CO2 Separation System and Method

Abstract

A combustion system is provided that may include a combustion assembly operably 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.

Description

[Technical field]

[0001] [CROSS REFERENCE TO RELATED APPLICATIONS] This application is a continuation-in-part of PCT Patent Application No. PCT / US2021 / 057111, filed October 28, 2021, entitled "CO2 Separation Systems and Methods," which claims priority to and the benefit of U.S. Provisional Patent Application No. 63 / 106,729, filed October 28, 2020, entitled "Building Emission Processing and / or Sequestration Systems and Methods," U.S. Provisional Patent Application No. 63 / 106,759, filed October 28, 2020, entitled "Building Emission Processing and / or Sequestration Systems and Methods," and U.S. Provisional Patent Application No. 63 / 106,862, filed October 28, 2020, entitled "Building Emission Processing and / or Sequestration Systems and Methods," each of which is incorporated by reference in its entirety herein.

[0002] 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 by reference in its entirety herein.

[0003] The field of the invention relates to CO2 separation systems and methods. In certain embodiments, the system and / or method can separate CO2 and provide heat and / or power. In certain implementations, heat and power can be provided to buildings. Also, combustion products can be processed to separate CO2 from the combustion products. In addition, CO2 can be separated from air. Furthermore, power in the form of electricity can be generated while separating CO2 from the combustion products and / or air. [Background technology]

[0004] 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 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. Summary of the Invention

[0005] A system for separating CO2 from combustion products is provided. The system can include a combustion product stream, a combustion stream including at least CO2 and N2, and a 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 a CO2 product stream.

[0006] 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.

[0007] A system for separating CO2 from air is also provided. The system can include an air stream having an air stream including 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.

[0008] A system and method are provided for operating a combustion boiler in a building. The system or method can 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 can include combusting the air and fuel in the burner to produce a flue gas having an oxygen concentration, and restricting air from the flue gas by substantially removing tramp air in a conduit operatively aligned to convey the flue gas from the burner.

[0009] A system and method are provided for cooling flue gas from a combustion boiler in a building. The system or method may include supplying the flue gas to at least one economizer having at least one set of cooling coils carrying boiler feed water, the supplying step cooling the flue gas and heating the boiler feed water.

[0010] A system and method are provided for separating carbon dioxide from flue gas generated from a combustion boiler in a building. 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 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, which may or may not include a silencer.

[0011] A system and method are provided for cooling carbon dioxide separated from flue gas produced from a combustion boiler in a building. The system or method can include separating nitrogen from the flue gas using a pressure swing adsorption assembly, expanding the 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 operatively aligned with the carbon dioxide product of the pressure swing adsorption assembly to cool the carbon dioxide product.

[0012] A system and method for liquefying carbon dioxide separated from flue gas produced from a combustion boiler in a building is provided. The system or method can include supplying gaseous carbon dioxide to liquid carbon dioxide in a storage vessel through a sparging assembly.

[0013] A building is provided that utilizes a carbon fuel source and generates carbon emissions upon combustion of the carbon fuel source. The building's emissions can be operatively 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 the carbon emissions and return heat to the building. The system can be configured to process the carbon emissions and generate electricity. The system can be configured to process the carbon emissions and store electrical energy. The system can be configured to dynamically control the combustion and capture system to reduce carbon combustion and increase carbon capture.

[0014] A combustion system is provided that may include a combustion assembly operatively engaged with an air intake, the air intake performing air enrichment.

[0015] A method of enriching air to a combustion assembly is also provided that can 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.

[0016] A system for separating CO2 from a flue gas is also provided. The system can include a vortex tube assembly operably coupled to a component of the system that provides pressurized N2.

[0017] A method for heating or cooling a component of a system for separating CO2 from a flue gas is also provided. The method may include providing 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, providing the heated nitrogen stream to a component benefiting from a heat source, and providing the cooled nitrogen stream to a component benefiting from a cooling source.

[0018] The system for separating CO2 from the flue gas can also include a separation assembly including a membrane assembly configured to separate CO2 from N2.

[0019] The method for separating CO2 from a flue gas may also include feeding the flue gas stream containing CO2 and N2 to a first membrane separation system to form a CO2-rich stream and an N2-rich stream. [Brief description of the drawings]

[0020] Embodiments of the present disclosure are described below with reference to the accompanying drawings.

[0021] [Figure 1] FIG. 1 illustrates a carbon dioxide capture method and / or system according to one embodiment of the present disclosure. [Diagram 2] FIG. 1 illustrates a carbon dioxide capture method and / or system according to another embodiment of the present disclosure. [Figure 3A] FIG. 1 illustrates an exemplary boiler with a free oxygen sensor according to one embodiment of the present disclosure. [Figure 3B] FIG. 1 illustrates an exemplary boiler configuration operably coupled to a plenum, according to one embodiment of the disclosure. [Figure 3C] FIG. 1 illustrates an exemplary boiler with a free oxygen sensor according to one embodiment of the present disclosure. [Figure 4]FIG. 2 is a diagram of a series combustion assembly and separation assembly according to one embodiment of the present disclosure. [Diagram 5] FIG. 1 illustrates a combustion assembly according to one embodiment of the present disclosure. [Figure 6] FIG. 1 is a diagram of an air enrichment assembly according to one embodiment of the present disclosure. [Figure 7] FIG. 2 is a diagram of a combustion inlet flow / assembly according to one embodiment of the present disclosure. [Figure 8A] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to one embodiment of the present disclosure. [Figure 8B] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to another embodiment of the present disclosure. [Figure 8C] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to another embodiment of the present disclosure. [Figure 9A] FIG. 1 illustrates an exemplary arrangement of components of a carbon dioxide capture method and / or system, according to one embodiment of the present disclosure. [Figure 9B] 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. [Figure 10] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to one embodiment of the present disclosure. [Figure 11] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to one embodiment of the present disclosure. [Figure 12A] FIG. 2 is a diagram of a carbon dioxide separation assembly according to an embodiment of the present disclosure. [Figure 12B] FIG. 2 is a diagram of a carbon dioxide separation assembly according to an embodiment of the present disclosure. [Figure 13] FIG. 1 is a diagram of a vortex tube according to one embodiment of the present disclosure. [Figure 14] 14 is an exemplary implementation of the vortex tube assembly of FIG. 13 in combination with a separation assembly (eg, a pressure swing adsorption (PSA) assembly) according to one embodiment of the present disclosure. [Figure 15] FIG. 1 illustrates an exemplary arrangement of components of a carbon dioxide capture method and / or system, according to one embodiment of the present disclosure. [Figure 16A] FIG. 1 illustrates an example of a CO2 separation system according to an embodiment of the present disclosure. [Figure 16B] FIG. 1 illustrates an exemplary CO2 separation system component configured to operate as a carbonate pump according to one embodiment of the present disclosure. [Figure 16C] FIG. 1 illustrates an exemplary CO2 separation system component configured to receive CO2 and N2 from a flue gas source and operate as a carbonate fuel cell according to one embodiment of the present disclosure. [Figure 16D] FIG. 1 illustrates an exemplary CO2 separation system configured to receive CO2 and N2 from an air source and operate as a carbonate fuel cell according to one embodiment of the present disclosure. [Figure 17] FIG. 1 illustrates a generalized separation component according to one embodiment of the present disclosure. [Figure 18] FIG. 1 illustrates a membrane separation component according to one embodiment of the present disclosure. [Figure 19] 1A-1D illustrate configurations of membrane separation assemblies and methods according to embodiments of the present disclosure. [Figure 20] 1A-1D illustrate configurations of membrane separation assemblies and methods according to embodiments of the present disclosure. [Figure 21] 1A-1D illustrate configurations of membrane separation assemblies and methods according to embodiments of the present disclosure. [Figure 22] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to one embodiment of the present disclosure. [Diagram 23] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to another embodiment of the present disclosure. [Figure 24] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to one embodiment of the present disclosure. [Figure 25A] FIG. 1 illustrates a portion of a carbon dioxide capture method and / or system according to one embodiment of the present disclosure. [Figure 25B] FIG. 25B illustrates another portion of the carbon dioxide capture method and / or system of FIG. 25A according to one embodiment of the present disclosure. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0022] The present disclosure will be described with reference to Figures 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 routine maintenance. Referring initially to Figure 1, a system 10 is provided that includes a source of flue gas, such as a boiler that combusts air and fuel to generate flue gas. The flue gas 12 can include typical combustion products from a building's heating and / or cooling system. These buildings can be considered commercial, residential, and / or industrial buildings. The system 10 can rely on the combustion of fossil fuels. These fossil fuels can include oil and / or natural gas. Upon combustion of the fuel, CO2 can be generated as part of the flue gas. In the case of natural gas combustion, the system 10 can generate at least about 10% CO2 and about 18% water. The systems and / or methods of the present disclosure can include a section 14 for separation, a section 16 for liquefaction, a section 18 for storage, and a section 19 for transport of the CO2.

[0023] According to an exemplary implementation, at least about 600 standard cubic feet per minute of building flue gas can be diverted to a flue gas process stream, where the CO2 is separated and purified in component 14 of system 10. This separation / purification component can be an adsorption purification system operating under conditions of pressure swing (PSA), vacuum pressure swing adsorption (VPSA); temperature swing (TSA), or electric swing (ESA), or any combination thereof. According to an exemplary implementation, this can be a pressure swing adsorption system, which is a multi-component adsorption system including multiple vessels containing layered solid-phase adsorbents configured to combine and / or act together to provide greater than 85% CO2 capture. These multi-component adsorption systems can remove carbon dioxide from an essentially "dry" flue gas stream to a purity of greater than 95% in most cases, and at least 99% in other cases. This purified carbon dioxide gas is then liquefied in successive cooling and compression steps to effect a phase change to form liquid carbon dioxide in liquefaction component 16, and then this liquefied carbon dioxide can be supplied to storage component 18 for scheduled removal as desired. According to an exemplary implementation, this liquefied carbon dioxide can be transported remotely in transport component 19 and the transport can be provided to another source, such as a storage facility from which the carbon dioxide can be distributed for use in applications such as concrete curing, wastewater treatment, other carbon dioxide sequestration methods, reclamation in fire suppression systems, consumption in the production of industrial specialty gases, hybrid fuels and organic intermediate chemicals, or beverage carbonation, to name a few.

[0024] 2, a building system 30 is shown having a system 32 therein. Flue gas 12 is fed to a series of portions 14, 16, 18, 19 of a system and / or method and / or a cooling tower 31 for the capture of CO2 from the flue gas produced by the building.

[0025] 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 the plenum 48.

[0026] 3C, a boiler configured with the systems and / or methods of the present disclosure is shown. Thus, air 60 and fuel 62 may be supplied to a combustion burner, the mixing, and therefore the 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 to hot water or steam 50 that is used to heat a building and / or building systems, such as a water heater 58. The water heater system 58 may be configured to receive heated potable water and / or heated industrial process water.

[0027] According to an exemplary implementation, the control 66 can utilize a sensor 43 to monitor the amount of free oxygen in the combustion burner and maintain the amount of free oxygen at approximately 3%. Approximately 3% free oxygen can include 3 to 7% free oxygen. According to an exemplary implementation, the combustion can produce a flue gas 44. The combustion of the (wet) flue gas 44 can be controlled to include at least approximately 8% carbon dioxide. Approximately 10% carbon dioxide can include 9 to 11% carbon dioxide of flue gas (dry basis) from the combustion of natural gas. The system 10 can be utilized to burn fuels other than natural gas that may specify other optimal CO2 flue gas concentrations. Thus, the system 10 can be configured to utilize multiple fuels.

[0028] The systems and / or methods of the 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.

[0029] With reference to both FIG. 3B and FIG. 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 operatively 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 operatively 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.

[0030] According to at least one embodiment 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 achieve at least about 10% carbon dioxide concentration (dry basis) in the flue gas through combustion control, approaching a 12% concentration value of CO2 when burning natural 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.

[0031] Within 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: 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 across 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 amount of 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.

[0032] Thus, the boiler and system controls (eg, 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.

[0033] 4, there is shown an assembly 100 including a combustion assembly 11 that may or may not be in fluid communication with a separation assembly 14. FIG 1 may be viewed 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.

[0034] According to an exemplary implementation, the combustion assembly 11 may utilize an air enrichment assembly 130 to perform air enrichment prior to receiving air for combustion. Air 60 may be supplied and enriched prior to use by the combustion assembly 11. The combustion assembly 11 may generate an exhaust gas mixture 170 that may include carbon dioxide. The mixture 170 may be supplied to the separation assembly 14, for example after additional processing. During exemplary processing, the mixture 170 may be dried sufficiently to separate the carbon dioxide within the separation assembly 14. The separation assembly 14 may supply a separated gas mixture 200 that includes a substantially higher concentration of carbon dioxide than is supplied to the separation assembly.

[0035] 5, an exemplary combustion system is shown that includes a burner configured to receive enriched air 210 and supply air 60 through an enrichment assembly 130. According to an exemplary implementation, the burner and / or the air and / or fuel being supplied to the burner may be controlled by a combustion controller (not shown) to heat water that is part of a steam loop. The combustion assembly may generate exhaust 44, such as flue gas.

[0036] 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 bundle hollow fiber membrane. Exemplary membrane assemblies can include SEPURAN® (Evonik Industries AG, Rellinghauser Strase 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.

[0037] As can be seen, air 60 can enter membrane assembly 170 and can contain 21% or more oxygen and 78.5% nitrogen. Exiting as retentate mixture 160 can be a stream that is substantially nitrogen ranging from about 90% to 95% while proceeding to another stream as permeate mixture 140 can be a stream that is approximately 36% to 43% oxygen with less nitrogen (58-64%). According to an exemplary implementation, permeate mixture 140 can be fed to enrich air stream 60 in mixing system 180, which can be configured as a valve system and / or plenum system to form enriched air mixture 210. Enriched air mixture 210 has a higher oxygen concentration than standard air and can continue to a burner for combustion.

[0038] With reference to FIG. 7, further details are provided for an additional embodiment of enrichment of air for combustion. Thus, air 60 can be compressed and fed to a membrane assembly 170, which feeds an N2-rich stream 160 and an O2-rich stream 140. Using a flow controller, the O2-rich stream 140 can be mixed with the air 60 in a mixing system 180 to feed enriched air 210 to a boiler burner, for example, via a boiler blower. According to an exemplary implementation, the N2-rich stream 160 can be operatively coupled to a turbo expander and / or vortex tubes to generate electrical power and / or hot and cold N2 as needed. This is just one example of a turbo expander and / or vortex tubes coupled to a high pressure N2 source.

[0039] According to an exemplary implementation, supplying 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.

[0040] 8A-8C, there are shown portions of a system and method for separating water from flue gas and cooling the flue gas. Referring first to FIG. 8A-8C, there are shown three different configurations of a system and / or method for cooling flue gas from a combustion boiler in a building. Referring first to FIG. 8A, the flue gas 44 can proceed to a combined non-condensing and condensing economizer 60a. The 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 coil, the flue gas is cooled, and the boiler feed water is heated. Thus, a method is provided for cooling flue gas from a combustion boiler in a building. Once the boiler feed water is heated, it can be fed to the boiler, thus reducing the required energy required to heat the feed water to hot water and / or steam.

[0041] In addition, the economizer can be configured for condensation. Thus, the conduits, conduit sets, and coils 54 can be configured to convey potable water or industrial process water received, for example, from a public utility. This water can have a temperature close to that of groundwater, as it is typically conveyed through underground pipes. Thus, the water has a substantially different temperature than the flue gas, even after it has been partially cooled in the non-condensing economizer. Supplying flue gas to these conduits can remove water from the flue gas, thus creating a water condensate effluent 53. This water traveling through the conduits can be heated and supplied to the hot water system 58 (FIG. 3C) as hot water system intake 54, and heated and received through outlet 56. Thus, less energy is required to heat the water in the hot water system 58, at least because the water received for heating does not need to be heated from the low temperatures associated with typical tap water, but rather is preheated. According to an alternative configuration, referring to FIG. 8B, one set of coils 52 can be associated with one economizer 60b, and another set of coils 54 can be associated with another economizer 65a. In this configuration, the economizer 60b can be a non-condensing economizer, and the economizer 65a can be configured as a condensing economizer. According to another embodiment of the disclosure, as shown in FIGS. 8A-8C, a diverter 64 can be operatively coupled to the economizer. According to an exemplary implementation, cooled flue gas can be provided from the diverter 64 using a blower. The system and / or method can control the amount of flue gas treated using the diverter. According to an exemplary implementation, the current system according to FIG. 8C will receive 450 standard cubic feet per minute (SCFM) to 500 SCFM of wet flue gas 44. The diverter can be controlled by an overall master system (FIG. 24) that can control a motor-operated butterfly valve in the diverter. The master system can also collect gas temperature and flow data and operate the blower as shown in FIG.

[0042] 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, where the method may include additional separation, as well as liquefaction, storage, and transport.

[0043] 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 separation of the CO2, 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.

[0044] Flue gas condensate tends to be slightly acidic (pH<=5), a condition that can damage some building plenums due to construction materials that are not acid resistant (such as carbon steel). In these cases, the gas must be removed from the plenum and condensed in an external heat exchanger with acid resistant stainless steel components. In addition, depending on the condenser design, some amount of micro-droplets may remain in the gas stream. These micro-droplets can be referred to as acid aerosols that can be present at ppm levels. The present disclosure contemplates the removal of acid aerosols. These systems and / or methods include, for example, wet wall heat exchangers, impingers or mist eliminators with inert reticulated carbon or metal foams, and precipitators.

[0045] In accordance with the above, a non-condensing economizer can operate above the dew point temperature and prevents the formation of any liquid condensate. Because there is no condensation, this economizer can accommodate most plenum building materials.

[0046] As mentioned above, the condensing economizer may be provided downstream of a diverter (FIG. 8C) that extracts the flue gas from the plenum and directs it to the condensing economizer. The condensate from this condensing economizer may be chemically neutralized before proceeding to the building drain, as shown by 75 in FIG. 10.

[0047] 10, to increase the pressure of the flue gas from the diverter, flue gas drying may continue with a blower 68. This blower 68 may support flow through a heat exchanger / condenser 70, which may include a water outlet 71 operably coupled to an acid neutralizer assembly 75. The heat exchanger 70 may 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.

[0048] The heat exchanger 70 can be a tube and shell configuration, cooled, for example, by an external water / glycol loop supplied by a chiller and / or water from a building cooling tower. As shown, it is anticipated that the water removed from the system in the heat exchanger 70 may be slightly acidic and may be neutralized before proceeding to a public wastewater treatment plant (POTW) or through the sewer system. In addition, some water remains in the process stream as small micro-droplets, mist, or acid aerosols that are minimized or removed with special heat exchanger designs, mist eliminators, impingement devices, or possibly precipitators. These components may generate additional condensate or effluent that can be treated before proceeding to the POTW.

[0049] After most of the water has been removed and acid aerosols mitigated, the cooled flue gas 72 may continue to a compressor to increase the pressure of the flue gas to an optimum level, approximately 100 psig or less, as defined by the PSA system specifications. The compressor may generate additional condensate or effluent because compression increases the process gas dew point.

[0050] 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, and the gas may be at a temperature of less than 40°C and at a pressure of about 100 psig.

[0051] 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.

[0052] According to another exemplary implementation, a mist eliminator subsystem 89 can be provided that can produce an effluent 53. During water removal from the flue gas, liquid condensate can be produced 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.

[0053] Very small amounts of this slightly acidic condensate remain entrained in the process gas as mist or acid aerosols. To remove these liquid micro-droplets, 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.

[0054] 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, 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.

[0055] In this process, the PSA 80 can provide a pressurized substantially nitrogen stream, which can be provided to one or more assemblies, such as, as shown, to the turbine expander 48 via stream 42 and to the control valve 50 via stream 44. According to an exemplary implementation, a nitrogen stream 86 can be provided from these assemblies.

[0056] According to an exemplary implementation, yet another stream 46 can be provided to a vortex tube assembly 52 that receives pressurized nitrogen and provides cold nitrogen 54 and hot nitrogen 56. The present disclosure can be configured to utilize the heat of streams 54 and / or 56 in combination with the operational functions of the system and / or particularly the PSA assembly. This is one example of coupling a vortex tube to utilize the pressurized N2 produced by the system and / or method of the present disclosure. As described herein, the vortex tube and / or turbo expander can be coupled to other components in the system that generate pressurized N2, for example, the membrane retentate stream.

[0057] 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 in 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.

[0058] An exemplary vortex tube assembly 300 is shown in FIG. 13 including an input 302 configured to receive compressed nitrogen and provide cold nitrogen at outlet 304 and hot nitrogen at outlet 306 .

[0059] 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.

[0060] 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 transportation. 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 that is supplied from a local chiller or directly from a central chiller. The local chiller can be water cooled with a water loop that comes 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.

[0061] 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 dries 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 dries 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. This 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.

[0062] From the dryer, flue gas 79 containing less than 10 ppm water can proceed to a pressure swing adsorption (PSA) assembly 80. This pressure swing adsorption assembly can provide greater than 85% CO2 capture at greater than 95% purity at 1 psig from ambient up to about 100°C. The maximum CO2 output flow at this point can be approximately 40 SCFM. The remainder of the flue gas, mostly nitrogen, can continue under pressure and / or be split so that a portion returns to the dryer 78. Another portion of the nitrogen, at near atmospheric pressure, can proceed to a turbine expander 82 / generator 93, which can provide electrical energy 94 and a low temperature output gas. Additionally, a control valve 84 with a silencer can be operatively aligned in parallel with the expander 82 / generator 93.

[0063] Thus, a method is provided for separating carbon dioxide from flue gas generated from a combustion boiler in a building, which may include removing at least a portion of the nitrogen from the flue gas to produce greater than about 95% carbon dioxide 78 using a pressure swing adsorption assembly 80. The nitrogen removed from the flue gas may be used to remove water from the flue gas, for example, in a dryer 78, prior to providing the flue gas to the pressure swing adsorption assembly. Alternatively, or in addition, at least a portion of the nitrogen removed from the flue gas may be provided to a gas expander / generator. Alternatively, or in addition, a portion of the nitrogen from the PSA may be provided to a control valve with a silencer and another portion may be provided to the expander / generator. According to an exemplary implementation, the disclosed system and / or method may include separating the nitrogen into several portions and providing one portion to the dryer and another portion to the expander / generator. In one exemplary implementation, the one portion is about one-third of the nitrogen from the pressure swing adsorption assembly.

[0064] According to an exemplary implementation, a small amount of rejected gas may be generated during the PSA process, including both CO2 and nitrogen. Rather than purging this gas, it may be recycled through the compressor via recycle line 81 to enhance the overall recovery of CO2.

[0065] 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 the nitrogen exhaust of the PSA. The system and / or method can 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 can be part of a generator 93, for example, or can be provided to cool the exchanger 92.

[0066] Typically, the nitrogen gas exiting the PSA may be at least 85 psig, with a flow rate in excess of 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 multi-phase 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.

[0067] 16A-16D, different embodiments of CO2 separation systems and / or methods are shown that may be used alone or in combination with some or all of the components of the system and / or method of FIG.

[0068] For example, referring to FIG. 16A, an electrochemical cell is shown that includes a cathode configured to receive the reactions CO2 and O2. The CO2 and O2 can be received from the same or different streams. For example, the 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, the streams may be considered wet or dry, with a wet stream including H2O from the combustion process that generated the flue gas. The O2 may be received as part of the flue gas stream, the air stream, and / or as part of the O2 stream.

[0069] Leaving the cathode side of the cell can be a N2 stream. This N2 stream is mixed with carbonate ions (CO3 2- For example, it may contain CO2, H2O, and / or O2. This N2 stream contains less CO2 than the stream exposed to the cathode.

[0070] 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 CO3 2- to CO2 and O2 as CO2 products. As described in more detail below, this system can be implemented in a variety of ways, for example, as a carbonate ion pump (FIG. 16B), as a flue gas carbonate fuel cell (FIG. 16C), and / or as a fuel cell (FIG. 16D). In one or more of these implementations, CO2 can be removed / separated / sequestered from one or more streams.

[0071] 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 supplied from an O2 source, for example, from air. The flue gas can contain N2 that does not react at the cathode and proceeds to the gas stack along with other unreacted components (e.g., H2O, O2, CO2).

[0072] The electrochemical formula is CO2+1 / 2O2+2e - >>,CO3 -- Multiple cells can be configured in a stack, which feeds CO2 and O2 through their respective manifolds.

[0073] Once carbonate ions are produced at the cathode, a solid or liquid electrolyte can be in ionic communication with the cathode and provide a pathway for the carbonate ions to migrate to the associated anode. This electrochemical activity is the basis for the formation and transport of carbonate ions and the separation of CO2 from the original cathode gas mixture.

[0074] Upon reaching the anode, an electron can be removed from the carbonate ion(s), causing dissociation back into CO2 and 1 / 2O2.

[0075] 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 separation can utilize solvent absorption and / or polymer-based membranes with suitable 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 sieve, solution diffusion separation, surface diffusion, and / or capillary condensation.

[0076] 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.

[0077] 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). The 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.

[0078] Natural gas can be supplied as part of the fuel cell, and this natural gas can be tapped into an existing building through an intake. Thus, using natural gas, which can be directly reformed into syngas at operating temperatures, heat and power can be generated electrochemically, which can be supplied to the building, thereby offsetting some or all of the building's heat and power demand without natural gas combustion, thus significantly reducing CO2 emissions.

[0079] 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.

[0080] Thus, the fuel cell can receive flue gas at the cathode, and CO2 is electrochemically purified and made available for separation and liquefaction. As shown, the flue gas can be fed through a tortuous path to maximize the exposure of CO2 to the cathode electrode surface area. This flue gas can be fed directly from a combustion boiler or can be treated as described with reference to Figures 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 can provide improved performance at higher CO2 concentrations, thus allowing less pre-treatment of the flue gas prior to CO2 separation.

[0081] 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.

[0082] Thus, natural gas that reforms directly to syngas at operating temperatures can be used to electrochemically generate heat and power that can be supplied to a building, thereby offsetting some or all of the building's heat and power needs without natural gas combustion.

[0083] Thus, synthesis gas 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 resulting gas can be purified CO2. This concept further teaches the removal of water vapor through condensation followed by liquefaction of the CO2.

[0084] Thus, there is provided a system for separating CO2 from a combustion product, 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 a CO2 product stream.

[0085] The carbonate electrochemical cell can include a cathode configured to receive electrons from a power source and react those electrons with CO2 and O2 of the combustion product stream to form carbonate ions. 2- The carbonate ions may be, for example, a component of a carbonate electrolyte. The battery may also include an anode configured to react the carbonate ions to form CO2, O2, and electrons. Thus, the system may include a cathode and an anode around the carbonate electrolyte.

[0086] 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.

[0087] The system can include a catalytic burner operably coupled to the CO2 product stream, and a heat exchanger operably coupled to the catalytic burner and configured to remove H2O from the CO2 product stream. The heat exchanger can be operably coupled to a heat recovery loop with an additional conduit configured to supply CO2 to the cathode.

[0088] 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.

[0089] Additionally, synthesis gas can be provided to react with the carbonate ions to form a CO2 product stream, and natural gas can be provided to form synthesis gas. Embodiments of the method can generate a net positive potential upon forming the CO2 product stream.

[0090] 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.

[0091] In some implementations, a portion of the CO2 can be returned to the cathode if desired, and the remaining CO2 is sent for liquefaction, as described with reference to Figures 22-25B.

[0092] 17, a portion of system 10 is shown including separation assembly 14. Entering separation assembly 14 may be a fluid mixture 12, typically in the gas phase. Mixture 12 may include flue gas, which may be treated to remove water. The mixture may typically include amounts of carbon dioxide in the range 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, which may have a higher concentration of carbon dioxide than the carbon dioxide concentration of mixture 12.

[0093] 18, according to an exemplary implementation, a membrane separation assembly 1000 is shown that can receive the mixture 12 and provide at least two separated streams, a retentate stream 1018 and a permeate stream 1020. The separation assembly 540 can be configured as a bundle hollow fiber membrane. Exemplary membrane assemblies can include SEPURAN® (Evonik Industries AG, Rellinghauser Strase 1-11 45128 Essen Germany) and / or custom assemblies (UniSieve Ltd, Regina-Kagi-Strasse 11, CH-8050 Zurich, Switzerland).

[0094] Thus, stream 1018 may be enriched in nitrogen than mixture 12, and stream 1020 may be substantially enriched in carbon dioxide than mixture 12. According to an exemplary implementation, membrane separation assembly 540 may have multiple components and configurations including flow rate, temperature, pressure, membrane, and / or stage configurations. The stages may include stages in series, stages back to back, and / or stages that cause separation to occur at a particular flow rate, pressure, and / or temperature. According to an exemplary implementation, the configuration may include a back pressure regulator or control valve 1022 to maintain a back pressure of membrane separation assembly 540.

[0095] 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 an exemplary implementation, assembly 540A can be fed with mixture 12. 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 feed retentate mixture 1018A, which can proceed to optional assembly 540B, while also feeding permeate mixture 1020A. Alternatively, mixture 1018A can be fed to other points in the separation and purification system. Permeate mixture 1020A can have a percentage of carbon dioxide of about 60% to about 70%. According to an exemplary implementation, the stages can be operated in different configurations to provide, for example, a carbon dioxide yield of more than 90%, as well as a purity of carbon dioxide exiting the system that can be as high as 70%. If included, assembly 540B can provide a retentate mixture 1018B and a permeate mixture 1020B.

[0096] 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.

[0097] 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. According to 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 more than 70%.

[0098] 21, another configuration includes assemblies 540A and 540B, where assembly 540B receives permeate mixture 1020A. The assemblies can have the mixture provided under pressure by compressors 400 and 420, as shown.

[0099] According to an exemplary implementation, and with reference to the above figures, 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 by reference herein in its entirety.

[0100] Referring now to FIG. 22, in another series of components of the present disclosure, the >95% purity CO2 78 can be cooled and compressed in sequential steps as shown in heat exchanger 104, compressors 106 and 108, and heat exchanger 110, with the compressor operatively engaged with the cooling transfer fluid 90 to approach a phase change state for liquefaction. According to an exemplary implementation, the >95% purity CO2 can have a temperature as high as 100° C. exiting the PSA. As previously mentioned, a heat exchanger can 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 can be passed through an external water / glycol cooling loop back to the thermal management system that supports preheating of the feed water as shown in FIG. 22. This can 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 the nitrogen stream before exceeding the COLD temperature output limit. 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 a liquid.

[0101] 23, a CO2 liquefaction and storage system and / or method is shown in which CO2 gas 112 is sparged inside a vessel 113, such as an insulated vessel. An exemplary insulated vessel may include, but is not limited to, a vacuum jacketed liquid storage tank. Within the vessel, the gas 112 may be converted to a liquid 114. According to an exemplary implementation, the gas 112 may be provided to a sparging assembly 118, where it is provided as a sparging gas 120 that liquefies to the liquid 114 upon sparging.

[0102] The vapor 116 at the top of the vessel 113 is managed by a low temperature system 122 that cools the vapor 116, causing it to condense back into liquid 114 and return to the vessel 113. According to an exemplary configuration, the system 122 can be configured as a loop in fluid communication with the vessel 113, where the vapor CO2 116 enters the system 122 and returns to the vessel 113 as liquid CO2 114. In at least one configuration, the system 122 is configured as a low temperature condenser with an evaporator.

[0103] 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 the ISBT, International Beverage Guidelines. Both the controlled venting subsystem and the purity analysis system can take into account non-condensable gases that can dissolve in the body.

[0104] 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 and dissolve 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 the non-condensable gases and reduce pressure buildup 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.

[0105] In the event of a building power loss, for example, the excellent insulation of the vacuum jacketed tank can maintain liquid CO2 for at least 30 days. According to an exemplary implementation, the building itself can tap in a supply of CO2 to the vessel 113 to put out fires, for example fires involving electronic components that require CO2 fire suppression methods.

[0106] 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 pick-up times based on a number of parameters, such as the capacity of the container 113, the CO2 generation of the system 10, the statutory date / time pick-up window, and / or the CO2 delivery demand. It is believed that in this way high purity CO2 can be delivered directly to the user without being warehoused or requiring additional purification with respect to the CO2 delivery demand. 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 certify the product with the ability to issue a test report prior to transportation.

[0107] 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, chilling / storage, and food grade CO2 delivery. These systems are also coupled to electric, natural gas, and water utility systems. These control systems are good examples of basic network architecture diagrams. The MASTER PLC controls the entire plant with Ethernet loop connections and Internet IP protocol communication to local package controllers, as well as 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.

[0108] With reference to FIG. 25A and FIG. 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, chillers, as well as existing cooling towers, may be in the building. 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 regard 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.

[0109] As shown in FIG. 24 and FIG. 25A-B, the thermal management system (see, e.g., MASTER PLC, controller, etc.) can conserve fuel such as natural gas in the boiler by optimizing combustion with a combustion controller, control water removal from the flue gas with a front-end controller, perform additional separation with a dryer and PSA with a separation controller, liquefy and store CO2 with a liquefaction / storage controller, and specify offtake to pickup and / or delivery trucks with an offtake controller. These and additional controllers can function to control boiler feed water, potable and / or industrial water, chiller water, and / or cooling tower water, as well as nitrogen expansion cooling to reduce and / or eliminate heat load in the system. Thus, flue gas can be cooled for water knockout, and heat-generating electrical components such as compressors, blowers, pumps, and fans can also be cooled.

[0110] In addition, localized gas analysis instruments can be configured to provide localized CO2 and O2 concentration measurements in near real-time. By placing gas sampling instruments / sensors directly at the sampling point within a subsystem, such as a PSA subsystem, a small stream of sample gas can be pumped through a sensor cap just a few inches away from the process gas being measured. This innovation provides near instantaneous measurements at sub-second sampling rates from multiple devices simultaneously. Each measurement device can be configured to prepare and format data for immediate transmission to a master controller using standard communication protocols. Individual sensor devices can be uniquely addressed by the master controller via common hardwire connections (Ethernet, RS232, RS485, etc.).

[0111] 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.

[0112] 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.

[0113] 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 of 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 all of the impurities of interest exhibit a molecular dipole and involve some degree of motion (observable frequency).

[0114] Additionally, in a separate embodiment, the FTIR system can also be connected to the "front end" to accurately measure impurities in the flue gas from the boiler system.

[0115] According to an exemplary implementation, the disclosed systems and / or methods can include an energy storage system that can be configured to include power conversion components and / or battery or battery bank components. As an example, energy can be generated via turbine expansion of nitrogen, which can be converted and stored within the building. The energy can be converted and fed directly to a system component, such as a compressor, and / or stored and then fed to a system component, thus lowering the building energy demand. Additionally, the energy can be fed to a power grid associated with the building itself.

[0116] 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 the 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.

[0117] 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.

[0118] In accordance with the statute, embodiments of the invention have been described in language that is somewhat explicit with respect to structural and methodological features. However, since the disclosed embodiments include forms of practicing the invention, it is to be understood that the entire invention is not limited to the specific features and / or embodiments shown and / or described. The invention is therefore claimed in any of its forms or modifications within the proper scope of the appended claims appropriately interpreted in accordance with the doctrine of equivalents.

Claims

1. A combustion system comprising a combustion assembly operatively engaged with an air intake, the air intake providing air enrichment.

2. The system of claim 1 , wherein the combustion assembly is coupled to a separation assembly.

3. 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.

5. The intake port is N ２ Rich Stream and O ２ The system of claim 1 comprising a membrane assembly configured to provide a rich stream.

6. The above O ２ a rich stream for supplying enriched air to a burner of the combustion assembly; ２ A mixing assembly configured to mix the rich stream with air is provided with the O ２ The system of claim 5 further comprising a flow controller combining the rich stream.

7. 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 a hydrocarbon fuel.

9. 1. A method for enriching air to a combustion assembly, comprising: The first air stream to N ２ Rich Stream and O ２ forming a rich stream; The second air stream is O ２ The second air stream is passed through the O ２ Steps to supplement with Rich Stream, and combusting the enriched air stream.

10. The N ２ The step of forming a rich stream comprises: ２ The method of claim 9 comprising retaining the rich stream in a membrane separation assembly.

11. The above O ２ The step of forming a rich stream comprises: ２ 10. The method of claim 9, comprising permeating the rich stream through a membrane separation assembly.

12. than the unenriched air stream. ２ The method of claim 9 , further comprising the step of producing a flue gas stream from the combusted enriched air stream having a low.

13. CO from flue gas ２ 1. A system for separating a component of a gas, the system comprising: a vortex tube assembly operably coupled to a component of the system, for example 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.

15. The system of claim 13 further comprising a liquefaction assembly operably coupled to the pressure swing adsorption assembly.

16. The system of claim 15 , further comprising a storage assembly operably coupled to the liquefaction assembly.

17. CO from flue gas ２ 1. A method for heating or cooling a component of a system for separating providing 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; providing said heated nitrogen stream to a component that benefits from a heat source; and providing said cooled nitrogen stream to a component that benefits from a cooling source.

18. 20. 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.

20. 18. The method of claim 17, wherein the cooled nitrogen is supplied to a flue gas dryer.

21. 18. The method of claim 17, wherein the cooled nitrogen is fed to a condensing heat exchanger.

22. CO from flue gas ２ A system for separating N ２ From CO ２ A system comprising a separation assembly comprising a membrane assembly configured to separate.

23. The system of claim 22 , further comprising a combustion assembly operably coupled to the membrane assembly.

24. 24. The system of claim 23, further comprising a liquefaction assembly operably coupled to the membrane assembly.

25. 25. The system of claim 24, further comprising a storage assembly operably coupled to the pressure liquefaction assembly.

26. 23. The system of claim 22, wherein the membrane assembly is made up of stages of membrane components.

27. CO from flue gas ２ A method for separating CO ２ Rich Stream and N ２ To form a rich stream, ２ and N ２ feeding a flue gas stream comprising:

28. The CO ２ 30. The method of claim 27, further comprising the step of supplying the rich stream to a liquefaction assembly.

29. Additional CO ２ Rich Stream and N ２ To provide a rich stream, ２ 30. The method of claim 27, further comprising the step of feeding the rich stream to a second membrane separation assembly.

30. A system for separating CO2 from combustion products, comprising: a combustion product stream comprising at least CO2 and N2; a carbonate electrochemical cell operatively aligned with the combustion stream and configured to react the CO2 and O2 from the combustion product stream to form carbonate ions and to react the carbonate ions to form a CO2 product stream; A system comprising:

31. The system of claim 30, wherein the carbonate electrochemical cell comprises a cathode configured to receive electrons and react those electrons with the CO2 and O2 in the combustion product stream to form the carbonate ions.

32. The system of claim 31, wherein the carbonate electrochemical cell comprises an anode configured to react the carbonate ions to form CO 2 , O 2 and electrons.

33. The system of claim 30, further comprising a power source operably coupled to the carbonate electrochemical cell.

34. The system of claim 30, further comprising a liquefaction system operably coupled to the carbonate electrochemical cell and configured to receive the CO2 product stream.

35. The system of claim 30, wherein the carbonate electrochemical cell comprises a cathode and an anode surrounding a carbonate electrolyte.

36. The system of claim 35, further comprising an O 2 source operably coupled to the cathode of the carbonate electrochemical cell, the cathode configured to react CO 2 from the combustion stream and O 2 from the O 2 source to form the carbonate ions.

37. The system of claim 30, further comprising a syngas source operably coupled to the anode of the carbonate electrochemical cell to provide a carbonate fuel cell, the anode configured to receive the carbonate ions and the syngas and form the CO2 product stream.

38. The system of claim 37, further comprising a catalytic burner operably coupled to the CO2 product stream and configured to remove hydrocarbons from the CO2 product stream.

39. The system of claim 38, further comprising a heat exchanger operably coupled to the catalytic burner and configured to remove H2O from the CO2 product stream.

40. The system described in claim 39, wherein the heat exchanger is operably coupled to a heat recovery loop.

41. A method for separating CO2 from a combustion product stream, comprising: receiving a combustion product stream comprising CO2 and N2; reacting the combustion product stream to form carbonate ions; reacting the carbonate ions to form a CO2 product stream; A method comprising:

42. The method of claim 41, wherein the combustion product stream is a wet gas.

43. The method of claim 41, further comprising providing an electron to form the carbonate ion.

44. The method of claim 41, further comprising removing electrons to form the CO2 product stream.

45. The method of claim 41, further comprising liquefying at least a portion of the CO2 from the CO2 product stream.

46. ​​The method of claim 41, further comprising providing a synthesis gas to react with the carbonate ions to form the CO2 product stream.

47. The method of claim 46, further comprising providing natural gas to form the synthetic gas.

48. The method of claim 46, further comprising the step of generating a net positive potential upon forming the CO2 product stream.

49. The method of claim 46, wherein the CO2 product stream comprises water.

50. The method of claim 49, further comprising cooling the CO2 product stream to remove water.

51. A system for separating CO2 from air, comprising: an air stream comprising at least CO2 and N2; a carbonate fuel cell operatively aligned with the air stream for reacting the CO2 and O2 from the air stream to form carbonate ions and reacting the carbonate ions to form a CO2 product stream; A system comprising:

52. The system of claim 51, wherein the carbonate fuel cell comprises a cathode and an anode surrounding a carbonate electrolyte.

53. The system of claim 52, further comprising an air source operably coupled to the cathode of the carbonate fuel cell, the cathode configured to react CO 2 from the air stream and O 2 from an O 2 source.

54. The system of claim 52, further comprising a syngas source operably coupled to the anode of the carbonate fuel cell, the anode configured to receive the carbonate ions and syngas and form the CO2 product stream.

55. The system of claim 52, further comprising a catalytic burner operably coupled to the CO2 product stream and configured to remove hydrocarbons from the CO2 product stream.

56. The system of claim 55, further comprising a heat exchanger operably coupled to the catalytic burner and configured to remove H2O from the CO2 product stream.

57. The system described in claim 56, wherein the heat exchanger is operably coupled to a heat recovery loop.

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