygen (02) inlet 709 configured to provide oxygen for combustion.-n-

[0299] In some instances, the system 700 may comprise a CO2 collection system 707 configured to capture and process CO2 from the exhaust stream. The numbered flow paths (1-8) shown in FIG. 7 may indicate the movement of various process streams through the system components. For example, flow path (7) may direct natural gas to the combustor 703, while flow path (5) may direct exhaust gases from the turbine 702.

[0300] In this way, the system 700 may integrate the compressor 701, turbine 702, combustor 703, and heat recovery system 704 to create an efficient power generation cycle optimized for heat recovery applications. The elimination of the recuperator may allow for enhanced heat recovery capabilities while maintaining the benefits of sub-atmospheric operation. In some embodiments, this configuration may be particularly suited for applications requiring substantial heat output, such as industrial steam generation, while simultaneously providing carbon dioxide capture from natural gas combustion.

[0301] FIG. 8 shows an example of a high-level system workflow diagram 800 illustrating a sub-atmospheric oxy-fuel combustion process for cogeneration and carbon capture. The system 800 is arrayed in multiple interconnected process blocks, including a fuel input block 801, a central process block 802, a CO2 utilization block 803, and a sequestration block 804.

[0302] Fuel input block 801 may receive a wide range of hydrocarbon feedstocks — such as natural gas, pyrolysis vapors, or biogas from anaerobic digestion (AD) — and optionally a modestly enriched oxygen stream. The central process block 802 operates at sub-atmospheric pressures using a recirculated CO2 working fluid to combust the incoming fuel. This arrangement produces heat, power, and a highly concentrated CO2 exhaust suitable for downstream capture.

[0303] In the illustrated workflow, the captured CO2 may be routed to either the CO2 utilization block 803 (e.g., methanol synthesis, enhanced oil recovery, or mineralization processes) or the sequestration block 804 (e.g., geologic or rock injection for long-term storage). FIG. 8 thereby exemplifies a flexible architecture for both power generation and low-carbon or net-negative emissions, without necessarily requiring a large onsite oxygen supply. An air separation unit or pipeline oxygen may be used, but the workflow does not assume close-coupling with an industrial O2 producer.

[0304] FIG. 9 shows an example of a system 900 for generating power and capturing carbon dioxide. The system 900 may comprise a combustor 901 configured to receive inputs from a fuel source 912 and an oxygen source 911.

[0305] In some instances, the system 900 may comprise a gas exchanger 910 configured to receive oxygen from the oxygen source 911 and exchange heat with a CO2 stream 904. The gas exchanger 910 may be configured to provide a preheated oxygen stream to the combustor 901.

[0306] In some cases, the system 900 may comprise a turbine 905 configured to receive combustion products from the combustor 901. The turbine 905 may be configured to expand the combustion products to generate mechanical energy. As an example, the turbine 905 may be coupled to a generator 907 via connection 908 for converting the mechanical energy to electrical power 902.

[0307] Additionally, the system 900 may comprise a heat recovery unit 906 configured to receive expanded gases from the turbine 905. In some instances, the heat recovery unit 906 may be configured to extract thermal energy to provide heat output 903. The heat recovery unit 906 may also be configured to condense and separate water 906 from the gas stream.

[0308] In some cases, the system 900 may comprise a compressor 909 configured to receive cooled gases from the heat recovery unit 906. The compressor 909 may be configured to compress the gases and provide them to the gas exchanger 910, where a portion may be extracted as the CO2 stream 904. For example, in operation, fuel from source 912 and oxygen from source 911 may be combusted in combustor 901 to generate a CCh-rich working fluid. This working fluid may drive the turbine 905 to generate power 902 while also providing heat recovery 903 and CO2 capture 904. In this way, the system 900 may integrate power generation, heat recovery, and carbon capture functionalities into a unified process.

[0309] FIG. 10 shows an example of a closed loop bioenergy system 1000 configured for carbon capture and utilization. The system 1000 may comprise a gasifier, pyrolyzer, or anaerobic digester (AD) 1001 configured to process biomass feedstock into biogenic syngas.

[0310] In some instances, the system 1000 may comprise a power generation unit 1002 configured to receive the biogenic syngas from the gasifier, pyrolyzer, or anaerobic digester (AD) 1001. The power generation unit 1002 may be configured to generate multiple outputs including heat, power, and carbon dioxide (CO2). Additionally, the power generation unit 1002 may be configured to separate water (H2O) as a byproduct of the process.

[0311] In some cases, the system 1000 may comprise a utilization unit 1003 configured to receive at least a portion of the CO2 output from the power generation unit 1002. Theutilization unit 1003 may be configured to process the CO2 for use in low-carbon energy products.

[0312] Additionally, the system 1000 may comprise a sequestration unit 1004 configured to receive at least a portion of the CO2 output from the power generation unit 1002. The sequestration unit 1004 may be configured to provide long-term storage of the captured CO2.

[0313] For example, in operation, biomass may be gasified or pyrolyzed in unit 1001 to generate biogenic syngas. The biogenic syngas may be fed to the power generation unit 1002, which may produce heat for onsite, local, or district use, electrical power for distribution, and a CO2 stream for capture. The captured CO2 may then be directed to either the utilization unit 1003 for conversion into low-carbon energy products or to the sequestration unit 1004 for permanent storage. In this way, the system 1000 may integrate bioenergy production with carbon capture and management functionalities in a closed loop configuration.

[0314] FIG. 11 shows an example of a biomass-based carbon capture and sequestration system 1100. The system 1100 may comprise a gasifier, pyrolyzer, or anaerobic digester (AD) 1101 configured to process biomass feedstock into biogenic syngas.

[0315] In some instances, the system 1100 may comprise a power generation unit 1102 configured to receive the biogenic syngas from the gasifier, pyrolyzer, or anaerobic digester (AD) 1101. The power generation unit 1102 may be configured to generate multiple outputs including heat, power, and carbon dioxide (CO2). Additionally, the power generation unit1102 may be configured to separate water (H2O) as a byproduct of the process.

[0316] In some cases, the system 1100 may comprise a direct air capture unit 1103 configured to receive heat from the power generation unit 1102. The direct air capture unit1103 may be configured to capture CO2 directly from the atmosphere using excess heat from the power generation process. In some instances, the direct air capture unit 1103 may be configured to provide an additional CO2 output stream.

[0317] Additionally, the system 1100 may comprise a rock injection unit 1104 configured to receive CO2 from both the power generation unit 1102 and the direct air capture unit 1103. The rock injection unit 1104 may be configured to inject the CO2 into rock formations for long-term storage of at least about 1,000 years. For example, in operation, biomass may be gasified or pyrolyzed in unit 1101 to generate biogenic syngas. The biogenic syngas may be fed to the power generation unit 1102, which may produce heat and power for onsite use, including powering the direct air capture unit 1103. The CO2 streams from both the powergeneration unit 1102 and direct air capture unit 1103 may be directed to the rock injection unit 1104 for permanent storage in rock formations. In this way, the system 1100 may integrate bioenergy production with both point-source and direct air capture of CO2 for permanent geological sequestration.

[0318] In some embodiments, the system comprises at least one sub-atmospheric oxy-fuel combustor. In some cases, the at least one sub-atmospheric oxy-fuel combustor comprises at least one combustion chamber configured to operate at pressures below about 1 bar or up to about 2 bar, although other suitable pressures may be used. In some instances, the at least one combustion chamber comprises a swirl-stabilized zone for mixing a hydrocarbon feedstock with oxygen at concentrations of at least about 30% O2. In some cases, the at least one sub- atmospheric oxy-fuel combustor comprises at least one dilution or recirculation subsystem that reintroduces carbon dioxide (CO2) to moderate flame temperatures. In some instances, the at least one dilution or recirculation subsystem comprises a return line directing C Ch-rich exhaust back into the combustor inlet. For example, the at least one sub-atmospheric oxy-fuel combustor may be configured to maintain near-stoichiometric combustion while achieving high CO2 purity in the exhaust stream. As an example, the resulting low-pressure operation may permit the use of standard-grade alloys for the combustor walls and burners.

[0319] In some embodiments, the system comprises at least one oxygen supply interface. In some cases, the at least one oxygen supply interface comprises at least one inlet manifold configured to deliver an oxygen-rich gas comprising at least about 30% O2, up to substantially pure oxygen (e.g., 90-100% O2). In some instances, the at least one inlet manifold comprises flow control valves that regulate oxygen flow into the combustor to maintain near-stoichiometric conditions. In some cases, the at least one oxygen supply interface comprises at least one heat exchanger that preheats the incoming oxygen using hot CO2 or turbine exhaust. In some instances, the at least one heat exchanger comprises a counterflow plate-fin configure, raising oxygen temperature by at least about 50°C prior to combustion. For example, the at least one oxygen supply interface may be configured to minimize nitrogen dilution in the system, thereby enhancing the purity of the captured CO2. As an example, the system may incorporate an industrial by-product O2 feed or electrolysis- derived O2 without requiring a standalone air separation unit.

[0320] In some embodiments, the system comprises at least one anaerobic digestion (AD) integration for wet biomass feedstocks. In some cases, the at least one anaerobic digestion integration comprises at least one biogas inlet that supplies a methane-rich stream (e.g., 50-70% CH4by volume) to the sub-atmospheric oxy-fuel combustor. In some instances, the at least one biogas inlet comprises a moisture removal or scrubbing unit to reduce unwanted contaminants or sulfur compounds prior to combustion. In some cases, the at least one anaerobic digestion integration comprises at least one digestate handling subsystem that collects residual solids for potential soil amendment or further processing. In some instances, the at least one digestate handling subsystem comprises a sealed container to prevent oxidation of stored carbon. For example, the anaerobic digestion feedstock option may be configured to facilitate negative-carbon or near-zero-carbon operation when combined with CO2 capture in the disclosed cycle. As an example, the use of AD-derived biogas may eliminate the need for a high-pressure fuel booster since the sub-atmospheric combustor passively draws in fuel at moderate or slightly below-atmospheric pressures.

[0321] In some embodiments, the system comprises at least one turbine configured to expand a CCh-rich exhaust gas. In some cases, the at least one turbine comprises at least one multistage expansion section operating at moderate inlet pressures up to about 10 bar, although other suitable pressures may be used. In some instances, the at least one multi-stage expansion section comprises rotating blades formed from standard-grade alloys such as stainless steel or nickel -based alloys suitable for temperatures below about 1000°C. In some cases, the at least one turbine comprises at least one mechanical shaft shared with a compressor or generator. In some instances, the at least one mechanical shaft comprises direct drive at about 3600 rpm, allowing synchronous power generation. For example, the at least one turbine may be configured to drive a generator that produces power while lowering the exhaust gas pressure down to sub-atmospheric levels. As an example, the system may harness the expanded CO2 for subsequent compression and sequestration without requiring a separate booster.

[0322] In some embodiments, the system comprises at least one CO2 compressor configured to raise the pressure of an exhaust gas comprising carbon dioxide (CO2) to no greater than about 73.9 bar, although other pressures may be used in different embodiments. In some cases, the at least one CO2 compressor comprises at least one radial or axial stage for sub- atmospheric inlet conditions. In some instances, the at least one radial or axial stage comprises a variable inlet guide vane mechanism to stabilize flow across varying loads. In some cases, the at least one CO2 compressor comprises at least one intercooler to remove heat during intermediate compression steps. In some instances, the at least one intercooler comprises a shell-and-tube heat exchanger that cools the partially compressed CO2. Forexample, the CO2 compression pathway may be configured to route a portion of the compressed CO2 back to the combustor for temperature moderation, while another portion is diverted for sequestration or utilization. As an example, the partial recirculation helps maintain a high CO2 concentration in the combustor while reducing the need for a separate air separation process.

[0323] In some embodiments, the system comprises at least one pyrolysis reactor for lignocellulosic biomass (e.g., wood chips, agricultural residues). In some cases, the at least one pyrolysis reactor comprises at least one rotary kiln or auger-based chamber configured to operate between about 400°C and about 600°C, although other suitable temperatures may be used. In some instances, the at least one rotary kiln comprises a residence time control that determines the yield of volatiles and char. In some cases, the at least one pyrolysis reactor comprises at least one heat recovery loop connected to turbine exhaust, providing necessary thermal energy for biomass drying or pyrolysis. In some instances, the at least one heat recovery loop comprises a small recuperator or direct gas-to-solid heat exchange. For example, the system may be configured to convert lignocellulosic feedstock into volatile organic compounds (VOCs) for combustion in the sub-atmospheric oxy-fuel combustor, while the remaining char is collected for carbon sequestration or further usage. As an example, the resulting negative-carbon approach arises when char is stably stored or applied to soil amendments.

[0324] In some embodiments, the system comprises at least one char handling subsystem. In some cases, the at least one char handling subsystem comprises at least one sealed hopper or silo configured to receive pyrolysis char at elevated temperatures. In some instances, the at least one sealed hopper or silo comprises an inert atmosphere or low-oxygen environment that minimizes oxidation of the stored char. In some cases, the at least one char handling subsystem comprises at least one conveyor or feeder that transfers char to a packaging station for long-term storage or soil application. In some instances, the at least one conveyor or feeder comprises a screw auger allowing controlled discharge rates. For example, the char handling subsystem may be configured to collect carbon-rich solids for negative-carbon pathways, thereby enhancing overall carbon capture beyond gaseous CO2. As an example, stable storage of char for months or years sequesters carbon that may otherwise return to the atmosphere.

[0325] In some embodiments, the system comprises at least one heat exchanger network configured to manage temperature flows among the combustor, turbine, and feedstockprocessing units. In some cases, the at least one heat exchanger network comprises at least one recuperator that transfers heat from turbine exhaust to the compressor outlet or incoming oxygen stream. In some instances, the at least one recuperator comprises plate-fin elements capable of handling CCh-rich gas at about 0.5-5 bar. In some cases, the at least one heat exchanger network comprises at least one secondary exchanger configured to provide steam, hot water, or drying capability for biomass feed. In some instances, the at least one secondary exchanger comprises shell-and-tube coils receiving heat from 800-950 K gas streams. For example, the heat exchanger network may be configured to maximize energy utilization within the sub-atmospheric cycle, thereby increasing overall process efficiency. As an example, the system may divert partially cooled gases to a pyrolysis reactor or anaerobic digestion preheater, further improving net carbon capture.

[0326] In some embodiments, the system comprises at least one control system for dynamic load-following. In some cases, the at least one control system comprises at least one PLC or distributed control module that monitors real-time signals for turbine speed, combustor temperature, and oxygen flow. In some instances, the at least one PLC or distributed control module comprises PID or advanced process controllers tuned to maintain stoichiometric or near-stoichiometric combustion. In some cases, the at least one control system comprises at least one HMI (human-machine interface) for operator oversight and parameter adjustment. In some instances, the at least one HMI comprises graphical dashboards displaying CO2 purity, turbine power output, and feedstock flow rates. For example, the load-following control system may be configured to modulate oxygen and fuel injection in real time, ensuring that the sub-atmospheric oxy -fuel cycle may rapidly respond to changes in power demand. As an example, the system may maintain stable CO2 capture rates and minimize unburned hydrocarbons despite large load swings.

[0327] In some embodiments, the system comprises at least one sequestration or utilization interface for the compressed CO2 stream. In some cases, the at least one sequestration or utilization interface comprises at least one pipeline connection delivering CO2 at about 5-10 bar, although other suitable pressures may be used. In some instances, the at least one pipeline connection comprises flow meters and sampling ports to confirm CO2 purity exceeding about 90-99%. In some cases, the at least one sequestration or utilization interface comprises at least one EOR (enhanced oil recovery) injection line or geological injection well. In some instances, the at least one EOR injection line comprises downhole equipment rated for 15-30 MPa pressures. For example, the system may be configured to split the CO2flow, sending one portion to a mineralization unit (e.g., rock injection or green concrete curing) and another portion to a pipeline for EOR. As an example, the system may provide multiple CO2 off-takers, providing operational flexibility and revenue from diverse carbon markets.

[0328] In some embodiments, the system comprises parallel sub-atmospheric oxy-fuel modules. In some cases, the parallel modules each include at least one small-scale turbine, one combustor, and one compressor on a shared shaft. In some instances, the parallel modules are arrayed in a daisy-chain formation, each generating about 2-6 MWe. In some cases, the parallel modules collectively supply 10-50 MWe to industrial facilities while capturing CO2. In some instances, the parallel configuration comprises interconnected CO2 lines allowing consolidated compression or sequestration streams. For example, each module may be configured to operate independently or in tandem to accommodate variable loads. As an example, the system may start or stop individual modules to match seasonal or real-time power demands without requiring a single large-scale plant.

[0329] FIG. 13 shows an example of a Brayton power system 1300 that is closely integrated with an abundant oxygen source, such as an ammonia production facility, hydrogen production via electrolysis, or another industrial site generating high-purity O2. A fuel input 1301 (e.g., hydrocarbon feedstock such as natural gas, upgraded biogas, or syngas from pyrolysis or AD) is combusted in a sub-atmospheric oxy-fuel environment within a central module 1302, which recirculates CO2 and operates at turbine inlet temperatures near 900°C. By leveraging the readily available oxygen, system 1300 avoids the need for an expensive air separation unit.

[0330] The near-pure CO2 exhaust may be directed to utilization unit 1303 — for instance, green methanol synthesis, enhanced oil recovery (EOR), or mineralization — or to a sequestration unit 1304 for permanent geological storage. Multiple parallel modules (1302a, 1302b, etc.) may be added to match higher power demands while sharing the same abundant O2 source. Additionally, the system harnesses waste heat for steam generation, biomass drying, or feedstock preheating, thereby achieving an overall thermal efficiency of about 20- 60%. In certain embodiments, the local O2 supply, combined with sub-atmospheric turbine operation, providing cost-effective negative-carbon pathways if the feedstock is biogenic

[0331] FIG. 14 shows an example of a natural gas-based power generation system 1400 configured for carbon capture. The system 1400 may comprise a natural gas input unit 1401configured to supply hydrocarbon fuel to a power generation unit 1402. In some instances, the power generation unit 1402 may comprise a sub-atmospheric oxy-fuel combustion turbine utilizing recirculated CO2 as a working fluid.

[0332] In some embodiments, the power generation unit 1402 may be configured to produce multiple outputs, including heat for onsite or district use, electrical power configurable for grid connection, and a near-pure CO2 stream. The unit 1402 may operate at temperatures around 900°C using standard alloys and may run at approximately 3600 RPM, thereby eliminating the need for a gearbox or additional power electronics. For example, each unit 1402 may be configured to generate about 4 MW of electrical output. As an example, multiple units 1402 may be arrayed in a daisy-chain configuration to scale total system output.

[0333] The system 1400 may further comprise a utilization pathway 1403 and a sequestration pathway 1404 configured to receive CO2 from the power generation unit 1402. In some cases, the utilization pathway 1403 may direct CO2 to merchant markets, green concrete production, methanol synthesis, enhanced oil recovery, or sustainable aviation fuel production. In some instances, the sequestration pathway 1404 may comprise enhanced rock weathering, Class VI well injection, green cement production, or enhanced oil recovery operations. For example, each unit 1402 may be configured to capture approximately 15,000 tons of CO2 annually.

[0334] The power generation unit 1402 may also produce water (H2O) as a byproduct, which may be separated from the CO2 stream prior to utilization or sequestration. In this way, the system 1400 may integrate power generation with carbon capture while eliminating the need for a separate air separation unit.

[0335] FIG. 15 shows an example of a biogenic gas power generation system 1500 configured for carbon capture. The system 1500 may comprise a biogenic gas input unit 1501 configured to receive gas from a pyrolyzer, gasifier, anaerobic digester, calciner, or other biomass processing unit.

[0336] In some embodiments, the power generation unit 1502 may be configured similarly to unit 1402 of FIG. 14, but optimized for biogenic gas feedstock. The unit 1502 may comprise a sub-atmospheric oxy-fuel combustion turbine utilizing recirculated CO2 as a working fluid. In some instances, multiple units 1502 may be arrayed in parallel to scale the total system output, allowing a flexible modular configure. The unit 1502 may operate at about 900°C under sub-atmospheric conditions, reducing the need for high-grade alloys and allowing theuse of standard materials. In some cases, the system 1500 may also be integrated with external oxygen sources, such as electrolyzers, thereby eliminating the need for a separate air separation unit. When operating with biogenic feedstock, each unit 1502 may capture approximately 37,000 tons of CO2 annually.

[0337] The system 1500 may further comprise a utilization pathway 1503 and a sequestration pathway 1504. In some cases, the “green” CO2 captured from biogenic sources may qualify for additional environmental credits or incentives compared to fossil-derived CO2. For example, when combined with biochar production, the system 1500 may achieve net-negative carbon emissions. The power generation unit 1502 may also produce water (H2O) as a byproduct, which may be separated from the CO2 stream prior to utilization or sequestration.

[0338] In some embodiments, the system 1500 may be integrated with agricultural or forestry operations to process biomass waste streams, simultaneously generating power while capturing biogenic carbon for long-term storage or utilization. Additionally, waste heat from the turbine exhaust may be employed for biomass drying or preheating, supporting overall system efficiencies of about 20% to about 60%.

[0339] FIG. 16 shows an example of a power generation system 1600 configured for geological carbon sequestration. The system 1600 may comprise a gas input unit 1601 configured to supply hydrocarbon fuel to a power generation unit 1602. The gas input may comprise natural gas, biogas, biogenic gas, or other suitable hydrocarbon feedstocks.

[0340] In some embodiments, the power generation unit 1602 may produce heat and power outputs while capturing CO2 from the combustion process. The unit 1602 may operate as a sub-atmospheric oxy-fuel combustion turbine utilizing recirculated CO2 as a working fluid. Water (H2O) may be separated as a byproduct from the CO2 stream.

[0341] The system 1600 may comprise a well injection unit 1603 configured to receive the captured CO2. In some instances, the well injection unit 1603 may be configured for rock injection or Class VI well sequestration. For example, the CO2 may be compressed and injected into suitable geological formations for permanent storage. In some cases, the geological formations may comprise basalt, mafic, ultramafic, or anhydrite rock types selected for their CO2 storage capacity and stability.

[0342] FIG. 17 shows an example of a power generation system 1700 configured for enhanced oil recovery (EOR). The system 1700 may comprise a gas input unit 1701 configured to supply hydrocarbon fuel to a power generation unit 1702.

[0343] In some embodiments, the power generation unit 1702 may be configured to produce heat and power outputs while capturing CO2 from the combustion process. The unit 1702 may operate as a sub-atmospheric oxy -fuel combustion turbine utilizing recirculated CO2 as a working fluid. Water (H2O) may be separated as a byproduct.

[0344] The system 1700 may comprise a well injection unit 1703 specifically configured for EOR operations. In some instances, the well injection unit 1703 may receive both the captured CO2 and heat outputs from unit 1702. The heat output may be utilized for base heating or steam flooding applications in the EOR process, while the CO2 may be injected for enhanced hydrocarbon recovery. For example, about 1 ton of CO2 may be sequestered for every 3 barrels of oil recovered through the EOR process.

[0345] FIG. 18 shows an example of a power generation system 1800 configured for CO2 mineralization. The system 1800 may comprise a gas input unit 1801 configured to receive stranded gas or natural gas liquids, and a power generation unit 1802 configured to produce heat, power, and captured CO2.

[0346] In some embodiments, the system 1800 may comprise a mineralization partner unit 1803 configured to receive both CO2 and heat outputs from unit 1802. The mineralization partner unit 1803 may be configured for ex-situ mineralization, in-situ mineralization, enhanced rock weathering, or cement / concrete carbonation processes. In some cases, the heat output may be utilized to enhance mineralization reaction kinetics. For example, the mineralization partner unit 1803 may inject CO2 into suitable rock formations for permanent storage through mineral carbonation reactions. In some instances, the CO2 may be used to produce low-carbon building materials through mineralization in concrete or cement products.

[0347] FIG. 19 shows an example of a power generation system 1900 configured for chemical and fuel production. The system 1900 may comprise a gas input unit 1901 configured to receive stranded gas or natural gas liquids, and a power generation unit 1902 configured to produce heat, power, and captured CO2.

[0348] In some embodiments, the system 1900 may comprise a utilization partner unit 1903 configured to receive both CO2 and heat outputs from unit 1902. The utilization partner unit 1903 may be configured for various chemical processes including chemical looping, blue methanol production, or sustainable aviation fuel synthesis. In some instances, the heat output may be utilized to support endothermic chemical reactions or process heating requirements.For example, the utilization partner unit 1903 may combine the captured CO2 with hydrogen to produce methanol or other low-carbon fuels. In some cases, integration with nearby chemical facilities may provide efficient use of both the CO2 and thermal energy outputs for chemical production.

[0349] FIG. 20 shows an example of a methanol production system 2000. The system 2000 may comprise a gas input unit 2001 configured to receive gasified or pyrolyzed biomass- derived syngas, and a power generation unit 2002 configured to produce heat, power, CO2, and water outputs.

[0350] In some embodiments, the system 2000 may comprise an electrolyzer unit 2003 configured to receive heat and water outputs from unit 2002. The electrolyzer unit 2003 may be configured to produce hydrogen (H2) using power generated by unit 2002. A methanol loop unit 2004 may be configured to combine the H2 from the electrolyzer with captured CO2 to synthesize methanol.

[0351] In some instances, the methanol produced by system 2000 may be marketed as green methanol for maritime fuel applications. For example, the green methanol may be pre-sold through a Book and Claim Certificate system. The integration of biomass gasification / pyrolysis with electrolysis and methanol synthesis may provide production of low-carbon methanol using primarily renewable inputs.

[0352] FIG. 21 illustrates an example integration system 2100 configured to combine power generation with hydrogen production. The system 2100 includes a gas input 2101 configured to supply hydrocarbon fuel to a power generation unit 2102. In certain embodiments, the power generation unit 2102 may be configured to produce multiple outputs including heat, electrical power, and carbon dioxide (CO2). An electrolyzer 2103 may be arrayed to receive water (H2O) from the power generation unit 2102 and produce hydrogen (H2) as an output. In some instances, the electrolyzer 2103 may also supply oxygen (O2) back to the power generation unit 2102 in a closed-loop arrangement, as shown by the separate O2 line in FIG. 21. For example, O2 from the electrolyzer 2103 may be directed to an oxy-fuel combustor within the power generation unit 2102, while H2O is fed back to the electrolyzer. Although shown crossing or in close proximity in the schematic, the O2 and H2O lines are physically and operationally distinct.

[0353] In some embodiments, the power generation unit 2102 may comprise a sub- atmospheric oxy-fuel combustion system that uses the oxygen from the electrolyzer 2103 tocombust the hydrocarbon fuel from gas input 2101. In some cases, by relying on the electrolyzer’s oxygen output, the power generation unit 2102 may eliminate the need for a separate air-separation unit. In addition, the power generation unit 2102 may be configured to provide process heat (e.g., for pre-heating solid oxide electrolyzer cells) at temperatures suitable for efficient electrolysis.

[0354] The system 2100 may be configured to achieve operational synergies through the integration of the power generation unit 2102 with the electrolyzer 2103. For instance, waste heat from power generation may be routed to support electrolysis, and the oxygen stream from the electrolyzer may be used for oxy-fuel combustion. This closed-loop configuration allows for more efficient use of energy and material streams that may otherwise be discarded.

[0355] FIG. 22 shows an example of a carbon dioxide removal (CDR) system 2200. In this case, the system may comprise a biomass-to-syngas unit 2201 configured to receive biomass and produce biogenic syngas. As illustrated, unit 2201 may include processes for gasification, pyrolysis, or anaerobic digestion. In some instances, these processes may yield syngas with varying compositions of CO2, H2, CO, and other species. In some embodiments, the composition of the syngas may be altered based on feedstock type or operating conditions. In some cases, the unit 2201 may also generate byproducts such as char or digestate, which may be further utilized or sequestered.

[0356] As illustrated in FIG. 22, the biogenic syngas from unit 2201 may be directed into a central power block 2202. In some instances, the power block 2202 may be configured to combust the syngas to generate power, heat, and a CCh-rich exhaust. In some embodiments, the system may capture a portion of the exhaust for further processing. In some instances, the power block 2202 may also produce water (H2O) suitable for re-use or steam generation. As an example, variations in the composition of the biogenic syngas may lead to different ratios of heat, power, and CO2 output. In some cases, the power block 2202 may be tuned to accommodate a wide range of syngas qualities and flow rates.

[0357] In some cases, a direct air capture (DAC) unit 2203 may receive heat from the power block 2202 to drive sorbent regeneration or other DAC processes. In some embodiments, the DAC unit 2203 may intake atmospheric air and extract CO2 therefrom. In some instances, the DAC unit 2203 may also receive an additional CCh-laden stream from the power block 2202, thereby increasing total captured CO2. As an example, DAC configurations may vary in sorbent material or adsorption conditions, potentially impacting the overall energy demand.In some cases, the system may reconfigure flows so that only surplus heat from 2202 is used by 2203, thereby improving overall energy efficiency.

[0358] In some embodiments, a rock injection module 2204 may be configured to receive CO2 from both the power block 2202 and the DAC unit 2203. In some instances, the module 2204 may inject the CO2 into subsurface geological formations, such as basalt reservoirs, where mineralization may occur. In some cases, this rock injection pathway provides prolonged carbon storage. As an example, injection conditions may be optimized to promote stable, long-term sequestration. In some embodiments, additional equipment (e.g., compression or fluid handling systems) may condition the CO2 stream prior to injection.

[0359] In this way, the system 2200 integrates the biomass-to-syngas unit 2201, the power block 2202, the direct air capture unit 2203, and the rock injection module 2204 to yield a combined approach for power generation, CO2 capture, and sequestration. By leveraging both point-source and atmospheric CO2 capture, the overall arrangement may facilitate negativeemissions operation, improved net energy production, and flexible pathways for long-term carbon storage.

[0360] FIG. 23 shows an example of a companion integration for direct air capture (DAC) in a system 2300. In this case, the system may comprise a gas feed 2301 configured to supply one or more gaseous fuels (e.g., natural gas, biogas, syngas, or other suitable inputs). As illustrated, gas feed 2301 may interface with a core power block 2302. In some instances, the power block 2302 may be configured to combust or otherwise utilize the incoming gas to produce heat, power, and a CCh-laden stream. In some embodiments, the power block 2302 may also generate water (H2O), which may be directed for reuse within the system. In some cases, variations in the gas composition or flow rate may lead to different ratios of heat, power, and CO2.

[0361] As illustrated in FIG. 23, the system 2300 may include a DAC unit 2303. In some instances, the DAC unit 2303 may receive heat from the power block 2302, thereby providing sorbent regeneration or related processes for capturing CO2 from ambient air. In some embodiments, the DAC unit 2303 may also receive a partial CO2 stream from the power block 2302 to increase total capture. In some cases, the amount of CO2 directed to the DAC unit 2303 may vary based on energy availability, process demands, or other operational conditions. As an example, DAC unit 2303 may be configured with one or more adsorptiondesorption cycles optimized for the available heat level.

[0362] In this way, the system 2300 integrates a gas feed 2301, a power block 2302, and a DAC unit 2303 to achieve efficient CO2 capture from both process exhaust and atmospheric sources. By leveraging surplus heat from the power block 2302, the DAC unit 2303 may reduce its net energy requirements. As an example, captured CO2 from the system 2300 may be sequestered or otherwise utilized, providing a pathway toward reduced greenhouse gas emissions or negative-emissions operation. Any references to numeric or scalable parameters (e.g., flow rate, temperature, stoichiometric ratio) remain illustrative and non-limiting.

[0363] The following Table 1 is illustrative only and compares cost and performance metrics of conventional IC gensets and gas turbines (both using ASUs) against the proposed unrecuperated and recuperated system configurations.

[0364] Table 1 - Brief Cost and Performance Comparison of Proposed System vs.Conventional TechnologiesXVI. METHOD

[0365] In some embodiments, the method may comprise providing an oxygen-rich gas (O2). In some cases, the method may comprise configuring the oxygen concentration from about 30% to about 100% by volume (including sub-ranges such as about 30% to about 70%, or about 90% to about 99.5% for higher-purity demands). In some instances, the method may comprise using an adjustable oxygen feed to meet combustion requirements. For example, the method may comprise dynamically controlling oxygen purity based on system efficiency targets. As an example, the method may comprise supplying varying levels of oxygen concentration depending on fuel type or availability. The method may comprise accommodating flexible operation across different oxygen-availability conditions.

[0366] In some embodiments, the method may comprise providing the oxygen-rich gas at a concentration of O2 greater than about 90% by volume (e.g., about 90% to about 99.9%). In some cases, the method may comprise selecting substantially pure or high-purity oxygen to enhance combustion efficiency. In some instances, the method may comprise minimizing nitrogen presence in the combustor to reduce NOx formation. For example, the method may comprise sourcing high-purity oxygen from an industrial process such as cryogenic separation or water electrolysis. As an example, the method may comprise modifying the combustor configuration to optimize reaction with near-pure O2. The method may comprise improving CO2 capture purity by limiting other gases.

[0367] In some embodiments, the method may comprise sourcing the oxygen-rich gas as an output from an industrial process (e.g., ammonia production, hydrogen production, ethanol production, chemical looping, water electrolysis, or other industrial processes). In some cases, the method may comprise integrating the oxygen output stream directly into the combustor. In some instances, the method may comprise utilizing pre-existing industrialseparation that yields oxygen-rich off-gas. For example, the method may comprise connecting an ammonia production facility to the power generation system. As an example, the method may comprise routing oxygen from water electrolysis to the combustor. The method may comprise reducing external oxygen supply requirements by harnessing process by-products.

[0368] In some embodiments, the method may comprise coordinating production schedules, so the oxygen by-product is available when combustion demand is high. In some cases, the method may comprise balancing industrial process flow rates to match the power generation system. In some instances, the method may comprise storing intermediate oxygen if the industrial process produces surplus O2. For example, the method may comprise using buffer tanks to manage fluctuations. As an example, the method may comprise prioritizing real-time integration to minimize storage. The method may comprise promoting efficient resource utilization between the industrial process and the power cycle.

[0369] In some embodiments, the method may comprise using an oxygen-rich gas (e.g., about 30% O2 by volume). In some cases, the method may comprise feeding the oxygen-rich gas to a combustor without pre-separation. In some instances, the method may comprise tolerating higher nitrogen content in the exhaust. For example, the method may comprise allowing for simpler equipment at the cost of reduced CO2 purity. As an example, the method may comprise incorporating downstream CO2 purification if desired. The method may comprise simplifying system configuration by relying on ambient conditions.

[0370] In some embodiments, the method may comprise combusting a hydrocarbon feedstock with the oxygen-rich gas , thereby obtaining an exhaust gas comprising CO2. In some cases, the method may comprise expanding the exhaust gas in a turbine, thus producing power. In some instances, the method may comprise compressing at least a portion of the exhaust gas with some of the turbine-generated power, thereby obtaining compressed CO2 at a pressure no greater than about 73.9 bar (e.g., about 1 bar to about 10 bar, or narrower ranges such as 3 bar to 8 bar). For example, the method may comprise combining at least a portion of the compressed CO2 with additional oxygen, forming a combined gas. As an example, the method may comprise controlling the combined gas composition to facilitate power generation while capturing CO2 at moderate pressures. The method may comprise providing power production alongside CO2 capture.

[0371] In some embodiments, the method may comprise producing an exhaust gas with a CO2 concentration greater than about 90% by volume (for instance, 90% to about 98%). In some cases, the method may comprise adjusting oxygen feed rates or combustion stoichiometry to maximize CO2 concentration. In some instances, the method may comprise recycling CO2 in a semi-closed loop. For example, the method may comprise controlling temperature and pressure to reduce diluents like N2. As an example, the method may comprise operating near-stoichiometrically to limit excess air. The method may comprise enhancing overall carbon capture by maintaining high CO2 purity.

[0372] In some embodiments, the method may comprise generating an exhaust gas with a CO2 concentration greater than about 95% by volume (e.g., 95% to about 99.5%). In some cases, the method may comprise refining combustion conditions to minimize by-products (e.g., CO, NOx). In some instances, the method may comprise employing near-pure oxygen feeds to reduce nitrogen entry. For example, the method may comprise deploying gas cleanup units that remove trace contaminants. As an example, the method may comprise monitoring real-time gas composition to maintain strict CO2 purity targets. The method may comprise facilitating downstream sequestration or utilization of high-purity CO2.

[0373] In some embodiments, the method may comprise controlling the combustion such that unreacted hydrocarbon feedstock in the exhaust gas is less than about 1% by volume (e.g., below 0.5% or even 0.1%). In some cases, the method may comprise using precise flow control for both fuel and oxidant. In some instances, the method may comprise maintaining improved mixing and temperature in the combustor. For example, the method may comprise employing a monitoring sensor that detects unburned hydrocarbons. As an example, the method may comprise adjusting injection rates to ensure complete combustion. The method may comprise reducing fuel waste and ensuring cleaner exhaust.

[0374] In some embodiments, the method may comprise maintaining a sulfur oxides (SOx) concentration in the exhaust gas of less than about 1% by volume (possibly much lower, e.g., 0.1% or 100 ppm). In some cases, the method may comprise selecting low-sulfur feedstocks or applying desulfurization steps. In some instances, the method may comprise incorporating flue-gas cleaning to remove SOx. For example, the method may comprise adding sorbentbased processes downstream of combustion. As an example, the method may comprise controlling combustor temperature to reduce sulfur compound formation. The method may comprise providing emissions compliance by minimizing SOx output.

[0375] In some embodiments, the method may comprise keeping nitrogen oxides (NOx) below about 1% by volume (e.g., under 0.5% or 0.1%). In some cases, the method may comprise using low-NOx burners or staged combustion. In some instances, the method may comprise employing high-purity oxygen to reduce nitrogen sources. For example, the method may comprise implementing selective catalytic reduction (SCR) if needed. As an example, the method may comprise controlling flame temperature to moderate NOx formation. The method may comprise achieving cleaner emissions for stringent environmental standards.

[0376] In some embodiments, the method may comprise maintaining carbon monoxide (CO) levels at less than about 1% by volume (e.g., under 0.5% or 1000 ppm). In some cases, the method may comprise ensuring sufficient residence time for complete combustion. In some instances, the method may comprise tuning the stoichiometric ratio to avoid partial oxidation. For example, the method may comprise including an oxidation catalyst downstream. As an example, the method may comprise measuring CO content in real time and adjusting controls. The method may comprise producing a cleaner exhaust stream while boosting CO2 purity.

[0377] In some embodiments, the method may comprise generating exhaust gas that includes water vapor (H2O). In some cases, the method may comprise allowing steam to form naturally during combustion. In some instances, the method may comprise regulating humidity in the exhaust. For example, the method may comprise measuring dew point to optimize downstream condensation. As an example, the method may comprise collecting water vapor for possible reuse. The method may comprise utilizing steam content for energy recovery or cooling.

[0378] In some embodiments, the method may comprise removing at least a portion of the water from the exhaust gas prior to compression. In some cases, the method may comprise condensing moisture to improve compression efficiency. In some instances, the method may comprise lowering dew point through intercooling or a condenser. For example, the method may comprise passing exhaust gas through a moisture separator. As an example, the method may comprise using a dehydration unit or membrane separation. The method may comprise preventing compressor corrosion and reducing power load by controlling water content.

[0379] In some embodiments, the method may comprise ensuring H2O concentration in the exhaust gas prior to compression is less than about 10% by volume (e.g., 2% to 10% or even below 2%). In some cases, the method may comprise monitoring the exhaust gas withmoisture sensors. In some instances, the method may comprise adjusting cooling steps to achieve the desired fraction. For example, the method may comprise employing multi-stage condensation. As an example, the method may comprise recirculating cooled exhaust gas to dilute overall moisture. The method may comprise protecting downstream equipment by keeping residual water low.

[0380] In some embodiments, the method may comprise performing combustion in a combustor where the oxygen feed is stoichiometric for the hydrocarbon fuel. In some cases, the method may comprise sizing the combustor for complete reaction of available oxygen. In some instances, the method may comprise using precise flow meters to maintain the stoichiometric ratio. For example, the method may comprise automating oxygen and fuel injection for near-complete oxidation. As an example, the method may comprise verifying negligible CO or unburned hydrocarbons. The method may comprise optimizing energy output and reducing pollutants by accurate stoichiometry.

[0381] In some embodiments, the method may comprise ensuring high oxygen utilization — at least about 99% of the O2 in the feed is consumed. In some cases, the method may comprise employing high-efficiency burner configurations that promote near-total oxygen usage. In some instances, the method may comprise adjusting residence time and turbulence in the combustor. For example, the method may comprise controlling flame shape and mixing patterns. As an example, the method may comprise using real-time O2 sensors to modulate input flows. The method may comprise minimizing wasted oxygen and improving efficiency.

[0382] In some embodiments, the method may comprise performing stoichiometric combustion (matching the exact molar ratio of oxygen to fuel). In some cases, the method may comprise preventing excess oxygen from diluting the exhaust stream. In some instances, the method may comprise limiting surplus gas to enhance CO2 purity. For example, the method may comprise mitigating partial oxidation products by ensuring complete combustion. As an example, the method may comprise controlling oxygen injection with flow controllers. The method may comprise producing exhaust with minimal contaminants or unreacted species.

[0383] In some embodiments, the method may comprise compressing CO2 to form a compressed stream with CO2 greater than about 90% by volume (and up to 99.9% purity). In some cases, the method may comprise operating the compressor so that the final pressure is no greater than about 73.9 bar (e.g., about 3 bar to about 8 bar). In some instances, themethod may comprise removing non-CCh constituents prior to compression. For example, the method may comprise routing exhaust gas through a polishing unit. As an example, the method may comprise using a compressor configured for high-CCh-content gas. The method may comprise providing effective carbon capture with minimal impurities.

[0384] In some embodiments, the method may comprise compressing CO2, so the resulting stream has a concentration above about 95% or 99%. In some cases, the method may comprise fine-tuning upstream combustion conditions to limit impurities. In some instances, the method may comprise using scrubbing or adsorption to remove trace contaminants (e.g., sulfur or moisture). For example, the method may comprise employing multi-stage compression with intermediate cooling. As an example, the method may comprise controlling operating temperatures to minimize solubility of unwanted gases. The method may comprise facilitating high-purity CO2 for sequestration or utilization.

[0385] In some embodiments, the method may comprise ensuring the compressed CO2 is still at sub-atmospheric or near-atmospheric pressure (e.g., below 1 bar). In some cases, the method may comprise maintaining a vacuum for specialized processes. In some instances, the method may comprise adapting booster stages downstream if higher pressures are required. For example, the method may comprise configuration in a vacuum-based piping to reduce leaks. As an example, the method may comprise adjusting compression strategy for unique industrial needs. The method may comprise accommodating sub-atmospheric CO2 management when beneficial.

[0386] In some embodiments, the method may comprise performing the compressing step in a compressor mechanically coupled to the turbine on a common shaft. In some cases, the method may comprise using intercooling between stages to reduce compression work. In some instances, the method may comprise selecting impeller or blade geometry optimized for CO2. For example, the method may comprise drawing exhaust gas passively into the compressor via a pressure differential. As an example, the method may comprise operating at 1800-7200 rpm to match power availability. The method may comprise streamlining the mechanical layout for higher efficiency.

[0387] In some embodiments, the method may comprise forming a combined gas by adding additional oxygen to compressed CO2, ensuring O2 concentration is less than about 30% by volume (e.g., 5% to 25%). In some cases, the method may comprise balancing the ratio of compressed CO2 to oxygen. In some instances, the method may comprise preventing overlyrich oxygen streams that lead to high combustion temperatures. For example, the method may comprise managing partial pressures of CO2 and O2. As an example, the method may comprise using flow controls that maintain a stable mixture. The method may comprise optimizing performance while keeping safe conditions.

[0388] In some embodiments, the method may comprise configuring the combined gas to have at least about 50% CO2 by volume (e.g., 50% to 95%). In some cases, the method may comprise limiting the quantity of added O2. In some instances, the method may comprise using CO2 recirculation to moderate combustion intensity. For example, the method may comprise replacing nitrogen with CO2 as the diluent. As an example, the method may comprise reducing NOx formation by avoiding high N2 content. The method may comprise enhancing CO2 capture efficiency overall.

[0389] In some embodiments, the method may comprise preheating the oxygen-rich gas in a heat exchanger before combustion. In some cases, the method may comprise transferring heat from a hot exhaust stream to the incoming O2. In some instances, the method may comprise improving combustion efficiency by raising reactant temperature, for example from about 20 °C up to 500-600 °C. As an example, the method may comprise controlling the heat exchange rate with a recuperator. The method may comprise enhancing overall thermal efficiency by recovering waste heat.

[0390] In some embodiments, the method may comprise passing the compressed CO2 through a first heat exchanger to preheat additional oxygen prior to combining. In some cases, the method may comprise transferring thermal energy from hot CO2 to the cooler O2 stream. In some instances, the method may comprise adjusting flow rates to achieve an O2 outlet temperature of about 300 °C to about 600 °C. For example, the method may comprise using a counterflow configuration for efficient transfer. As an example, the method may comprise preventing oxygen degradation by limiting maximum temperatures. The method may comprise raising oxygen temperature to boost combustion efficiency.

[0391] In some embodiments, the method may comprise directing the oxygen-rich gas through a second heat exchanger after partial heating in the first. In some cases, the method may comprise achieving incremental temperature increases to match combustor requirements (e.g., final O2 temperature > 600 °C). In some instances, the method may comprise regulating flow distribution across multiple exchangers. For example, the method may comprise capturing waste heat from the turbine exhaust in each stage. As an example, the method maycomprise optimizing temperature profiles for stable combustion. The method may comprise refining reactant conditions for better system performance.

[0392] In some embodiments, the method may comprise combusting the combined gas (compressed CO2 + additional O2) with extra hydrocarbon feedstock, obtaining additional exhaust gas. In some cases, the method may comprise utilizing elevated temperatures of the combined gas to improve combustion kinetics. In some instances, the method may comprise feeding fuel into a secondary combustor. For example, the method may comprise producing an additional exhaust stream with high CO2 concentration for capture. As an example, the method may comprise controlling stoichiometry in this second combustion stage. The method may comprise enhancing total power generation via sequential combustion.

[0393] In some embodiments, the method may comprise directing the additional exhaust gas through a second heat exchanger so that it transfers heat to the incoming combined gas. In some cases, the method may comprise operating the heat exchanger in a counterflow mode to maximize thermal recovery. In some instances, the method may comprise cooling the additional exhaust to at most about 300 °C, condensing some water. For example, the method may comprise balancing flows to avoid excessive exhaust cooling. As an example, the method may comprise retaining usable heat for preheating reactants. The method may comprise integrating multiple heat exchange processes for compact configuration.

[0394] In some embodiments, the method may comprise expanding the additional exhaust gas in another turbine stage, producing extra power. In some cases, the method may comprise routing the second combustion output through a secondary expansion. In some instances, the method may comprise harvesting more power at elevated temperatures and pressures. For example, the method may comprise connecting multiple turbines in series for a combined cycle arrangement. As an example, the method may comprise adjusting expansion ratios based on real-time demand. The method may comprise boosting total power output and efficiency.

[0395] In some embodiments, the method may comprise performing combustion at a pressure below about 1.6 bar (e.g., 1.0-1.5 bar or even sub-atmospheric at 0.5-0.9 bar). In some cases, the method may comprise operating the combustor near or below atmospheric pressure. In some instances, the method may comprise using a vacuum pump or controlling turbine outlet pressures accordingly. For example, the method may comprise running the combustor at temperatures under about 1500 °C. As an example, the method may comprise managingflame conditions to avoid excessive thermal stress. The method may comprise optimizing low-pressure combustion for specialized or safer operation.

[0396] In some embodiments, the method may comprise maintaining a combustor temperature of less than about 1500 °C (e.g., 1000-1400 °C). In some cases, the method may comprise recirculating CO2 or using diluted oxygen. In some instances, the method may comprise selecting fuel injection modes that keep peak temperatures down. For example, the method may comprise avoiding high thermal NOx formation conditions. As an example, the method may comprise adjusting reactant flow in real time using temperature sensors. The method may comprise protecting combustor materials and extending equipment life.

[0397] In some embodiments, the method may comprise operating below about 1000 °C in the combustor (e.g., 700-900 °C for some low-temperature processes). In some cases, the method may comprise cooling or dilution to maintain a cooler flame. In some instances, the method may comprise precise stoichiometric control to limit heat release. For example, the method may comprise recirculating cool CO2 as a thermal sink. As an example, the method may comprise staging fuel injection to avoid localized hotspots. The method may comprise using standard alloys and reducing thermal stress.

[0398] In some embodiments, the method may comprise selecting hydrocarbon feedstock from natural gas, biogas, propane, methane, diesel, or any combination thereof. In some cases, the method may comprise accommodating multiple fuel types in a flexible combustion system. In some instances, the method may comprise adjusting burner or injector settings for each fuel’s characteristics. For example, the method may comprise calibrating ignition timing or stoichiometry for variable fuels. As an example, the method may comprise switching fuels based on availability or cost. The method may comprise ensuring robust configuration to manage common fuel sources.

[0399] In some embodiments, the method may comprise using biomass or a derivative thereof as the hydrocarbon feedstock. In some cases, the method may comprise converting lignocellulosic biomass into a combustible stream. In some instances, the method may comprise adapting the combustor to manage particulate or vaporized biofuel. For example, the method may comprise coping with ash or tars in the system. As an example, the method may comprise blending biomass-derived fuel with standard hydrocarbons. The method may comprise providing renewable or lower-carbon-intensity power.

[0400] In some embodiments, the method may comprise using one or more volatile organic compounds (VOCs) as the hydrocarbon feedstock. In some cases, the method may comprise capturing VOCs from industrial off-gases or biomass processing. In some instances, the method may comprise feeding VOCs directly into the combustor. For example, the method may comprise adjusting flame stability for low-molecular-weight VOCs. As an example, the method may comprise mixing VOCs with other fuels to maintain a consistent heat value. The method may comprise turning waste streams into a beneficial energy source.

[0401] In some embodiments, the method may comprise obtaining VOCs by drying and pyrolyzing biomass. In some cases, the method may comprise controlling pyrolysis temperature (e.g., 400-600 °C) and residence time. In some instances, the method may comprise recovering char for reuse or sequestration. For example, the method may comprise employing fast pyrolysis to maximize liquid or gaseous volatiles. As an example, the method may comprise refining the resulting vapors before combustion. The method may comprise providing a biomass-to-energy route aligned with CO2 capture.

[0402] In some embodiments, the method may comprise facilitating biomass drying or pyrolysis with heat from the exhaust gas. In some cases, the method may comprise routing hot exhaust to a heat exchanger or rotary drum. In some instances, the method may comprise recovering sensible heat for biomass processing. For example, the method may comprise preheating feedstock to reduce moisture content. As an example, the method may comprise improving pyrolysis efficiency by recycling waste heat. The method may comprise enhancing system-wide energy integration and lowering external heat requirements.

[0403] In some embodiments, the method may comprise producing carbon-rich char or a stable solid pyrolysis product in addition to VOCs. In some cases, the method may comprise separating this char from volatile fractions. In some instances, the method may comprise storing char in a way that prevents oxidation. For example, the method may comprise turning char into biochar for long-term soil sequestration. As an example, the method may comprise monitoring char properties for industrial applications. The method may comprise achieving negative-carbon or carbon-neutral operations through biomass management.

[0404] In some embodiments, the method may comprise directing an additional portion of the compressed CO2 to a destination other than mixing with oxygen. In some cases, the method may comprise splitting the CO2 flow for different applications. In some instances, the method may comprise bypassing an air separation unit. For example, the method maycomprise sending extra CO2 to a storage or utilization process (e.g., enhanced oil recovery). As an example, the method may comprise balancing recirculation to control combined gas composition. The method may comprise customizing CO2 distribution as operational needs dictate.

[0405] In some embodiments, the method may comprise directing a portion of the compressed CO2 to sequestration, purification, or storage units without further air separation. In some cases, the method may comprise providing near-pure CO2 directly to industrial customers. In some instances, the method may comprise injecting CO2 into geological formations or for EOR. For example, the method may comprise coordinating injection schedules with local operators. As an example, the method may comprise storing CO2 in saline aquifers. The method may comprise integrating CO2 managing into broader carbon management strategies.

[0406] In some embodiments, the method may comprise utilizing compressed CO2 for oil recovery or other industrial processes requiring CO2 injection. In some cases, the method may comprise delivering CO2 via pipeline to EOR fields. In some instances, the method may comprise improving hydrocarbon extraction through miscible flooding. For example, the method may comprise aligning CO2 supply with EOR demand. As an example, the method may comprise marketing CO2 for chemical synthesis (e.g., urea production). The method may comprise turning captured carbon into valuable products or storage.

[0407] In some embodiments, the method may be operated as a semi-closed Brayton Cycle, recycling a portion of CO2-rich exhaust. In some cases, the method may comprise controlling purge flows to avoid inert buildup. In some instances, the method may comprise partially recirculating CO2 while venting or capturing a slipstream. For example, the method may comprise adjusting turbine and compressor sizing for semi-closed operation. As an example, the method may comprise combining closed-cycle efficiency with open-cycle practicality. The method may comprise achieving high CO2 purity with flexible integration.

[0408] In some embodiments, the method may comprise utilizing CO2 as a working fluid at mass flow rates from about 14 kg / s to about 100 kg / s (or broader ranges, such as 10-50 kg / s). In some cases, the method may comprise sizing turbomachinery and piping to manage these flows. In some instances, the method may comprise balancing heat sources and sinks to maintain stable circulation. For example, the method may comprise verifying thermal loads for each flow range. As an example, the method may comprise modulating recirculation tomatch power demand. The method may comprise providing moderate to large-scale power generation using CO2 loops.

[0409] In some embodiments, the method may comprise using a second portion of the power produced (beyond that used for compression) to power an industrial process. In some cases, the method may comprise driving ancillary equipment in the same facility. In some instances, the method may comprise exporting power to an adjacent grid. For example, the method may comprise matching real-time power output to industrial loads like electrolysis. As an example, the method may comprise supporting local manufacturing with low-carbon power. The method may comprise improving overall resource utilization by coupling power generation to direct consumption.

[0410] In some embodiments, the method may comprise performing at least one of providing oxygen, combusting, expanding, compressing, or combining under sub-atmospheric pressure (e.g., 0.5-0.9 bar). In some cases, the method may comprise utilizing a vacuum environment to reduce NOx or handle material constraints. In some instances, the method may comprise installing vacuum pumps on specific loops. For example, the method may comprise validating partial vacuum operation for efficiency or emissions benefits. As an example, the method may comprise adjusting system boundaries to prevent air ingress. The method may comprise tailoring pressures across the cycle for improved performance.

[0411] In some embodiments, the method may comprise operating all steps (providing O2, combusting, expanding, compressing, combining) at sub-atmospheric pressure. In some cases, the method may comprise configured specialized equipment that tolerates negative gauge pressures. In some instances, the method may comprise sealing system boundaries against inward leaks. For example, the method may comprise employing low-pressure turbines and compressors. As an example, the method may comprise running a fully vacuumbased cycle for unique advantages. The method may comprise simplifying exhaust handling or reducing oxidative stress in some components.

[0412] In some embodiments, the method may comprise maintaining a pressure at the turbine inlet from about 0.4 bar to about 1.5 bar (e.g., partial vacuum up to slightly above atmospheric). In some cases, the method may comprise verifying stable flow by adjusting upstream compression. In some instances, the method may comprise controlling recycled CO2 to manage pressure. For example, the method may comprise monitoring real-time instrumentation for flow stability. As an example, the method may comprise optimizingexpansion ratio to maximize power extraction. The method may comprise providing the turbine to operate effectively with lower-than-atmospheric feeds.

[0413] In some embodiments, the method may comprise expanding the exhaust gas in a turbine to generate power. In some cases, the method may comprise selecting a turbine configuration suitable for CO2-rich flows. In some instances, the method may comprise operating the turbine at moderate or sub-atmospheric pressures (e.g., inlet 0.8-1.5 bar, outlet down to 0.3-0.5 bar). For example, the method may comprise driving a generator on the same shaft. As an example, the method may comprise controlling inlet conditions to optimize expansion efficiency. The method may comprise converting mechanical power into electrical output.

[0414] In some embodiments, the method may comprise manufacturing the turbine and its components from standard-grade alloys. In some cases, the method may comprise limiting turbine inlet temperature below about 1000 °C or 900 °C. In some instances, the method may comprise avoiding exotic superalloys. For example, the method may comprise using partial CO2 recirculation to moderate flame temperature. As an example, the method may comprise reducing capital costs by employing widely available materials. The method may comprise providing cost-effective turbine deployment in commercial settings.

[0415] In some embodiments, the method may comprise controlling exhaust gas temperature entering the turbine to be less than about 1000 °C (e.g., 800-900 °C for conservative configurations). In some cases, the method may comprise regulating combustion or using heat exchangers to cool the gas. In some instances, the method may comprise maintaining safe operating limits for standard alloys. For example, the method may comprise implementing a bypass or quench line to reduce temperature spikes. As an example, the method may comprise verifying turbine inlet temperature with thermocouple feedback. The method may comprise ensuring turbine longevity by mitigating thermal stress.

[0416] In some embodiments, the method may comprise coupling the turbine directly to an electrical generator at synchronous speed (e.g., -1800 or -3600 rpm for 60 Hz systems, or -1500 or -3000 rpm for 50 Hz). In some cases, the method may comprise matching rotor speeds to the required grid frequency. In some instances, the method may comprise eliminating gearboxes and extra power electronics. For example, the method may comprise selecting turbine wheel diameters appropriate for direct drive. As an example, the methodmay comprise reducing mechanical complexity and losses. The method may comprise achieving robust, maintenance-friendly operation.

[0417] In some embodiments, the method may comprise configuring the turbine so that a dimensionless specific speed (Ns) is about 0.21 to about 0.63. In some cases, the method may comprise varying inlet conditions to shift Ns within that range. In some instances, the method may comprise operating with expansion ratios from about 1.5 to about 4.8. For example, the method may comprise stepping expansion across multiple stages. As an example, the method may comprise adjusting bypass or recirculation to maintain the target ratio. The method may comprise optimizing turbine performance across different load conditions.

[0418] In some embodiments, the method may comprise rotating the turbine at speeds from about 1800 rpm to about 7200 rpm. Alternatively, the turbine rotational speed may be optimized based on specific operating conditions, allowing for higher speeds, such as up to 9000 rpm, if necessary to meet performance requirements. In some cases, the method may comprise maintaining a pressure drop ratio (Ap / p) from about 2.5% to about 7.5%. Alternatively, the method may include maintaining a pressure drop ratio optimized for system-specific conditions, such as a Ap / p resulting from a pressure drop from approximately 1.0 atm to 0.2 atm, corresponding to a significant change, for example, around 80%.

[0419] In some embodiments, the method may comprise employing a turbine stress management (TSM) component to reduce mechanical stress, where the inlet pressure to the TSM may be between about 0.4 bar to about 1.6 bar (or up to 10 bar in some configurations). In some cases, the method may comprise using reinforcing structures or bypass lines. In some instances, the method may comprise handling transient spikes with the TSM. For example, the method may comprise avoiding over-pressurization that may damage turbine blades. As an example, the method may comprise ensuring robust sealing in low-pressure or vacuum conditions. The method may comprise extending operational life via stress control.

[0420] In some embodiments, the method may comprise producing from about 2000 kWe to about 6000 kWe of power from the turbine (e.g., 2 MWe to 6 MWe). In some cases, the method may comprise sizing the turbine-generator to meet site requirements. In some instances, the method may comprise achieving an electrical efficiency between about 20% and about 60%. For example, the method may comprise optimizing cycle configuration (e.g., recuperation, intercooling) for higher efficiency. As an example, the method may comprisecomparing real-time output to theoretical models. The method may comprise balancing cost, complexity, and thermal efficiency in final deployment.

[0421] In some embodiments, the method may comprise operating the turbine with a polytropic or isentropic efficiency from about 46% to about 100% (practically, 46%-90% or 46%-95%). In some cases, the method may comprise refining blade profiles to reduce losses. In some instances, the method may comprise minimizing tip clearances or applying advanced CFD in configuration. For example, the method may comprise thermally isolating the turbine to reduce heat losses. As an example, the method may comprise verifying stage-by-stage performance with instrumentation. The method may comprise approaching near-ideal expansion under stable operating conditions.

[0422] In some embodiments, the method may comprise performing the combusting step without using a separate air separation unit (ASU). In some cases, the method may comprise utilizing an oxygen supply that is already sufficiently enriched. In some instances, the method may comprise avoiding cryogenic or membrane-based separation. For example, the method may comprise connecting directly to an oxygen pipeline from a nearby facility. As an example, the method may comprise reducing complexity while still achieving high CO2 concentrations. The method may comprise simplifying overall system configuration and lowering capital cost.

[0423] In some embodiments, the method may comprise keeping a stoichiometric ratio of hydrocarbon feedstock to oxygen, reducing incomplete combustion products. In some cases, the method may comprise matching fuel and O2 flows to meet theoretical demand. In some instances, the method may comprise using CO or residual O2 sensors to confirm stoichiometry in real time. For example, the method may comprise verifying minimal CO or unburned hydrocarbons. As an example, the method may comprise adjusting flow controllers continuously. The method may comprise optimizing efficiency and exhaust purity by accurate stoichiometric control.

[0424] In some embodiments, the method may comprise controlling the flow rate of oxygen into the combustor, thereby modifying the exhaust gas composition. In some cases, the method may comprise implementing automated valves or flow controllers. In some instances, the method may comprise adjusting O2 flow based on real-time sensor feedback of CO2 or CO. For example, the method may comprise using advanced control algorithms to maintain target combustion efficiency. As an example, the method may comprise increasing oxygenflow when higher power is demanded. The method may comprise tuning exhaust quality and power output responsively.

[0425] In some embodiments, the method may comprise controlling the injection rate of the hydrocarbon feedstock, thereby modifying exhaust composition. In some cases, the method may comprise synchronizing fuel injection with oxygen supply for balanced combustion. In some instances, the method may comprise responding to fluctuating demand or feedstock availability. For example, the method may comprise ramping fuel injection up or down to track a load setpoint. As an example, the method may comprise avoiding incomplete combustion by not exceeding available oxygen. The method may comprise optimizing performance and emissions via real-time feedstock control.

[0426] In some embodiments, the method may comprise partitioning the combustor into an oxygen-rich combustion zone and a CO2 dilution zone. In some cases, the method may comprise directing high-purity O2 to the primary flame region. In some instances, the method may comprise introducing recirculated CO2 downstream to moderate temperatures. For example, the method may comprise physically separating sections of the combustor to control mixing. As an example, the method may comprise using baffles or swirlers to achieve staged combustion. The method may comprise lowering NOx formation and controlling heat release rates.

[0427] In some embodiments, the method may comprise introducing the hydrocarbon feedstock into the combustor without a separate fuel booster or compressor. In some cases, the method may comprise relying on ambient pressure or minimal pumping. In some instances, the method may comprise configuring the combustor to tolerate lower fuel inlet pressures. For example, the method may comprise employing a naturally aspirated system. As an example, the method may comprise reducing capital cost by removing extra equipment. The method may comprise taking advantage of feedstock properties that allow direct combustion.

[0428] In some embodiments, the method may comprise dynamically controlling the flow rates of both hydrocarbon feedstock and oxygen based on real-time power demand. In some cases, the method may comprise monitoring grid load or an industrial process. In some instances, the method may comprise ramping up or down oxygen and fuel to match the desired power output. For example, the method may comprise employing a plant control system that receives demand signals. As an example, the method may comprise ensuringstable combustion under varying loads. The method may comprise delivering flexible, on- demand power while capturing CO2.

[0429] In some embodiments, the method may comprise extracting a small fraction of CO2 from the compressor discharge for sequestration or merchant usage. In some cases, the method may comprise heating and introducing a stoichiometric O2 flow back into the cycle. In some instances, the method may comprise exchanging heat between extracted CO2 and incoming O2 for thermal efficiency. For example, the method may comprise routing the heated O2 to the combustor. As an example, the method may comprise fine-tuning fuel injection to maintain near-stoichiometric conditions. The method may comprise generating power while continuously removing CO2.

[0430] In some embodiments, the method may comprise preheating a CO2 / O2 mixture and conveying it to a combustor, introducing hydrocarbon fuel at or near atmospheric pressure. In some cases, the method may comprise achieving nearly complete combustion to form primarily CO2 and H2O. In some instances, the method may comprise controlling fuel flow for a turbine inlet temperature near 900-1173 K. For example, the method may comprise monitoring oxygen content to remain stoichiometric. As an example, the method may comprise adjusting real-time flows based on demanded power. The method may comprise balancing high efficiency with material limits.

[0431] In some embodiments, the method may comprise expanding hot combustion products from about 1 atm down to about 0.3 atm (or 0.4 atm) in a turbine. In some cases, the method may comprise driving a compressor and generator on a common shaft to produce power. In some instances, the method may comprise controlling turbine stages to manage moderate temperatures (e.g., below 1000 °C). For example, the method may comprise generating about 4 MWe or another target output. As an example, the method may comprise using standard alloys to lower capital costs. The method may comprise achieving power generation while capturing CO2 at sub-atmospheric pressures.

[0432] In some embodiments, the method may comprise routing turbine exhaust through a recuperator or heat exchanger to recover heat. In some cases, the method may comprise cooling the exhaust enough to condense water vapor. In some instances, the method may comprise draining the condensed water prior to CO2 recycling. For example, the method may comprise adjusting cooling flows to maintain an exhaust outlet near ambient temperature. Asan example, the method may comprise reusing condensed water on-site. The method may comprise reducing exhaust moisture to simplify compression or CO2 capture.

[0433] In some embodiments, the method may comprise integrating biomass pyrolysis using turbine exhaust heat. In some cases, the method may comprise drying or heating biomass in a dedicated reactor. In some instances, the method may comprise producing gaseous volatiles for combustion and stable char for storage. For example, the method may comprise adjusting reactor temperature (e.g., 400-600 °C) based on feedstock. As an example, the method may comprise storing char in a sealed container to prevent oxidation. The method may comprise achieving negative-carbon or lower-carbon operations with combined CO2 and char sequestration.

[0434] In some embodiments, the method may comprise receiving sub-atmospheric CCL-rich flow at a compressor inlet (e.g., 0.3-0.5 atm). In some cases, the method may comprise compressing this CO2 to about 1 atm or slightly higher using a multi-stage compressor at -3600 rpm. In some instances, the method may comprise employing intercooling to manage compression temperatures. For example, the method may comprise monitoring inlet temperature (e.g., -306 K) for stability. As an example, the method may comprise adapting the flow rate based on desired sequestration capacity. The method may comprise facilitating efficient sub-atmospheric cycle operation with minimal leakage.Machine Learning

[0435] As used herein, the terms “artificial intelligence,” “artificial intelligence techniques,” “artificial intelligence operation,” and “artificial intelligence algorithm” generally refer to any system or computational procedure that may take one or more actions to enhance or maximize a chance of achieving a goal. The term “artificial intelligence” may include “generative modeling,” “machine learning” (ML), or “reinforcement learning” (RL).

[0436] As used herein, the terms “machine learning,” “machine learning techniques,” “machine learning operation,” and “machine learning model” generally refer to any system or analytical or statistical procedure that may progressively improve computer performance of a task. In some cases, machine learning may generally involve identifying and recognizing patterns in existing data in order to facilitate making predictions for subsequent data. Machine learning may include a machine learning model (which may include, for example, a machine learning algorithm). Machine learning, whether analytical or statistical in nature, may provide deductive or abductive inference based on real or simulated data. The machine-1 lolearning model may be a trained model. Machine learning (ML) may comprise one or more supervised, semi-supervised, self-supervised, or unsupervised machine learning techniques. For example, an ML model may be a trained model that is trained through supervised learning (e.g., various parameters are determined as weights or scaling factors). ML may comprise one or more of regression analysis, regularization, classification, dimensionality reduction, ensemble learning, meta learning, association rule learning, cluster analysis, anomaly detection, deep learning, or ultra-deep learning. ML may comprise, but is not limited to: k-means, k-means clustering, k-nearest neighbors, learning vector quantization, linear regression, non-linear regression, least squares regression, partial least squares regression, logistic regression, stepwise regression, multivariate adaptive regression splines, ridge regression, principal component regression, least absolute shrinkage and selection operation, least angle regression, canonical correlation analysis, factor analysis, independent component analysis, linear discriminant analysis, multidimensional scaling, non-negative matrix factorization, principal components analysis, principal coordinates analysis, projection pursuit, Sammon mapping, t-distributed stochastic neighbor embedding, AdaBoosting, boosting, gradient boosting, bootstrap aggregation, ensemble averaging, decision trees, conditional decision trees, boosted decision trees, gradient boosted decision trees, random forests, stacked generalization, Bayesian networks, Bayesian belief networks, naive Bayes, Gaussian naive Bayes, multinomial naive Bayes, hidden Markov models, hierarchical hidden Markov models, support vector machines, encoders, decoders, auto-encoders, stacked autoencoders, perceptrons, multi-layer perceptrons, artificial neural networks, feedforward neural networks, convolutional neural networks, recurrent neural networks, long short-term memory, deep belief networks, deep Boltzmann machines, deep convolutional neural networks, deep recurrent neural networks, or generative adversarial networks.

[0437] Training the machine learning model may include, in some cases, selecting one or more untrained data models to train using a training data set. The selected untrained data models may include any type of untrained machine learning models for supervised, semisupervised, self-supervised, or unsupervised machine learning. The selected untrained data models be specified based upon input (e.g., user input) specifying relevant parameters to use as predicted variables or other variables to use as potential explanatory variables. For example, the selected untrained data models may be specified to generate an output (e.g., a prediction) based upon the input. Conditions for training the machine learning model from the selected untrained data models may likewise be selected, such as limits on the machine-I l l-leaming model complexity or limits on the machine learning model refinement past at some point. The machine learning model may be trained (e.g., via a computer system such as a server) using the training data set. In some cases, a first subset of the training data set may be selected to train the machine learning model. The selected untrained data models may then be trained on the first subset of training data set using appropriate machine learning techniques, based upon the type of machine learning model selected and any conditions specified for training the machine learning model. In some cases, due to the processing power requirements of training the machine learning model, the selected untrained data models may be trained using additional computing resources (e.g., cloud computing resources). Such training may continue, in some cases, until at least one aspect of the machine learning model is validated and meets selection criteria to be used as a predictive model.

[0438] In some cases, one or more aspects of the machine learning model may be validated using a second subset of the training data set (e.g., distinct from the first subset of the training data set) to determine accuracy and robustness of the machine learning model. Such validation may include applying the machine learning model to the second subset of the training data set to make predictions derived from the second subset of the training data. The machine learning model may then be evaluated to determine whether performance is sufficient based upon the derived predictions. The sufficiency criteria applied to the machine learning model may vary depending upon the size of the training data set available for training, the performance of previous iterations of trained models, or user-specified performance requirements. If the machine learning model does not achieve sufficient performance, additional training may be performed. Additional training may include refinement of the machine learning model or retraining on a different first subset of the training dataset, after which the new machine learning model may again be validated and assessed. When the machine learning model has achieved sufficient performance, in some cases, the machine learning may be stored for present or future use. The machine learning model may be stored as sets of parameter values or weights for analysis of further input (e.g., further relevant parameters to use as further predicted variables, further explanatory variables, further user interaction data, etc.), which may also include analysis logic or indications of model validity in some instances. In some cases, a plurality of machine learning models may be stored for generating predictions under different sets of input dataconditions. In some embodiments, the machine learning model may be stored in a database (e.g., associated with server).

[0439] In some embodiments, the machine learning may be based on a large language model (LLM). An LLM is a type of Al model configured to understand generate human language. These models are built using deep learning techniques, such as transformers, which configure them to capture complex language patterns and relationships. LLMs are trained on massive amounts of text data, such as books, articles, websites, and more, to learn grammar, syntax, semantics, and even some level of common-sense reasoning. They may generate coherent and contextually relevant text, making them highly versatile for a wide range of language processing tasks.XVII. Materials

[0440] In some embodiments, the system comprises materials selection configured for efficient and economical operation. In some cases, the system comprises at least one alloy material configured to operate under sub-atmospheric pressure conditions. In some instances, the at least one alloy material comprises mechanical properties suitable for temperatures below about 1000°C.

[0441] In some embodiments, the system comprises at least one turbine component. In some cases, the at least one turbine component comprises materials selected from the group consisting of nickel-based alloys, iron-based alloys, cobalt-based alloys, and combinations thereof. In some instances, the at least one turbine component comprises alloys configured to maintain structural integrity at operating temperatures between about 500°C and about 900°C. For example, the at least one turbine component may comprise standard-grade Inconel alloys. As an example, the system may utilize readily available engineering materials rather than requiring exotic or advanced superalloys.

[0442] In some embodiments, the system comprises at least one compressor component. In some cases, the at least one compressor component comprises materials selected from conventional aerospace-grade alloys, including aluminum alloys, titanium alloys, and stainless steels. In some instances, the at leas...

Claims

CLAIMSWHAT IS CLAIMED IS:

1. A method of power generation, comprising:(a) providing a gas comprising oxygen (O2);(b) combusting a hydrocarbon feedstock with the gas comprising oxygen, thereby obtaining an exhaust gas comprising carbon dioxide (CO2);(c) expanding the exhaust gas in a turbine, thereby producing power;(d) compressing at least a portion of the exhaust gas using at least a portion of the power produced in (c), thereby obtaining compressed CO2 at a pressure no greater than 73.9 bap and(e) combining at least a portion of the compressed CO2 with additional oxygen, thereby obtaining a combined gas.

2. The method of claim 1, wherein the gas comprising oxygen comprises a concentration of O2 from about 30% to about 100% by volume.

3. The method of claim 1 or 2, wherein the gas comprising oxygen comprises a concentration of O2 greater than 90% by volume.

4. The method of any one of claims 1-3, wherein the gas comprising oxygen is an output of an industrial process.

5. The method of claim 4, wherein the industrial process comprises ammonia production, hydrogen production, ethanol production, chemical looping, water electrolysis, or other industrial processes, or any combination thereof.

6. The method of claim 1, wherein the gas comprising oxygen comprises at least about 30% O2 by volume.

7. The method of any one of claims 1-6, wherein the exhaust gas comprises a concentration of CO2 of greater than 90% by volume.

8. The method of any one of claims 1-7, wherein the exhaust gas comprises a concentration of CO2 of greater than 95% by volume.

9. The method of any one of claims 1-8, wherein a concentration of unreacted hydrocarbon feedstock in the exhaust gas is less than 1% by volume.

10. The method of any one of claims 1-9, wherein a concentration of sulfur oxides (SOX) in the exhaust gas is less than 1% by volume.

11. The method of any one of claims 1-10, wherein a concentration of nitrogen oxides (NOX) in the exhaust gas is less than 1% by volume.

12. The method of any one of claims 1-11, wherein a concentration of carbon monoxide (CO) in the exhaust gas is less than 1% by volume.

13. The method of any one of claims 1-12, wherein the exhaust gas further comprises water (H2O).

14. The method of claim 13, further comprising removing at least a portion of the water from the exhaust gas prior to the compressing in (d).

15. The method of claim 14, wherein a concentration of H2O in the exhaust gas prior to the compression in (d) is less than 10% by volume.

16. The method of claim 1, wherein (b) occurs in a combustor, and wherein the gas comprising oxygen is fed to the combustor in a stochiometric amount to fully combust the hydrocarbon feedstock.

17. The method of any one of claims 1-16, wherein at least about 99% of O2 in the gas comprising oxygen is consumed during the combusting in (b).

18. The method of any one of claims 1-17, wherein the combusting in (b) comprises stoichiometric combustion of the hydrocarbon feedstock.

19. The method of any one of claims 1-18, wherein a concentration of CO2 in the compressed CO2 stream is greater than about 90% by volume.

20. The method of any one of claims 1-19, wherein a concentration of CO2 in the compressed CO2 stream is greater than about 95% by volume.

21. The method of any one of claims 1-20, wherein a concentration of CO2 in the compressed CO2 stream is greater than about 99% by volume.

22. The method of any one of claims 1-21, wherein the combined gas comprises a concentration of O2 less than about 30% by volume.

23. The method of any one of claims 1-22, wherein the combined gas comprises a concentration of CO2 greater than about 50% by volume.

24. The method of any one of claims 1-23, wherein prior to (b), the gas comprising oxygen is preheated in a heat exchanger.

25. The method of any one of claims 1-24, wherein an additional portion of the compressed CO2 is not combined with the additional oxygen.

26. The method of claim 25, wherein the additional portion of the compressed CO2 is directed to a carbon sequestration unit, a purification unit, a storage unit, or a carbon utilization unit, or any combination thereof without passing through an air separation unit.

27. The method of claim 25 or 26, wherein the additional portion of the compressed CO2 is passed through a first heat exchanger to preheat the additional oxygen prior to the combining in (e).

28. The method of claim 27, wherein the first heat exchanger comprises a gas exchange recuperator.

29. The method of claim 27 or 28, wherein a temperature of the additional oxygen after exiting the first heat exchanger is at least about 26 °C.

30. The method of any one of claims 27-29, wherein a temperature of the additional oxygen after exiting the first heat exchanger is at least about 600 °C.

31. The method of any one of claims 27-30, wherein a temperature of the additional oxygen prior to entering the first heat exchanger is less than about 400 °C.

32. The method of any one of claims 27-31, wherein a temperature of the additional oxygen increases by at least about 10 °C in the first heat exchanger.

33. The method of any one of claims 27-32, wherein a temperature of the additional oxygen increases by at least about 100 °C in the first heat exchanger.

34. The method of any one of claims 1-33, wherein the gas comprising oxygen is directed through a second heat exchanger prior to (b).

35. The method of any one of claims 1-34, further comprising, subsequent to (e), directing the combined gas through a second heat exchanger.

36. The method of claim 34 or 35, wherein a temperature of the combined gas or the gas comprising oxygen after exiting the second heat exchanger is at least about 200 °C.

37. The method of any one of claims 34-36, wherein a temperature of the combined gas or the gas comprising oxygen after exiting the second heat exchanger is at least about 600 °C.

38. The method of any one of claims 34-37, wherein a temperature of the combined gas or the gas comprising oxygen prior to entering the second heat exchanger is at least about 500 °C.

39. The method of any one of claims 34-38, optionally comprising passing the combined gas or the gas comprising oxygen through a second heat exchanger to increase its temperature prior to combustion.

40. The method of any one of claims 34-39, wherein a temperature of the combined gas or the gas comprising oxygen increases by at least 200 °C in the second heat exchanger.

41. The method of any one of claims 35-40, wherein after exiting the second heat exchanger, the combined gas is combusted with additional hydrocarbon feedstock, thereby obtaining additional exhaust gas comprising CO2.

42. The method of claim 41, further comprising directing the additional exhaust gas through the second heat exchanger such that heat is transferred from the additional exhaust gas to the combined gas.

43. The method of claim 42, wherein the second heat exchanger is optionally bypassed or operated at reduced capacity, so that the temperature of the additional exhaust gas after exiting the second heat exchanger is at most about 300 °C (if in use) or remains substantially unchanged (if not in use).

44. The method of any one of claims 1-43, further comprising combusting the combined gas with additional hydrocarbon feedstock, thereby obtaining additional exhaust gas comprising CO2.

45. The method of claim 44, further comprising expanding the additional exhaust gas, thereby producing additional power.

46. The method of claim 44 or 45, further comprising compressing at least a portion of the additional exhaust gas, thereby obtaining additional compressed CO2 at a pressure no greater than 10 bar.

47. The method of any one of claims 1-46, wherein the combusting in (b) occurs in a combustor.

48. The method of claim 47, wherein a pressure in the combustor is less than about 1.6 bar.

49. The method of claim 47, wherein a pressure in the combustor is less than atmospheric pressure.

50. The method of claim 47, wherein the temperature of the exhaust gas leaving the combustor during the combusting in (b) is less than about 1500 °C.

51. The method of claim 47, wherein the temperature of the exhaust gas leaving the combustor during the combusting in (b) is less than about 1000 °C.

52. The method of any one of claims 1-51, wherein the hydrocarbon feedstock comprises natural gas, biogas, propane, methane, kerosene, jet fuel, or diesel, or any combination thereof.

53. The method of any one of claims 1-52, wherein the hydrocarbon feedstock comprises biomass or a derivative thereof.

54. The method of any one of claims 1-53, wherein the hydrocarbon feedstock comprises one or more volatile organic compounds (VOCs).

55. The method of claim 54, wherein the one or more VOCs are obtained by drying and pyrolyzing a biomass feedstock.

56. The method of claim 55, wherein the drying or the pyrolyzing of the biomass feedstock is at least partially facilitated by heat from the exhaust gas.

57. The method of claim 55, wherein the drying or the pyrolyzing of the biomass feedstock produces a carbon-rich char or stable solid pyrolysis product in addition to the one or more VOCs.

58. The method of claim 57, further comprising storing the carbon-rich char or stable solid pyrolysis product in a manner that prevents its oxidation.

59. The method of any one of claims 47-51, further comprising controlling a flow rate of the gas comprising oxygen into the combustor, thereby controlling, or modifying a composition of the exhaust gas.

60. The method of any one of claims 47-51 and 59, further comprising controlling a rate of injection of the hydrocarbon feedstock into the combustor, thereby controlling or modifying a composition of the exhaust gas.

61. The method of any one of claims 47-51, 59, and 60, wherein the combustor is partitioned into an oxygen-rich combustion zone and a CO2 dilution zone.

62. The method of any one of claims 47-51 and 59-61, wherein the hydrocarbon feedstock is introduced into the combustor without the use of a resolute fuel booster or separate fuel compressor.

63. The method of any one of claims 1-62, wherein a flow rate of the hydrocarbon feedstock and a flow rate of the gas comprising oxygen is dynamically controlled based on real-time demand for the power produced in (c).

64. The method of any one of claims 1-63, wherein the combusting in (b) is performed without a separate air separation unit.

65. The method of any one of claims 1-64, wherein in (b), a stoichiometric ratio of the hydrocarbon feedstock and the gas comprising oxygen is maintained, thereby reducing formation of incomplete combustion products in the exhaust gas.

66. The method of any one of claims 1-65, wherein the expanding in (c) occurs in a turbine.

67. The method of claim 66, wherein the turbine and components thereof are manufactured from standard-grade alloys.

68. The method of claim 66 or 67, wherein a temperature of the exhaust gas entering the turbine is less than 1000 °C.

69. The method of claim 66 or 67, wherein a temperature of the exhaust gas entering the turbine is less than 900 °C.

70. The method of any one of claims 66-69, wherein the turbine is directly coupled to an electrical generator at a synchronous or otherwise compatible speed, thereby eliminating the need for a gearbox or additional power electronics.

71. The method of any one of claims 66-70, wherein a dimensionless specific speed (Ns) of the exhaust gas through the turbine is adjustable between about 0.21 and about 2.0.

72. The method of any one of claims 66-71, wherein an expansion ratio of the turbine is from about 1.5 to about 10.0.

73. The method of any one of claims 66-72, wherein a rotational speed of the turbine is between about 1800 rpm and about 10,000 rpm.

74. The method of claim 73, wherein the compatible speed comprises at least one of 3000 RPM, 3600 RPM, 6000 RPM, or 7200 RPM.

75. The method of any one of claims 66-74, wherein a turbine stress management (TSM) component is used to reduce mechanical stress on the turbine or components thereof, and wherein a pressure at an inlet of the TSM is no less than about 10 bar.

76. The method of claim 75, wherein the pressure at the inlet of the TSM is from within a about 0.1 bar to about 1.6 bar.

77. The method of any one of claims 66-76, wherein a pressure at an inlet of the turbine is from about 0.1 bar to about 1.5 bar.

78. The method of any one of claims 66-77, wherein a pressure at an outlet of the turbine is less than about 0.5 bar.

79. The method of any one of claims 66-78, wherein a pressure at an outlet of the turbine is from about 0.1 bar to about 0.5 bar.

80. The method of any one of claims 66-79, wherein the power output from the turbine is from about 2000 kilowatts electrical (kWe) to about 20,000 kWe.

81. The method of any one of claims 66-80, wherein an overall net electrical efficiency of the power generation system is between about 10% and about 60%.

82. The method of any one of claims 66-81, wherein a polytropic efficiency of the turbine is from about 46% to about 100%.

83. The method of any one of claims 66-82, wherein an isentropic efficiency of the turbine is from about 46% to about 100%.

84. The method of any one of claims 1-83, wherein the compressed CO2 obtained from the compressor is at a pressure of no greater than 8 bar.

85. The method of any one of claims 1-84, wherein the compressed CO2 obtained from the compressor is at a pressure of no greater than 5 bar.

86. The method of any one of claims 1-85, wherein the compressed CO2 obtained from the compressor is at a pressure of no greater than 3 bar.

87. The method of any one of claims 1-86, wherein the compressed CO2 obtained from the compressor is at a pressure less than atmospheric pressure.

88. The method of any one of claims 1-87, wherein the compressing in (d) occurs in a compressor.

89. The method of claim 88, wherein the compressor is mechanically coupled to the turbine on a common shaft.

90. The method of claim 88 or 89, wherein at least one intercooling stage is included in the compressor.

91. The method of any one of claims 88-90, wherein the cycle working fluid is drawn into the compressor passively.

92. The method of any one of claims 88-91, wherein the compressor has a polytropic efficiency from about 40% to about 90%.

93. The method of any one of claims 88-92, wherein a flow rate of the cycle working fluid through the compressor is adjustable based on real-time demand for compression or CO2 sequestration.

94. The method of any one of claims 88-93, wherein the compressor comprises one or more axial, radial (centrifugal), or multi-stage compressors.

95. The method of any one of claims 88-94, wherein a shaft speed of the compressor is from about 1800 rpm to about 7200 rpm.

96. The method of any one of claims 1-95, further comprising routing at least a portion of the compressed CO2 to a carbon capture or sequestration unit.

97. The method of claim 94, wherein the compressed CO2 is utilized for oil recovery or for any industrial processes requiring CO2 injection.

98. The method of claim 1, wherein the method is a semi-closed Brayton Cycle.

99. The method of any one of claims 1-98, wherein the method utilizes a CO2 working fluid, and wherein a mass flow rate of the working fluid is from about 14 kg / s to about 100 kg / s.

100. The method of any one of claims 1-99, wherein at least one of (a), (b), (c), (d), or (e) is performed at sub-atmospheric pressure.

101. The method of any one of claims 1-99, wherein (a), (b), (c), (d), and (e) are performed at sub-atmospheric pressure.

102. The method of any one of claims 1-101, wherein a second portion of the power produced in (c) that is not used in the compressing in (d) is used in an industrial process.

103. The method of claim 102, wherein the industrial process produces the gas comprising oxygen.

104. The method of claim 1, wherein the power produced in (c) is usable for at least one of: (i) generating electricity, (ii) directly driving a mechanical device or system, or (iii) providing other useful work output.

105. The method of any one of claims 1-104, further comprising operating the turbine at an inlet temperature exceeding about 1000 °C by employing advanced high-temperature alloys or thermal barrier coatings on turbine components, thereby providing higher-temperature combustion while maintaining material integrity.

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