Integrated carbon sequestration and power generation system and method of use

Abstract

Systems and methods are disclosed that provide an integrated carbon sequestration and power generation system. The integrated carbon sequestration and power generation system may include a thermodynamic cycle configured to receive biomass and output heat and power, and a direct air capture system configured to receive at least a portion of the heat and power output from the thermodynamic cycle. Other aspects are described and claimed.

Description

[Technical Field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims priority to U.S. Provisional Patent Application No. 63 / 479,875, filed January 13, 2023, and U.S. Provisional Patent Application No. 63 / 535,990, filed August 31, 2023, both of which are incorporated by reference in their entireties.

[0002] Various embodiments of the present disclosure relate generally to integrated carbon sequestration and power generation systems and related methods of use, and more particularly to biomass to energy conversion cycles coupled with direct air capture carbon systems. [Background technology]

[0003] For hundreds of years, anthropogenic emissions of carbon dioxide (CO2) gas from thermal processes (combustion) have been altering the Earth's atmospheric composition. This has led to a planetary warming effect, which is changing the Earth's climate system at an unprecedented rate. Due to rapid changes in atmospheric boundary conditions, biome adaptation mechanisms are at risk of collapse. The Intergovernmental Panel on Climate Change (IPCC) has decreed that humans must remove 100 to 1,000 gigatons of CO2 from the atmosphere during the 21st century to limit the average atmospheric temperature increase to 1.5°C.

[0004] Accordingly, the present disclosure is directed to addressing the aforementioned problem(s). The description of the background art provided herein is intended to generally present the context of the present disclosure. Unless otherwise indicated herein, the material described in this section is not prior art to the claims of this application, and no admission is made that inclusion in this section is prior art or suggests prior art. Summary of the Invention

[0005] According to certain aspects of the present disclosure, an integrated carbon sequestration and power generation system is disclosed.

[0006] According to an embodiment, an integrated carbon sequestration and power generation system is disclosed that includes a thermodynamic power cycle, such as a regenerative Brayton thermodynamic cycle, configured to receive biomass and generate heat and power, and a direct air capture (DAC) carbon sequestration system configured to receive at least a portion of the heat and power generated by the thermodynamic power cycle, such as the regenerative Brayton thermodynamic cycle, to facilitate carbon sequestration.

[0007] According to another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes generating syngas via a gasification reaction involving the generation of biomass, oxygen, and steam in a gasifier, passing the generated syngas through a scrubber to generate purified syngas, and cooling the purified syngas by introducing it into a low-temperature heat exchanger, where heat of the syngas is removed to generate steam. The method further includes introducing the cooled syngas, oxygen, and a recycled carbon dioxide (CO) stream into a combustor, combusting the syngas to provide a combustion stream comprising CO and water, expanding the combustion stream through a first turbine to generate a first turbine discharge stream and power, and expanding the first turbine discharge stream through a second turbine to generate a second turbine discharge stream and power, where the power is provided to a generator. The method further includes cooling at least a portion of the second turbine discharge stream by passing the second turbine discharge stream through a regenerator heat exchanger, and passing the cooled second turbine discharge stream through a cooling bank, the cooling bank having a sorption material containing the captured CO2, whereby the CO2 sorption material is heated by passing the cooled second turbine discharge stream through the cooling bank. The method also includes passing a recirculated CO2 stream from the cooling bank through a compressor to produce a supercritical CO2 stream, passing a first portion of the supercritical CO2 stream through a storage location and a second portion of the supercritical CO2 stream through a recirculation pump to produce a recirculated CO2 stream, and passing the recirculated CO2 stream through a regenerator heat exchanger, where the recirculated CO2 stream exchanges heat with the second turbine discharge stream, and the method further includes passing the heated recirculated CO2 stream through a combustor.

[0008] According to another embodiment, an integrated carbon sequestration and power generation system is disclosed, comprising: a gasifier configured to receive biomass and configured to produce syngas; a combustor configured to produce a combustion stream from the purified syngas, oxygen, and a recirculated carbon dioxide (CO) stream; and at least one turbine operably coupled to a direct air capture (DAC) carbon sequestration system and to a high-pressure recirculation pump, wherein the at least one turbine supplies power generated by the at least one turbine to the DAC carbon sequestration system or to a power grid separate from, or simultaneously with, the integrated carbon sequestration and power generation system.

[0009] According to another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes using one or more processors of a computer system to operate the integrated carbon sequestration and power generation system in a first operating mode, where power generated by a turbine generator of the integrated carbon sequestration and power generation system in the first operating mode is sent to power a direct air capture (DAC) carbon sequestration system, the method further includes using the one or more processors to determine that a predetermined condition is met, and using the one or more processors to switch the operating mode of the integrated carbon sequestration and power generation system from the first operating mode to a second operating mode based on the determination, and after switching, operating the integrated carbon sequestration and power generation system in the second operating mode, where power generated by the turbine generator in the second operating mode is sent to a power grid of a power grid operator.

[0010] According to another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes using one or more processors of a computer system to operate the integrated carbon sequestration and power generation system in a first operating mode, wherein power generated by a turbine generator of the integrated carbon sequestration and power generation system in the first operating mode is sent to power a direct air capture (DAC) carbon sequestration system, the method further includes using the one or more processors to determine that a predetermined condition is met, and using the one or more processors to switch the operating mode of the integrated carbon sequestration and power generation system from the first operating mode to a second operating mode based on the determination, and after switching, operating the integrated carbon sequestration and power generation system in the second operating mode, wherein a first portion of the power generated by the turbine generator is sent to the DAC carbon sequestration system and a second portion of the power generated by the turbine generator is sent to a power grid of a power grid operator separate from the integrated carbon sequestration and power generation system.

[0011] According to another embodiment, a method for supplying power generated by a turbine generator of an integrated carbon sequestration and power generation system to a power grid of a power grid operator is disclosed. The method includes: using one or more processors of a computing system to identify a predetermined number or type of assets that are unavailable to the power grid operator during a first time interval and available to the power grid operator during a second time interval; using the one or more processors to transfer the power generated by the turbine generator to the power grid of the power grid operator during the first time interval; and using the one or more processors to transfer the power generated by the turbine generator to a direct air capture (DAC) carbon sequestration system of the integrated carbon sequestration and power generation system during the second time interval.

[0012] According to another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes identifying a first predicted value derived from sequestration of carbon dioxide when operating the integrated carbon sequestration and power generation system in a first mode of operation, identifying a second predicted value derived from powering a third-party system when operating the integrated carbon sequestration and power generation system in a second mode of operation, operating the integrated carbon sequestration and power generation system in the second mode of operation in response to determining that the second predicted value is greater than the first predicted value, and operating the integrated carbon sequestration and power generation system in the first mode of operation in response to determining that the second predicted value is less than the first predicted value.

[0013] It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the disclosed embodiments, as claimed.

[0014] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate disclosed embodiments and, together with the description, serve to explain the principles of the disclosed embodiments. Numerous aspects and embodiments are described herein. Those skilled in the art will readily recognize that the features of a particular aspect or embodiment may be used in combination with the features of any or all of the other aspects or embodiments described in the present disclosure. [Brief explanation of the drawings]

[0015] [Figure 1] FIG. 1 shows a schematic diagram of an exemplary integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 2-1] FIG. 1 shows a schematic diagram of an exemplary integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 2-2] FIG. 1 shows a schematic diagram of an exemplary integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 3] 3 illustrates exemplary thermodynamic conditions of pressure and temperature for the system of FIG. 2 in accordance with various embodiments of the present disclosure. [Figure 4] 1 illustrates an exemplary operational flow of an integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 5] FIG. 1 shows a schematic diagram of another exemplary integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 6-1] FIG. 1 shows a schematic diagram of another exemplary integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 6-2] FIG. 1 shows a schematic diagram of another exemplary integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 7-1] FIG. 1 shows a schematic diagram of another exemplary integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 7-2] FIG. 1 shows a schematic diagram of another exemplary integrated carbon sequestration and power generation system according to various aspects of the present disclosure. [Figure 8] 1A and 1B show plots illustrating cycle efficiency of a power system, not including parasitic losses, according to various embodiments of the present disclosure. [Figure 9] 1 illustrates an exemplary computing system in accordance with various aspects of the present disclosure. DETAILED DESCRIPTION OF THE INVENTION

[0016] Both the foregoing general description and the following detailed description are exemplary and explanatory only and are not intended to limit the features as claimed. In this disclosure, the term "based on" means "based at least in part on." Unless context dictates otherwise, the singular forms "a," "an," and "the" include plural referents. As used herein, the terms "comprises," "comprising," or other variations thereof are intended to refer to a non-exclusive inclusion; thus, a process, method, product, or apparatus that includes a list of elements may include not only those elements, but also other elements not expressly listed or that are inherent to such process, method, product, or apparatus. Furthermore, as used herein, the term "exemplary" is used in the sense of "example," rather than "ideal." An embodiment or implementation described herein as "exemplary" should not be construed as preferred or advantageous over other embodiments or implementations, for example, but rather is intended to reflect or indicate that the embodiment(s) are "exemplary" embodiment(s).

[0017] It should be noted that all numerical values ​​disclosed or claimed herein (including all disclosed values, limits, and ranges) may have a variation of + / - 10% from the disclosed numerical value (unless a different variation is specified). Furthermore, in the claims, values, limits, and / or ranges refer to the value, limit, and / or range + / - 10%. Furthermore, relative terms such as "approximately" and "about" are typically used to indicate a possible variation of ±10% from the stated or understood value, unless otherwise indicated in the specification. Furthermore, the term "between" when used to describe a range of values ​​is intended to include the minimum and maximum values ​​set forth herein. The use of the term "or" in the claims and specification is used to mean "and / or" unless explicitly stated to refer to alternatives only or unless the alternatives are mutually exclusive; however, the present disclosure supports the definition referring to alternatives only and "and / or." As used herein, "another" can mean at least a second, or more.

[0018] Certain terms used herein, such as "working fuel," "CO2 stream," "syngas," and other similar terms, may be used interchangeably throughout the description of the embodiments.

[0019] Additional objects and advantages of the embodiments will be set forth in part in the description which follows, and in part will be obvious from the description, or may be learned by practice of the embodiments. It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the scope of the claims.

[0020] To achieve carbon sequestration, alternatives may be available, including reforestation, direct air carbon capture and sequestration, biomass and carbon removal and storage (BiCRS), and other technologies (e.g., algae production and sedimentation) that may be unproven. Afforestation / reforestation is low cost, difficult to model, and has a short time horizon for CO2 capture (e.g., potentially 50–100 years). Direct air carbon capture and sequestration is higher cost (e.g., due to energy requirements), easy to model and quantify, and has a long time horizon for carbon capture (e.g., 1000 years or more, depending on the capture medium). BiCRS is moderate cost (e.g., due to equipment capital investment), easy to model and quantify, and has a long time horizon for carbon capture (e.g., 1000 years or more, depending on the capture medium).

[0021] Most of the aforementioned approaches require long-term energy use, and in today's society, energy typically comes from carbon-emitting sources, substantially reducing the amount of carbon sequestered. Furthermore, the carbon reduction benefits of afforestation / reforestation are difficult to measure and verify, and their permanence is highly uncertain. While these afforestation / reforestation and other land- and sea-based capture methods can play a role in carbon reduction efforts, they are unlikely to reach the scale and permanence necessary to avert the climate crisis. Furthermore, current bioenergy and carbon capture and sequestration (BECCS) systems, also known as BiCRS, are generally not designed for scalability and involve retrofitting existing biomass power plants with carbon sequestration systems, which can be prohibitively expensive and may prevent these power generation plants from competing in the grid market.

[0022] In light of the foregoing, a solution is proposed for a system design built from the ground up with BiCRS, using oxy-fuel combustion to generate a CO2-enriched stream and using the CO2-enriched stream to power the system. Pairing this system with a bottoming temperature and pressure swing adsorption cycle that utilizes waste heat to regenerate the sorbent can create a hybrid BiCRS+direct air carbon (DAC) sequestration system with greater carbon reduction potential compared to other energy-based engineered systems. More specifically, in some embodiments, carbon-neutral or carbon-negative fuels, such as waste biomass, can be converted into ready-to-sequester CO2, heat, and power using, for example, a thermodynamic power cycle. Exemplary thermodynamic power cycles can include, for example, a Brayton cycle, a regenerative Brayton thermodynamic cycle, a Rankine cycle, a steam turbine cycle with Rankine, and the like. Such thermodynamic cycles can use CO2 and / or supercritical CO2 (sCO2) as the primary working fluid. At least a portion of the heat and power generated from the thermodynamic cycle may then be used to drive an integrated direct air carbon capture system, or the power may be used for one or more other purposes (e.g., the power may be electricity utilized for power grid integration, or the power may be output in the form of mechanical power). Such an exemplary system 100 is shown schematically in Figure 1. It should be understood that Figure 1 generally describes an entirely integrated carbon sequestration and power generation system, of which systems 200, 500, 600, and 700 (discussed further herein) are exemplary embodiments.

[0023] As shown in FIG. 1 , biomass 105 can be introduced into a thermodynamic power cycle 110, which uses waste heat to power a DAC sequestration system and regenerate a sorbent. In the context of this application, biomass 105 refers to any carbon-neutral or carbon-negative fuel. For example, potential types of biomass 105 can include, for example, wood products such as wood processing waste (e.g., firewood, wood pellets, wood chips, lumber and sawdust waste, etc.), agricultural products including crops and waste materials (e.g., corn, soybeans, sugarcane, woody plants, algae, etc.), biological materials in municipal solid waste (e.g., paper, cotton, wool products, food, yard waste, etc.), non-biological materials in municipal solid waste (e.g., plastics or petroleum-based products), animal manure, or human wastewater (e.g., biowaste discharge from a water treatment plant). Biomass 105 can be decomposed in the thermodynamic power cycle 110 to produce CO2. In aspects, non-limiting types of possible thermodynamic power cycles that may be utilized include Brayton thermodynamic power cycles, regenerative Brayton thermodynamic power cycles, Rankine thermodynamic power cycles, etc. Specific examples of thermodynamic cycles and processes for decomposing biomass 105 are discussed in further detail below. While the examples described throughout this specification may refer to a regenerative Brayton thermodynamic power cycle, it is important to note that this designation is not limiting and other thermodynamic power cycles may be utilized instead of or in addition to a regenerative Brayton thermodynamic power cycle.

[0024] In an embodiment, CO may be heated by combustion heat resulting from the reaction of biosyngas and oxygen in a thermodynamic power cycle 110 (e.g., a regenerative Brayton thermodynamic cycle) to form a CO working fluid. The CO working fluid may be a supercritical CO working fluid, a subcritical CO working fluid, steam, or a combination thereof. The working fluid may be utilized to generate power and heat. In one configuration, the generated power may be supplied to a direct air capture (DAC) system 115, which may be configured to capture CO directly from the atmosphere. More specifically, the DAC system 115 may include sorbent materials, such as solid sorbent materials (e.g., metal-organic frameworks (MOFs), zeolites, silica, activated carbon, etc.), and / or liquid sorbent materials, such as aqueous inorganic bases or aqueous organic amines, that can effectively adsorb or absorb and store atmospheric CO and have low temperatures, i.e., require significant energy to regenerate the CO. The heat rejected from the thermodynamic power cycle 110 (e.g., a regenerative Brayton thermodynamic power cycle) can be used to extract the captured atmospheric CO2 and to regenerate the sorption material, and the generated power can be used to compress the extracted CO2 captured from the DAC system 115. Once extracted, the captured CO2 can be permanently stored underground, reintroduced into the thermodynamic power cycle 110, and / or sold. In another operating configuration, the generated power produced by the thermodynamic power cycle 110 (e.g., a regenerative Brayton thermodynamic power cycle) can optionally be integrated into the power grid 120. In yet another operating configuration, a portion of the generated power can be integrated into the power grid 120, and another portion can be used to power the DAC system 115, thereby enabling both the power grid 120 and the DAC system 115 to be powered simultaneously.

[0025] Thus, exemplary embodiments of the present disclosure provide a power generation system that uses biomass as fuel and CO2 as a working fluid. For example, a gasifier may be used to convert carbonaceous biomass into a usable fuel source for power generation. Such systems may utilize a CO2 working fluid to pressurize a biomass solids conveying system, cool the walls of a syngas reactor, or quench the syngas stream exiting the gasifier reactor, as further described below.

[0026] The power generation system may also be integrated with a carbon sequestration system capable of directly capturing carbon from the air. As described with reference to FIG. 1, embodiments of the present disclosure provide for the integration of a CO power cycle with a direct air capture (DAC) system, which may use the CO and / or sCO thermodynamic power cycle waste heat as a sorbent regenerator for the CO sequestration cycle. Additionally, the power generation system of the present disclosure may be used as a "peaker plant," i.e., a power plant that generates power for the grid only when demand for electricity is high, as described further below. In such embodiments, the energy produced by the disclosed system may be used for multiple functions, such as generating power for the grid and powering carbon sequestration via an integrated DAC system.

[0027] In some aspects, other embodiments of the present disclosure provide for high-pressure cycle pump inlet selection to enable inlet flow robustness and independence from ambient conditions at the pump system inlet. Compressors can be sensitive to inlet conditions and may be forced to reduce their rate (i.e., reduce power) or turn off altogether if conditions are unfavorable. More specifically, CO2 density can be sensitive to the temperature of the CO2 fluid at the bottom of the pressure stage. The temperature at the bottom of the pressure stage can be affected by ambient temperature or near ambient temperature due to heat rejection methods. This CO2 density can affect the operation of the cycle's turbine machinery. At 73.8 bar (7.38 MPa), near the critical pressure of CO2, temperature-density sensitivity can become significant. In aspects, increasing the inlet pressure of the recirculation pump (which may be the lowest pressure in the recirculation loop) can reduce the first derivative of density and pressure at a given temperature, thereby reducing the dependency of CO2 density on CO2 temperature, e.g., ambient conditions. This may allow the system to operate in a variety of geographic locations that may have high, low, or moderate ambient temperature conditions without the need for a body of water to provide cooling. In some embodiments, by operating above the critical pressure of CO (e.g., above about 100 bar (10.0 MPa), at about 100 bar (10.0 MPa) to about 150 bar (15.0 MPa), at about 120 bar (12.0 MPa) to about 130 bar (13.0 MPa), or at about 125 bar (12.5 MPa)), CO density may change by about 20% or less, about 15% or less, about 10% or less, or about 5% or less over a standard temperature swing in ambient conditions (e.g., from day to night or from summer to winter). Conversely, in other embodiments, the system may be transcritical at a minimum pressure of, for example, about 35 bar (3.5 MPa), thereby eliminating the need to increase the inlet pressure of the recirculation pump, as described above. Thus, embodiments of the present disclosure may be directed to more robust systems that may be capable of operating under a wider range of ambient conditions compared to systems designed to be capable of operating near the critical pressure of CO2.

[0028] The subject matter of the present disclosure will now be described more fully with reference to the accompanying drawings, which form a part hereof and which show, by way of illustration, specific exemplary embodiments. System 100 may take the form of any of the alternative embodiments described herein, for example, with reference to FIGS. 2, 5, 6, and 7. The subject matter may be embodied in a variety of different forms, and thus, it is intended that the subject matter as claimed or claimed be construed as not limited to any exemplary embodiments described herein, which exemplary embodiments are provided for illustrative purposes only. Likewise, the scope of the subject matter as claimed or claimed is intended to be quite broad. For example, the subject matter may be embodied as a method, device, component, or system, among others. Thus, embodiments may take the form of, for example, hardware, software, firmware, or any combination thereof. Accordingly, the following detailed description is not intended to be construed in a limiting sense.

[0029] Throughout this specification and claims, terms may have subtle meanings that are suggested or implied in context beyond their explicitly stated meaning. Similarly, the phrases "in one embodiment" or "in some embodiments" as used herein do not necessarily refer to the same embodiment, and the phrase "in another embodiment" as used herein does not necessarily refer to different embodiments. For example, claimed subject matter is intended to include, in whole or in part, combinations of the exemplary embodiments.

[0030] The terms used below are to be interpreted in their broadest reasonable manner, even when used in conjunction with detailed descriptions of certain specific embodiments of this disclosure. Indeed, although certain terms may be emphasized below, any terms intended to be interpreted in a limiting manner are expressly and specifically so defined in this Detailed Description section.

[0031] 2 is a diagram illustrating an exemplary integrated carbon sequestration and power generation system 200 (“system”) according to one or more embodiments of the present disclosure. System 200 may include a torrefaction reactor 202, a grinding system 204, a torrefied biomass conveying system 206, a load and lock hopper 208, a feed hopper 210, a gasification reactor vessel (“gasifier”) 212, an air separation unit 214, a first HO recirculation pump 216, and a scrubber 218. Collectively, these components may prepare biomass for use as fuel. System 200 may further include a low-temperature heat exchanger 220, a syngas boost compressor 222, an oxygen boost compressor 224, a combustor 226, a regenerator heat exchanger 228, a high-pressure turbine 230, a high-pressure CO recirculation pump 232, a low-pressure turbine 234, and a generator 236 for generating power. In some embodiments, the system 200 may further include a direct air recovery fan bank 238, a low / intermediate pressure compressor 240, a water condenser 242, a second H2O recirculation pump 244, a CO2 compressor 246, and a designated storage location 248 for sequestering the CO2.

[0032] In an embodiment, suitable biomass, for example, any carbon-neutral or carbon-negative fuel (such as agricultural produce or waste, timber, trees, or undergrowth removed from forests, other organic waste, other municipal waste, and any combination of the foregoing), can be pretreated by a torrefaction process involving a torrefaction reactor 202. The torrefaction reactor 202 can be of any suitable type, including, but not limited to, a fixed-bed reactor, a rotary drum reactor, a microwave reactor, a fluidized-bed reactor, and / or a horizontal and vertical moving-bed reactor. The torrefaction process can include drying the biomass in the torrefaction reactor 202 and heating the biomass in an oxygen-deficient environment. Heat generated by combustion of the torrefaction gas can be used for both torrefaction of the biomass and drying the biomass. When the biomass reaches temperatures between 200°C and 350°C, the reaction can become exothermic, and products of the reaction can include water, oxygen, nitrogen, and volatile organic compounds (VOCs) in the biomass. The VOCs can be combusted to generate heat for drying and initiating the biomass reaction. The VOCs can be combusted in pure oxygen or air.

[0033] The biomass may be discharged from the torrefaction reactor 202 in a more pulverizable state and may have other beneficial properties, such as increased carbon content density, hydrophobic reactions, a higher heating value, a more homogeneous composition, removal of waste materials (e.g., water or low-energy compounds) so that transport may be more efficient, etc. This torrefied biomass may be transferred to a comminution system 204 (e.g., a stage-1 coarse grinder, a stage-2 coarse grinder, a bowl mill, an impact hammer, a jet mill, or other suitable system utilized in coal comminution, or any combination thereof) where it is pulverized to an appropriate size and prepared for transport and pressurization to a gasifier injector where it may be partially oxidized to separate the torrefied biomass into its constituent components. More specifically, pulverized torrefied biomass may be transported from the comminution system 204 to the load and lock hopper 208 by components of the torrefied biomass transport system 206 (e.g., conveyor belts, pneumatic systems, screws, buckets, etc.). Pressurization of the gasifier injector may be accomplished via pneumatic or mechanical modalities. Examples of mechanical pressurization include the use of a solids transfer pump or pumping a slurry of pulverized biomass and other components into the pressurized volume of the gasifier 212. When utilizing pneumatic pressure, the biomass may be pressurized using an inert gas, such as CO or N, which may be introduced into the load and lock hopper 208. For example, CO siphoned off from other parts of the system 200 may be diverted toward the load and lock hopper 208 via actuation of a three-way valve 254 or other suitable flow control mechanism. Suitable flow control mechanisms as used herein may include, for example, valves, orifice plates, manifolds, backpressure regulators, etc., used alone or in combination with one or more sensors. The pressurized pulverized torrefied biomass may then be fed into a feed hopper 210, which may be configured to convey the pressurized pulverized torrefied biomass into a gasifier 212 at a controlled, predetermined feed rate, for example, via a gasifier injector.2, it is contemplated that one or more of these components may be omitted from system 200, for example, if pre-torrefied biomass is received by system 200. In such a case, system 200 may not need to be capable of performing a torrefaction process and may be able to operate without utilizing one or more of the aforementioned components if the biomass received into system 200 (e.g., fed to gasifier 212) is already in a torrefied state. In other embodiments, non-torrefied biomass, for example, biomass that is unprocessed or processed by a method that does not include torrefaction, may be introduced into the system.

[0034] In embodiments, one of a variety of different types of gasifier 212 may be utilized in system 200, such as a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier type. Pressurized biomass components may be injected into gasifier 212 and react with oxygen (O) and injected steam in a gasification reaction. In embodiments, the oxygen used in the gasification reaction may be obtained from and supplied to gasifier 212 by an air separation unit 214 fluidly coupled to gasifier 212. Air separation unit 214 may separate air into its components using, for example, vacuum pressure swing adsorption (VPSA) or temperature swing adsorption (TSA) techniques. In another embodiment, oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, air separation unit 214 may be a cryogenic oxygen system. In yet another embodiment, oxygen may be obtained from a dedicated oxygen delivery service or pipeline. Injected steam may be derived from one or more different sources. For example, as described further herein, water may be extracted from the synthesis gas (syngas) before it is inserted into one or more compressors and used as the basis for injected steam. Additionally or alternatively, water produced during combustion may be removed from the system, vaporized (e.g., with heat from the gasifier or a low-temperature heat exchanger), and injected as steam into the gasifier.

[0035] The product of the foregoing reaction is a syngas mixture containing gaseous hydrogen (H), carbon monoxide (CO), and CO, along with trace amounts of materials formed as a result of trace elements in the biomass. Solid products that cannot be gasified during the reaction are collected at the bottom of the gasifier 212 as molten slag and ash (e.g., fly ash, bottom ash, etc.). The solid products are a result of solid elements and compounds within the biomass, such as potassium, calcium, and silica. These solid products can be collected and reused for other purposes, such as fertilizer. For example, molten slag can be used to produce cement concrete for roads.

[0036] After the syngas is formed in the gasifier 212, it must be quenched to a usable temperature before it can be sent downstream. These temperatures may be determined, at least in part, by the configuration of downstream components, such as the scrubber 218. More specifically, a temperature may be selected to cool the syngas so that water can condense in the scrubber 218 to remove contaminating chemicals. Such a process may be facilitated by introducing water or CO2 from other parts of the system 200 into the gasifier 212. For example, water may be obtained from the low-temperature heat exchanger 220 or the regenerator heat exchanger 228 and supplied to the gasifier, e.g., via the pump 216. As another example, water extracted from biomass dried in the torrefaction reactor 202 may be utilized. If water from within the system 200 is reused, it may need to be purified or otherwise treated before use. Alternatively or additionally, water may be supplied from an external source, such as a water treatment plant or a body of water. In an embodiment, CO may be introduced into the gasifier 212, for example, from the low-pressure compressor 240. In other embodiments where the gasifier operates at a higher pressure, CO may be introduced into the gasifier from the high-pressure recirculation pump 232. Introducing water or CO to quench the syngas may allow for the formation of non-liquid ash on the condensable materials. The ash may be recovered and removed from the main flow path of the power-producing machine, thereby enabling longer machine operation. The non-liquid ash may be biological in nature and comprised primarily of minerals and compounds used by the biomass. It may be returned to the biodome from which it was extracted. Additionally or alternatively, it may be extracted and used as fertilizer. After the syngas exits the gasifier 212, water may be removed, for example, via the scrubber 216 or the low-temperature heat exchanger 220. CO may be retained in the CO stream for purposes of oxy-fuel combustion and expansion in downstream turbine systems.

[0037] In an embodiment, syngas exits gasifier 212 and may be transported into scrubber 216 where it may be processed to remove ash particulates and halogen compounds to produce a syngas that is clean-burning and does not adversely affect machinery downstream of the primary combustion system. Additionally or alternatively, the syngas may be processed in one or more candle filters or other available gas treatment systems to remove particulate pollutants.

[0038] After exiting the scrubber 216, the syngas may pass through a low-temperature heat exchanger 220. Syngas heat generated from the gasification oxidation reaction may be removed in the low-temperature heat exchanger 220, which may be set at a low temperature suitable for steam extraction, thereby acting as a syngas cooler. In embodiments, as described further herein, this steam may be used to remove captured CO from the sorbent material in the direct air capture fan bank 238 of an integrated direct air capture carbon system. For example, after the scrubber, there may be a large amount of steam and / or saturated water in the syngas. This steam and / or saturated water may be used to boil another lower-pressure water stream (e.g., at ambient pressure) and vaporize it in the low-temperature heat exchanger 220, which may then be routed to regenerate the sorbent in the direct air capture fan bank 238. In some aspects, this steam may be introduced into the gasifier 212 to promote hydrogen formation in the gasifier, particularly to change the amount of H and CO in the syngas using water shift. Additionally or alternatively, heat extracted from the syngas can be supplied to a CO2 cycle for increased efficiency (e.g., CO2 and / or sCO2 are used as working fluids, etc.). It is important to note that while FIG. 2 only illustrates the syngas passing through a single heat exchanger (i.e., low-temperature heat exchanger 220), such designation is not limiting. For example, in an embodiment, system 200 may include two heat exchangers that may be configured to extract and cool the syngas (e.g., low-temperature heat exchanger 220 and another heat exchanger positioned between gasifier 212 and scrubber 218, as illustrated in FIG. 6 later in this specification). The other heat exchanger may be a high-temperature heat exchanger and may be operable to generate more steam.

[0039] Additionally or alternatively, in some implementations, the gasifier 212 may have cooling water in its jacket / liner and may include an internally integrated heat exchanger. In some embodiments of the systems described herein (e.g., systems 100, 200, 500, 600, 700), heat may additionally or alternatively be removed from cooling elements in the gasifier jacket / liner or from cooling elements associated with one or more other components of the system. In such embodiments, heat may be removed directly through cooling by a component of a system of the present disclosure (e.g., a gasifier liner of systems 100, 200, 500, 600, 700) in conjunction with, or in contrast to, removing heat through cooling of the syngas product (e.g., cooling may be achieved through the liner, the syngas, or a combination thereof). The removed heat may be sent to other components of a system of the present disclosure to improve the efficiency of the system. As described further herein, for example, steam generated from the syngas heat rejected by the low-temperature heat exchanger 220 may be routed to the DAC bank 238 to remove CO gas from the sorption material. The systems described herein provide examples where heat may be extracted and redirected to improve the overall efficiency of such systems.

[0040] Once the syngas is fully cooled and dried, it may be compressed, if necessary, to full pressure (a suitable combustion injection pressure, such as about 415 bar (41.5 MPa)), for example, by a syngas boost compressor 222 configured to increase the temperature and pressure of the syngas. For example, in an exemplary flow, the cooled syngas exiting the low-temperature heat exchanger 220 may enter the syngas boost compressor 222 at a pressure of about 40 bar (4.0 MPa) and a temperature of about 350°K. The compressed syngas stream exiting the syngas boost compressor 222 may have a pressure of about 413 bar (41.3 MPa) and a temperature of about 685°K.

[0041] After compression, the syngas may be introduced into a combustor 226 (e.g., a biosyngas oxy-combustor) where it may be fully oxidized (e.g., with an oxygen stream derived from the air separation unit 214 and compressed via the oxygen boost compressor 224), thereby producing a stream primarily of water and CO2. The stream resulting from the oxidation reaction between the syngas and the oxygen stream may be mixed with a recycle stream primarily of CO2 within the combustor 226. The recycle stream of CO2 may pass through a regenerator heat exchanger 228 to preheat the regenerator heat exchanger 228 to a temperature suitable for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power remains to run all supplemental power requirements of the system 200). More specifically, the inlet of the regenerator heat exchanger 228 may be configured to receive a CO2 stream having a temperature of about 800°K to about 900°K. The CO2 exhaust stream exiting the regenerator heat exchanger 228 may have a temperature in the range of about 725°K to about 825°K.

[0042] In an embodiment, the pressure and temperature of an exemplary combustion stream exiting the combustion outlet of combustor 226 may be approximately 375 bar (37.5 MPa) and approximately 1036°K, respectively. The combustion stream may be diluted and then expanded in a turbine, such as, for example, first turbine 230 (i.e., high-pressure turbine). High-pressure turbine 230 may be a direct-fired turbine and is the first main engine turbine that receives the combustion stream from combustor 226. High-pressure turbine 230 is designed to efficiently extract work from the high-pressure combustion stream, which is then utilized to power main cycle recirculation pump 232, the operation of which is described further below.

[0043] In an embodiment, after the combustion stream undergoes expansion in the first turbine 230, an exemplary first turbine discharge stream pressure and temperature may be approximately 281.3 bar (28.13 MPa) and approximately 995°K, respectively. The turbine discharge stream may be injected into the second turbine 234 (i.e., the low-pressure turbine) and fully expanded to its lowest pressure level in the cycle. The second turbine expansion may power a generator 236 (i.e., a turbine alternator), which is mechanically attached to the rotor of the second turbine 234 and the low / intermediate pressure compressor 240.

[0044] Although a first turbine and a second turbine are described herein, it is contemplated that one, two, three or more turbines may be incorporated.

[0045] The energy generated by generator 236 may be utilized in a variety of different ways depending on the operating mode of system 200. For example, in a first operating mode, system 200 may function as a power plant, and power generated by generator 236 may be output from system 200. For example, the power may be output in the form of electricity and sent to a power grid, which may be associated with a third party (e.g., an energy provider). In some aspects, the power may be output in the form of mechanical power. In a second operating mode, system 200 may function as a CO2 capture system, and power generated by generator 236 may be utilized to power components of a DAC system (e.g., an air contact fan and compressor). In a third operating mode, system 200 may be configured to distribute power from generator 236 to both a power grid and a DAC system. Additional details regarding the various operating modes and power transfer paths of system 200 are described further herein.

[0046] In an embodiment, after the combustion stream undergoes expansion in the second turbine 234 (if multiple turbines are used), an exemplary second turbine discharge stream pressure and temperature may be approximately 63 bar (6.3 MPa) and approximately 800° K. The second turbine discharge stream is then passed through a regenerator heat exchanger 228. While one regenerator heat exchanger 228 is shown in FIG. 2 , multiple heat exchangers may be incorporated into the system 200. A recirculated CO2 stream from the high-pressure recirculation pump 232 may also be introduced into the regenerator heat exchanger 228. This allows the second turbine discharge stream to exchange heat with the recirculated CO2 stream pumped from the high-pressure recirculation pump 232, thereby heating the recirculated CO2 stream by sending it to the primary combustor 226 and cooling the second turbine discharge stream by sending it to the DAC fan bank 238. In various embodiments described herein, heat from the CO stream passing through the regenerator heat exchanger 228 may be used to boil water in the low temperature range of the regenerator heat exchanger 228. In some aspects, instead of extracting heat from the CO stream, heat may be extracted directly from the regenerator heat exchanger 228. In still other aspects, heat may be extracted from a low-pressure or high-pressure heat exchanger stream. Extracting heat in this manner may increase thermal power at lower quality temperatures, improving the efficiency of the system 200. Referring back to the embodiment of FIG. 2, the second turbine discharge stream may lose most of its water as it passes through the regenerator heat exchanger 228. This water may be reused for other purposes in other aspects of the system 200 (e.g., as quench water supplied to the gasifier 212, as steam supplied to the sorption material of a direct air capture system, etc.).

[0047] In an embodiment, after passing through the regenerator heat exchanger 228, the pressure and temperature of an exemplary second turbine discharge stream (i.e., the regenerator exhaust stream) may be about 60 bar (6.0 MPa) and about 360°K to about 375°K. The cooled second turbine discharge stream may be sent through the DAC bank 238. The outlet of the DAC bank 238 may be held at about 320°K and the remaining heat removed to return the stream to approximately ambient temperature, e.g., about 320°K or below. In an embodiment, the DAC bank 238 may reject heat via conduction at a given temperature (e.g., 300°K to 322°K) suitable for use in direct-air carbon sequestration sorbent regeneration. More specifically, the DAC bank 238 may include a piping manifold interconnected with the low-temperature CO sorbent. In embodiments, one type of CO sorbent may be a metal-organic framework (MOF), such as "mmen-Mg(dobpdc)." MOF sorbents have been shown to be amenable to regeneration processes (i.e., processes in which the sorbent material becomes reusable for another cycle). For example, MOF-based technologies may be regenerative at temperatures between about 353.15°K and about 393.15°K, which may result in lower energy consumption and costs. Other embodiments may utilize other types of low-temperature CO sorbents, such as zeolite materials or ammonia-based sorbents. Non-limiting types of low-temperature CO sorbents can include, for example, liquid amines (e.g., monoethanolamine (MEA)), solid amines (e.g., amine-functionalized cellulose, amine-functionalized silica), zeolites (e.g., Zeliote 13X (Na[(AlO)(SiO]]·nH0), Zeliote 4A (Na[(AlO)(SiO]]·nH0)), covalent organic frameworks (COFS) (e.g., COF-609), or one or more other types of MOFs (e.g., MOF-74).

[0048] In embodiments, to facilitate carbon capture, atmospheric air may be passed through multiple fans in the DAC bank 238, cooling and contacting the sorbent. In some embodiments, the fans in the DAC bank 238 may be used as fans for the condenser units utilized in the CO2 loop, thereby improving system efficiency by utilizing the power utilized to operate the DAC bank 238. In the absorption cycle, CO2 is captured from the air as it contacts the sorbent. In the discharge cycle, the cooled second turbine discharge stream may be used to heat (e.g., via conduction) the sorbent material in the DAC bank 238. Preheating the sorbent material in this manner allows it to receive steam generated from the syngas heat rejected by the low-temperature heat exchanger 220. This steam is used to remove CO2 gas from the sorbent material. Preheating the sorbent material, using heat from the system to generate steam, or using steam already generated from the system may reduce the amount of energy required to perform carbon capture and improve system efficiency. In some embodiments, instead of simply preheating the sorbent material, aspects of the system can be configured to allow heat drawn from a cooled second turbine discharge stream, or other heat source within system 200, to provide substantially all of the heat needed to operate DAC bank 238. The liberated CO2-containing stream is passed through condenser 242, where water therein is removed, and pumped back to low-temperature heat exchanger 220 via pump 244 for use in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in CO2 compressor 246 and sent to a pipeline via valve 252 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated geological storage location. For example, the CO2 may be transported to well 248, which may be a Class VI well. In another embodiment, the pipeline may transport the sequestered CO2, for example, to one or more other contracting entities. In some embodiments, at least a portion of the CO2 released from the sorbent may be sent to other components of the system 200, such as the lock and load hopper 208, rather than to a pipeline or storage facility.For example, CO2 transferred to the lock and load hopper 208 can be used to pressurize the biomass prior to introduction into the gasifier 212. Optionally, CO2 can be routed to either a pipeline / storage facility or to the load and lock hopper 208 using a three-way valve 254 or other components.

[0049] In embodiments, after passing through the direct air recovery bank 238, the pressure and temperature of an exemplary cooled CO stream may be approximately 131 bar (13.1 MPa) and approximately 360°K. The cooled CO stream is then transferred to the low / intermediate pressure compressor 240, where it passes through a critical point to form sCO, in some embodiments, before being injected into the high-pressure recirculation pump 232, which is configured to increase the pressure of the CO stream to the combustion injection pressure. For example, the recirculation pump discharge stream may have a pressure and temperature of approximately 417 bar (41.7 MPa) and approximately 360°K. In embodiments, one or both of the cooled CO stream exiting the DAC bank 238 and the compressed CO stream exiting the low / intermediate pressure compressor 240 may be cooled by a separate chiller 256 to increase efficiency. The recirculation pump discharge stream may then be heated by passing through the regenerator heat exchanger 228 and then recycled back to the combustor 226. The recirculation pump discharge stream may have a pressure and temperature of, for example, about 396 bar (39.6 MPa) and about 730° K after passing through the regenerator heat exchanger 228. In an embodiment, CO produced in the combustion process may be siphoned off at a pressure via a three-way valve or other suitable flow control mechanism (e.g., via an orifice plate configured to reduce the amount discharged, or via a leakage path in the main pump flow area) at a pressure ready for pipeline injection or liquefaction transfer via highway (e.g., via valves 250 and 254, or other suitable flow control mechanism) to well 248. A suitable pipeline injection pressure may be about 142 bar (14.2 MPa). In an embodiment, the low / intermediate pressure compressor section may utilize intercooling to increase cycle efficiency (although this is not required for system 200 to operate).

[0050] It is important to note that effective operation of system 200 may be achieved with fewer or more components. In other words, the number and types of components shown in Figure 2 are exemplary only, and other embodiments may exist in which fewer components are present yet the same results are achieved.

[0051] FIG. 3 shows a simplified version of the power-generating portion of system 200 of FIG. 2. Additionally, Tables 1 and 2 below provide exemplary thermodynamic conditions at various locations throughout system 200. It is important to note that the temperatures and pressures provided are examples only, and may vary depending on, for example, the size of the power plant, the type of biomass used, variations in the carbon content of the syngas, the efficiency of the power cycle, or other factors or combinations of factors. While CO density gradients can create operational issues for turbine mechanical systems when a heat rejection step to the atmosphere is performed, in embodiments, this cycle allows for high-pressure operation and avoids CO density gradients above the steam dome. If the pressure entering the pump is close to the CO steam dome (when CO is gaseous and not supercritical), the cooling temperature at the pump inlet can affect the fluid density enough to render the pumping system in the cycle inoperable. Therefore, because the fluid density gradient may be less sensitive to the inlet temperature condition, the pump inlet pressure condition can be set to a pressure higher than the critical pressure of CO. This may allow the system 200 to operate on waste heat (ie, using air to cool the cycle) independent of water requirements. [Table 1] [Table 2]

[0052] 4, an exemplary method of operating an integrated carbon sequestration and power generation system, for example, switching between operating modes of the integrated carbon sequestration and power generation system, is disclosed. An exemplary process flow 400 may be implemented by components of systems 100, 200.

[0053] As previously discussed above, the systems 100, 200 may be capable of operating in a variety of different operating modes, and power generated by the generator 236 of the systems 100, 200 (e.g., as a result of the expansion of the combustion flow across the low-pressure turbine 234) may be delivered to a particular destination and utilized to transfer power to particular components based on the selected operating mode. The systems 100, 200 may switch between operating modes without changing the cycle operation, thereby enabling the systems 100, 200 to have diverse utility and participate in a variety of different markets. While the flow 400 is described in conjunction with a computer-controlled system, it is contemplated that the flow 400 may proceed either manually or automatically.

[0054] At step 405, the computer control system may operate the system 100, 200 in a first operating mode. In embodiments, the system 100, 200 in the first operating mode may be configured to send energy generated by the turbine generator 236 to power a DAC carbon sequestration system integrated as part of the system 100, 200. In this regard, power may be sent by operating a switching relay governed by the computer control system to operate and power one or more air contact fans in the DAC bank 238, as well as the DAC CO2 compressor 246. Once operational, the DAC system may operate to capture and sequester atmospheric carbon. Additionally, the system 100, 200 may itself be configured, or manually configured, to supply heat from the thermodynamic power cycle 110 (e.g., a regenerative Brayton thermodynamic power cycle) to the sorption material included in the DAC bank 238 (e.g., via conductive heat provided by the exhaust stream from the regenerator heat exchanger 228, as described above).

[0055] At step 410, the computer control system may determine whether a predetermined condition is met. In an embodiment, if the predetermined condition is met, then a transfer of power generated by turbine generator 236 to a second destination may be initiated, as described in steps 420-425. Alternatively, if the predetermined condition is not met, then the computer control system may maintain system 100, 200 in the first operating mode, as described in step 415. Several possible types of predetermined conditions are contemplated herein and are further described below.

[0056] In an embodiment, determining whether a predetermined condition is met may correspond to identifying whether one or more other power sources are available to power the power grid. For example, the predetermined condition may correspond to whether the power grid operator has access to another type of renewable energy to power the power grid. In response to determining that the power grid operator entity does not have access to the other type of renewable energy, the predetermined condition may be deemed met. By way of background, further to the foregoing, power costs may vary throughout the day, with some periods being more expensive than others. These variations may be based in part on the type of renewable energy (e.g., solar energy, wind energy, etc.) to which the power grid operator has access. Specifically, a renewable energy provider may be able to power the power grid operator at a lower cost than a conventional gas- and / or coal-fired power plant can provide power. Thus, when renewable energy sources are available, the power grid operator may obtain power for its power grid at a lower cost, resulting in relatively lower power costs. However, if conditions prevent renewable energy providers from operating (e.g., due to no sunlight or wind, low sunlight or wind, inclement weather, etc.), grid operators may be required to obtain power for their grids at relatively high costs because obtaining energy from gas- and / or coal-fired plants may be relatively expensive. These high electricity cost, or "peaker," periods may be periods that occur daily (e.g., at night when solar power is not available) and / or may persist for extended periods of time (e.g., days or weeks depending on the weather).

[0057] The computerized control system may be configured to predict when a renewable energy provider will be inoperable and unable to generate renewable energy. For example, in an embodiment, the computerized control system may receive an indication from a timer or sensor, which may be configured to provide an alert to the computerized control system at a predetermined time each day. The predetermined time may be the estimated time when the renewable energy provider will no longer be able to power the power grid. In an embodiment, the predetermined time may be static (i.e., the same each day) or dynamic and may be adjusted throughout the year. In another embodiment, the computerized control system may have access to historical sunlight data for the relevant geographic region (e.g., stored in a database, accessible via an online source, etc.), which may provide an indication of average daily sunrise and sunset times throughout the year. A solar-based energy provider may be operable during a period between sunrise and sunset and inoperable during a period between sunset and sunrise. Thus, the computerized control system may associate a known daily sunset time as the end of the power grid operator's ability to receive renewable energy for that day. In another embodiment, the computerized control system may access weather forecast data (e.g., weather forecast data from online sources), which may provide an indication of upcoming weather events that may affect the renewable energy provider's renewable energy production capacity. For example, if the upcoming weather forecast data predicts cloudy and / or stormy conditions, the computerized control system may determine that the solar energy provider's power generation capacity may be limited during these predicted severe weather periods. In another example, if the weather forecast data predicts a severe storm or weather event (e.g., a snowstorm, a hurricane, a tornado, etc.), the computerized control system may determine that the solar energy provider's power generation capacity may be impaired for an extended period of time (e.g., several days, etc.). In a further example, if the upcoming weather forecast data predicts little or no wind, the computerized control system may determine that the wind energy provider's power generation capacity may be limited during these predicted weather periods.

[0058] Additionally or alternatively, in embodiments, determining whether a predetermined condition is met may correspond to identifying whether an increased load is required on a power grid operator's power grid. In response to determining that the increased load required on the power grid is greater than a predetermined threshold, the predetermined condition may be deemed to be met. More specifically, in embodiments, various types of events may occur that place additional strain on the power grid. Some of these events may be scheduled, while others may not. For example, with regard to the former, a major local concert, sporting event, festival, etc. may require additional power to be supplied by the power grid. A computer control system may have access to schedules of these events and may predict which events may impose load demands on the power grid that are greater than a predetermined threshold. In another example, with regard to the latter, a weather phenomenon may occur that increases the load demand required on the power grid (e.g., an unexpected heat wave that may cause individuals to run air conditioners or fans more than usual, a cold snap that may cause people to use more heat than usual, etc.). In such a situation, the computer control system may receive an indication (eg, from a power grid operator) or may determine that the load demand on the power grid is greater than a predetermined threshold.

[0059] Additionally or alternatively to the foregoing, in embodiments, determining whether a predetermined condition is met may correspond to identifying whether a power grid operator's power grid is becoming unstable. In embodiments, power grid instability may occur, for example, because various assets on which the power grid operator relies may fail (e.g., not with other power providers contracted to power the power grid). These assets may fail as a result of various circumstances, such as, for example, experiencing operational problems and damage resulting from weather, geographic, and / or other natural disaster phenomena (e.g., damage from fire, earthquake, flood, etc.). In embodiments, the predetermined condition may be deemed met in response to an expectation that the power grid will become unstable within or beyond a predetermined time threshold.

[0060] Additionally or alternatively, in embodiments, determining whether the predetermined condition is met may correspond to identifying whether a revenue projection from operating the system 100, 200 in the second operating mode is greater than a revenue projection from operating the system 100, 200 in the first operating mode. In response to determining that operating the system 100, 200 in the second operating mode is more profitable, the predetermined condition may be deemed met. As further described herein, the system 100, 200 may operate in a first or second operating mode. When in the second operating mode, the system 100, 200 may be configured to transfer power generated by the generator 236 to a power grid operator's power grid. In embodiments, the system 100, 200 may verify whether a first projected value accrued or obtained from sequestering and selling CO2 (e.g., total revenue from selling CO2 to a third party at a contract or spot price, carbon sequestration tax incentives, etc.) may be greater than a second projected value accrued from powering the power grid. In response to determining that a second mode of operation, for example, a mode of operation that transfers generated power to a power grid, has greater predictive value, the predetermined condition may be deemed satisfied.

[0061] In response to determining at step 410 that the predetermined condition is not met, the computerized control system may maintain the operating mode of the system in the first operating mode at step 415. Conversely, in response to determining at step 410 that the predetermined condition is met, the computerized control system may initiate a switch of the operating mode of the system 100, 200 from the first operating mode to a second operating mode at step 420. Upon switching to the second operating mode, the computerized control system may operate the system 100, 200 in the second operating mode to transfer energy from the DAC system to the power grid at step 425.

[0062] In embodiments, in the second operating mode, the system 100, 200 may output power generated by the generator 236 in electrical or mechanical form. For simplicity, much of this disclosure is described with reference to examples in which electrical power is output, and more specifically, with reference to situations in which the system 100, 200 may function as a power plant and be configured to send power generated by the generator 236 directly to a power grid operator's power grid, although any power output is contemplated. When switched to the second operating mode, the DAC system may be substantially turned off (i.e., only the fan necessary to reject heat from the CO2 stream at the bottom of the power cycle may be utilized), and syngas low-temperature vapor may be utilized to preheat any of the fluids in the power cycle. Alternatively to the foregoing, the second operating mode of the system 100, 200 may be an “intermediate” mode in which the system 100, 200 is configured to send a first portion of the energy generated by the generator 236 to components of the DAC system and a second portion of the energy to the power grid. In an embodiment, the system 100, 200 in intermediate mode may power only a subset of the air contact fans in the DAC bank 238, and the CO2 compressor 246 may operate at a lower power requirement depending on the desired amount of CO2 captured by the DAC system.

[0063] In embodiments, the switch in step 420 may be facilitated by actuating a series of valves configured to control the transfer of working fluid CO2 through the system 100, 200. More specifically, the valves may be used to route the CO2 heat flow to more contactors or coolers depending on the resulting operating mode. In embodiments, the system 100, 200 may be operable to alternate between two operating modes without altering the operation of the supercritical cycle. More specifically, the CO2 heat flow may be managed as the CO2 sorbent pack is regenerated to facilitate periodic or constant heat rejection in the sCO2 cycle. For example, switching the operating mode from a power plant mode or a power supply mode to a carbon sequestration mode may include multiple steps. In a power plant mode, in which energy is generated and may be output, for example, to a power grid, the power cycle may use a subset of fans to reject heat from the contactor bank. In response to detecting an indication to initiate a mode switch, the system 100, 200 may begin sending more power to the DAC bank 238 (e.g., in a controlled manner according to architectural considerations established by the DAC system). As more power is sent from the power grid to the DAC bank 238, the amount of air purification performed by the system 100, 200 may increase accordingly. While air purification is occurring, CO2 working fluid from the cycle may be sent to the contactors. Additionally or alternatively, heat may also be sent to the DAC bank 238 from at least the low-temperature heat exchanger 220 (i.e., the syngas cooling system). Upon detecting that a predetermined number of contactors in the DAC bank 238 are saturated with CO2 from the atmosphere, the system 100, 200 may be configured to dynamically remove at least one fan subset from operation and begin heating the sorbent to a predetermined temperature using conduction, thereby rejecting its heat to the sorbent and initiating the process of releasing CO2. Supplementary cooling of the CO2 working fluid in the cycle can be achieved by sending the CO2 working fluid to another saturated sorbent bank in series (if required).More and more power can be sent to the DAC bank 238 until all power is sent to the DAC bank 238 and the system is in carbon sequestration mode.

[0064] In the opposite scenario, the system 100, 200 may begin switching from carbon sequestration mode to power plant mode. Upon detecting this switch initiation, the system 100, 200 may begin reducing power to the fan modules in the DAC bank 238, turning the fan bank off, thereby reducing the air purification potential of the system 100, 200. When the system switches to carbon sequestration mode and power to the fan modules is reduced, heat rejection may be concentrated in a subset of contactors that can be saturated with CO. For example, valves may be used to route hot CO between separate fan modules in the DAC bank 238 (which preheats and regenerates the sorbent). When switching to power plant mode, one or more valves may be repeatedly closed to continue directing CO flow only to the condenser fan and not to the DAC bank 238. As the amount of CO purified decreases, less and less power may be sent to the DAC bank 238 until the DAC bank 238 is shut down. In some embodiments, when the air purification potential of the contactors is determined to be below a predetermined threshold, power to the DAC bank 238 may be terminated. Once steady-state power regeneration is achieved, the heat load of the power cycle may then be drained and the power previously utilized to power the contactor fans in the DAC bank 238 may be transferred to the power grid.

[0065] The exemplary switching process described above enables the systems 100, 200 to operate during "peaker" periods when electricity costs are high. More specifically, gas combined cycle power plants and / or coal power plants may require a long start-up period when turned on before they are ready to supply power to the power grid. As a result, they must consume fuel for an extended period of time before any power can be supplied to the power grid. This results in both additional CO2 and other forms of pollution being released into the atmosphere by the conventional power plants, as well as wasted fuel, resources, and ultimately money, such as coal. For the reasons described above, because renewable energy sources can generate power for the power grid at a lower cost compared to conventional gas or coal power plants, it may be impractical for conventional power plant owners to operate their conventional power plants throughout the day. As a result, for example, at the end of the day, when renewable power sources may be unavailable or available in small amounts, the conventional power plants may need to be turned off and then back on again. The need to be online for only part of the day, combined with long start-up times, can result in wasted energy and resources, as well as excessive pollution.

[0066] However, systems 100 and 200 may address one or more of these shortcomings by providing an integrated power generation and carbon capture system configured to function continuously or for longer periods of time, either as a power plant to power a power grid or as a carbon sequestration system. By allowing systems 100 and 200 to operate continuously and switch between a power plant and a carbon sequestration system, the CO2 cycle system components can continue to operate even when not powering the power grid, simply by redirecting the load, thereby avoiding or mitigating the start-up penalties experienced by conventional power plants in terms of engine component emissions or lifespan. Thus, the disclosed systems may conserve resources, reduce pollution, such as CO2 emissions, and provide a carbon-negative method of power generation. Systems 100 and 200 may achieve carbon-negative power generation by using biomass as fuel and CO2 as the working fluid, and when a DAC system is incorporated, the system may function as even more carbon-negative.

[0067] Products of the systems described herein (e.g., heat, water, syngas, etc.) may be described as being recycled within the system to promote the efficiency of the system, although recycling of the products is not required.

[0068] The time period for facilitating the switch from the first operating mode to the second operating mode at step 420 or the time period for facilitating the switch from the second operating mode to the first operating mode at step 440 may vary. For example, in embodiments, the computer controller system may cause the system 100, 200 to switch operating modes within a first “normal” time period, such as one hour or less. Alternatively, some situations may require facilitating the switch more quickly (e.g., if a sudden load demand occurs on the power grid, if the power grid is on the verge of instability, etc.). In these situations, the system 100, 200 may undergo a “brupt switch” from carbon sequestration mode to power supply mode in a matter of minutes. However, this type of abrupt switch may result in the loss of captured CO2 midway through the process or at the expense of the long-term life of components.

[0069] At step 430, the computer control system may determine whether the predetermined condition is no longer satisfied. This determination may vary based on the type of predetermined condition, as described below.

[0070] In embodiments, the predetermined condition may be deemed no longer satisfied in response to a determination that the power grid operator has access to another type of renewable energy. In embodiments, this determination may be facilitated by receiving a second indication from the timer or sensor. More specifically, just as the timer or sensor provided an indication to the computerized control system to switch from the first operating mode to the second operating mode at a predetermined time, the timer or sensor may similarly provide a second indication to the computerized control system to switch from the second operating mode to the first operating mode. For example, the second indication may be received at a scheduled predetermined time. Like the first indication, the receipt of the second indication may be static (e.g., provided at the same time each day) or dynamic (e.g., provided at different times throughout the year based on conditions). Additionally or alternatively, in another embodiment, the determination may be facilitated by utilizing historical sunshine data for the relevant geographic area to identify a sunrise time, which may be associated with the power grid operator's ability to receive another type of renewable energy, such as solar energy. Additionally or alternatively, in another embodiment, the determination may be facilitated by utilizing weather forecast data to identify whether upcoming weather conditions may be favorable for generating a particular type of renewable energy. For example, the weather forecast may indicate whether the next day is likely to be sunny or windy, which may be favorable for solar or wind energy generation, respectively.

[0071] In embodiments, in response to a determination that the power grid no longer requires the previously required increased load, the predetermined condition may be deemed no longer satisfied. In embodiments, this determination may be facilitated by identifying that the increased load has fallen below, or is expected to fall below, a predetermined threshold. In some aspects, the computerized control system may receive an indication from a power grid operator that there is a need for additional power, or that there is no longer a need for additional power. Additionally or alternatively, the computerized control system may predict when the power grid will no longer require additional power. For example, the computerized control system may identify a designated end time for a scheduled load-generating event (e.g., a concert, sporting event, festival, etc.) from available schedule information. As another example, the computerized control system may dynamically predict the end of a scheduled load-generating event based on access to historical contextual data (e.g., the computerized control system may predict the end of a concert based on knowledge of previous concert performances in general or the length of time that previous performances of a particular performance have run). With respect to a weather event that creates a strain on the power grid, the computer control system may identify that the expected end of the weather event may remove the strain on the power grid, and thus the need for additional power. For example, once a heat wave ends, individuals may resume their normal habits with respect to the operation of energy-consuming devices (e.g., individuals may no longer run air conditioners or fans as usual).

[0072] In embodiments, in response to a determination that the power grid has stabilized, the predetermined condition may be deemed no longer satisfied. In embodiments, this determination may be facilitated by receiving an indication from the power grid operator that the failed asset causing the power grid instability has been repaired and / or is now operational again (e.g., another power provider contracted to power the power grid has updated its ability to supply power to the power grid, etc.). Additionally or alternatively, in another embodiment, the determination may be dynamically facilitated by predicting the period of time during which the failed asset may be unavailable based on knowledge of the operational issue that caused the asset to become unavailable and / or weather, geographic, and / or natural disaster phenomena. For example, the computerized control system may identify that a particular operational issue affecting a power plant may be resolved within X period of time, the end of which may approximately correspond to the stabilization of the power grid. In another example, the computerized control system may estimate from weather data and / or historical event data the amount of time until the asset may again become operational after the event that caused the asset failure has ended.

[0073] In another embodiment, the predetermined condition may be deemed no longer satisfied in response to a determination that the predicted value of operating the system 100, 200 in the second mode of operation is lower than the predicted value of operating the system 100, 200 in the first mode of operation. In other words, the predetermined condition may be deemed no longer satisfied in response to a determination that operating the system 100, 200 in the second mode of operation provides less value to society, e.g., less profit, than operating the system 100, 200 in the first mode of operation. In an embodiment, this determination may be facilitated by identifying that the predicted value resulting from sequestration and sale of CO2 is lower than the predicted value of powering the grid (e.g., due to an increase in the spot price for selling CO2).

[0074] In response to determining at step 430 that the predetermined condition is still met, the system may maintain the system 100, 200 in the second mode of operation at step 435. In an embodiment, the second mode of operation may be maintained as long as the predetermined condition is still met. Alternatively, in another embodiment, the second mode of operation may be maintained only for a predetermined period of time, or only until a predetermined amount of power is supplied to the power grid, regardless of whether the predetermined condition is still met.

[0075] In response to determining at step 430 that the predetermined condition is no longer satisfied, the system 100, 200 may initiate a switch of operating modes from the second operating mode to the first operating mode at step 440. The method 400 may be repeated multiple times during operation of the system 100, 200. This switching may allow the system 100, 200 to cycle back and forth between the two operating modes based on the demands of a particular situation or based on what is most beneficial to the system (e.g., value in terms of operating costs, revenue generation, carbon capture, power generation, etc.).

[0076] Provided below are several alternative systems that can be used as system 100 in place of system 200 to perform carbon sequestration and power generation. Each of these alternative systems includes one or more variations to the components and / or process operations detailed in system 200 of FIG. 2 and may be used in a manner similar to or compatible with system 200 described herein. For example, FIGS. 5, 6, and 7 may be used to perform the method of FIG. 4 and may be used as described above with respect to system 200. Additionally, while the portions of the systems described herein each specify components from which heat can be removed and components to which heat can be sent, these are not necessarily limiting, and heat may be removed from any of the system's components and / or from the generated syngas and sent to portions of the system that require heat to function.

[0077] Referring now to FIG. 5, an exemplary integrated carbon sequestration and power generation system 500 is shown. System 500 may use biomass as a fuel. As discussed with respect to systems 100 and 200 above, biomass refers to any carbon-neutral or carbon-negative fuel. For example, potential types of biomass may include, for example, wood products such as wood processing waste (e.g., firewood, wood pellets, wood chips, lumber and sawdust waste, etc.), agricultural products including crops and waste materials (e.g., corn, soybeans, sugarcane, woody plants, algae, etc.), biological materials in municipal solid waste (e.g., paper, cotton, wool products, food, yard waste, etc.), non-biological materials in municipal solid waste (e.g., plastics or petroleum-based products), animal manure, or human wastewater (e.g., biowaste discharge from a water treatment plant). In an embodiment, suitable biomass may be pretreated, for example, by a torrefaction process performed in torrefaction reactor 502. However, in other embodiments, previously torrefied or otherwise pretreated or untreated biomass may be received by system 500, and system 500 may not include torrefaction reactor 502.

[0078] If a torrefaction process is incorporated into system 500, the torrefaction process may include drying the biomass and heating the biomass in an oxygen-deficient environment. When the biomass reaches approximately 250-350°C, the reaction becomes exothermic, and the products of the reaction may include water, oxygen, nitrogen, and VOCs in the biomass. The VOCs may be combusted to generate heat for drying and initiating the biomass reaction (combustion may occur in pure oxygen or air).

[0079] In aspects, biomass may exit torrefaction reactor 502 (if included) in a state that is easy to pulverize and contains other beneficial properties, such as increased carbon content density. This torrefied biomass may be fed to comminution system 504, which may be configured to pressurize the biomass, for example, via lock hopper 506, and prepare the biomass for conveyance to injector 508, which then conveys the pulverized torrefied biomass to gasifier 510, where the biomass is partially oxidized and separated into its constituent components, for example, using oxygen obtained from at least air separation unit 512. The CO may then be pressurized. In embodiments, the primary gaseous products of the foregoing reaction include hydrogen (H), carbon monoxide (CO), and carbon dioxide (CO), along with trace amounts of materials formed by trace elements in the biomass. Solid products that cannot be gasified during the reaction may be collected at the bottom of the gasifier 510 as molten slag, which may include solid elements and compounds within the plant biomass, such as potassium, among others.

[0080] In embodiments, after the syngas is formed, it may be quenched to cool it down to a usable temperature. Such a process may be facilitated by introducing water or CO from the primary cycle into the gasifier 510, which may allow for the formation of a non-liquid ash on the condensable materials. After the syngas exits the reactor, the water may be removed, but the CO may be retained with the CO stream for oxy-fuel combustion purposes and expansion in a downstream turbine system. In fully pressurized systems, the aforementioned water removal step may not be necessary. To produce a clean syngas that burns cleanly and does not adversely affect machinery downstream of the primary combustion system, the syngas may be processed in one or more scrubbers, candle filters, and / or other available gas processing systems upon exiting the gasification reactor vessel 510. The syngas may then be fully oxidized (e.g., by an oxygen stream directed from the air separation unit 512) in the primary combustion system (e.g., the oxy-fuel combustor 514), thereby producing a stream primarily of water and CO. This stream may be mixed with a primarily CO2 recycle stream that has passed through regenerator 516 and preheated to a temperature suitable for the cycle to have acceptable thermodynamic efficiency. The combustion stream may be diluted and then expanded in a first turbine stage (e.g., high-pressure turbine 518) that powers a main cycle recirculation pump 522. After that turbine expansion, the CO2 stream may be injected into another set of turbine stages (e.g., low-pressure turbine 520) and fully expanded to its lowest pressure level in the cycle. This may power a generator / alternator 524 that is mechanically attached to the system.

[0081] In embodiments, once the combined recycle and combustion streams are expanded, they may pass through one or more heat exchanger(s) (e.g., heat exchanger(s) located in a “regenerator” section, such as regenerator 516). This may allow the stream to exchange heat with the discharge stream of high-pressure cycle pump 522, which is then sent to primary combustor system 514 to be heated. The CO stream from the turbine loses most of its water in the heat exchanger system. The CO stream is then sent to cooling bank 526 to return the temperature of the CO stream to near ambient temperature, removing the remaining heat, before siphoning off the amount of CO produced in the combustion process via three-way valve 528 or other suitable mechanism. This CO stream may then be inserted into a pipeline at 530 for transport to an underground storage location, such as a well. In other embodiments, the CO may be liquefied for transport via highway into the well.

[0082] In an embodiment, the cooling bank system 526 can reject heat at a given temperature suitable for use in direct-air carbon sequestration sorbent regeneration. The cooling bank system can be interconnected with a bank of sorbent material 532, which can be a solid sorbent material (e.g., metal-organic frameworks (MOFs), zeolites, silica, activated carbon, etc.) and / or a liquid sorbent material, such as an aqueous inorganic base or aqueous organic amine, that can effectively adsorb, or absorb, and store atmospheric CO2 but has a low temperature, i.e., requires a lot of energy to regenerate CO2. Once the sorbent system captures CO2 from the atmosphere via a series of fans, the sorbent material bank can be heated using the CO2 flow to regenerate the system. The series of fans is configured to cool the sorbent system and capture CO2 from the air by contacting the sorbent system with air in an absorption cycle. The sorbent material can be vented using waste heat from a CO2-powered system. The fan and compression train for the captured CO2 may use energy in the form of electricity from the turbine expander. Condensate released from the sorption material may be fed to pump 534 and returned to high-pressure cycle pump 522 via passage through three-way valve 528 or other suitable device, where it may be pressurized and fed to regenerator 516 and to oxy-fuel combustor 514 as a recycle stream.

[0083] Referring now to FIG. 6, an exemplary carbon sequestration and power generation system 600 configured for high-temperature heat recovery is shown. In some embodiments, the components and process flow within system 600 may be substantially equivalent to system 200 downstream of the oxy-fuel combustor. However, system 600 may include two heat exchangers disposed in the syngas line. The first heat exchanger may be a high-temperature heat exchanger disposed upstream of the scrubber and configured to heat the syngas after it is conditioned from the gasifier. This heating process may be used, for example, to increase the heat input to a CO2 cycle (such as a supercritical CO2 cycle) via a discharge stream from the first heat exchanger to the primary combustor. The first high-temperature heat exchanger disposed upstream of the scrubber may enable high-quality heat delivery to the top end of cycle 600. The second heat exchanger may be a low-temperature heat exchanger disposed downstream of the scrubber and configured to remove water in the syngas by quenching. This process produces steam that can be used to regenerate the DAC recovery cryogenic sorbent. In embodiments, the heat removed from the first and second heat exchangers can be transferred to other components of system 600 according to electrical or carbon sequestration energy needs.

[0084] In system 600, biomass, for example, any carbon-neutral or carbon-negative fuel (such as agricultural produce or waste, timber, trees, or undergrowth removed from forests, other organic waste, other municipal waste, and any combination of the foregoing, as described above), may be fed from biomass conveying system 602 to feed hopper 604, which may be configured to convey the biomass into gasifier 606, for example, at a controlled, predetermined feed rate.

[0085] Any suitable type of gasifier 606 may be utilized in system 600, such as a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier type. Biomass fed to gasifier 606 may react with oxygen (O) and injected steam in a gasification reaction. In an embodiment, oxygen may be supplied to gasifier 606 from air separation unit 608, for example, via pump 610. Air separation unit 608 may separate air into its constituent components using, for example, vacuum pressure swing adsorption (VPSA) or temperature swing adsorption (TSA) techniques. In another embodiment, oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, air separation unit 608 may be a cryogenic system. In yet another embodiment, oxygen may be obtained from a dedicated oxygen delivery service or pipeline. In an embodiment, as described further herein, the injected steam may be obtained from the syngas condensate and supplied to the gasifier 606 from a "second" heat exchanger, such as low-temperature heat exchanger 612, via pump 614. The product of the foregoing reaction is a syngas mixture including gaseous hydrogen (H), carbon monoxide (CO), and CO, along with trace amounts of materials formed as a result of trace elements in the biomass. Solid products that cannot be gasified during the reaction are collected at the bottom of the gasifier 606 as molten slag and ash (e.g., fly ash, bottom ash, etc.).

[0086] The syngas formed via the gasification reaction may then be sent to a "first" heat exchanger, such as high temperature heat exchanger 616, which may be configured to heat the syngas. This heated syngas may be passed to a scrubber 618 configured to process the syngas, where it may be processed to remove water and / or other ash particulates and halogen compounds from the syngas stream to produce a syngas that is clean burning and does not adversely affect machinery downstream of the primary combustion system.

[0087] After exiting the scrubber 618, the purified syngas may pass through a low-temperature heat exchanger 612. The low-temperature heat exchanger 612 may be configured to remove water within the syngas by quenching. The syngas may be sent to a pump 614 and reinjected into the gasifier 606. This process may thus use energy from the condensation to generate steam used to regenerate the DAC recovery low-temperature sorbent and / or for steam injection into the gasifier 606.

[0088] After exiting the low-temperature heat exchanger 612, the syngas stream may be compressed to full pressure, if necessary, for example, by a syngas boost compressor 620. After compression, the compressed syngas may be sent back to the high-temperature heat exchanger 616, heated, and then utilized to increase the heat input to a CO2 cycle (such as a supercritical CO2 cycle), for example, via a discharge stream from the high-temperature heat exchanger 616 to a combustor 622.

[0089] In an embodiment, combustor 622 may be a biosyngas oxy-combustor. The syngas fed to combustor 622 may be fully oxidized (e.g., with an oxygen stream derived from air separation unit 608 and compressed via oxygen boost compressor 624), thereby producing a stream primarily of water and CO. The stream resulting from the oxidation reaction between the syngas and the oxygen stream may be mixed within combustor 622 with a recycle stream primarily of CO. The recycle stream of CO may pass through regenerator heat exchanger 626 to preheat regenerator heat exchanger 626 to a suitable temperature for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power remains to run all supplemental power requirements of system 600).

[0090] In an embodiment, the combustion stream exiting combustor 622 may be expanded in one or more turbines, such as a first turbine 628 (e.g., a high-pressure turbine). High-pressure turbine 628 may be a direct-fired turbine and may be designed to efficiently extract work from the high-pressure combustion stream, which may then be utilized to power a main cycle recirculation pump 630. The turbine exhaust from high-pressure turbine 628 may be routed to a second turbine 632 (e.g., a low-pressure turbine). The low-pressure turbine expansion may power a generator 634 (i.e., a turbine alternator), which may be mechanically attached to the rotor of low-pressure turbine 632 and low / intermediate-pressure compressor 636.

[0091] The energy generated by generator 634 may be utilized in a variety of different ways depending on the operating mode of system 600. For example, in a first operating mode, system 600 may function as a power plant, and power generated by generator 634 may be output from system 600. In a second operating mode, system 600 may function as a CO2 capture system, and power generated by generator 634 may be utilized to power components of a DAC system (e.g., air contact fans and compressors). In a third operating mode, system 600 may be configured to distribute power from generator 634 to both the power grid and the DAC system.

[0092] The low-pressure turbine discharge stream may then be passed to a regenerator heat exchanger 626. A recycled CO stream from a high-pressure recirculation pump 630 may also be introduced into the regenerator heat exchanger 626. This allows the low-pressure turbine discharge stream to exchange heat with the recycled CO stream pumped from the high-pressure recirculation pump 630, whereby the recycled CO stream is routed to the primary combustor 622 for heating and the secondary turbine discharge stream is routed to the DAC fan bank 638 for cooling. In various embodiments, the heat of the CO stream passing through the regenerator heat exchanger 626 may be used to boil water in the low temperature range of the regenerator heat exchanger 626.

[0093] The cooled second turbine discharge stream may be sent through the DAC fan bank 638. The DAC fan bank 638 may be configured to reject heat at a given temperature suitable for use in direct-air carbon sequestration sorbent regeneration. The cooling bank system may be interconnected with a bank of sorbent material, which may be solid sorbent materials (e.g., metal-organic frameworks (MOFs), zeolites, silica, activated carbon, etc.) and / or liquid sorbent materials, such as aqueous inorganic bases or aqueous organic amines, that can effectively adsorb or absorb and store atmospheric CO2 but have low temperatures, i.e., require a lot of energy to regenerate the CO2. In the release cycle, the cooled second turbine discharge stream may be used to heat (e.g., via conduction) the sorbent material in the DAC bank 638. This preheating allows the sorbent material to receive steam generated from the syngas heat rejected by the low-temperature heat exchanger 612. This steam may be used to remove CO2 gas from the sorbent material.

[0094] The liberated CO2-containing stream is passed through condenser 640, where water in the liberated CO2-containing stream is removed, and sent back to low-temperature heat exchanger 612 via pump 642 for use in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in CO2 compressor 644 and sent to a pipeline via valve 646 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated geological storage site. For example, the CO2 may be transported to well 248, which may be a Class VI well. In another embodiment, the pipeline may transport the sequestered CO2, for example, to one or more other contracting entities.

[0095] In embodiments, the cooled CO stream passes through a direct air recovery bank 638 before being transferred to a low / intermediate pressure compressor 636, where it passes through a critical point, and in some embodiments, forms sCO, before being injected into a high-pressure recirculation pump 630, which is configured to increase the pressure of the CO stream to the combustion injection pressure. In embodiments, one or both of the cooled CO stream exiting the DAC bank 638 and the compressed CO stream exiting the low / intermediate pressure compressor 636 may be cooled by a separate chiller 650 to increase efficiency. The recirculation pump discharge stream may then be heated by passing through a regenerator heat exchanger 626 before being recycled back to the combustor 622. In an embodiment, the CO produced in the combustion process may be siphoned off through a three-way valve or other suitable flow control mechanism (e.g., through an orifice plate configured to reduce the amount discharged, or through a leakage passage in the main pump flow area, etc.) at a pressure that is ready for pipeline injection or liquefaction transfer through a highway (e.g., routed by valve 652 or other suitable flow control mechanism) to well 648.

[0096] 7, an exemplary carbon sequestration and power generation system 700 configured for low-temperature heat recovery is shown. In this configuration, only one heat exchanger is provided after the scrubber, and this heat exchanger is configured to remove syngas heat to generate steam used to regenerate the DAC recovery low-temperature sorbent. This may enhance or maximize DAC recovery capacity.

[0097] In system 700, biomass, for example, any carbon-neutral or carbon-negative fuel (such as agricultural produce or waste, timber, trees, or undergrowth removed from forests, other organic waste, other municipal waste, and any combination of the foregoing), may be fed from a biomass conveying system 702 to a feed hopper 704, which may be configured to convey the biomass into a gasifier 706, for example, at a controlled, predetermined feed rate.

[0098] Any suitable type of gasifier 706 may be utilized in system 700, such as a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier type. Biomass fed to the gasifier 706 may react with oxygen (O) and injected steam in a gasification reaction. In an embodiment, oxygen may be supplied to the gasifier 706 from an air separation unit 708 via a pump 710. The air separation unit 708 may separate air into its constituent components using, for example, vacuum pressure swing adsorption (VPSA) or temperature swing adsorption (TSA) techniques. In another embodiment, oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, the air separation unit 708 may be a cryogenic oxygen system. In yet another embodiment, oxygen may be obtained from a dedicated oxygen delivery service or pipeline. In an embodiment, as further described herein, injected steam may be obtained from syngas condensate and supplied to the gasifier 706 from a cryogenic heat exchanger 712 via a pump 714. The product of the foregoing reaction is a syngas mixture containing gaseous hydrogen (H), carbon monoxide (CO), and CO, along with trace amounts of materials formed as a result of trace elements in the biomass. Solid products that cannot be gasified during the reaction are collected at the bottom of the gasifier 706 as molten slag and ash (e.g., fly ash, bottom ash, etc.).

[0099] The syngas formed via the gasification reaction may then be passed to a scrubber 716 configured to process the syngas, where it may be processed to remove water and / or other ash particulates and halogen compounds from the syngas stream to produce a syngas that is clean-burning and does not adversely affect machinery downstream of the primary combustion system.

[0100] After exiting the scrubber 716, the purified syngas may pass through a low-temperature heat exchanger 712. The low-temperature heat exchanger 712 may be configured to remove water within the syngas by quenching. The syngas may be sent to a pump 714 and reinjected into the gasifier 706. This process may thus use energy from the condensation to generate steam used to regenerate the DAC recovery low-temperature sorbent and / or for steam injection into the gasifier 706.

[0101] After exiting the low-temperature heat exchanger 712, the syngas stream may be compressed to full pressure, if necessary, by, for example, a syngas boost compressor 718. After compression, the compressed syngas may be introduced into a combustor 720.

[0102] In an embodiment, combustor 720 may be a biosyngas oxy-combustor. The syngas fed to combustor 720 may be fully oxidized (e.g., with an oxygen stream derived from air separation unit 708 and compressed via oxygen boost compressor 722), thereby producing a stream primarily of water and CO. The stream resulting from the oxidation reaction between the syngas and the oxygen stream may be mixed within combustor 720 with a recycle stream primarily of CO. The recycle stream of CO may pass through regenerator heat exchanger 724 to preheat regenerator heat exchanger 724 to a suitable temperature for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power remains to run all supplemental power requirements of system 700).

[0103] In an embodiment, the combustion stream exiting the combustor 720 may be expanded in one or more turbines, such as a first turbine 726 (e.g., a high-pressure turbine). The high-pressure turbine 726 may be a direct-fired turbine and may be designed to efficiently extract work from the high-pressure combustion stream, which may then be utilized to power a main cycle recirculation pump 728. The turbine exhaust from the high-pressure turbine 726 may be routed to a second turbine 730 (e.g., a low-pressure turbine). The low-pressure turbine expansion may power a generator 732 (e.g., a turbine alternator), which may be mechanically attached to the rotor of the low-pressure turbine 730 and the low / intermediate-pressure compressor 734.

[0104] The energy generated by generator 732 may be utilized in a variety of different ways depending on the operating mode of system 700. For example, in a first operating mode, system 700 may function as a power plant, and power generated by generator 732 may be output from system 700. In a second operating mode, system 700 may function as a CO2 capture system, and power generated by generator 732 may be utilized to power components of a DAC system (e.g., air contact fans and compressors). In a third operating mode, system 700 may be configured to distribute power from generator 732 to both the power grid and the DAC system.

[0105] The low-pressure turbine discharge stream may then be passed to a regenerator heat exchanger 724. A recycled CO stream from a high-pressure recirculation pump 728 may also be introduced into the regenerator heat exchanger 724. This allows the low-pressure turbine discharge stream to exchange heat with the recycled CO stream pumped from the high-pressure recirculation pump 728, whereby the recycled CO stream is routed to the primary combustor 720 for heating and the secondary turbine discharge stream is routed to the DAC fan bank 736 for cooling. In various embodiments, the heat of the CO stream passing through the regenerator heat exchanger 724 may be used to boil water in the low temperature range of the regenerator heat exchanger 724.

[0106] The cooled second turbine discharge stream may be sent through a DAC fan bank 736. The DAC fan bank 736 may be configured to reject heat at a given temperature suitable for use in direct-air carbon sequestration sorbent regeneration. The cooling bank system may be interconnected with a bank of sorption material, which may be a solid sorption material (e.g., metal-organic frameworks (MOFs), zeolites, silica, activated carbon, etc.) and / or a liquid sorption material, such as an aqueous inorganic base or an aqueous organic amine, that can effectively adsorb or absorb and store atmospheric CO2 but has a low temperature, i.e., requires a lot of energy to regenerate the CO2. In the release cycle, the cooled second turbine discharge stream may be used to heat (e.g., via conduction) the sorption material in the DAC bank 736. This preheating allows the sorption material to receive steam generated from the syngas heat rejected by the low-temperature heat exchanger 712. This steam may be used to remove CO2 gas from the sorption material.

[0107] The liberated CO2-containing stream is passed through condenser 738, where water therein is removed, and sent back to low-temperature heat exchanger 712 via pump 740 for use in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in CO2 compressor 742 and sent to a pipeline via valve 744 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated geological storage site. For example, the CO2 may be transported to well 746, which may be a Class VI well. In another embodiment, the pipeline may transport the sequestered CO2, for example, to one or more other contracted entities.

[0108] In embodiments, the cooled CO stream passes through a direct air recovery bank 736 before being transferred to the low / intermediate pressure compressor 734, where it passes through a critical point to, in some embodiments, form sCO, before being injected into a high-pressure recirculation pump 728, which is configured to increase the pressure of the CO stream to the combustion injection pressure. In embodiments, one or both of the cooled CO stream exiting the DAC bank 736 and the compressed CO stream exiting the low / intermediate pressure compressor 734 may be cooled by a separate chiller 748 to increase efficiency. The recirculation pump discharge stream may then be heated by passing through a regenerator heat exchanger 724 before being recycled back to the combustor 720. In an embodiment, CO2 produced in the combustion process may be siphoned off through a three-way valve or other suitable flow control mechanism (e.g., through an orifice plate configured to reduce the amount discharged, or through a leakage passage in the main pump flow area, etc.) at a pressure that is ready for pipeline injection or liquefaction transfer through a highway (e.g., routed by valve 750 or other suitable flow control mechanism) to well 746.

[0109] As previously mentioned, the exemplary integrated carbon sequestration and power generation systems described herein may incorporate a Rankine cycle as the thermodynamic power cycle 110 (FIG. 1). A typical Rankine cycle may have a backpressure sufficiently below ambient pressure so that the temperature of the condensed water is near room temperature, promoting the efficiency of the system. The condensation of water releases a large amount of heat. The pressure in such systems tends to be around 0.1 bar (0.01 MPa), which puts the saturation temperature near normal ambient temperature.

[0110] Embodiments of the present disclosure that include a Rankine cycle as the thermodynamic power cycle may vary the backpressure of the steam turbine in the integrated carbon sequestration and power generation system from about 0.5 bar (0.05 MPa) to about 1.0 bar (0.1 MPa), for example, about 1 bar (0.1 MPa). At about 1 bar (0.1 MPa), the saturation temperature is 100 degrees Celsius, and constant-temperature heat rejection occurs until all steam condenses into water. As a result, maintaining the backpressure of the steam turbine at about 1 bar (0.1 MPa) may advantageously allow the sorbent temperature in the DAC portion of the integrated system to reach 100 degrees Celsius during regeneration. Thus, in some exemplary systems of the present disclosure, the backpressure of the steam turbine may be selected to target the required temperature of the sorbent, and steam may be diverted around a second steam turbine to match the amount of electrical and thermal power required by the DAC system. For example, a first portion of the steam passing through a first steam turbine can be used to regenerate the sorbent in an integrated DAC system, and a second portion of the steam (e.g., the remaining steam) can continue through a second steam turbine to reach normal Rankine backpressure. These two streams can be combined after a pump repressurizes the condensed 0.1 bar (0.01 MPa) water.

[0111] 8A and 8B and Table 2 above, plots are provided to illustrate the benefits of the pressure and temperature ranges described herein. One potential advantage of the system embodiments described herein is the ability to adjust the power output in the cycles generated by systems 100, 200, 500, 600, and 700 while maintaining the turbine machinery "as designed" by adjusting the pressure on the streams. For example, if the power output of the system needs to be reduced, CO2 can be flushed out of the system more quickly, resulting in a corresponding pressure drop. As an example of the foregoing, if CO2 is removed so that the suction pressure of the low-pressure compressor is about 20 bar (2.0 MPa), the discharge pressure of the high-pressure compressor will be about 96 bar (9.6 MPa), thereby reducing power generation by about 40%. This capability allows for flexibility with respect to gasification output, power demand, and the like.

[0112] Furthermore, as the temperature of the system increases, the pressure must increase accordingly to maintain the regenerator temperature. This can result in higher efficiency while using essentially the same cycle. For example, in this case, the bottom pressure is held at about 35 bar (3.5 MPa), but if a variant that operates at higher efficiency is desired, the compression can be increased, and subsequently the temperature can be increased. As a result, in the embodiments of the present disclosure described herein, efficiency can be increased by increasing the discharge pressure and combustor temperature, but the cycle is generally equivalent.

[0113] Generally, any computer-implementable process discussed in this disclosure may be performed manually or by one or more processors of a computer system. Processes or process steps performed by one or more processors may also be referred to as operations. One or more processors may be configured to perform such processes by accessing instructions (e.g., software or computer-readable code) that, when executed by one or more processors, cause the one or more processors to perform a process. The instructions may be stored in a memory of a computer server. The processor may be a central processing unit (CPU), a graphics processing unit (GPU), or any suitable type of processing device.

[0114] A computer system, such as a computer control system associated with any of systems 100, 200, 500, 600, and 700, may include one or more computing devices. If one or more processors of the computer system are implemented with multiple processors, the multiple processors may be included in a single computing device or may be distributed across multiple computing devices. If the system environment includes multiple computing devices, the memory of the computer system may include each memory of each computing device of the multiple computing devices.

[0115] FIG. 9 is a simplified functional block diagram of a computer system 900, which may be configured as a computing device for executing the process illustrated in FIG. 4 and / or may be compatible with any of systems 100, 200, 500, 600, and 700 according to exemplary embodiments of the present disclosure. FIG. 9 is a simplified functional block diagram of a computer that may be configured according to exemplary embodiments of the present disclosure. In various embodiments, any of the systems herein may be a hardware assembly including a data communication interface 920, e.g., for packet data communication. The platform may also include a central processing unit (“CPU”) 902 in the form of one or more processors for executing program instructions. The platform may include an internal communication bus 908 and a storage unit 906 (e.g., ROM, HDD, SDD, etc.) that may store data on a computer-readable medium 922, while the system 900 may receive programming and data (e.g., voice, video, audio, images, or any other data via electronic network 925) by network communication via electronic network 925. The system 900 may also have a memory 904 (such as a RAM) that stores instructions 924 for executing the techniques presented herein, although the instructions 924 may also be stored temporarily or permanently in other modules of the system 900 (e.g., the processor 902 and / or the computer-readable medium 922). The system 900 may also include input / output ports 912 and / or a display 910 for connecting input / output devices such as a keyboard, mouse, touchscreen, monitor, display, etc. Various system functions may be implemented in a distributed fashion across multiple similar platforms to distribute the processing load. Alternatively, a server may be implemented by appropriate programming of one computer hardware platform.

[0116] Program aspects of the technology may be considered a "product" or "article of manufacture," typically in the form of executable code and / or associated data, carried or embodied on some type of machine-readable medium. "Storage" type media includes any or all of the tangible memory of a computer, or processor, or its associated modules, such as various semiconductor memories, tape drives, and disk drives, which may provide non-transitory storage for software programming at any time. All or portions of the software may sometimes be communicated via the Internet or various other telecommunications networks. Such communication may enable, for example, loading of the software from one computer or processor to another, e.g., from an administrative server or host computer of a mobile communications network to a server computing platform and / or from a server to a mobile device. Thus, other types of media that may carry software elements include light waves, radio waves, and electromagnetic waves, which are used across physical interfaces between local devices via wired and optical terrestrial communications networks and via various air links. The physical elements that carry such waves, such as wired or wireless links, or optical links, may also be considered media that carry the software. As used herein, terms such as computer "readable medium" or machine "readable medium" refer to any medium that participates in providing instructions to a processor for execution, including but not limited to non-transitory, tangible "storage" media.

[0117] As will be understood by those skilled in the art, some embodiments described herein include some features and not others included in other embodiments, but it is meant that combinations of features from different embodiments are within the scope of the present invention and form different embodiments. For example, in the following claims, any of the claimed embodiments can be used in any combination.

[0118] Thus, while particular embodiments have been described, those skilled in the art will recognize that other and further modifications may be made to these embodiments without departing from the spirit of the present invention, and all such changes and modifications are intended to be claimed as being within the scope of the present invention. For example, functions may be added to or deleted from the block diagrams, and operations may be interchanged between functional blocks. Steps may be added to or deleted from the methods described within the scope of the present invention.

[0119] The subject matter disclosed above should be considered illustrative and not limiting, and the appended claims are intended to cover all such modifications, enhancements, and other embodiments that fall within the true spirit and scope of the present disclosure. Accordingly, the scope of the present disclosure should be determined by the broadest permissible interpretation of the following claims and their equivalents to the fullest extent permitted by law, and should not be restricted or limited by the foregoing detailed description. While various embodiments of the present disclosure have been described, it will be apparent to those skilled in the art that many more embodiments are possible within the scope of the present disclosure. Accordingly, the present disclosure should not be limited except in light of the appended claims and their equivalents.

Claims

1. 1. An integrated carbon sequestration and power generation system, comprising: a thermodynamic cycle configured to receive biomass and produce heat and power; a direct air capture (DAC) carbon sequestration system configured to receive at least a portion of the heat and at least a portion of the power produced by the thermodynamic cycle to facilitate carbon sequestration; 1. An integrated carbon sequestration and power generation system comprising:

2. 10. The integrated carbon sequestration and power generation system of claim 1, wherein the biomass comprises at least one of plant matter or municipal waste.

3. The sorbent material in the DAC carbon sequestration system absorbs carbon dioxide (CO ２ 10. The integrated carbon sequestration and power generation system of claim 1, comprising a solid or liquid sorbent configured to adsorb .

4. 4. The integrated carbon sequestration and power generation system of claim 3, wherein at least a portion of the heat produced by the thermodynamic cycle is utilized to regenerate the sorbent material after carbon capture.

5. 10. The integrated carbon sequestration and power generation system of claim 1, wherein the integrated carbon sequestration and power generation system is configured to supply at least a portion of the power generated by the thermodynamic cycle to a power grid separate from the integrated carbon sequestration and power generation system.

6. 6. The integrated carbon sequestration and power generation system of claim 5, wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode in which at least a portion of the power generated by the thermodynamic cycle is used to power a DAC carbon sequestration system and a second operating mode in which at least a portion of the power generated by the thermodynamic cycle is supplied to the power grid.

7. 7. The integrated carbon sequestration and power generation system of claim 6, wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode and a second operating mode based at least in part on whether a predetermined condition is determined to be met.

8. The integrated carbon sequestration and power generation system of claim 7 , wherein at least one of a sensor or a timer is used to determine if the predetermined condition is met.

9. 8. The integrated carbon sequestration and power generation system of claim 7, wherein determining whether the predetermined condition is met comprises receiving information from a power grid operator that the predetermined condition is met.

10. 8. The carbon sequestration and power generation integrated system of claim 7, wherein determining whether the predetermined condition is met comprises determining whether a power grid operator has access to renewable energy from a renewable energy provider.

11. The integrated carbon sequestration and power generation system of claim 7 , wherein determining whether the predetermined condition is met comprises assessing a weather forecast.

12. The integrated carbon sequestration and power generation system of claim 7 , wherein determining whether the predetermined condition is met comprises determining whether an increased load is required on the power grid.

13. 8. The integrated carbon sequestration and power generation system of claim 7, wherein determining whether the predetermined condition is met comprises determining whether a threshold number or type of power sources associated with the power grid are available.

14. 8. The integrated carbon sequestration and power generation system of claim 7, wherein determining whether the predetermined condition is met comprises determining whether a first predicted value derived from operation of the integrated carbon sequestration and power generation system in the first mode of operation is greater than or less than a second predicted value derived from operation of the integrated carbon sequestration and power generation system in the second mode of operation.

15. The integrated carbon sequestration and power generation system of claim 1 , wherein the power generation system includes at least one of a Brayton cycle, a regenerative Brayton cycle, or a Rankine cycle.

16. 1. An integrated carbon sequestration and power generation system, comprising: a gasifier configured to receive biomass and configured to produce syngas; The purified syngas, oxygen, and recycled carbon dioxide (CO ２ a combustor configured to generate a combustion stream from the gas flow; at least one turbine; the at least one turbine is operably coupled to a direct air capture (DAC) carbon sequestration system and to a high pressure recirculation pump, and power generated by the at least one turbine is supplied to the DAC carbon sequestration system or to a power grid separate from the integrated carbon sequestration and power generation system, optionally or simultaneously. Carbon sequestration and power generation integrated system.

17. 17. The integrated carbon sequestration and power generation system of claim 16, wherein the biomass is torrefied biomass.

18. 17. The integrated carbon sequestration and power generation system of claim 16, further comprising a scrubber fluidly connected to the gasifier and configured to clean the syngas.

19. 20. The integrated carbon sequestration and power generation system of claim 18, further comprising a low temperature heat exchanger fluidly connected to the scrubber and configured to cool the purified syngas.

20. 17. The integrated carbon sequestration and power generation system of claim 16, wherein the power generation system comprises at least one of a Brayton cycle, a regenerative Brayton cycle, or a Rankine cycle.

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