JP2024514378A - CO2 separation system and method - Google Patents

Abstract

A combustion system is provided that may include a combustion assembly operatively engaged with an air inlet, the air inlet performing air enrichment. A method of enriching air to the combustion assembly is also provided. A system and method for separating CO2 from flue gas is also provided. A method for heating or cooling components of a system for separating CO2 from flue gas is also provided.Selected Figure:

Description

[Cross reference to related applications]
This application is a continuation-in-part of PCT Patent Application No. PCT/US2021/057111 filed on October 28, 2021 and entitled "CO ₂ Separation Systems and Methods," which U.S. Provisional Patent Application No. 63/106,729 filed on October 28, 2020 and entitled “Building Emission Processing and/or Sequencing Systems and Methods”; ng Emission Processing and U.S. Provisional Patent Application No. 63/106,759 entitled “Building Emission Processing and/or Sequencing Systems and Methods” filed on October 28, 2020; estration systems and methods” 63/106,862, each of which is incorporated herein by reference in its entirety.

This application claims priority to and the benefit of U.S. Provisional Patent Application No. 63/168,794, filed March 31, 2021, entitled "Carbon Dioxide Separation Assemblies and Methods," and U.S. Provisional Patent Application No. 63/168,825, filed March 31, 2021, entitled "Combustion Assemblies and Methods and Carbon Dioxide Separation Assemblies and Methods," each of which is incorporated herein by reference in its entirety.

The field of the invention relates to _CO2 separation systems and methods. In certain embodiments, the system and/or method can separate CO ₂ and provide heat and/or power. In certain implementations, heat and power can be provided to the building. Also, the combustion products can be treated to separate _CO2 from the combustion products. In addition, _CO2 can be separated from air. Additionally, power can be generated in the form of electricity while separating _CO2 from combustion products and/or air.

Carbon dioxide generation in buildings is a large contributor to overall carbon dioxide generation, especially in metropolitan areas. Carbon dioxide is listed as a global warming compound that is currently being sought to be reduced worldwide. Carbon dioxide generation is a necessary part of breathing, which is a necessary part of life, but it is important to limit carbon dioxide generation in order to address climate change. The present disclosure provides power systems and methods for building emission treatment and sequestration systems that can address carbon dioxide generation and its rapid increase from the combustion of fossil fuels in urban areas. In addition, the _CO2 separation system and method of the present disclosure can separate _CO2 from combustion products and/or air, and in some embodiments, from the power generated in the form of electricity.

A system is provided for separating _CO2 from combustion products. The system is operably aligned with the combustion product stream and a combustion stream comprising at least CO ₂ and N ₂ and reacts the CO ₂ and O ₂ from the combustion product stream to form carbonate ions. and a carbonate electrochemical cell configured to react carbonate ions to form a CO ₂ product stream.

A method for separating _CO2 from a combustion product stream is also provided. The method can include receiving a combustion product stream including _CO2 and _N2 , reacting the combustion product stream to form carbonate ions, and reacting the carbonate ions to form a _CO2 product stream.

A system for separating _CO2 from air is also provided. The system has an air stream that includes at least CO ₂ and N ₂ and is operably aligned with the air stream to react CO 2 and O 2 from the air stream to form carbonate ions and to react CO ₂ and O ₂ from the air stream to form _carbonate ions. and a carbonate fuel cell configured to react carbonate ions to form a product stream.

A system and method for operating a combustion boiler in a building is provided. The system or method may include the steps of: supplying air and fuel to a combustion burner; combusting the air and fuel in the combustion burner; monitoring an amount of free oxygen in the burner; and controlling the amount of air and fuel supplied to the burner to maintain the amount of free oxygen at about 3%. The system or method may include combusting the air and fuel in the burner to generate a flue gas having an oxygen concentration; and restricting air from the flue gas by substantially removing tramp air in a conduit operably aligned to convey the flue gas from the burner.

A system and method is provided for cooling flue gas from a combustion boiler within a building. The system or method can include supplying flue gas to at least one economizer having at least one set of cooling coils conveying boiler feed water, the supplying step cooling the flue gas and Heat the feed water.

A system and method for separating carbon dioxide from flue gas generated from a combustion boiler in a building is provided. The system or method can include providing a flue gas containing less than about 3% water, compressing the flue gas, cooling the compressor with a heat transfer fluid and providing the heat transfer fluid to/from a chiller and/or a cooling tower. The system or method can include compressing the flue gas and drying the flue gas using nitrogen recovered during the separation of the carbon dioxide recovered from the flue gas. The system or method can include removing at least a portion of the nitrogen from the flue gas to produce greater than about 95% carbon dioxide using a pressure swing adsorption assembly, and using the nitrogen removed from the flue gas to remove water from the flue gas before providing the flue gas to the pressure swing adsorption assembly. The system or method can include removing at least a portion of the nitrogen from the flue gas to produce greater than about 95% carbon dioxide using a pressure swing adsorption assembly, and providing at least a portion of the nitrogen removed from the flue gas to a gas expander/generator. The system or method may include removing at least a portion of the nitrogen from the flue gas to produce greater than 95% carbon dioxide using a pressure swing adsorption assembly, and supplying at least a portion of the nitrogen removed from the flue gas to both the dryer and the expander/generator, or to the dryer and a control valve. The control valve may or may not include a silencer.

Systems and methods are provided for cooling carbon dioxide separated from flue gas produced from a combustion boiler within a building. A system or method includes the steps of separating nitrogen from flue gas using a pressure swing adsorption assembly and passing nitrogen through a turbine expander in the presence of a heat exchanger to cool a fluid in the heat exchanger. and transferring the cooled fluid to another heat exchanger operably aligned with the carbon dioxide product of the pressure swing adsorption assembly to cool the carbon dioxide product. be able to.

A system and method are provided for liquefying carbon dioxide separated from flue gas produced from a combustion boiler in a building. The system or method may include supplying gaseous carbon dioxide to liquid carbon dioxide in a storage vessel through a sparging assembly.

A building is provided that utilizes a carbon fuel source and produces carbon emissions upon combustion of the carbon fuel source. Building emissions can be operably coupled to a carbon capture system, the system configured to separate and condense carbon dioxide from the carbon emissions. The system can be configured to process carbon emissions and return heat to the building. The system can be configured to process carbon emissions and generate electricity. The system can be configured to process carbon emissions and store electrical energy. The system can be configured to dynamically control the combustion and capture system to reduce carbon burn and increase carbon capture.

A combustion system is provided that may include a combustion assembly operably engaged with an intake, the intake performing air enrichment.

A method of enriching air to a combustion assembly is also provided. The method may include forming an N2-rich stream and an O2-rich stream from a first air stream, supplementing the second air stream with the O2-rich stream to enrich the second air stream with O2, and combusting the enriched air stream.

A system for separating _CO2 from a flue gas is also provided. The system may include a vortex tube assembly operably coupled to a component of the system that provides pressurized _N2 .

Also provided are methods for heating or cooling components of a system for separating _CO2 from flue gas. The method includes the steps of supplying compressed nitrogen from one or more components of the system to a vortex tube to form a heated nitrogen stream and a cooled nitrogen stream; and providing the cooled nitrogen stream to a component that benefits from the cooling source.

A system for separating _CO2 from flue gas can also include a separation assembly that includes a membrane assembly configured to separate _CO2 from _N2 .

A method for separating _CO2 from flue gas includes feeding a flue gas stream containing _CO2 and _N2 to a first membrane separation system to form a _CO2 -rich stream and a N2 _- rich stream. It can also include steps.

Embodiments of the present disclosure will be described below with reference to the accompanying drawings.

1 illustrates a carbon dioxide capture method and/or system according to an embodiment of the present disclosure. FIG. FIG. 3 illustrates a carbon dioxide capture method and/or system according to another embodiment of the present disclosure. 1 illustrates an exemplary boiler with a free oxygen sensor, according to an embodiment of the present disclosure. FIG. FIG. 1 illustrates an exemplary boiler configuration operably coupled to a plenum, according to one embodiment of the disclosure. 1 illustrates an exemplary boiler with a free oxygen sensor, according to an embodiment of the present disclosure. FIG. 1 is a diagram of a combustion assembly and a separation assembly in series, according to an embodiment of the present disclosure; FIG. 1 is a diagram of a combustion assembly according to an embodiment of the present disclosure; FIG. 1 is a diagram of an air enrichment assembly according to an embodiment of the present disclosure; FIG. FIG. 2 is a diagram of a combustion inlet flow/assembly according to one embodiment of the present disclosure. 1 is a diagram illustrating a portion of a carbon dioxide capture method and/or system according to an embodiment of the present disclosure. FIG. FIG. 2 illustrates a portion of a carbon dioxide capture method and/or system according to another embodiment of the present disclosure. FIG. 4 illustrates a portion of a carbon dioxide capture method and/or system according to another embodiment of the present disclosure. 1 is a diagram illustrating an example configuration of components of a carbon dioxide capture method and/or system, according to an embodiment of the present disclosure. FIG. FIG. 2 illustrates another exemplary configuration of components of a carbon dioxide capture method and/or system, according to an embodiment of the present disclosure. 1 is a diagram illustrating a portion of a carbon dioxide capture method and/or system according to an embodiment of the present disclosure. FIG. 1 is a diagram illustrating a portion of a carbon dioxide capture method and/or system according to an embodiment of the present disclosure. FIG. 1 is an illustration of a carbon dioxide separation assembly according to an embodiment of the present disclosure. FIG. FIG. 2 is a diagram of a carbon dioxide separation assembly according to an embodiment of the present disclosure. FIG. 1 is a diagram of a vortex tube according to one embodiment of the present disclosure. 14 is an exemplary implementation of the vortex tube assembly of FIG. 13 in combination with a separation assembly (e.g., a pressure swing adsorption (PSA) assembly) according to an embodiment of the present disclosure. 1 illustrates an example configuration of components of a carbon dioxide capture method and/or system, according to an embodiment of the present disclosure. FIG. 1 is a diagram illustrating an example of a CO ₂ separation system according to an embodiment of the present disclosure. FIG. FIG. 1 illustrates an exemplary _CO2 separation system component configured to operate as a carbonate pump according to one embodiment of the present disclosure. FIG. 2 illustrates exemplary CO ₂ separation system components according to an embodiment of the present disclosure that receive CO ₂ and N ₂ from a flue gas source and are configured to operate as a carbonate fuel cell. 1 illustrates an exemplary CO ₂ separation system according to an embodiment of the present disclosure that receives CO ₂ and N ₂ from an air source and is configured to operate as a carbonate fuel cell. FIG. FIG. 3 illustrates a general separation component according to one embodiment of the present disclosure. FIG. 2 illustrates a membrane separation component according to one embodiment of the present disclosure. 1A-1D illustrate configurations of membrane separation assemblies and methods according to embodiments of the present disclosure. 1A-1D illustrate configurations of membrane separation assemblies and methods according to embodiments of the present disclosure. 1A-1D illustrate configurations of membrane separation assemblies and methods according to embodiments of the present disclosure. 1 is a diagram illustrating a portion of a carbon dioxide capture method and/or system according to an embodiment of the present disclosure. FIG. FIG. 2 illustrates a portion of a carbon dioxide capture method and/or system according to another embodiment of the present disclosure. 1 is a diagram illustrating a portion of a carbon dioxide capture method and/or system according to an embodiment of the present disclosure. FIG. 1 is a diagram illustrating a portion of a carbon dioxide capture method and/or system according to an embodiment of the present disclosure. FIG. 25B illustrates another portion of the carbon dioxide capture method and/or system of FIG. 25A, according to an embodiment of the present disclosure. FIG.

The present disclosure will be described with reference to FIGS. 1-25B. The systems and methods of the present disclosure can be operated unattended and/or continuously in a building for up to 10 years with only minor periodic maintenance. Referring initially to FIG. 1, a system 10 is provided that includes a source of flue gas, such as a boiler that burns air and fuel to produce flue gas. Flue gas 12 may include typical combustion products from a building's heating and/or cooling system. These buildings can be considered commercial, residential, and/or industrial buildings. System 10 may rely on burning fossil fuels. These fossil fuels can include oil and/or natural gas. During combustion of fuel, _CO2 may be produced as part of the flue gas. For natural gas combustion, the system 10 can produce at least 10% _CO2 and about 18% water. The systems and/or methods of the present disclosure may include a section 14 for separation, a section 16 for liquefaction, a section 18 for storage, and a section 19 for transfer of _CO2 .

According to an exemplary implementation, at least about 600 standard cubic feet/minute of building flue gas may be diverted to the flue gas process stream, where the CO ₂ is separated and removed within component 14 of system 10 . Refined. The separation/purification component is an adsorbent operating under conditions of pressure swing (PSA), vacuum pressure swing adsorption (VPSA); temperature swing (TSA), or electric swing (ESA), or any combination thereof. It can be a purification system. According to an exemplary implementation, this includes a plurality of vessels housing layered solid phase adsorbents configured to combine and/or act together to provide greater than 85% CO ₂ capture. It can be a pressure swing adsorption system, which is a multi-component adsorption system. These multicomponent adsorption systems are capable of removing carbon dioxide from essentially "dry" flue gas streams to greater than 95% purity in most cases, and at least 99% purity in others. can. This purified carbon dioxide gas is then liquefied in successive cooling and compression steps to effect a phase change to form liquid carbon dioxide within the liquefaction component 16, followed by scheduled removal as desired. This liquefied carbon dioxide can be supplied to storage component 18 for storage. According to example implementations, this liquefied carbon dioxide can be transported remotely within the transport component 19, where the transport is carried out through concrete curing, wastewater treatment, other carbon dioxide sequestration methods, to name a few. , storage facilities where carbon dioxide can be distributed for use in applications such as recycling in fire extinguishing systems, consumption in the production of industrial specialty gases, hybrid fuels and organic intermediate chemicals, or in applications such as drinking carbonation. Can be supplied to another source.

Referring now to FIG. 2, a building system 30 is shown having a system 32 therein. The flue gas 12 is fed to a series of parts 14, 16, 18, 19 and/or a cooling tower 31 of the system and/or method for the capture of _CO2 from the flue gas produced by the building. Ru.

3A-3C, an exemplary boiler configuration is shown as part of the systems and/or methods of the present disclosure. Referring first to FIG. 3A, a boiler 40 is shown generating combustion 42 in the presence of a free oxygen sensor 43. Combustion 42 generates flue gas 44 that is fed to a boiler exhaust 45. Referring to FIG. 3B, the boiler exhaust is operably coupled to a plenum 48. In this illustrated configuration, multiple boilers are shown, each having exhausts 45 and 46, e.g., each exhaust operably coupled to a plenum 48.

Referring now to FIG. 3C, a boiler configured with the systems and/or methods of the present disclosure is shown. Accordingly, air 60 and fuel 62 may be supplied to the combustion burner, their mixing and thus combustion being controlled by a combustion controller 66 operably coupled to the free oxygen sensor 43. Thus, boiler feed water 52 is received by the combustion boiler and heated into hot water or steam 50 that is used to heat the building and/or building systems, such as water heater 58. Water heater system 58 may be configured to receive potable water that requires heating and/or industrial process water that requires heating.

According to an exemplary implementation, control 66 may utilize sensor 43 to monitor the amount of free oxygen within the combustion burner and maintain the amount of free oxygen at approximately 3%. About 3% free oxygen can include 3 to 7% free oxygen. According to example implementations, combustion may produce flue gas 44. Combustion of the (wet) flue gas 44 can be controlled to contain at least about 8% carbon dioxide. About 10% carbon dioxide can include 9 to 11% carbon dioxide of flue gas (on a dry basis) from combustion of natural gas. System 10 can be utilized to burn fuels other than natural gas, which may specify other optimal _CO2 flue gas concentrations. Accordingly, system 10 may be configured to utilize multiple fuels.

The systems and/or methods of the present disclosure may include separating the carbon dioxide from the flue gas, liquefying the carbon dioxide after separating the carbon dioxide from the flue gas, liquefying the separated carbon dioxide after separating the carbon dioxide from the flue gas, storing the carbon dioxide after liquefying the carbon dioxide, and/or transporting the carbon dioxide after storing the carbon dioxide.

3B and 3C, a system and/or method for operating a combustion boiler in a building is provided, the system and/or method including combusting air and fuel in a burner to generate a flue gas 44 having an oxygen concentration, and restricting air from the flue gas by substantially removing the tramp air in a conduit operably aligned to convey the flue gas from the burner. According to an exemplary implementation, in the case of multiple boilers as shown in FIG. 3B, exhausts 45 and 46 can be operably aligned with a plenum 48. Unused exhausts such as 46 can be a source of tramp air to the plenum. According to an exemplary implementation, the system and/or method of the present disclosure can include providing fluid communication between an operating burner of one boiler and the plenum while restricting fluid communication between the plenum and an idle burner of another operating boiler. In at least one configuration, a door or partition 47 can be provided and operable to remove the tramp air from the exhaust of the idle burner.

According to at least one aspect of the present disclosure, real-time control of a combustion source or boiler can achieve high efficiency, for example, reducing the burning of natural gas or fuel while increasing the concentration of carbon dioxide in the flue gas. This can be considered counterintuitive to increase the concentration of carbon dioxide in the flue gas when the disclosed system and/or method is utilized to reduce carbon emissions from a building. However, increasing the carbon dioxide concentration can provide the advantage of reducing fuel consumption by reducing heat loss through the exhaust. Adjusting the combustion to control free oxygen to 3% can result in more efficient combustion. According to an exemplary implementation, it is desirable to approach a 12% concentration value of _CO2 when burning natural gas through combustion control and achieve at least about 10% carbon dioxide concentration (dry basis) in the flue gas. This is at least one feature of the disclosed building emission treatment system and/or method, which can be utilized as one of the initial steps in carbon capture.

In a building, boiler operation can be specified in response to hot water or steam needs by controlling the combustion burners to various predetermined firing rates, i.e., 1) off, 2) low firing, and/or 3) high firing. These rates may be established in older boilers, for example, through calibrated mechanical linkages. Recognizing that cyclical boiler operation can vary significantly from hour to hour, day to day, and season to season, it is desirable to establish automatic control of the amount of flame continuously throughout the entire boiler load range, while also controlling free oxygen as discussed above. The disclosed systems and/or methods can be configured to extend boiler operating time with less flame, extend boiler life, and reduce on-off cycles by providing a more continuous flow of flue gas to the disclosed separation, liquefaction, storage, and/or transport systems and/or methods.

Thus, boiler and system controls (e.g., FIG. 24) can achieve higher building thermal efficiency while creating optimal conditions for flue gas supply to the systems and methods of the present disclosure.

Referring to FIG. 4, an assembly 100 is shown that includes a combustion assembly 11 that may or may not be in fluid communication with a separation assembly 14. FIG. 1 can be seen in the context of U.S. Patent Application Publication No. 2020/0340665, filed October 29, 2020, which is incorporated herein by reference in its entirety.

According to example implementations, combustion assembly 11 may utilize air enrichment assembly 130 to perform air enrichment prior to receiving air for combustion. Air 60 may be provided and enriched prior to use in combustion assembly 11. Combustion assembly 11 may produce an exhaust gas mixture 170 that may include carbon dioxide. Mixture 170 can be fed to separation assembly 14, eg, after additional processing. During exemplary processing, mixture 170 may be dried enough to separate carbon dioxide within separation assembly 14. Separation assembly 14 can provide a separation gas mixture 200 that includes a substantially higher concentration of carbon dioxide than that supplied to the separation assembly.

Referring now to FIG. 5, an exemplary combustion system is shown that includes a burner configured to receive enriched air 210 and supply air 60 through enrichment assembly 130. According to an exemplary implementation, the burner and/or the air and/or fuel being supplied to the burner are controlled by a combustion controller (not shown) to heat water that is part of the steam loop. be able to. The combustion assembly may generate exhaust gas 44, such as flue gas.

6, a more detailed view of the membrane enrichment assembly 130 is shown, including air 60 entering the membrane assembly 170. The membrane assembly 170 can be configured as a bundled hollow fiber membrane. Exemplary membrane assemblies can include SEPURAN® (Evonik Industries AG, Rellinghauser Strasse 1-11 45128 Essen Germany) and/or custom assemblies (UniSieve Ltd, Regina-Kagi-Strasse 11, CH-8050 Zurich, Switzerland). These membrane assemblies can include multiple membranes, for example, 3-5 membranes.

As can be seen, air 60 may enter membrane assembly 170, and the air may include 21% or more oxygen and 78.5% nitrogen. Exiting as retentate mixture 160 can result in a stream that is substantially nitrogen in the range of about 90% to 95%, but passing into another stream as permeate mixture 140 containing less nitrogen (58-64%). The stream may be between approximately 36% and 43% oxygen. According to an exemplary implementation, permeate mixture 140 is provided to enrich air stream 60 in mixing system 180, which may be configured as a valve system and/or a plenum system to form enriched air mixture 210. be able to. The enriched air mixture 210 has a higher oxygen concentration than standard air and can be followed to the burner for combustion.

Referring to FIG. 7, further details are provided for additional embodiments of air enrichment for combustion. Accordingly, air 60 may be compressed and provided to membrane assembly 170, which provides _N2- rich stream 160 and _O2- rich stream 140. Using a flow controller, O ₂ rich stream 140 can be mixed with air 60 in mixing system 180 to provide enriched air 210 to a boiler burner via a boiler blower, for example. According to example implementations, the _N2- rich stream 160 may be operably coupled to a turboexpander and/or vortex tube to generate electrical power and/or hot and cold _N2 as needed. can. This is just one example of a turboexpander and/or vortex tube coupled to a high pressure _N2 source.

According to an exemplary implementation, providing enriched air to the combustion assembly can reduce the amount of nitrogen in the exhaust or flue gas, thereby reducing the amount of nitrogen that may need to be processed when separating carbon dioxide from the nitrogen.

8A-8C, portions of a system and method for separating water from flue gas and cooling flue gas are shown. Referring first to FIGS. 8A-8C, three different configurations of systems and/or methods for cooling flue gas from combustion boilers within a building are shown. Referring first to FIG. 8A, flue gas 44 may proceed to a combined non-condensing and condensing economizer 60a. Flue gas 44 first proceeds to a non-condensing configuration where boiler feed water 52 is fed through a conduit, set of conduits, and/or coils to cool the flue gas and heat the boiler feed water. Accordingly, a method is provided for cooling flue gas from a combustion boiler within a building. Heating the boiler feed water can be fed to the boiler, thus reducing the required energy needed to heat the feed water to hot water and/or steam.

Additionally, the economizer can be configured for condensation. Accordingly, the conduit, set of conduits, and coil 54 may be configured to convey potable water or industrial process water received from a utility, for example. This water is typically conveyed through underground pipes, so it can have a temperature close to that of groundwater. Therefore, the water has a substantially different temperature than the flue gas even after being partially cooled in the non-condensing economizer. Supplying flue gas to these conduits allows water to be removed from the flue gas, thus creating a water condensate effluent 53. This water passing through the conduit can be heated and supplied to a hot water system 58 (FIG. 3C) as a hot water system inlet 54 and heated and received through an outlet 56. Thus, at least for the reason that the water received for heating does not need to be heated from the low temperatures associated with typical tap water, but rather is preheated, the water in the hot water system 58 is heated. The amount of energy required to do so is less. According to an alternative configuration, and referring to FIG. 8B, one set of coils 52 may be associated with one economizer 60b and another set of coils 54 may be associated with another economizer 65a. In this configuration, economizer 60b may be a non-condensing economizer and economizer 65a may be configured as a condensing economizer. According to another embodiment of the present disclosure, the diverter 64 can be operably coupled to an economizer, as shown in FIGS. 8A-8C. According to an example implementation, cooled flue gas may be provided from diverter 64 using a blower. The system and/or method can control the amount of flue gas treated using a diverter. According to an exemplary implementation, the current system according to FIG. 8C will receive between 450 standard cubic feet per minute (SCFM) and 500 SCFM of wet flue gas 44. This diverter can be controlled by an overall master system (FIG. 24) that can control motor-operated butterfly valves within the diverter. The master system can also collect gas temperature and flow data and operate the blower as shown in FIG.

Thus, when the economizer is downstream of the process stream from the diverter, the blower may precede the economizer. According to an exemplary implementation, the wet flue gas is at least about 8% carbon dioxide and/or at least about 3% free oxygen before entering the first economizer. The systems and/or methods of the present disclosure may use an economizer configured, for example, as shown in Figures 9A and 9B, and the method may include additional separation, as well as liquefaction, storage, and transport.

It has been determined that flue gas from a boiler can have a moisture content of approximately 18% and a temperature range of up to 350° F. Prior to _CO2 separation, this water can be substantially removed from the flue gas. This involves lowering the flue gas temperature below the dew point and condensing the water as a liquid. As the moisture content of the flue gas decreases, the dew point also decreases, requiring further cooling to continue to remove the water. This cooling can result in flue gas condensate.

Flue gas condensate tends to be slightly acidic (pH<=5), which can cause damage to some building plenums due to non-acid resistant building materials (such as carbon steel). There are certain conditions. In these cases, the gas must be removed from the plenum and condensed in an external heat exchanger with acid-resistant stainless steel components. Additionally, depending on the condenser design, some amount of microdroplets may remain in the gas stream. These microdroplets can be referred to as acidic aerosols, which can exist at ppm levels. The present disclosure contemplates the removal of acidic aerosols. These systems and/or methods include, for example, wet wall heat exchangers, impinger or mist eliminators with inert reticulated carbon or metal foams, and precipitators.

According to the above, non-condensing economizers can operate above the dew point temperature and prevent the formation of any liquid condensate. Since there is no condensation, this economizer can accommodate most plenum building materials.

As mentioned above, a condensing economizer can be provided downstream of a diverter (FIG. 8C) that extracts flue gas from the plenum and directs it to the condensing economizer. The condensate from this condensate economizer can be chemically neutralized before proceeding to the building drain, as shown by 75 in FIG.

Referring now to FIG. 10, flue gas drying can continue with a blower 68 to increase the pressure of the flue gas from the diverter. This blower 68 can support flow through a heat exchanger/condenser 70, which can include a water outlet 71 operably coupled to an acid neutralizer assembly 75. The heat exchanger 70 can be configured to cool the gas below the dew point to condense most of the water leaving less than about 3% water, or as little as approximately 0.2% water.

Heat exchanger 70 can be of a tube and shell configuration, cooled by, for example, an external water/glycol loop supplied from a chiller and/or water from a building cooling tower. As shown, the water removed from the system at heat exchanger 70 may be slightly acidic, and the water is clarified before proceeding to the public wastewater treatment plant (POTW) or through the wastewater system. It is expected that this will be possible. In addition, some water enters the process stream as small microdroplets, mist, or acid aerosols that are minimized or removed in special heat exchanger designs, mist eliminators, impingement devices, or possibly precipitators. remain. These components can generate additional condensate or effluent that can be treated before proceeding to the POTW.

After most of the water has been removed and acid aerosols mitigated, the cooled flue gas 72 can continue to a compressor to increase the pressure of the flue gas to an optimum level of approximately 100 psig or less, as defined by the PSA system specifications. The compressor can generate additional condensate or effluent because compression increases the process gas dew point.

Now referring to FIG. 11, a compressor 74 may receive the flue gas 72. The compressor 74 may be an "oil-free" compressor to eliminate downstream product contamination, and the compressor may be configured with a variable frequency drive (VFD) to respond to variable gas flows. Because compression increases the temperature and dew point of the flue gas, a second heat exchanger 76 may be utilized to reduce the temperature of the flue gas to below 40° C. At this stage, the gas may have less than about 0.2% water present as steam, the gas may be at a temperature of less than 40° C., and may be at a pressure of about 100 psig.

Referring to FIG. 11, a system and/or method for separating carbon dioxide from flue gas generated from a combustion boiler in a building may include providing flue gas 72 having less than about 3% water, compressing the flue gas, cooling a compressor 74 with a heat transfer fluid 90, and providing the heat transfer fluid to/from a chiller and/or cooling tower.

According to another exemplary implementation, a mist eliminator subsystem 89 can be provided that can generate an effluent 53. During water removal from the flue gas, liquid condensate can be generated as an effluent at another point in the process or system. This effluent can be slightly acidic (approximately 5 pH) and can be neutralized before being delivered to the building drain.

Very small amounts of this slightly acidic condensate remain entrained in the process gas as mist or acid aerosols. To remove these liquid microdroplets, a mist eliminator subsystem 89 can be added just before the compressor inlet. This subsystem can be an electrostatic unit, a wetted wall heat exchanger, or a passive impinger arrangement made of reticulated metal or carbon foam, wire mesh pads, or other materials designed with a tortuous gas path that causes mist particles to impact and nucleate on surface areas and drain the system by gravity. By reducing or eliminating the acid aerosols, the mist eliminator solution can largely prevent harmful corrosion in downstream components of the process gas stream. Thus, the mist eliminator can produce an effluent 53 that can be neutralized and fed to a drain.

Referring now to FIG. 12A, an exemplary implementation of separation assembly 14 is shown that includes a PSA or pressure swing adsorption assembly 80 that can be configured in-line to receive a quantity of an inlet fluid, such as a gas having, for example, 8% to 16% carbon dioxide and 86% to 78% nitrogen. The PSA 80 can be configured to separate the carbon dioxide from this stream and provide carbon dioxide of greater than 95% purity.

In this process, the PSA 80 may supply a pressurized stream of substantially nitrogen to one or more assemblies, such as a turbine expander via stream 42, as shown. 48 as well as via stream 44 to control valve 50 . According to example implementations, a nitrogen stream 86 can be provided from these assemblies.

According to an exemplary implementation, yet another stream 46 may be provided to a vortex tube assembly 52 that receives pressurized nitrogen and supplies cold nitrogen 54 and hot nitrogen 56. The present disclosure may be configured to utilize the heat of streams 54 and/or 56 in combination with the operating features of the system and/or specifically the PSA assembly. This is one example of coupling a vortex tube to utilize the pressurized N ₂ created in the systems and/or methods of the present disclosure. As described herein, the vortex tube and/or turboexpander can be coupled to other components in the system that produce pressurized N ₂ , such as a membrane retentate stream.

For example, referring to FIG. 12B, when the PSA assembly is configured to perform step cycling, different portions of the PSA include adsorbents configured to provide carbon dioxide adsorption or desorption when separating nitrogen from carbon dioxide at certain temperatures and/or pressures. For example, portion A as 60 can be configured to adsorb carbon dioxide, and thus cold nitrogen 54 can be provided to that portion to further facilitate adsorption of carbon dioxide during that step cycle. Alternatively, hot nitrogen 56 can be provided to warm the adsorbent for desorbing carbon dioxide in either a different time step cycle or a different portion D as 62 of the PSA, which is the desorbing step. Thus, the system can utilize hot and/or cold nitrogen provided from the pressurized nitrogen of the PSA as thermal energy to facilitate more efficient PSA separation.

An exemplary vortex tube assembly 300 is shown in FIG. 13 that includes an input 302 configured to receive compressed nitrogen and provide cold nitrogen at an outlet 304 and hot nitrogen at an outlet 306.

14, a more detailed diagram of the heat exchange is shown in which cold nitrogen can be supplied to a heat exchanger as part of one portion of the PSA and hot nitrogen can be supplied to another portion. These portions can be coordinated to supply thermal energy during synchronized step cycles of pressure swing adsorption to separate carbon dioxide from the inlet gas. According to an exemplary implementation, the portion of the PSA adsorbent can be in thermal communication with a heat exchange assembly configured to receive either cold or hot nitrogen or both from the vortex assembly (e.g., as part of the step cycling of the PSA). As shown, the vortex outlet can be provided with a valve to control the flow of hot or cold nitrogen to the heat exchanger in thermal communication with the adsorbent.

An exemplary compressor is shown in FIG. 15. The heat transfer fluid can be, for example, water, and the chiller water can be cooled in a building cooling tower before returning the spent heat transfer fluid to the chiller. Thus, the disclosed system and/or method can include additional separation, liquefaction, storage, and/or transport. This is just one example of a heat generating component of the system that can be cooled with the chiller and/or cooling tower heat transfer fluid. More than 70% of the cooling requirements of the disclosed system and/or method can come from heat generated in the compressor and/or pump, as well as the heat exchanger of the liquefaction skid. Each of these components can be provided with a water cooling circuit supplied from a local chiller or directly from a central chiller. The local chiller can be water cooled with a water loop coming from the central chiller or from cooling water from the building cooling tower. The central chiller can be designed to prioritize heat transfer in the following order: for example, a) domestic hot water make-up, b) cooling tower, c) exchange with outside air.

Referring again to FIG. 11, after compression, the flue gas can be fed to a dryer 78, such as a desiccant dryer. The dryer 78 can be operatively engaged with a nitrogen feed, such as a sweep feed, configured to regenerate the spent desiccant. Typically, the dryer is a two-chamber cycling device, where one chamber is drying while the other chamber is being regenerated for drying, and these cycles continue. Nitrogen can be fed to the spent desiccant in one chamber while the other chamber is drying the flue gas. Thus, a system and/or method is provided for separating carbon dioxide from flue gas generated from a combustion boiler in a building, which can include drying the flue gas using the nitrogen recovered during separation of the carbon dioxide recovered from the flue gas. The recovered nitrogen can be conveyed from the pressure swing adsorption assembly 80 to the dryer 78 via conduit 92 and then discharged through stack 86. According to an exemplary implementation, the dried flue gas can be fed for further separation, liquefaction, storage, and/or transportation.

From the dryer, flue gas 79 containing less than 10 ppm water may proceed to a pressure swing adsorption (PSA) assembly 80. This pressure swing adsorption assembly can provide greater than 85% CO ₂ capture with greater than 95% purity at 1 psig from an atmosphere up to about 100°C. The maximum _CO2 output flow at this point may be approximately 40 SCFM. The remainder of the flue gas, which is mostly nitrogen, may continue under pressure and/or be divided such that a portion is returned to dryer 78. Another portion of the nitrogen can go to a turbine expander 82/generator 93 that can provide electrical energy 94 and cold output gas at near atmospheric pressure. Additionally, a silencer-equipped control valve 84 can be operatively aligned in parallel with the expander 82/generator 93.

Accordingly, a combustion boiler in a building may include using a pressure swing adsorption assembly 80 to remove at least a portion of the nitrogen from the flue gas to produce greater than about 95% carbon dioxide 78. A method is provided for separating carbon dioxide from flue gas produced from. The nitrogen removed from the flue gas can be used, for example, in dryer 78 to remove water from the flue gas prior to supplying the flue gas to a pressure swing adsorption assembly. Alternatively or additionally, at least a portion of the nitrogen removed from the flue gas can be fed to a gas expander/generator. Alternatively, or additionally, a portion of the nitrogen from the PSA can be fed to a control valve with a silencer and another portion to an expander/generator. According to example implementations, the systems and/or methods of the present disclosure include separating nitrogen into portions, feeding one portion to a dryer and another portion to an expander/generator. The method may include the steps of: In one exemplary implementation, one portion is about one third of the nitrogen from the pressure swing adsorption assembly.

According to example implementations, a small amount of rejected gas can be generated during the PSA process, including both _CO2 and nitrogen. Rather than purging this gas, it can be recycled through the compressor via recycle line 81 to enhance the overall recovery of _CO2 .

A system and/or method is also provided for cooling carbon dioxide separated from flue gas generated from a combustion boiler in a building using nitrogen exhaust from a PSA. The system and/or method may include separating nitrogen from the flue gas using a pressure swing adsorption assembly 80, expanding the nitrogen through a turbine in the presence of a heat exchanger 92 to cool a fluid in the heat exchanger 92, and transferring the cooled fluid to another heat exchanger 100 operatively aligned with the carbon dioxide product 78 of the pressure swing adsorption assembly to cool the carbon dioxide product. The turbine may be part of a generator 93, for example, or may be provided to cool the exchanger 92.

Typically, the nitrogen gas exiting the PSA may be at least 85 psig, with a flow rate greater than 80% of the rated system flow rate. According to an exemplary implementation, the nitrogen may be processed and stored as a market commodity. For power generation, grid-compatible power conversion will be required. The turbogenerator has a 500 Hz output that is not compatible with the 60 Hz grid. Therefore, it is assumed that appropriate power conversion will be specified. This may be a DC-AC polyphase inverter, followed by rectification, with appropriate safety features in case of a building power outage. After use in the turbogenerator and _CO2 heat exchanger, the nitrogen exhaust gas may be returned to the exhaust stack or plenum.

16A-16D, different embodiments of _CO2 separation systems and/or methods that can be used alone or in combination with some or all of the components of the systems and/or methods of FIG. It is shown.

For example, referring to FIG. 16A, an electrochemical cell is shown that includes a cathode configured to receive reactant CO ₂ and O ₂ . This _CO2 and _O2 can be received from the same or different streams. For example, _CO2 can be received from a flue gas stream or may be received from an air stream. The flue gas stream may be _CO2 and _N2 , may include _O2 , and may also include a range of concentrations of _H2O . For example, a stream may be considered wet or dry, with a wet stream containing H ₂ O from the combustion process that produced the flue gas. _O2 may be received as part of the flue gas stream, air stream, and/or as part of the _O2 stream.

Exiting the cathode side of the cell can be a _N2 stream. This _N2 stream can also contain _CO2 that _{has not reacted to form carbonate ions (CO32-). For example, it can contain CO2, H2O , and} ^/ or _O2 . This _N2 stream contains less _CO2 than the stream exposed to the cathode.

When exposed to the cathode and the gaseous bond, the _CO2 reacts to form carbonate ions that are transported through the carbonate electrolyte to the anode, and the gaseous bond converts ^the _CO32− into the _CO2 product. as _CO2 and _O2 . As detailed below, this system can be used in a variety of ways, such as as a carbonate ion pump (FIG. 16B), as a flue gas carbonate fuel cell (FIG. 16C), and/or as a fuel cell (FIG. 16D) Can be implemented. In one or more of these implementations, CO ₂ may be removed/separated/sequestered from one or more streams.

For example, referring to FIG. 16B, a portion of a carbon dioxide capture method and/or system comprised of a carbonate ion pump is shown. As shown, carbonate ions can be electrochemically generated on the surface of a cathode electrode by reacting carbon dioxide and oxygen from air in the presence of electrons. _CO2 can be obtained from flue gas in wet or dry form, and _O2 can be part of the flue gas or can be supplied from an _O2 source, for example, from air. The flue gas can include _N2 that does not react at the cathode and travels to the gas stack along with other unreacted components (e.g., _H2O , _O2 , _CO2 ).

The electrochemical equation is CO ₂ +1/2O ₂ +2e ⁻ >>,CO ₃ ⁻ .Multiple cells can be arranged in a stack, which feeds CO ₂ and O ₂ through respective manifolds.

Once carbonate ions are generated at the cathode, a solid or liquid electrolyte can be in ion communication with the cathode and provide a path for the carbonate ions to migrate to the associated anode. This electrochemical activity is the basis for forming and transporting carbonate ions and separating _CO2 from the original cathode gas mixture.

Upon reaching the anode, electrons can be removed from the carbonate ion(s), causing dissociation back to _CO2 and 1/ _2O2 .

According to another implementation of the present disclosure, _CO2 can be separated from flue gas using membranes alone or in combination with other separation techniques. Membrane separations can utilize solvent-absorbing and/or polymer-based membranes with appropriate permeability and selectivity for _CO2 . Polymer membranes can also include mixed polymer membranes. Additional membranes can include carbon membranes and/or inorganic membranes. _CO2 separation can be performed using membranes configured to perform Knudson diffusion, molecular sieves, solution diffusion separation, surface diffusion, and/or capillary condensation.

As shown in Figures 16B-16D, _O2 can be generated from the _CO2 product stream, for example during liquefaction. This _O2 can be supplied to the cathode as part of the _O2 source. The amount of _O2 being supplied to the cathode can be monitored and/or adjusted as desired to operate the cell for optimal _CO2 separation.

According to one embodiment of the disclosure, and with reference to FIGS. 16C-16D, a carbonate fuel cell configuration can be fed with fuel, specifically sufficient hydrocarbon fuel to form syngas ( _H2 and CO). Syngas can be formed from natural gas ( _CH4 → _H2 and CO) and/or other hydrocarbon materials including, but not limited to, coal. The cathode can be exposed to _CO2 and O2 as described above to form carbonate ions which can be exposed to syngas at the anode to form _CO2 and _H2O and _electrons to provide power output in the form of heat and electricity. The system can be part of a building design replacing a generator or boiler in the building and/or can be a stand-alone system to provide heat and power.

Natural gas can be supplied as part of a fuel cell, and the natural gas can be tapped into an existing building through an intake. Thus, while using natural gas, which can be reformed directly into synthesis gas at operating temperatures, heat and power can be generated electrochemically, and this heat and power can be supplied to buildings, which can offset some or all of a building's heat and power needs without natural gas combustion, thus significantly reducing _CO2 emissions.

For example, the system can be paired with a typical boiler system configured to burn natural gas. Thus, both the boiler and ion pump systems can be configured to receive natural gas. Thus, the system of FIG. 16C can provide heat and power, while the boiler can provide thermal output in the form of steam. The system of FIG. 16C can also be operatively aligned with a _CO2 capture and purification system.

Thus, the fuel cell can receive flue gas at the cathode and the _CO2 is electrochemically purified and made available for separation and liquefaction. As shown, the flue gas can be delivered through a tortuous path to maximize exposure of _CO2 to the cathode electrode surface area. This flue gas may be supplied directly from the combustion boiler or may be treated as described with reference to FIGS. 8-11 before being exposed to the cathode side of the fuel cell. Multiple cells can be configured in a stack with appropriate gas manifolds. This particular embodiment may provide improved performance at higher _CO2 concentrations, thus allowing for less flue gas pretreatment prior to _CO2 separation.

Upon reaching the anode, electrons can be removed from the carbonate ion(s), causing reforming of _CO2 and _O2 . According to Figures 16A-16D, the stream containing _CO2 and _O2 can be fed to liquefaction, for example, as described herein with reference to Figure 1. The non-condensable oxygen can be separated and fed to the cathode side of the pump. Electrical energy can be provided to operate the pump. The pump can also utilize heat from the flue gas.

Therefore, heat and power can be generated electrochemically while using natural gas that is reformed directly into syngas at operating temperatures, and this heat and power can be supplied to buildings, thereby making it possible to Some or all of a building's heat and power needs can be offset without gas combustion.

Therefore, syngas can be introduced at the anode and the carbonate ions react exothermically to form more _CO2 and water vapor. At this stage, a significant amount of the gas obtained may be purified _CO2 . This concept further teaches the removal of water vapor through condensation followed by liquefaction of the _CO2 .

Thus, there is provided a system for separating _CO2 from combustion products, which may include a combustion product stream. The combustion product stream may be a wet or dry stream including _CO2 and _N2 , or, for example, _CO2 , _O2 , _H2O , and/or _N2 . The system may include a carbonate ion pump or carbonate electrochemical cell operatively aligned with the combustion stream and configured to react _CO2 and _O2 from the combustion product stream to form carbonate ions and to react the carbonate ions to form the _CO2 product stream.

A carbonate electrochemical cell can include a cathode configured to receive electrons from a power source and react those electrons with _CO2 and _O2 of a combustion product stream to form carbonate ions. The carbonate ions can be _CO3 ^2- , for example, a component of a carbonate electrolyte. The cell can also include an anode configured to react the carbonate ions to form _CO2 , _O2 , and electrons. Thus, the system can include a cathode and an anode around a carbonate electrolyte.

According to additional embodiments, an _O2 source can be operably coupled to the cathode of a carbonate electrochemical cell. In this configuration, the cathode can be configured to be exposed to _CO2 from the combustion stream and _O2 from the _O2 source. Further embodiments can utilize a syngas source operably coupled to the anode to provide a carbonate fuel cell. In this configuration, the anode can be configured to receive carbonate ions and syngas and form a _CO2 product stream.

The system includes a catalytic burner operably coupled to the CO ₂ product stream and a heat exchanger operably coupled to the catalytic burner and configured to remove H ₂ O from the CO ₂ product stream. be able to. The heat exchanger can be operably coupled to the heat recovery loop with an additional conduit configured to supply _CO2 to the cathode.

A method for separating _CO2 from a combustion product stream can include receiving a combustion product stream including _CO2 and _N2 , reacting the combustion product stream to form carbonate ions, and reacting the carbonate ions to form a _CO2 product stream. Electrons can be supplied to form the carbonate ions and electrons can be removed to form the _CO2 product stream.

Additionally, syngas can be supplied to react with carbonate ions to form a _CO2 product stream, and natural gas can be supplied to form syngas. Embodiments of this method can generate a net positive electrical potential upon forming the CO ₂ product stream.

Referring to FIG. 16D, a system for separating _CO2 from air is provided. The system can include an air stream, the air stream can include at least _CO2 and _N2 , and a carbonate fuel cell operatively aligned with the air stream and configured to react _CO2 and _O2 from the air stream to form carbonate ions and to react the carbonate ions to form a _CO2 product stream. An _O2 source can be operatively coupled to a cathode of the carbonate fuel cell, the cathode configured to react _CO2 from the combustion stream and/or _O2 from the source. As shown, the _O2 source can be from a _CO2 liquefaction process. A natural gas source can be operatively coupled to an anode of the carbonate fuel cell, the anode configured to receive carbonate ions and natural gas and form a _CO2 product stream.

In some implementations, a portion of the CO ₂ can be returned to the cathode if desired, and the remaining CO ₂ is sent for liquefaction, as described with reference to Figures 22-25B.

Referring now to FIG. 17, a portion of system 10 including separation assembly 14 is shown. Entering separation assembly 14 may be fluid mixture 12, typically in the gas phase. Mixture 12 can include flue gas that can be treated to remove water. The mixture can typically contain carbon dioxide in an amount of 8% to about 16%, and 86% to 82% nitrogen, with the remainder being oxygen and other trace substances. Exiting separation assembly 14 may be at least one separated mixture 78 that may have a higher concentration of carbon dioxide than the carbon dioxide concentration of mixture 12 .

Referring now to FIG. 18, according to an exemplary implementation, a membrane separation assembly 1000 can receive mixture 12 and provide at least two separated streams, a retentate stream 1018 and a permeate stream 1020. It is shown. Separation assembly 540 can be configured as a bundle hollow fiber membrane. Exemplary membrane assemblies include SEPURAN® (Evonik Industries AG, Rellinghauser Strase 1-11 45128 Essen Germany) and/or custom assemblies (UniSieve Ltd, Regina-Kagi-Strasse 1-11 45128 Essen Germany). 11, CH-8050 Zurich, Switzerland) can be included.

Thus, stream 1018 may have a higher concentration of nitrogen than mixture 12 and stream 1020 may have a substantially higher concentration of carbon dioxide than mixture 12. According to example implementations, membrane separation assembly 540 can have multiple components and multiple configurations, including flow rate, temperature, pressure, membrane, and/or stage configurations. The stages can include serial stages, returning stages, and/or stages that cause separation to occur at particular flow rates, pressures, and/or temperatures. According to an example implementation, this configuration may include a backpressure regulator or control valve 1022 to maintain backpressure in the membrane separation assembly 540.

19-21, multiple configurations of membrane separation assemblies 540A and 540B are shown, for example, in the context of systems 1100, 1200, and 1300. According to example implementations, mixture 12 may be provided to assembly 540A. With particular reference to FIG. 19, assembly 540A can have one or more membranes, and assembly 540B can have one or more membranes. As shown, assembly 540A can provide a retentate mixture 1018A that can proceed to optional assembly 540B while also providing permeate mixture 1020A. Alternatively, mixture 1018A can be fed to other points in the separation and purification system. Permeate mixture 1020A can have a carbon dioxide content of about 60% to about 70%. According to example implementations, the stages operate in different configurations to provide a yield of carbon dioxide of greater than 90%, as well as a purity of carbon dioxide exiting the system that can be as high as 70%, for example. can do. If included, assembly 540B can provide a retentate mixture 1018B and a permeate mixture 1020B.

According to another exemplary implementation, a vacuum pump 600 can be provided. The vacuum pump 600 can provide a pressure differential to facilitate the production of the permeate mixture 1020A. Thus, removal of the permeate mixture from the membrane assembly under reduced pressure can provide additional yield and/or purity of carbon dioxide in the permeate mixture.

20, multiple membrane assemblies 540A and 540B are provided, again in different configurations. With reference to an exemplary implementation, assembly 540A can include one or more membranes, and assembly 540B can include one or more membranes. Mixture 1020B can be fed to assembly 540A as enriched mixture 1700 along with mixture 12 and pressurized in compressor 400. With an exemplary implementation, mixture 1700 can have a higher concentration of carbon dioxide than mixture 12. With this configuration, the carbon dioxide yield can be increased to 90%, and the carbon dioxide can be maintained at a purity of greater than 70%.

21, another configuration includes assemblies 540A and 540B, where assembly 540B receives permeate mixture 1020A. The assemblies can have the mixture supplied under pressure by compressors 400 and 420, as shown.

According to an exemplary implementation, and with reference to the figures above, the present disclosure provides membrane separation technology that can be used as part of carbon dioxide separation systems and alternative systems, including but not limited to those of U.S. Patent Application Publication No. 2020/0340665, filed October 29, 2020, which is incorporated herein by reference in its entirety.

Referring now to FIG. 22, in another series of components of the present disclosure, >95% pure CO ₂ 78 is transferred to heat exchanger 104 , compressors 106 and 108 , and heat exchanger 110 . Cooling and compression may be performed in sequential steps, with the compressor operably engaged with the cooling transfer fluid 90 to approach a phase change state for liquefaction. According to example implementations, >95% pure CO ₂ can have a temperature as high as 100° C. exiting the PSA. As mentioned above, a heat exchanger may be provided to reduce the temperature of the gas to a sufficient temperature and then compress the gas to a higher pressure. According to an exemplary implementation, the heat removed from this _CO2 stream is returned through an external water/glycol cooling loop to a thermal management system that supports feed water preheating as shown in FIG. Can be done. This may also be provided to increase the temperature of the nitrogen gas exiting the PSA prior to expansion through the turbine. This can improve turbine efficiency by allowing full use of nitrogen flow before the COLD temperature output limit is exceeded. This is just one of several examples of utilizing heat from system components in other parts of the system to derive a more efficient overall system. According to Figure 23, there is a stepwise cooling and compression sequence of the _CO2 gas that drives it towards a final state of 311 psig and 0°F, at which point a phase change occurs and the _CO2 becomes liquid. become.

Referring now to FIG. 23, a CO ₂ liquefaction and storage system and/or method is shown in which CO ₂ gas 112 is distributed inside a container 113, such as an insulated container. Exemplary insulated containers can include, but are not limited to, vacuum jacketed liquid storage tanks. Within this container, gas 112 can be converted to liquid 114. According to an exemplary implementation, gas 112 may be supplied to sparge assembly 118 where it is provided as sparge gas 120, which liquefies into liquid 114 upon dispensing.

The vapor 116 in the upper part of the vessel 113 is managed by a cryogenic system 122 that cools the vapor 116 and the vapor 116 condenses back into liquid 114 and returns into the vessel 113. According to an exemplary configuration, system 122 may be configured as a loop in fluid communication with vessel 113, where vaporized CO ₂ 116 enters system 122 and returns to vessel 113 as liquid CO ₂ 114. In at least one configuration, system 122 is configured as a cryogenic condenser with an evaporator.

According to additional embodiments, the vessel 113 can be configured with a controlled venting subsystem to facilitate removal of non-condensable gases while minimizing _CO2 loss. The inlet gas to the _CO2 liquefaction system can be high concentration _CO2 , preferably >95%. The remaining gases, such as nitrogen and oxygen, can be considered non-condensable gases in the liquefaction process. In addition, a very small subset of impurity gases remains that are miscible with the liquid _CO2 . These impurities must be accurately measured in order to certify the liquid _CO2 product according to commercial standards such as ISBT, International Beverage Guidelines, etc. Both the controlled venting subsystem and the purity analysis system can take into account non-condensable gases that can dissolve in the body.

Without pretreatment by the distillation column, non-condensable gases in the continuous feed to the liquefaction can accumulate in the storage system vapor space 116. Without removal, these non-condensable gases can continue to build up pressure in the vapor space of the storage tank, dissolving some of the gas into the liquid, thus contaminating the liquid. In addition, excess pressure in the tank can inhibit both the gas supply system and the cryogenic system that manages the vapor and re-condenses the _CO2 as a liquid back into the tank. The vent system can be controlled to manage the tank vapor space in conjunction with the cryogenic unit to release non-condensable gases and reduce pressure rise while minimizing the loss of _CO2 vapor. Instrumentation in the tank (see, for example, FIG. 11) can be configured to obtain data on vapor pressure, dissolved gases, vapor composition, gas flow, etc., and provide the data to a processor that can operate a solenoid valve in the vent line to perform a controlled release of tank vapor within strict parameters.

In case of building power loss, for example, good insulation of a vacuum jacketed tank can maintain liquid _CO2 for at least 30 days. According to an exemplary implementation, the building itself may tap a supply of CO ₂ into the container 113 to extinguish a fire, for example, a fire involving electronic components that requires CO ₂ extinguishing methods.

Referring to the figure, according to another exemplary implementation, a _CO2 removal and/or delivery system is provided that can include off-take management using one or more vehicles provided to meet _CO2 removal and/or delivery demands provided by the system control. For example, a removal and/or delivery truck 200 can be provided that directly transfers _CO2 from the container 113 via a transfer pump 202 into a liquid _CO2 tank mounted on the truck 200. The system can be configured to generate CO2 pickup times based on a number of parameters, such as the capacity of the container 113, the _CO2 generation of the system 10, legal date/time pickup windows, and/or _CO2 delivery demands. It is believed that such high _{purity CO2 can be delivered directly to users without being warehoused or requiring additional purification with respect to CO2 delivery} demands. Just one example of direct delivery can be delivery to a wastewater treatment plant. However, in either case, an off-take analysis can be provided to qualify the product with the ability to issue a test report before shipping.

Referring now to FIG. 24, the plant, process, and field level components of the control system are shown. According to an exemplary implementation, an exemplary overall control system is provided showing combustion emissions and control, MASTER PLC controller, diverter, compression, dryer, separation, cooling and compression, refrigeration/storage, and food grade _CO2 delivery. These systems are also coupled to electric, natural gas, and water utility systems. These control systems are a good example of a basic network architecture diagram. The MASTER PLC controls the entire plant with Ethernet loop connections and Internet IP protocol communication to local package controllers, and through direct connection and control to the digital and analog I/O field instrumentation level. The HMI server collects data from the MASTER PLC, manages real-time views of the plant, runs logging, data management applications, and communicates with external users through a secure firewall. Also implied is an engineering development workstation that maintains all operational software and updates that are periodically downloaded to the MASTER PLC.

25A and 25B, an exemplary implementation of the system and/or method is disclosed that details the sequence of the different components and processes described herein, as well as additional thermal management components associated with the building. As can be seen throughout the figures and accompanying description, there are multiple locations where heat is transferred from the different components of the disclosed system to the existing building system. For example, as shown, a chiller may be in the building, as well as an existing cooling tower. These active cooling components can be operatively coupled to the heat being removed from the process components via individual cooling loops. According to an exemplary implementation, the heat, sometimes referred to as waste heat, can be transferred to the building systems that can use the excess heat to operate more efficiently. Thus, with respect to waste heat from the disclosed system, the design priority is to transfer the waste heat first to the building steam and hot water make-up system, second to the building cooling tower, and finally to a suitable chiller with heat exchange with air.

As shown in Figures 24 and 25A-25B, a thermal management system (see e.g. MASTER PLC, controller, etc.) conserves fuel, such as natural gas, in a boiler by optimizing combustion with a combustion controller. , the front-end controller controls the water removal from the flue gas, the dryer performs additional separation and PSA with the separation controller, the liquefaction/storage controller liquefies and stores the _CO2 , and the off-take controller picks up and /or an offtake to a delivery truck may be specified. These and additional controllers control boiler feed water, potable and/or industrial water, chiller water, and/or cooling tower water, and nitrogen expansion cooling to reduce and/or eliminate heat loads within the system. be able to function as such. Flue gases can thus be cooled for water knockout, and heat generating electrical components such as compressors, blowers, pumps and fans can also be cooled.

In addition, localized gas analysis instruments can be configured to provide near real-time localized _CO2 and _O2 concentration measurements. By placing the gas sampling equipment/sensor directly at the sampling point within a subsystem, such as a PSA subsystem, it is possible to pump a small stream of sample gas through the sensor cap just a few inches from the process gas being measured. can. This innovation provides near-instantaneous measurements from multiple devices simultaneously at sub-second sampling rates. Each measurement device can be configured to prepare and format data for immediate transmission to the master controller using standard communication protocols. Individual sensor devices can be uniquely addressed by a master controller via common hardwired connections (Ethernet, RS232, RS485, etc.).

As mentioned above, an offtake analysis can be provided that is incorporated into the system to certify the offtake weight of the removed liquid _CO2 and certify the _CO2 product purity within the required commercial specifications to meet the commercial requirements for transporting and selling the liquid _CO2 . This offtake analysis system can be configured to issue a certificate of analysis for the product _CO2 upon transfer from the building or from the intermediate storage and processing facility. Additionally, the offtake analysis system can be configured to document all information to formally account for all offtake processing.

According to an exemplary implementation, a set of electronic load batteries can be placed under each storage tank to accurately measure the weight of the tank and its contents. The system performs a differential calculation to authenticate the weight of the liquid _CO2 removed.

According to another implementation, the analytical system can be configured to measure product impurities within strict specifications. Just prior to product transfer, the analytical system automatically removes a small liquid _CO2 sample from a storage tank, vaporizes it, and then flows the sample gas into a state-of-the-art FTIR spectrum analyzer or into a field-grade gas chromatograph system. The FTIR spectrum analyzer is equipped with sufficient procedures and chemical spectrum libraries to identify and measure all the "impurities" indicated in the customer's contractual purity specifications for the liquid _CO2 . Such specifications typically stipulate the ISBT beverage guidelines along with one or more additional compounds of importance to the customer. At least one advantage of the FTIR analytical system is that it is configured to operate automatically, without manual assistance, while providing several times more measurement fidelity than required by the ISBT guidelines. It is commonly understood that FTIR systems cannot measure chemical compounds that do not exhibit a molecular dipole. This is not the case for the impurities of interest, as they all exhibit a molecular dipole and involve some degree of motion (observable frequency).

Additionally, in a separate embodiment, the FTIR system can also be connected to the "front end" to accurately measure flue gas impurities from the boiler system.

According to an exemplary implementation, the systems and/or methods of the present disclosure may include an energy storage system that may be configured to include power conversion components and/or battery or battery bank components. As an example, energy may be generated via turbine expansion of nitrogen, which may be converted and stored within the building. The energy may be converted and fed directly to a system component, such as a compressor, and/or may be stored and then fed to a system component, thus lowering building energy demands. Additionally, energy may be fed to a power grid associated with the building itself.

According to an exemplary implementation, the MASTER PLC allows energy generated by the system to be utilized during "peak demand" times (e.g., when electricity rates are higher) and/or when the building is utilizing "peak" amounts of power. During these times, the MASTER PLC monitors building demand and then modifies system parameters to efficiently use energy storage and/or change carbon dioxide separation, liquefaction, storage, and/or transportation to lower energy consumption during "peak demand," thus saving energy costs.

Exemplary implementations of the disclosed systems and/or methods can provide not only a carbon capture system, but also improved overall building energy efficiency (both thermal and electric) while reducing _CO2 emissions. Exemplary implementations can include reducing carbon fuel consumption by optimizing boiler firing, providing warmer boiler feedwater and thus reducing the energy required to heat the boiler feedwater, generating and using electrical energy for power system components, using building cooling towers to reduce the building's heat load, and the like, which individually and/or collectively can be part of a system that dramatically improves building efficiency.

In accordance with the statute, embodiments of the invention have been described in somewhat clear language with respect to structural and methodical features. However, it is to be understood that the disclosed embodiments include modes of implementing the invention, and the invention as a whole is not limited to the specific features and/or embodiments illustrated and/or described. The invention is therefore claimed in any of its forms or modifications within the proper scope of the appended claims, properly construed in accordance with the doctrine of equivalents.

Claims (29)

A combustion system comprising a combustion assembly operably engaged with an air intake, the air intake performing air enrichment. The system of claim 1, wherein the combustion assembly is coupled to a separation assembly. The system of claim 2, wherein the separation assembly is coupled to a liquefaction assembly. 4. The system of claim 3, wherein the liquefaction assembly is coupled to a storage assembly. 10. The system of claim 1, wherein the intake comprises a membrane assembly configured to provide a _N2- rich stream and an _O2- rich stream. a flow rate for coupling the _O2 -rich stream to a mixing assembly configured to receive the _O2- rich stream and mix the _O2- rich stream with air to provide enriched air to a burner of the combustion assembly; 6. The system of claim 5, further comprising a controller. The system of claim 6, wherein the combustion assembly is configured as a combustion boiler assembly. 8. The system of claim 7, wherein the combustion boiler assembly is configured to utilize hydrocarbon fuel. 1. A method for enriching air to a combustion assembly, comprising:
forming an _N2- rich stream and an _O2- rich stream from a first air stream;
supplementing a second air stream with the _{O2-rich stream to enrich the second air stream with O2 ;}
and combusting the enriched air stream. 10. The method of claim 9, wherein the step of forming the _N2 -rich stream includes retaining the _N2- rich stream within a membrane separation assembly. 10. The method of claim 9, wherein the step of forming the _O2- rich stream comprises permeating the _O2- rich stream through a membrane separation assembly. 10. The method of claim 9, further comprising producing a flue gas stream from the combusted enriched air stream that is lower in _N2 than a non-enriched air stream. A system for separating _CO2 from a flue gas, the system comprising a vortex tube assembly operably coupled to a component of the system, such as a pressure swing adsorption assembly of a separation assembly. 14. The system of claim 13, further comprising a combustion assembly operably coupled to the pressure swing adsorption assembly. 14. The system of claim 13, further comprising a liquefaction assembly operably coupled to the pressure swing adsorption assembly. The system of claim 15, further comprising a storage assembly operably coupled to the liquefaction assembly. A method for heating or cooling components of a system for separating _CO2 from flue gas, the method comprising:
supplying compressed nitrogen from one or more components of the system to a vortex tube to form a heated nitrogen stream and a cooled nitrogen stream;
supplying the heated nitrogen stream to components benefiting from a heat source;
supplying the cooled nitrogen stream to a component benefiting from a cooling source. 18. The method of claim 17, wherein the compressed nitrogen is provided from a separation assembly. 19. The method of claim 18, wherein the separation assembly is a pressure swing adsorption assembly. The method of claim 17, wherein the cooled nitrogen is supplied to a flue gas dryer. 18. The method of claim 17, wherein the cooled nitrogen is fed to a condensing heat exchanger. A system for separating _CO2 from flue gas, the system comprising a separation assembly comprising a membrane assembly configured to separate _CO2 from _N2 . 23. The system of claim 22, further comprising a combustion assembly operably coupled to the membrane assembly. 24. The system of claim 23, further comprising a liquefaction assembly operably coupled to the membrane assembly. 25. The system of claim 24, further comprising a storage assembly operably coupled to the pressure liquefaction assembly. 23. The system of claim 22, wherein the membrane assembly is configured in membrane component stages. 1. A method for separating _CO2 from a flue gas, the method comprising: feeding a flue gas stream containing _CO2 and _N2 to a first membrane separation system to form a CO2 _- rich stream and a N2 _- rich stream. 30. The method of claim 27, further comprising the step of supplying the _CO2- rich stream to a liquefaction assembly. 30. The method of claim 27, further comprising the step of supplying the _{CO2- rich} stream to a second membrane separation assembly to provide additional CO2-rich and _N2- rich streams.

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