System and method for carbon capture

Abstract

A system includes a compression system having a first gas inlet configured to receive a gas from a gas turbine system. The compression system also includes a first compressor configured to compress the gas to a pressure above atmospheric pressure. Additionally, the compression system includes a first drive configured to drive the first compressor. Further, the compression system includes a gas outlet configured to direct the gas to a carbon capture system.

Description

SYSTEM AND METHOD FOR CARBON CAPTUREBACKGROUND

[0001] The present application relates generally to a system and method for capturing undesirable gases associated with a combustion system, such as a combustion-driven power plant.

[0002] An industrial plant, such as a combustion-driven power plant, may produce a variety of gases, such as a flue gas of a combustion system. The combustion system may include a gas turbine engine, a reciprocating piston-cylinder engine, a furnace, a boiler, or other industrial equipment. These flue gases may include one or more undesirable gases, such as acid gases and / or greenhouse gases. For example, the undesirable gases may include carbon oxides (COx) such as carbon dioxide (CO2) and carbon monoxide (CO), nitrogen oxides (NOx) such as nitrogen dioxide (NO2), and / or sulfur oxides (SOx) such as sulfur dioxide (SO2). CO2 is both an acid gas and a greenhouse gas. Unfortunately, the atmospheric content of CO2 has generally increased over thousands of years, and currently exceeds about 420 parts per million by volume (ppmv) or 643 parts per million by weight (ppmw) in the atmosphere. With various regulations and environmental concerns regarding global warming, it would be desirable to reduce the output of undesirable gases (e.g., CO2) into the atmosphere, particularly for hydrocarbon fuel consuming equipment such as combustion systems. Additionally, it would be desirable to increase the efficiency and reduce the footprint and energy consumption of gas capture sy stems used to capture the undesirable gases (e.g., CO2).BRIEF DESCRIPTION

[0003] Certain embodiments commensurate in scope with the originally claimed subject matter are summarized below. These embodiments are not intended to limit the scope of the claimed embodiments, but rather these embodiments are intended only to provide a brief summary7of possible forms of the subject matter. Indeed, the presentlyclaimed embodiments may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

[0004] In certain embodiments, a system includes a compression system having a first gas inlet configured to receive a gas from a gas turbine system. The compression system also includes a first compressor configured to compress the gas to a pressure above atmospheric pressure. Additionally, the compression system includes a first drive configured to drive the first compressor. Further, the compression system includes a gas outlet configured to direct the gas to a carbon capture system.

[0005] In certain embodiments, a method includes receiving a gas from a gas turbine system via a first gas inlet of a compression system. The method also includes compressing the gas to a pressure above atmospheric pressure via a first compressor of the compression system. Furthermore, the method includes driving the first compressor via a first drive directing the gas to a carbon capture system via a gas outlet of the compression system.

[0006] In certain embodiments, a system includes a controller having a processor, a memory, and instructions stored on the memory and executable by the processor to control a compression system to receive a gas from a gas turbine system via a first gas inlet of the compression system. Additionally, the instructions are executable by the processor to control the compression system to compress the gas to a pressure above atmospheric pressure via a first compressor of the compression system. Furthermore, the instructions are executable by the processor to control the compression system to drive the first compressor via a first drive to direct the gas to a carbon capture system via a gas outlet of the compression system.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] These and other features, aspects, and advantages of the presently disclosed techniques will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

[0008] FIG. 1 is a block diagram of an embodiment of a power plant having one or more gas capture systems.

[0009] FIG. 2 is a schematic of an embodiment of the power plant of FIG. 1 , further illustrating a compression system driven using a recuperator and an expansion turbine.

[0010] FIG. 3 is a schematic of an embodiment of the power plant of FIG. 1 , further illustrating a compression system driven by a motor.

[0011] FIG. 4 is a schematic of an embodiment of the power plant of FIG. 1. further illustrating a compression system driven by a gas turbine.

[0012] FIG. 5 is a schematic of an embodiment of the power plant of FIG. 1 , further illustrating a compression system driven by a gas turbine and a steam turbine.

[0013] FIG. 6 is a schematic of an embodiment of the power plant of FIG. 1 , further illustrating a compression system driven by an auxiliary steam turbine.

[0014] FIG. 7 is a flowchart of a process for controlling a compression system based on a monitored operating condition.

[0015] FIG. 8 is a flowchart of a process for controlling a compression system based on a load.DETAILED DESCRIPTION

[0016] One or more specific embodiments of the presently disclosed systems and methods are described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementationspecific decisions must be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless bea routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0017] When introducing elements of various embodiments of the presently disclosed embodiments, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including.” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements.

[0018] The disclosed embodiments include systems and methods to reduce the carbon footprint of combustion systems, such as combustion-driven power plants and / or combined cycle power plants, using a gas treatment system having one or more gas capture systems. The gas capture systems are configured to remove undesirable gases (e.g., CO2) from the flue gas of the combustion systems. In the disclosed embodiments, the flue gas is pressurized before being treated by the gas capture system. For example, one or more compressors are configured to compress the flue gas upstream of the gas capture systems, thereby increasing the partial pressure of the undesirable gases (e.g., CO2) in the flue gas, resulting in an increase in the efficiency of gas capture with a lower energy consumption. As a result, the size and footprint of the gas capture systems may be reduced by up to 40%, 50%, 60%, or more.

[0019] FIG. 1 is a block diagram of an embodiment of a power plant 10 (e.g., combustion-driven power plant) having a gas turbine system 12, a steam turbine system 14. a heat recovery steam generator (HRSG) 16. a gas treatment system 18 having one or more gas capture systems 20, and a controller 22 coupled to each of the systems 12, 14, 16, and 18. The one or more gas capture systems 20 of the gas treatment system 18 are configured to capture an undesirable gas (e.g., CO2) from flue gas (e.g., flue gas). The gas treatment system 18 also includes a compression system 24 configured to receive the flue gas at a gas inlet 26 and pressurize the flue gas before the undesirable gas is subject to capture by the one or more gas capture systems 20. As shown in FIG.1, the gas inlet 26 of the compression system 24 may be located downstream of the HRSG 16 and / or upstream of the gas treatment system 18. The compression system 24 also includes a gas outlet 27 configured to direct the pressurized flue gas downstreamtoward a carbon capture system 100. The compression system 24 is driven by a drive source 28 (e.g.. drive, driving mechanism, drive system). In different embodiments, or in different drive configurations of the compression system 24, the drive source 28 may take different forms. For example, in some embodiments or drive configurations, the drive source 28 may be a turbine shaft (e.g., gas turbine shaft, steam turbine shaft). In other embodiments or drive configurations, the drive source 28 may be an electric motor. The compression system 24 may include multiple drive sources 28 that may be used at the same time or in different drive configurations. The controller 22 may selectively operate the compression system 24 using one drive source 28 or another based on an operating condition, operating parameters, or operator inputs. In some instances, one drive source 28 may function as a backup for another drive source 28.

[0020] Before discussing details of the gas treatment system 18, various aspects of the power plant 10 are discussed in further detail. For purposes of orientation in the drawings, reference may be made to an axial direction or axis 40, a radial direction or axis 42 extending radially away from the axial direction or axis 40, and a circumferential direction or axis 44 extending circumferentially around the axial direction or axis 40. The directions or axes 40, 42, and 44 may be in reference to a rotational axis 36 of the gas turbine system 12, for example.

[0021] The gas turbine system 12 includes an air intake 50, a compressor 52 having one or more compressor stages, one or more combustors 54, a turbine 56 having one or more turbine stages, and a load 58 (e.g., electrical generator) driven by the turbine 56. In certain embodiments, the gas turbine system 12 further includes an exhaust gas recirculation (EGR) system 60 configured to recirculate a portion (e g., 30%) of a flue gas 62 (e.g., exhaust gas) into the air intake 50 and / or into one of the compressor stages of the compressor 52. The recirculated flue gas 62 helps to reduce the temperature and formation of certain emissions (e.g., nitrogen oxides (NOx) or sulfuric oxides (SOx)) associated with combustion in the combustors 54. In operation, the compressor 52 receives air (and also flue gas 62 if the EGR system 60 is active) from the air intake 50, and compresses the air and / or flue gas 62 in one or more compressor stages (e.g., stages of rotating compressor blades). The combustors 54 then combust fuel from a fuel supply system with the compressed air and / or flue gas, and generate hot combustiongases. The hot combustion gases expand and drive one or more turbine stages (e.g., stages of rotating turbine blades) in the turbine 56, thereby driving rotation of the compressor 52 and the load 58 via shafts. The turbine 56 then outputs the hot combustion gases as the flue gas 62.

[0022] The HRSG 16 recovers waste heat from the flue gas 62 to generate steam for driving the steam turbine system 14. The HRSG 16 includes a high-pressure (HP) steam section 70, an intermediate-steam (IP) section 72, and a low-pressure (LP) steam section 74 configured to generate HP steam 76, IP steam 78, and LP steam 80. The steam turbine system 14 may include an HP steam turbine 82 driven by the HP steam 76, an IP steam turbine 84 driven by the IP steam 78, and a LP steam turbine 86 driven by the LP steam 80. In addition to the steam provided by the HRSG 16, the HP steam turbine 82 provides IP steam to the IP steam turbine 84, and the IP steam turbine 84 provides LP steam to the LP steam turbine 86. The LP steam turbine 86 then outputs any remaining steam / water to a condensate line 88 coupled to the LP steam section 74 of the HRSG 16. The condensate line 88 may include a condenser 90 configured to condense any remaining steam to form a condensate, and a pump 92 configured to pump the condensate back to the LP steam section 74. In operation, the steam turbine system 14 drives a load 94 (e.g., electrical generator) via a shaft. In certain embodiments, the steam turbine system 14 and / or the HRSG 16 may provide heated water and / or steam (e.g., HP steam 76, IP steam 78, and / or LP steam 80) to the gas treatment system 18 to support a desorption mode of the one or more gas capture systems 20. For example, the gas capture systems 20 may receive heated water and / or steam in a temperature range of 100 to 150 degrees Celsius, 110 to 150 degrees Celsius, 120 to 150 degrees Celsius, or 130 to 150 degrees Celsius.

[0023] After the HRSG 16, a portion of the flue gas 62 may flow along a first recirculation flow path 95 from the HRSG 16 to the EGR system 60 to be recirculated to the intake 50 of the gas turbine system 12. A remaining portion of the flue gas 62 may flow to the compression system 24. The compression system 24 may include one or more compressors or compressor stages configured to pressurize the flue gas 62 flowing from the HRSG 16. A portion of the flue gas 62 (e.g., recirculated flue gas) pressurized by the compression system 24 may flow along a second recirculation flowpath 96 (e.g., conduit, line) to a compressor stage (e.g., intermediate stage) of the gas turbine system 12 after it is pressurized by part or all of the compression system 24. For example, the flue gas 62 may flow out of the HRSG 16 and into a first compression stage of the compression system 24. From the compression system 24, the remaining portion of the flue gas 62 (not recirculated) may flow to the gas capture system 20 along a gas capture flow path 98 (e g., gas capture conduit, CCS intake conduit). In this way, the flue gas 62 may be pressurized by the compression system 24 prior to subsequent treatment by the gas capture system 20. As a partial pressure of the flue gas 62 is increased by the compression system 24, an efficiency of the gas capture system 20 may be increased, a capacity of the gas capture system 20 may be increased, and / or a footprint of the gas capture system 20 may be decreased. The pressure of the flue gas 62 flowing out of the compression system 24 may be between 5 and 20 bar. In certain embodiments, the flue gas 62 is compressed to a pressure of at least equal to or greater than 5, 10, 15, or 20 bar. Additionally, the ducts, enclosures, and associated equipment of the gas capture system 20 are designed to contain the increased pressures of the flue gas 62.

[0024] In the illustrated embodiment, the flue gas 62 flows through one or more gas capture systems 20 configured to capture undesirable gases. The undesirable gases may include carbon oxides (COx) (e.g.. carbon dioxide (CO2) and carbon monoxide (CO)), nitrogen oxides (NOx) (e.g., nitrogen dioxide (NO2)), sulfur oxides (SOx) (e.g., sulfur dioxide (SO2)), or any combination thereof. In the following discussion, CO2 may be used as an example of the undesirable gases; however, the gas capture systems 20 may be designed to capture any of the foregoing undesirable gases. For example, the gas capture systems 20 include one or more carbon capture systems 100 (e.g., CO2 capture systems). The gas capture systems 20 (e.g., carbon capture systems 100) may include sorbent-based gas capture systems, solvent-based gas capture systems, cryogenic gas capture systems, membrane-based gas capture systems, or any combination thereof, configured to remove and capture undesirable gases. The carbon capture system 100 may include components 102, 104, 106, and 108 configured to enable gas capture of undesirable gases (e.g., CO2) from the flue gas 62, thereby outputting a treated gas 110 and a captured gas 112 (e.g., CO2). The treated gas 110 may be substantially free ofthe undesirable gases (e.g., CO2) and may be discharged through an exhaust stack. The captured gas 112 (e.g., CO2) may be compressed by a compression system 114 and stored and / or transported by a storage and / or pipeline system 116.

[0025] In certain embodiments, the carbon capture system 100 is a sorbent-based carbon capture system, and the components 102, 104, 106, and / or 108 include multiple sorbent-based carbon capture units (e.g., adsorbers). For example, the sorbent-based carbon capture units may include temperature swing adsorption (TSA) units or adsorbers, wherein a temperature swing or change is used to sequentially operate in an adsorption mode, a desorption mode, and a cooling mode at different temperatures. In the adsorption mode, the adsorber is configured to adsorb undesirable gases (e.g.. CO2) into sorbent material at a first temperature. In the desorption mode, the adsorber is configured to desorb the undesirable gases (e.g., CO2) from the sorbent material, for example, by heating the sorbent material from the first temperature to a higher second temperature using a heat source. The heat source may include a heated fluid, such as a heated gas and / or liquid (e.g., steam). In the cooling mode, the adsorber is cooled in preparation for the next adsorption mode.

[0026] In certain embodiments, the carbon capture system 100 is a solvent-based carbon capture system, and the components 102, 104, 106. and / or 108 include one or more absorbers, strippers, and associated equipment. For example, the absorber is configured to absorb undesirable gases (e.g., CO2) into a solvent, thereby outputting the treated gas 110 through an exhaust stack and a CCh-rich solvent to the stripper. The stripper is configured to apply heat to the CCh-rich solvent, thereby stripping the undesirable gases (e.g., CO2) from the solvent to produce the captured gas 112 and a CCh-lean solvent. The stripper may receive heat via a heat source, such as a heated gas and / or liquid (e.g., steam). The stripper returns the CCh-lean solvent to the absorber to repeat the cycle.

[0027] In certain embodiments, the carbon capture system 100 is a cryogenic carbon capture system, wherein the components 102, 104, 106, and / or 108 may include a heat exchanger configured to cool the flue gas 62 to a very low cryogenic temperature, causing CO2 in the flue gas 62 to solidify or desublimate. The components 102, 104.106, and / or 108 may further include a separator configured to separate the solid CO2 from other components of the flue gas 62, thereby generating a treated flue gas and the solid CO2. The heat exchanger (or other heat source) may then heat the solid CO2 to transition the solid CO2 to a liquid CO2 or a gaseous CO2 (e.g., sublimation), such that the CO2 can be collected, stored, and / or transported to another site.

[0028] In certain embodiments, the carbon capture system 100 may be a membranebased carbon capture system, wherein the components 102, 104, 106, and / or 108 include C Ch-selective membranes configured to separate CO2 from a flue gas stream. The membranes may be permeable to some gases and impermeable to others. For example, the membranes may include pores that enable different gases to pass through at different rates. In this way, CO2 may be separated from the flue gas 62.

[0029] An advantage of the compression system 24 disclosed herein is that it may be modular and / or adaptable to operate with any type carbon capture system, including sorbent-based, solvent-based, cryogenic, and / or membrane-based carbon capture systems. Regardless of the type of carbon capture system, the compression system 24 may be configured to receive the flue gas 62 from the HRSG 16 and provide a flow of pressurized flue gas 62 to the carbon capture system 100. In some embodiments, the compression system 24 may be packaged as a modular system that can be retrofit into existing gas treatment systems to improve efficiency, increase capacity, and / or reduce the footprint of carbon capture systems. Indeed, the amount (e.g., rate, capacity) of carbon capture by the carbon capture system 100 may be related (e.g., proportional) to a partial pressure of CO2 in the flue gas 62 and / or a concentration of CO2 per unit of volume in the flue gas 62.

[0030] In the illustrated embodiment, the controller 22 is configured to control all aspects of the power plant 10. The controller 22 includes one or more processors 120, memory 122, instructions 124 stored on the memory 122 and executable by the processor 120, and communication circuitry 126 configured to communicate with sensors and various equipment of the power plant 10. For example, the controller 22 is configured to receive sensor feedback from sensors coupled to the gas turbine system 12. the steam turbine system 14. the HRSG 16. the gas treatment system 18 (e.g.. gascapture systems 20), and / or the compressions system 24 and control the same equipment based on the sensor feedback, operating modes, user input, computer models, or any combination thereof. The sensors may include temperature sensors, pressure sensors, flow rate sensors, gas composition sensors, or any combination thereof. In certain embodiments, the controller 22 is configured to control operation of the compression system 24, gas capture systems 20 (e.g., carbon capture systems 100), such by controlling modes of operation (e.g., adsorption mode, desorption mode, and cooling mode), controlling heat sources for supplying heated fluid (e.g., steam) to the gas capture systems 20, controlling cooling sources for supply cooled fluids to the gas capture systems 20, controlling compression of the flue gas 62 by the compression system 24, or any combination thereof.

[0031] In some embodiments, the compressed flue gas 62 may be directed to multiple carbon capture systems 100. For example, the flue gas 62 may flow from the compression system 24 to a first carbon capture system. The treated gas 110 treated by the first carbon capture system may flow to a second carbon capture system. Subsequently, the flue gas 62 may flow through any number of carbon capture systems (e.g., a third, a fourth, and a fifth carbon capture system) in sequence (e.g., in series). In some embodiments, the flue gas 62 may be recirculated and / or repressurized by the compression system 24 in between treatment by one or more carbon capture systems. Alternatively, the flue gas 62 may flow from the compression system 24 to multiple carbon capture systems 100 in parallel. For example, a first portion of the flue gas 62 may flow from the compressions system 24 to a first carbon capture system, a second portion of the flue gas 62 may flow to a second carbon capture system, and so on.

[0032] FIGS. 2-6 illustrate different drive configurations that may be used to drive the compression system 24. The different drive configurations include different embodiments of the drive source 28. For example, the drive source 28 in one drive configuration may include a recuperator and an expansion turbine, whereas the drive source 28 in another configuration may include a turbine shaft (e.g., gas turbine shaft and / or steam turbine shaft). While each drive configuration can stand alone as a separate embodiment of the compression system 24, it is noted that elements of the different drive configurations may be combined in a single embodiment. As a result.the features of FIGS. 2-6 may not be mutually exclusive relative to one another. In some embodiments, the gas treatment system 18 may include a combination of two or more of the different drive configurations. In such cases, the controller 22 may switch operation of the gas treatment system 18 between the different drive configurations based on an operating condition (e.g., startup, steady-state, full load, part load), operating parameters (e.g., operating capacity, flue gas flow rate, gas turbine speed, pressure ratio, compressor speed), or operator inputs. As such, the compression system 24 may include multiple drive sources 28, one of which one may be selected based on the operating condition or mode. Alternatively, the multiple drive sources 28 may be used in combination with one another.

[0033] FIG. 2 is a schematic of an embodiment of the power plant 10 of FIG. 1, further illustrating a first drive configuration 150 (e.g., drive system, drive mechanism) of the compression system 24 where the drive source 28 includes a recuperator 152 and an expansion turbine 160 to drive a compressor 154. The gas treatment system 18 may also include a direct contact cooler (DCC) 156 disposed along a gas flow path 158 downstream of the HRSG 16 and / or upstream of the compression system 24. The DCC 156 may include a heat exchanger configured to cool a cooling fluid and a cooling fluid distributor configured to distribute the cooling fluid across an internal volume of the DCC 156. As the flue gas 62 flows through the DCC 156, the cooling fluid may directly contact and cool the flue gas 62.

[0034] The flue gas 62 may flow from the DCC 156 to the gas inlet 26 of the compression system 24. The gas inlet 26 may be an inlet of the compressor 156 or an inlet that is fluidly coupled to the inlet of the compressor 154. In the first drive configuration 150, the compressor 154 is driven by an expansion turbine 160 (e.g., turboexpander). For example, a shaft of the compressor 154 may be rotationally- coupled to a shaft of the expansion turbine 160. Alternatively, the compressor 154 and the expansion turbine 160 may share a single drive shaft 162. In some embodiments, the expansion turbine 160 may be coupled to a generator 164 to generate electric power from rotation of the expansion turbine 160. The electric power may be used to power a motor to drive the compressor 154. In some embodiments, the compression system24 may include multiple compressors or compressor stages in place of or in addition to the compressor 154.

[0035] As the compressor 154 pressurizes the flue gas 62, the compression system 24 may direct a portion of the flue gas 62 along the second recirculation flow path 96 toward an intake and / or an intermediate stage 168 of the compressor 52 of the gas turbine system 12 and a remaining portion of the flue gas 62 toward the carbon capture system 100 along the gas capture flow path 98. As shown in FIG. 2, the portion of the flue gas 62 flowing along the second recirculation path 96 may be taken (e.g., branched) from a location 170 downstream of the compressor 154. In other embodiments, the portion of the flue gas 62 flowing to the second recirculation path 96 may flow from a location upstream of the compressor 154 toward the gas turbine system 12. The flow along the second recirculation path 96 may be controlled (e.g., opened, closed, modulated, regulated) using a valve (e.g., check valve, three-way valve). For example, the valve may regulate the flow of the flue gas 62 such that a certain amount (e.g., 10%, 15%, 20%, 30%, or 40%) of the flue gas 62 flows along the second recirculation path 96 and a remaining portion of the flue gas 62 flows toward the recuperator 152.

[0036] The recuperator 152 (e.g., heat exchanger) may be disposed along the gas capture flow path 98 between the carbon capture system 100 and the compressor 154. That is, the flue gas 62 may flow from the compressor 154 to the recuperator 152 and from the recuperator 152 to the carbon capture system 100. The recuperator 152 is configured to place the flue gas 62 flowing into the carbon capture system 100 in a heat exchange relationship (e.g., indirect heat transfer) with the treated gas 110 flowing out of the carbon capture system 100. In this way, the flue gas 62 may be cooled as it enters the carbon capture system 100, resulting in more efficient carbon capture. In some cases, the pressurization of the flue gas 62 in the compressor 154 may increase the temperature of the flue gas 62 beyond a suitable temperature for the carbon capture system 100. The recuperator 152 may cool the flue gas 62 to a suitable temperature.

[0037] As the flue gas 62 is cooled, the treated gas 110 flowing through the recuperator 152 may be heated. The heated treated gas 110 may then flow from the recuperator 152 to the expansion turbine 160. The expansion turbine 160 is configuredto generate work from expansion of the treated gas 110 to drive the compressor 154. For example, the expansion turbine 160 and the compressor 154 may be coupled to the same shaft such that rotation of the expansion turbine 160 causes rotation of the compressor 154. Additionally or alternatively, the expansion turbine 160 may be coupled to a generator 164 to produce electric power from the rotation of the expansion turbine 160. The electric power may be used to power a motor to drive the compressor 154.

[0038] FIG. 3 is a schematic of an embodiment of the power plant 10 of FIG. 1, further illustrating a second drive configuration 200 of the compression system 24 that may be used instead of or in combination with the first drive configuration 150 or any other drive configuration. The second drive configuration 200 utilizes a multi-stage compressor 202 having multiple compressor stages and one or more intercoolers disposed between the multiple compressor stages. The drive source 28 used to drive the multiple multi-stage compressor 202 may include a motor 204 coupled to a drive shaft 206 of the compression system 24. In this embodiment, the flue gas 62 may flow from the HRSG 16 and / or the DCC 156 to the gas inlet 26 (e.g., an inlet of the multistage compressor 202), where the flue gas 62 is received by a first compressor stage 208. The first compressor stage 208 may pressurize the flue gas 62 to a first pressure. A portion of the flue gas 62 may flow from an outlet of the first compressor stage 208 to the gas turbine system 12 via the second recirculation path 96. A remaining portion of the flue gas 62 may flow from the outlet of the first compressor stage 208 to a first intercooler 210 (e.g., first heat exchanger) disposed between the first compressor stage 208 and a second compressor stage 212. The first intercooler 210 may include a heat exchanger configured to cool the flue gas 62, for example, by placing the flue gas 62 in a heat exchange relationship (e.g., indirect heat transfer) with a cooling fluid (e.g., coolant, water, refrigerant). In some embodiments, the recirculated portion of the flue gas 62 may flow from a location downstream of the first intercooler 210 to the second recirculation path 96.

[0039] From the first intercooler 210, the flue gas 62 may flow to the second compressor stage 212. The second compressor stage 212 may pressurize the flue gas 62 to a second pressure, which may be greater than the first pressure. The flue gas 62may then flow from the second compressor stage 212 to a second intercooler 214 (e.g., second heat exchanger) disposed between the second compressor stage 212 and a third compressor stage 216. The second intercooler 214 may include a heat exchanger configured to further cool the flue gas 62. The flue gas 62 may then flow to the third compressor stage 216, where the flue gas 62 may be pressurized to a third pressure. The third pressure may be greater than the first pressure and / or the second pressure. By reducing the temperature of the flue gas 62, the intercoolers 210 and 214 may increase compression efficiencies of the compression stages 208, 212, and 216.

[0040] In the illustrated embodiment, the flue gas 62 flows from the outlet 27 of the compression system 24 (e.g.. an outlet of the third compressor stage 216) to the carbon capture system 100. In other embodiments, the compression system 24 may include any number of compressor stages (e.g., 2, 4, 10, or so on) and any number of intercoolers (e.g., 1, 3, 10, or so on) disposed between one or more of the compressor stages. Furthermore, the illustrated embodiment includes a flow of a portion of the flue gas 62 from outlet of the first compressor stage 208 the gas turbine 12 via the second recirculation path 96. Alternatively or additionally, portions of the flue gas 62 may be recirculated from other locations along the gas flow path 158, such as upstream of the first compressor stage 208, downstream of the second compressor stage 212. and / or downstream of the third compressor stage 216.

[0041] The first compressor stage 208, the second compressor stage 212, and the third compressor stage 216 may each be driven by a motor 204. For example, the motor 204 may be an electric motor powered by an external energy source (e.g., utility power, a battery, a generator). In some embodiments, the motor may be an internal combustion engine, such as a reciprocating piston-cylinder engine. In some embodiments, the motor 204 may be part of the load 58 (e.g., motor / generator) powered by the gas turbine 12. Each compressor stage may be driven along a common shaft, coupled to the motor 204.

[0042] FIG. 4 is a schematic of an embodiment of the power plant 10 of FIG. 1 , further illustrating a third drive configuration 240 of the compression system 24. The third drive configuration 240 includes the one or more compressor stages (e.g., firstcompressor stage 208, second compressor stage 212, third compressor stage 216) and the one or more intercoolers (e.g., first intercooler 210, second intercooler 214) in a substantially similar arrangement to the second drive configuration 200 shown in FIG.3. In a similar fashion to operation of the second drive configuration 200, the compressor stages pressurize the flue gas 62 to a pressure greater than atmospheric pressure, and the intercoolers cool the flue gas 62 in between the compression stages. The gas treatment system 18 may direct a portion of the flue gas 62 from one or more of the compressor stages (e.g., first compressor stage 208) to the gas turbine system 12 via the second recirculation path 96.

[0043] In the third drive configuration 240, the compression system 24 is driven by the gas turbine system 12. For example, each of the compressor stages 208, 212, and 216 may be coupled to a gas turbine shaft 242 (e.g., drive shaft) of the gas turbine system 12. In this way, the compressor stages 208, 212, and 216 may rotate as the gas turbine shaft 242 rotates. As such, an external drive source (e.g., motor 204 of the second drive configuration 200) may be excluded or reserved as a backup drive. The compressor stages 208, 212, and 216 may be directly coupled to the gas turbine shaft 242, or indirectly coupled via a gear system (e.g., gear box). In some embodiments, the compression system 24 may be part of the load 58 of the gas turbine system 12.

[0044] FIG. 5 is a schematic of an embodiment of the power plant 10 of FIG. 1, further illustrating a fourth drive configuration 260 of the compression system 24. The fourth drive configuration 260 includes the one or more compressor stages (e.g., first compressor stage 208, second compressor stage 212, third compressor stage 216) and the one or more intercoolers (e.g., first intercooler 210, second intercooler 214) in a substantially similar arrangement as described above with reference to the second and third drive configurations 200 and 240. In a similar fashion to operation of the second drive configuration 200 and the third drive configuration 240, the compressor stages pressurize the flue gas 62 to a pressure greater than atmospheric pressure, and the intercoolers cool the flue gas 62 in between the compression stages. The gas treatment system 18 may direct a portion of the flue gas 62 from one or more of the compressor stages (e.g., first compressor stage 208) to the gas turbine system 12 via the secondrecirculation path 96. A remaining portion of the flue gas 62 flows from the last compressor stage to the carbon capture system 100.

[0045] In the fourth drive configuration 260, the compression system 24 is driven by the gas turbine system 12 and the steam turbine system 14. For example, each of the steam turbines (e.g., HP steam turbine 82, IP steam turbine 84, and LP steam turbine 86) may be coupled to the gas turbine shaft 242. Additionally, each of the compressor stages 208, 212, and 216 may be coupled to the gas turbine shaft 242 and / or to a steam turbine shaft 262 (e.g., drive shaft) of the steam turbine system 14. In this way, the gas turbine system 12, the HP steam turbine 82, the IP steam turbine 84. and / or the LP steam turbine 86 may work together to drive rotation of the first compressor stage 208, the second compressor stage 212, and the third compressor stage 216. In some embodiments, the gas turbine shaft 242 may be coupled to the steam turbine shaft 262 of the steam turbines via a gear system (e.g., gear box) or a shaft coupling. The compressor stages 208, 212. and 216 may be coupled to the steam turbine shaft 262 and / or the gas turbine shaft 242. In this way, energy or torque may be transmitted from the gas turbine system 12 and the steam turbine system 14 to the compressor stages 208, 212, and 216. In some embodiments, the compression system 24 may be part of the load 58 of the gas turbine system 12 and / or the load 94 of the steam turbine system 14.

[0046] FIG. 6 is a schematic of an embodiment of the power plant 10 of FIG. 1, further illustrating a fifth drive configuration 280 (e.g., drive, drive system, drive mechanism) of the compression system 24. The fifth drive configuration 280 includes the one or more compressor stages (e.g., first compressor stage 208, second compressor stage 212, third compressor stage 216) and the one or more intercoolers (e.g., first intercooler 210, second intercooler 214) disposed between the one or more compressor stages. In a similar fashion to operation of the second drive configuration 200, the third drive configuration 240, and the fourth drive configuration 260, the compressor stages pressurize the flue gas 62 to a pressure greater than atmospheric pressure, and the intercoolers cool the flue gas 62 in between the compression stages. The gas treatment system 18 may direct a portion of the flue gas 62 from one or more of the compressor stages (e.g., first compressor stage 208) to the gas turbine system 12 via the secondrecirculation path 96. A remaining portion of the flue gas 62 flows from the last compressor stage to the carbon capture system 100.

[0047] In the fifth drive configuration 280, the compression system 24 includes an auxiliary steam turbine 282 (e.g., back pressure steam turbine) configured to receive a flow of steam from one or more of the HP steam turbine 82, the IP steam turbine 84, the LP steam turbine 86, and / or the HRSG 16. For example, the auxiliary steam turbine 282 may receive a flow of steam from an outlet of the HP steam turbine 82. The auxiliary steam turbine 282 may convert expansion of the steam into work to drive an auxiliary steam turbine shaft 284. One or more of the compressor stages 208. 212, and 216 may be coupled to the auxiliary steam turbine shaft 284, such that the auxiliary steam turbine 282 drives rotation of the compressor stages 208, 212, and / or 216. The steam may then flow out of the auxiliary steam turbine at a pressure suitable for a process steam application of the power plant. In some embodiments, the steam may flow from the auxiliary steam turbine 282 into one of the other steam turbines. Additionally or alternatively, the steam may flow from the auxiliary steam turbine 282 to the carbon captures system 100 to function as a heat source to facilitate capture of CO2 from the flue gas 62.

[0048] Techniques disclosed herein may be applied to direct air capture of certain gases (e g., CO2). For example, in some embodiments, the gas treatment system 18 may draw air directly into the gas treatment system 18 from an environment using fans. The air may be cooled by the DCC 156, compressed by the compression system 24, and treated using the carbon capture system 100.

[0049] FIG. 7 is a flowchart of an embodiment of a process 300 for controlling operation of the compression system 24 of FIG. 1 based on an operating condition of the power plant 10. As discussed above, the compression system 24 may include multiple drive configurations (e.g., first drive configuration 150, second drive configuration 200, third drive configuration 240, fourth drive configuration 260, and / or fifth drive configuration 280), providing different options for compressing the flue gas 62. In different situations, the controller 22 may control the power plant 10 to operate in different operating modes or under different operating conditions, such as a startupmode, a shutdown mode, a steady state mode, a full load mode, and / or a part load mode. For example, the power plant 10 may operate in the full load mode to generate more electricity when electricity demand is high, whereas the power plant 10 may operate in the part load mode to generate less electricity when electricity demand is low. As the power plant 10 changes between the full load mode and the part load mode (or between any of the operating modes), the demand for gas capture may change, and thus the controller 22 may switch between different drive configurations to operate the compression system 24 in a drive configuration best suited for a particular operating mode or condition.

[0050] At block 302. the controller 22 may monitor one or more parameters of the power plant 10. The one or more parameters may relate to the operation of the gas turbine system 12. For example, the one or more parameters may include a speed of the gas turbine shaft 242, a flow' rate of the flue gas 62, a pow er output of the gas turbine system 12, or the like. Additionally, the one or more parameters may correspond to aspects of the steam turbine system 14, such as a shaft speed of the steam turbine system 14, a flow rate of steam, a power output of the steam turbine system 14, or the like. Other examples of parameters include combustion parameters (e.g., fuel-air ratio, equivalence ratio, combustion flame temperature), EGR parameters (e.g., EGR flow rate, temperature, gas composition, etc.), emissions levels of undesirable gases in the flue gas (e.g., NOx, CO, CO2, etc.), flue gas temperature and flow' rate, steam parameters (e.g., steam production temperature, pressure, flow' rate, etc.), or any combination thereof. The energy demand may correspond to electricity demand on a power grid, which may vary between peak demand during hottest portions of the day and minimum demand at night. Thus, the energy demand may have an impact on the operation and pow er production by the power plant 10. The one or more parameters may also relate to operation of the compression system itself. For example, the one or more parameters may include a rotational speed of the compression system 24, a pressure of the flue gas 62 upstream or downstream of the compression system 24 or any compression stage of the compression system 24, and / or a temperature of the flue gas 62 downstream, upstream, or inside of the compression system 24.

[0051] At block 304, the controller 22 may proceed to control operating conditions (e.g., generate control signals) of the power plant at least partially based on the information gathered at block 302. For example, energy demand variations may be an operating parameter that the process 300 may use to increase or decrease the load of the power plant. In certain embodiments, the process 300 may control the power plant to change from a full load mode during a peak energy' demand to a part load mode during a lower or minimum energy demand by a power grid. Additionally, the process 300 may adjust operating conditions of the compression system 24 (e.g., part load mode, full load mode, etc.) depending on the needs and value generated by operating the gas treatment system 18.

[0052] At block 306, the controller 22 may determine a change in the operating condition base on the monitored parameters. As an example, possible operating conditions or modes may include a startup mode, a steady state mode, and a shutdown mode. In response to determining that the power plant 10 (e.g.. the gas turbine system 12, the steam turbine system 14, and / or the compression system 24) is operating in the startup mode, the controller 22 may proceed to operate the compression system using a drive configuration suitable for the startup mode. In the illustrated embodiment, the first drive configuration 150 is selected at block 308 as an example. In other embodiments, any of the drive configurations discussed above with respect to FIGS. 2-6 may be selected for any of the operating conditions.

[0053] Similarly, in response to determining that the power plant 10 is operating in the steady state mode, the controller 22 may proceed to block 310 to operate the compression system 24 using the second drive configuration 200, for example. This may entail switching the compression system 24 from one of the other drive configurations to the second drive configuration 200. For example, the controller 22 may operate a valve configured to selectively direct the flue gas 62 from the DCC to the compressor 154 of the first drive configuration 150 to the first compressor stage 208 of the second drive configuration 200. Furthermore, in response to determining that the power plant 10 is operating in the shutdown mode, the controller 22 may proceed to block 312 to operate the compression system 24 using the third drive configuration.Again, gas flow paths may be adjusted (e.g., using valves) to redirect the flue gas 62 when switching between the different drive configurations.

[0054] By switching between different drive configurations of the compression system 24, the compression system 24 may operate more efficiently in response to changing operating conditions and / or modes of the power plant. For example, the first drive configuration 150 may be most efficient in the startup mode, and the second drive configuration may be most efficient in the steady state mode. Therefore, when the power plant 10 changes from the startup condition to the steady state condition, the controller 22 may generate a control output to switch the compression system 24 from the first drive configuration 150 to the second drive configuration 200. Switching between drive configurations may entail operating one or more valves to redirect the flue gas 62 toward different compressors or compressor stages, activating and deactivating a motor (e g., motor 204 and / or coupling and decoupling compressors from the gas turbine shaft 242 or the auxiliary turbine shaft 284.

[0055] FIG. 7 is a flowchart of an embodiment of a process 330 for controlling operation of the compression system 24 of FIG. 1 based on a load of the power plant 10. At block 332, the controller 22 may monitor one or more parameters indicative of a load of the power plant 10. For example, the one or more parameters may include combustion parameters (e g., fuel-air ratio, equivalence ratio, combustion flame temperature), EGR parameters (e.g., EGR flow rate, temperature, gas composition, etc.), emissions levels of undesirable gases in the flue gas (e.g., NOx, CO, CO2, etc.), flue gas temperature and flow rate, steam parameters (e.g., steam production temperature, pressure, flow rate, etc.), a measured or predicted energy demand, or any combination thereof.

[0056] At block 334, the controller 22 may determine a change in the load, e.g., from a part load to a full load. In response to determining that the load is a part load, the controller 22 may operate the compression system 24 at block 336 using a drive configuration that is particularly suited for part load conditions. In the illustrated embodiment, the first drive configuration 150 is selected as an example. In otherembodiments, any of the drive configurations discussed above with respect to FIGS. 2-6 may be selected for the part load condition.

[0057] At block 338, the controller 22 may operate the compression system 24 using a different drive configuration. In the illustrated embodiment, the second drive configuration 200 is selected as an example for the full load condition. In other embodiments, any of the drive configurations discussed above with respect to FIGS. 2-6 may be selected for the full load condition.

[0058] In addition to the part load condition shown in FIG. 8, there may be additional operating modes corresponding to continuous or discrete ranges of the load between no load and full load. For each additional operating mode (e.g., load range), the controller 22 may switch the compression system 24 to a different drive configuration.

[0059] Technical effects of the disclosed embodiments enable improved efficiency, increased capacity, and / or smaller footprint of gas treatment systems in power plants. For example, by pressurizing flue gas from a gas turbine, a rate of carbon capture by a carbon capture system may be increased. A compression system for compressing the flue gas may be driven in different ways (e.g., drive configurations), including by an expansion turbine and a recuperator, a motor, a gas turbine shaft of the gas turbine, and / or a steam turbine shaft (e.g., of an auxiliary steam turbine). In some embodiments, the compression system may include multiple drive configurations and a controller configured to switch operation of the compression system between the multiple drive configurations based on an operating condition or a load of the power plant.

[0060] The subject matter described in detail above may be defined by one or more clauses, as set forth below.

[0061] A system includes a compression system having a first gas inlet configured to receive a gas from a gas turbine system. The compression system also includes a first compressor configured to compress the gas to a pressure above atmospheric pressure. Additionally, the compression system includes a first drive configured todrive the first compressor. Further, the compression system includes a gas outlet configured to direct the gas to a carbon capture system.

[0062] The system of the preceding clause, wherein the first drive comprises a turbine shaft of at least one turbine.

[0063] The system of any preceding clause, including the at least one turbine wherein the at least one turbine includes a gas turbine.

[0064] The system of any preceding clause, including the at least one turbine, wherein the at least one turbine includes a steam turbine.

[0065] The system of any preceding clause, including the at least one turbine, wherein the at least one turbine includes an expansion turbine driven by a treated gas output by the carbon capture system.

[0066] The system of any preceding clause, wherein the compression system comprises a recuperator configured to transfer heat between the gas output by the compression system and the treated gas output by the carbon capture system.

[0067] The system of any preceding clause, wherein the first drive includes an electric motor.

[0068] The system of any preceding clause, including a second drive configured to drive the first compressor, wherein the system is configured to change between the first and second drives based on an operating mode of the system, and the operating mode includes a startup mode, a steady state mode, a full load mode, or a part load mode.

[0069] The system of any preceding clause, including a gas turbine system upstream from the compression system, wherein the gas includes a flue gas from the gas turbine system.

[0070] The system of any preceding clause, including a heat recovery steam generator (HRSG) between the gas turbine system and the compression system, and a steam turbine system driven by steam generated in the HRSG.

[0071] The system of any preceding clause, including a direct contact cooler (DCC) between the HRSG and the compression system.

[0072] The system of any preceding clause, including a controller configured to select the first drive from a plurality of drives including a gas turbine shaft of the gas turbine system, a steam turbine shaft of the steam turbine system, an expansion turbine, and an electric motor.

[0073] The system of any preceding clause, including the carbon capture system configured to capture carbon dioxide from the gas, wherein the carbon capture system comprises a sorbent based carbon capture system, a solvent-based carbon capture system, a cryogenic carbon capture system, a membrane-based carbon capture system, or a combination thereof.

[0074] The system of any preceding clause, including an exhaust gas recirculation (EGR) system configured to recirculate the flue gas into a compressor of the gas turbine system.

[0075] The system of any preceding clause, wherein the compression system includes: a second compressor driven by the first drive, and a first cooler disposed between the first and second compressors; a third compressor driven by the first drive, and a second cooler disposed between the second and third compressors; or a combination thereof.

[0076] The system of any preceding clause, including a controller having a processor, a memory, and instructions stored on the memory and executable by the processor to control the compression system to maintain the pressure between a lower pressure threshold and an upper pressure threshold for treatment of the gas in the carbon capture system, wherein the pressure is between 5 and 20 bar.

[0077] A method includes receiving a gas from a gas turbine system via a first gas inlet of a compression system. The method also includes compressing the gas to a pressure above atmospheric pressure via a first compressor of the compression system.Furthermore, the method includes driving the first compressor via a first drive directing the gas to a carbon capture system via a gas outlet of the compression system.

[0078] The method of the preceding clause, including comprising capturing carbon dioxide from the gas in the carbon capture system.

[0079] The method of the preceding clause, including controlling the pressure between a lower pressure threshold and an upper pressure threshold for treatment of the gas in the carbon capture system.

[0080] A system includes a controller having a processor, a memory, and instructions stored on the memory and executable by the processor to control a compression system to receive a gas from a gas turbine system via a first gas inlet of the compression system. Additionally, the instructions are executable by the processor to control the compression system to compress the gas to a pressure above atmospheric pressure via a first compressor of the compression system. Furthermore, the instructions are executable by the processor to control the compression system to drive the first compressor via a first drive to direct the gas to a carbon capture system via a gas outlet of the compression system.

[0081] The system of the preceding clause, wherein the controller is configured to change between a plurality of drive configurations including the first drive and one or more additional drives based on one of a plurality of operating modes of the gas turbine system, and the plurality of operating modes comprise a startup mode, a steady state mode, a part load mode, and a full load mode.

[0082] This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.

Claims

CLAIMS1. A system, comprising:a compression system, comprising:a first gas inlet configured to receive a gas from a gas turbine system; a first compressor configured to compress the gas to a pressure above atmospheric pressure;a first drive configured to drive the first compressor; and a gas outlet configured to direct the gas to a carbon capture system.

2. The system of claim 1, wherein the first drive comprises a turbine shaft of at least one turbine.

3. The system of any of claims 1-2, comprising the at least one turbine, wherein the at least one turbine includes a gas turbine.

4. The system of any of claims 1-2, comprising the at least one turbine, wherein the at least one turbine includes a steam turbine.

5. The system of claim any of claims 1-2, comprising the at least one turbine, wherein the at least one turbine includes an expansion turbine driven by a treated gas output by the carbon capture system.

6. The system of any of claims 1-5, wherein the compression system comprises a recuperator configured to transfer heat between the gas output by the compression system and the treated gas output by the carbon capture system.

7. The system of any of claims 1-6, wherein the first drive comprises an electric motor.

8. The system of any of claims 1-7, comprising a second drive configured to drive the first compressor, wherein the system is configured to change between the first andsecond drives based on an operating mode of the system, and the operating mode comprises a startup mode, a steady state mode, a full load mode, or a part load mode.

9. The system of any of claims 1 -8, comprising a gas turbine system upstream from the compression system, wherein the gas comprises a flue gas from the gas turbine system.

10. The system of any of claims 1-9, comprising a heat recovery' steam generator (HRSG) between the gas turbine system and the compression system, and a steam turbine system driven by steam generated in the HRSG.

11. The system of any of claims 1-10, comprising a direct contact cooler (DCC) between the HRSG and the compression system.

12. The system of any of claims 1-11, comprising a controller configured to select the first drive from a plurality of drives including a gas turbine shaft of the gas turbine system, a steam turbine shaft of the steam turbine system, an expansion turbine, and an electric motor.

13. The system of any of claims 1-12, comprising the carbon capture system configured to capture carbon dioxide from the gas, wherein the carbon capture system comprises a sorbent based carbon capture system, a solvent-based carbon capture system, a cryogenic carbon capture system, a membrane-based carbon capture system, or a combination thereof.

14. The system of any of claims 1-13, comprising an exhaust gas recirculation (EGR) system configured to recirculate the flue gas into a compressor of the gas turbine system.

15. The system of any of claims 1-14, wherein the compression system comprises:a second compressor driven by the first drive, and a first cooler disposed between the first and second compressors;a third compressor driven by the first drive, and a second cooler disposed between the second and third compressors;or a combination thereof.

16. The system of any of claims 1-15, comprising a controller having a processor, a memory, and instructions stored on the memory and executable by the processor to control the compression system to maintain the pressure between a lower pressure threshold and an upper pressure threshold for treatment of the gas in the carbon capture system, wherein the pressure is between 5 and 20 bar.

17. A method, comprising:receiving a gas from a gas turbine system via a first gas inlet of a compression system;compressing the gas to a pressure above atmospheric pressure via a first compressor of the compression system;driving the first compressor via a first drive; anddirecting the gas to a carbon capture system via a gas outlet of the compression system.

18. The method of claim 17. comprising capturing carbon dioxide from the gas in the carbon capture system.

19. The method of any of claims 17-18, comprising controlling the pressure between a lower pressure threshold and an upper pressure threshold for treatment of the gas in the carbon capture system.

20. A system, comprising:a controller having a processor, a memory, and instructions stored on the memory and executable by the processor to control a compression system to:receive a gas from a gas turbine system via a first gas inlet of the compression system;compress the gas to a pressure above atmospheric pressure via a first compressor of the compression system;drive the first compressor via a first drive; anddirect the gas to a carbon capture system via a gas outlet of the compression system.

21. The system of claim 20, wherein the controller is configured to change between a plurality of drive configurations including the first drive and one or more additional drives based on one of a plurality of operating modes of the gas turbine system, and the plurality of operating modes comprise a startup mode, a steady state mode, a part load mode, and a full load mode.

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