EP4314535A1 - Systèmes et procédés de séparation de co2 - Google Patents

Systèmes et procédés de séparation de co2

Info

Publication number
EP4314535A1
EP4314535A1 EP22782222.8A EP22782222A EP4314535A1 EP 4314535 A1 EP4314535 A1 EP 4314535A1 EP 22782222 A EP22782222 A EP 22782222A EP 4314535 A1 EP4314535 A1 EP 4314535A1
Authority
EP
European Patent Office
Prior art keywords
assembly
stream
flue gas
combustion
air
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Pending
Application number
EP22782222.8A
Other languages
German (de)
English (en)
Inventor
William A. Fuglevand
Shane Johnson
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Carbonquest Inc
Carbonquest Inc
Original Assignee
Carbonquest Inc
Carbonquest Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Carbonquest Inc, Carbonquest Inc filed Critical Carbonquest Inc
Publication of EP4314535A1 publication Critical patent/EP4314535A1/fr
Pending legal-status Critical Current

Links

Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
    • F23L7/00—Supplying non-combustible liquids or gases, other than air, to the fire, e.g. oxygen, steam
    • F23L7/007—Supplying oxygen or oxygen-enriched air
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/02—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography
    • B01D53/04—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography with stationary adsorbents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/26—Drying gases or vapours
    • B01D53/265—Drying gases or vapours by refrigeration (condensation)
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J15/00—Arrangements of devices for treating smoke or fumes
    • F23J15/006—Layout of treatment plant
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/50—Carbon oxides
    • B01D2257/504—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2258/00—Sources of waste gases
    • B01D2258/02—Other waste gases
    • B01D2258/0283—Flue gases
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J2900/00—Special arrangements for conducting or purifying combustion fumes; Treatment of fumes or ashes
    • F23J2900/15061—Deep cooling or freezing of flue gas rich of CO2 to deliver CO2-free emissions, or to deliver liquid CO2
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
    • F23L2900/00—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber
    • F23L2900/07007—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber using specific ranges of oxygen percentage
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

  • the field of the invention relates to CO2 separation systems and methods.
  • the systems and/or methods can separate CO2 and provide heat and/or power.
  • the heat and power can be provided to buildings.
  • combustion products can be processed to separate CO2 from the combustion products.
  • CO2 can be separated from air.
  • power can be generated in the form of electricity while separating CO2 from combustions products and/or air.
  • the present disclosure provides power systems as well as power systems and methods for building emission processing and sequestration systems that can address carbon dioxide generation from combustion of fossil fuels and proliferation thereof in metropolitan areas. Additionally, the CO2 separation systems and methods of the present disclosure can separate CO2 from combustion products and/or air, and, in some embodiments, generated power in the form of electricity.
  • the systems can include: a combustion product stream; the combustion stream comprising at least CO2 and N2; and a carbonate electrochemical cell operatively aligned with the combustion stream and configured to react the CO2 from the combustion product stream and O2 to form carbonate ion and react the carbonate ion to form a CO2 product stream.
  • Methods for separating CO2 from a combustion product stream are also provided.
  • the methods can include: receiving a combustion product stream comprising CO2 and N2; reacting the combustion product stream to form carbonate ion; and reacting the carbonate ion to form a CO2 product stream.
  • the systems can include: an air stream with the air stream comprising at least C02 and N2; and a carbonate fuel cell operatively aligned with the air stream and configured to react the CO2 from the air stream and O2 to form carbonate ion and react the carbonate ion to form a CO2 product stream.
  • the systems or methods can include: providing air and fuel to a combustion burner; combusting the air and fuel within the combustion burner; monitoring the amount of free oxygen in the burner; and controlling the amount of air and fuel provided to the burner to maintain a free oxygen amount of about 3%.
  • the systems or methods can include: combusting air and fuel within a burner to produce flue gas having an oxygen concentration; and restricting air from the flue gas by substantially eliminating tramp air within the conduit operably aligned to convey flue gas from the burner.
  • Systems or methods for cooling flue gas from a combustion boiler within a building are provided.
  • the systems or methods can include providing the flue gas to at least one economizer having at least one set of cooling coils conveying the boiler feed water, the providing cooling the flue gas and heating the boiler feed water.
  • the systems or methods can include: providing flue gas comprising less than about 3% water; compressing the flue gas; and cooling the compressor with a heat transfer fluid and providing the heat transfer fluid to/from a chiller and/or a cooling tower.
  • the systems or methods can include: compressing the flue gas; and drying the flue gas using nitrogen recovered during separation of carbon dioxide recovered from the flue gas.
  • the systems or methods can include: removing at least some 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 systems or methods can include: removing at least some 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 some of the nitrogen removed from the flue gas to a gas expander/generator.
  • the systems or methods can include: removing at least some of the nitrogen from the flue gas to produce greater than 95% carbon dioxide using a pressure swing adsorption assembly; and providing the at least some of the nitrogen removed from the flue gas to both a dryer and an expander/generator, or to a dryer and control valve.
  • the control valve may or may not be equipped with a silencer.
  • System or methods for cooling carbon dioxide separated from flue gas generated from a combustion boiler within a building are provided.
  • the system or methods can include: separating nitrogen from flue gas using a pressure swing adsorption assembly; expanding the nitrogen through a turbine expander within the presence of a heat exchanger to cool fluid within the heat exchanger; and transferring that 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.
  • System or methods for liquefying carbon dioxide separated from flue gas generated from a combustion boiler within a building are provided.
  • the system or methods can include providing the gaseous carbon dioxide through a sparge assembly into liquid carbon dioxide within a storage vessel.
  • Buildings utilizing a carbon fuel source and generating carbon emission upon combustion of the carbon fuel source are provided. Building emissions can be operably coupled to a carbon capture system, the system configured to separate and condense carbon dioxide from the carbon emission.
  • the system can be configured to process the carbon emission and return heat to the building.
  • the system can be configured to process the carbon emission and generate electricity.
  • the system can be configured to process the carbon emission and store electrical energy.
  • the system can be configured to dynamically control the combustion and capture systems to reduce carbon combustion and increase carbon capture.
  • Combustion systems are provided that can include a combustion assembly operatively engaged with an air intake, wherein the air intake performs air enrichment.
  • Methods for enriching air to a combustion assembly are also provided.
  • the methods can include: forming an N2-rich stream and an 02-rich stream from a first air stream; supplementing a second air stream with the 02-rich stream to enrich the second air stream with 02; and combusting the enriched air stream.
  • the systems can include a vortex tube assembly operably coupled to a component of the system that provide pressurized N2.
  • Methods for heating or cooling components of a system for separating CO2 from flue gas are also provided.
  • the methods can include: providing compressed nitrogen from one or more components of the system to a vortex tube to form a heated nitrogen stream and cooled nitrogen stream; providing the heated nitrogen stream to components benefiting from a heat source; and providing the cooled nitrogen stream to components benefiting from a cooling source.
  • Systems for separating CO2 from flue gas can also include a separation assembly that includes a membrane assembly configured to separate CO2 from N2.
  • Methods for separating CO2 from flue gas can also include providing a flue gas stream comprising CO2 and N2 to a first membrane separation system to form a C02-rich stream and an N2-rich stream.
  • Fig. 1 is a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 2 is a carbon dioxide capture method and/or system according to another embodiment of the disclosure.
  • Fig. 3A is an example boiler equipped with a free oxygen sensor according to an embodiment of the disclosure.
  • Fig. 3B is a configuration of example boilers operably coupled to a plenum according to an embodiment of the disclosure.
  • Fig. 3C is an example boiler equipped with a free oxygen sensor according to an embodiment of the disclosure.
  • Fig. 4 is a depiction of a combustion assembly and a separation assembly in series according to an embodiment of the disclosure.
  • Fig. 5. is depiction of a combustion assembly according to an embodiment of the disclosure.
  • Fig. 6. is a depiction of an air enrichment assembly according to an embodiment of the disclosure.
  • Fig. 7 is a depiction of combustion in-take flow/assembly according to an embodiment of the disclosure.
  • Fig. 8A is a portion of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 8B is a portion of a carbon dioxide capture method and/or system according to another embodiment of the disclosure.
  • Fig. 8C is a portion of a carbon dioxide capture method and/or system according to another embodiment of the disclosure.
  • Fig. 9A is an example configuration of a component of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 9B is another example configuration of a component of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 10 is a portion of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 11 is a portion of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Figs. 12A and 12B are depictions of a carbon dioxide separation assemblies according to embodiments of the disclosure.
  • Fig. 13 is a depiction of a vortex tube according to an embodiment of the disclosure.
  • Fig. 14 is an example implementation of the vortex tube assembly of Fig. 13 in combination with a separation assembly (e.g., Pressure Swing Adsorption (PSA) assembly) according to an embodiment of the disclosure.
  • a separation assembly e.g., Pressure Swing Adsorption (PSA) assembly
  • Fig. 15 is a is an example configuration of a component of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 16A is an example of a CO2 separation system according to an embodiment of the disclosure.
  • Fig. 16B is an example CO2 separation system component according to an embodiment of the disclosure configured to operate as a carbonate pump.
  • Fig. 16C is an example CO2 separation system component according to an embodiment of the disclosure configured to receive CO2 and N2 from a flue gas source and operate as a carbonate fuel cell.
  • Fig. 16D is an example CO2 separation system according to an embodiment of the disclosure configured to receive CO2 and N2 from an air source and operate as a carbonate fuel cell.
  • Fig. 17 is a general separation component according to an embodiment of the disclosure.
  • Fig. 18 is a membrane separation component according to an embodiment of the disclosure.
  • Figs. 19-21 depict different configurations of membrane separation assemblies and methods according to embodiments of the disclosure.
  • Fig. 22 is a portion of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 23 is a portion of a carbon dioxide capture method and/or system according to another embodiment of the disclosure.
  • Fig. 24 is a portion of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 25A is a portion of a carbon dioxide capture method and/or system according to an embodiment of the disclosure.
  • Fig. 25B is another portion of the carbon dioxide capture method and/or system of Fig. 25A according to an embodiment of the disclosure. DESCRIPTION
  • a system 10 that includes a source of flue gas, such as a boiler that combusts air and fuel to produce flue gas.
  • Flue gas 12 can include typical combustion products from heating and/or cooling systems of a building. These buildings can be considered buildings that are commercial, residential, and/or industrial.
  • System 10 can rely on combustion of fossil fuels. These fossil fuels can include oil, and/or natural gas. Upon combustion of fuel, CO2 as part of flue gas can be produced.
  • system 10 can generate at least about 10% CO2 and about 18% water.
  • Systems and/or methods of the present disclosure can include a portion 14 for separation, a portion 16 for liquefaction, a portion 18 for storage, and a portion 19 for transfer of CO2.
  • At least about 600 standard cubic feet per minute of building flue gas can be diverted to the flue gas process stream where CO2 is separated and purified in component 14 of system 10.
  • This separation / purification component can be an adsorption purification system, operated under conditions of Pressure Swing (PSA), Vacuum Pressure Swing Adsorption (VPSA); Temperature Swing (TSA), or Electrical Swing (ESA), or any combination thereof.
  • PSA Pressure Swing
  • VPSA Vacuum Pressure Swing Adsorption
  • TSA Temperature Swing
  • ESA Electrical Swing
  • it can be a Pressure Swing Adsorption system that is a multicomponent adsorption system that includes multiple vessels containing layered solid phase adsorbent materials coupled and/or configured to work in concert to provide greater than 85% CO2 recovery.
  • These multicomponent adsorption systems can remove carbon dioxide from an essentially “dry” flue gas stream to a purity of greater than 95% in most cases, and in other cases, at least 99%.
  • This purified carbon dioxide gas can then be liquified with successive cooling and compression steps to effect phase change to form liquid carbon dioxide in liquefaction component 16, and then providing that liquified carbon dioxide to a storage component 18 for scheduled removal as desirable.
  • this liquified carbon dioxide can be transferred away in transfer component 19, and the transfer can be provided to another source such as a storage facility which can distribute the carbon dioxide for use in applications such as concrete curing, waste water treatment, other carbon dioxide sequestration methods, recycled for fire suppression systems, industrial specialty gas, consumed in production of hybrid fuels and organic intermediate chemicals, or for beverage carbonation, as a few examples.
  • a storage facility which can distribute the carbon dioxide for use in applications such as concrete curing, waste water treatment, other carbon dioxide sequestration methods, recycled for fire suppression systems, industrial specialty gas, consumed in production of hybrid fuels and organic intermediate chemicals, or for beverage carbonation, as a few examples.
  • a building system 30 is shown having system 32 therein.
  • Flue gas 12 is provided to a series of portions of system and/or methods 14, 16, 18, 19 and/or cooling tower 31 for the capture of CO2 from flue gas generated by the building.
  • a boiler 40 is shown generating combustion 42 in the presence of a free oxygen sensor 43.
  • Combustion 42 generates flue gas 44 which is provided to a boiler exhaust 45.
  • boiler exhaust is operatively coupled with a plenum 48.
  • multiple boilers are shown, each with an exhaust 45 and 46, for example, each exhaust operatively coupled to plenum 48.
  • a boiler configured with the systems and/or methods of the present disclosure is depicted. Accordingly, air 60 and fuel 62 can be provided to the combustion burner, the mix of which and accordingly the burn of which is controlled by combustion controller 66 which is operably connected with free oxygen sensor 43. Accordingly, boiler feed water 52 is received by the combustion boiler and heated to hot water or steam 50 which is used to heat the building and/or building systems such as water heater 58. Water heater system 58 can be configured to receive potable water for heating and/or industrial process water for heating. In accordance with example implementations, control 66 can utilize sensor 43 to monitor the amount of free oxygen in the combustion burner and maintain the amount of free oxygen to about 3%.
  • combustion can generate flue gas 44.
  • the composition of (wet) flue gas 44 can be controlled to include at least about 8% carbon dioxide.
  • About 10% carbon dioxide can include carbon dioxide from 9 to 11 % of the flue gas (dry basis) from combustion of natural gas.
  • System 10 can be utilized to combust fuels other than natural gas which may dictate other optimal CO2 flue gas concentrations. Accordingly, system 10 can be configured to utilize multiple fuels.
  • the systems and/or methods of the disclosure can 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.
  • systems and/or methods for operating the combustion boiler within the building can include combusting air and fuel within the burner to produce flue gas 44 having an oxygen concentration; and restricting air from the flue gas by substantially eliminating tramp air within the conduit operably aligned to convey flue gas from the burner.
  • exhausts 45 and 46 can be operatively aligned with plenum 48. Exhausts not in use, such as 46, can be a source of tramp air to the plenum.
  • the systems and/or methods of the present disclosure can include providing fluid communication between the operating burner of one boiler and the plenum while restricting fluid communication between the plenum and an idle burner of the other operating boiler.
  • a door or divider 47 can be provided and operable to eliminate tramp air from the exhaust of the idle burner.
  • real time control of the combustion source, or boiler can achieve higher efficiency to reduce consumption of natural gas or fuel, for example, while increasing the concentration of carbon dioxide in the flue gas.
  • This may be considered counter intuitive to increase the concentration of carbon dioxide in the flue gas when the systems and/or methods of the present disclosure are being utilized to reduce carbon emissions from a building.
  • increasing carbon dioxide concentration can provide the benefit of decreasing fuel consumption by reducing heat loss through the exhaust.
  • Adjusting combustion to control free oxygen to 3% can give a higher efficiency burn.
  • through combustion control it is desirable to approach the 12% concentration value of CO2, when burning natural gas, and achieve at least about 10% carbon dioxide concentration in the flue gas (dry basis). This is at least one feature of the disclosed building emission processing systems and/or methods and can be utilized as one of the initial steps in carbon capture.
  • boiler operation can be dictated by responding to the need for hot water or steam by controlling the combustion burner to various predetermined firing rates; 1 ) an off condition, 2) a low fire rate, and/or 3) a high fire rate. These rates may have been established on older boilers through calibrated mechanical linkages, for example. Recognizing that cyclic boiler operation will vary widely from hour to hour, day to day, and season to season, it is desired to establish automatic control of the flame rate continuously across the entire boiler load range, while also controlling free oxygen as discussed above.
  • the systems and/or methods of the present disclosure can be configured to reduce on-off cycles by extending boiler run time at a reduced flame rate, increasing the life on the boilers, and providing a more continuous flow of flue gas to the separation, liquefaction, storage and/or transport systems and/or methods of present disclosure. Accordingly, the boiler and system controls (for example 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.
  • FIG. 1 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 viewed in the context of U.S. Patent Application Publication No. US 2020/0340665 which was published October 29, 2020, the entirety of which is incorporated by reference herein.
  • combustion assembly 11 can have air enrichment performed before receiving air for combustion utilizing air enrichment assembly 130.
  • Air 60 can be provided and enriched prior to use in combustion assembly 11.
  • Combustion assembly 11 can generate an exhaust gas mixture 170 that can include carbon dioxide.
  • Mixture 170 can be provided to separation assembly 14, after additional treatment for example. Upon example treatment, mixture 170 can be sufficiently dry to have carbon dioxide separated out in separation assembly 14.
  • Separation assembly 14 can provide separated gas mixture 200 that includes a substantially higher concentration of carbon dioxide than is provided to the separation assembly.
  • an example combustion system includes a burner that is configured to receive enriched air 210 and provide air 60 through an enrichment assembly 130.
  • the burner and/or the air and/or fuel being provided to the burner can be controlled by a combustion controller (not shown) to heat water that is part of a steam loop.
  • This combustion assembly can generate an exhaust 44 such as a flue gas.
  • Membrane assembly 170 can be configured as a bundled hollow fiber membrane.
  • Example membrane assemblies can include SEPURAN® (Evonik Industries AG, Rellinghauser StraBe 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.
  • air 60 can enter membrane assembly 170, and this air can include oxygen from 21 %; and nitrogen 78.5%.
  • Exiting as the retentate mixture 160 can be a stream that is substantially nitrogen in the range from about 90% to 95%, but proceeding to another stream as permeate mixture 140 can be a stream that is oxygen in the range from about 36% to 43%, with less nitrogen contained therein (58-64%).
  • permeate mixture 140 can be provided to enrich air stream 60 at mixing system 180 which can be configured as a valving system and/or plenum system to form enriched air mixture 210.
  • Enriched air mixture 210 is higher in oxygen concentration than standard air and can continue to the burner for combustion.
  • air 60 can be compressed and provided to membrane assembly 170 wherein assembly 170 provides an N2-rich stream 160 and an 02-rich stream 140.
  • the 02-rich stream 140 can be mixed in a mixing system 180 with air 60 to provide enriched air 210 to a boiler burner via a boiler blower, for example.
  • N2-rich stream 160 can be operably coupled to a turbo expander and/or a vortex tube for the generation of power and/or warm/cool N2 as needed. This is just one example of the turbo expander and/or vortex tube being coupled to a high pressure N2 source.
  • 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.
  • Figs. 8A-C multiple portions of systems and methods are depicted for separating water from flue gas as well as cooling the flue gas.
  • Figs. 8A-8C three different configurations of systems and/or methods for cooling flue gas from a combustion boiler within a building are depicted.
  • flue gas 44 can proceed to a combination non-condensing and condensing economizer 60a.
  • Flue gas 44 first proceeds to a non condensing configuration in which boiler feed water 52 is provided through a conduit, set of conduits, and/or coils and flue gas is cooled and the boiler feed water heated. Accordingly, methods for cooling flue gas from a combustion boiler within a building are provided. Upon heating the boiler feed water, it can be provided to the boiler thus lowering the necessary energy required to heat the feed water to hot water and/or steam.
  • a conduit, set of conduits, or coils 54 can be configured to convey potable or industrial process water that is received from a utility for example.
  • This water can have the temperature close to that of ground water as it is conveyed through typically underground pipes. Accordingly, the water has a substantially different temperature than the flue gas, even after being partially cooled in the non-condensing economizer.
  • the providing of the flue gas to these conduits can remove water from the flue gas thus creating a water condensate effluent 53.
  • This water proceeding through the conduits can be heated and provided to a water heating system 58 (Fig. 3C) as water heating system water intake 54, heated and received through outlet 56.
  • 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.
  • economizer 60b can be a non-condensing economizer and economizer 65a can be configured as a condensing economizer.
  • a diverter 64 can be operably coupled to the economizers as shown in Figs.
  • the cooled flue gas can be provided from diverter 64 using a blower.
  • the systems and/or methods can control the amount of flue gas to be processed using the diverter.
  • the current system in accordance with Fig. 8C is going to receive 450 Standard Cubic Feet per Minute (SCFM) to 500 SCFM of wet flue gas 44.
  • SCFM Standard Cubic Feet per Minute
  • This diverter can be controlled by the overall master system (Fig. 24) which can control the motor operated butterfly valve within the diverter.
  • the master system can also collect gas temperature and flow data, and operate the blower as shown in Fig. 10.
  • a blower may precede the economizer.
  • the wet flue gas is at least about 8% carbon dioxide and/or at least about 3% free oxygen prior to entering the first economizer.
  • the systems and/or methods of the present disclosure can utilize economizers configured as shown in Figs. 9A and 9B for example, and the methods can include additional separation as well as liquefaction, storage, and transport.
  • flue gas from the boiler may have a water content of approximately 18%, and a temperature ranging up to 350°F. Prior to separation of CO2, this water can be substantially removed from the flue gas. This involves dropping the flue gas temperature below dewpoint and allowing water to condense out as a liquid. As the water content of the flue gas lowers, so does the dewpoint, requiring yet additional cooling to continue removing the water. This cooling can result in flue gas condensates.
  • the non-condensing economizer can operate above dew point temperature, preventing any liquid condensate from forming. Without condensation, this economizer can be compatible with most plenum construction materials.
  • a condensing economizer can be provided downstream of the diverter (Fig. 8C) which extracts flue gas from the plenum and directs it on to the condensing economizer. Condensate from this condensing economizer can be chemically neutralized before proceeding to the building drain as shown by 75 in Fig. 10.
  • flue gas drying can continue with a blower 68 to increase pressure of flue gas from the diverter.
  • This blower 68 can support flow through the heat exchanger/condenser 70 which can include a water outlet 71 operatively coupled to an acid neutralizer assembly 75.
  • Fleat exchanger 70 can be configured to cool the gas below dewpoint to condense out most water leaving less than about 3% water or as low as approximately 0.2% water.
  • Heat exchanger 70 can be a tube and shell configuration, cooled by an external water/glycol loop provided from a chiller and/or water from the building cooling tower for example. As shown, the water removed from the system at heat exchanger 70 can be slightly acidic, and it is anticipated that the water can be neutralized before proceeding to a Publicly Owned Treatment Works (POTW) or through a sewer system. Additionally, some water will remain in the process stream as small micro droplets, mist, or acidic aerosols which will be minimized or removed with special heat exchanger designs, mist eliminator, impingement devices, or possibly a precipitator. These components may produce additional condensate or effluent which can be treated before proceeding to a POTW.
  • POTW Publicly Owned Treatment Works
  • the cooled flue gas 72 can continue on to a compressor to increase pressure of the flue gas to an optimum level of approximately 100 psig, or lower, as dictated by the PSA system specification. Since compression raises process gas dew point, the compressor may produce additional condensate or effluent.
  • compressor 74 can receive flue gas 72.
  • Compressor 74 can be an “oil free” compressor to eliminate downstream product contamination, and the compressor can be configured with variable frequency drives (VFD’s) to respond to variable gas flows. Compression can raise the temperature and dew point of the flue gas, so a second heat exchanger 76 can be utilized to lower the temperature of the flue gas to less than 40 Q C.
  • the gas can have less than about 0.2% water which can exist as a vapor, the gas can be less than 40 Q C temperature, and can be about 100 psig in pressure.
  • the systems and/or methods for separating carbon dioxide from flue gas generated from a combustion boiler within a building can include providing flue gas 72 having less than about 3% water; compressing the flue gas; and cooling compressor 74 with a heat transfer fluid 90 and providing the heat transfer fluid to/from a chiller and/or a cooling tower.
  • mist eliminator subsystem 89 can be provided which can produce an effluent 53.
  • effluent 53 can be slightly acidic (approx. 5 pH) and can be neutralized before being provided to the building drain.
  • mist eliminator sub-system 89 can be added just prior to the compressor inlet.
  • This subsystem can be an electrostatic unit, wet walled heat exchanger, or a passive impinger arrangement comprised of reticulated metal or carbon foam, wire mesh pad, or other material designed with a tortuous gas path causing mist particles to strike surface areas, nucleate and drain from the system by gravity.
  • the mist eliminator solution can significantly prevent harmful corrosion in downstream components of the process gas stream. Accordingly, the mist eliminator can produce effluent 53 which can be neutralized and provided to a drain.
  • a separation assembly 14 includes a PSA or Pressure Swing Adsorption assembly 80 that can be configured in line to receive an amount of incoming fluid such as gas, for example having carbon dioxide of 8% to 16%; nitrogen of 86% to 78%.
  • PSA 80 can be configured to separate carbon dioxide from this stream and provide carbon dioxide that is greater than 95% purity.
  • PSA 80 can provide a substantially nitrogen stream that is pressurized, and this nitrogen can be provided to one or more assemblies, for example, via stream 42 to a turbine expander 48 as well as to a control valve 50 via stream 44 as shown.
  • nitrogen streams 86 can be provided from these assemblies.
  • 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 operating functions of the system generally and/or of the PSA assembly particularly. This is one example of coupling of the vortex tube to take advantage of pressurized N2 created with the system and/or methods of the present disclosure.
  • the vortex tube and/or the turbo expander can be coupled to other components in the system that generate pressurized N2, for example, membrane retentate streams.
  • membrane retentate streams for example, and with reference to Fig.
  • different portions of the PSA include adsorbent that is configured at temperatures and/or pressures to provide for the adsorption or desorption of carbon dioxide when separating nitrogen from carbon dioxide.
  • 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 the adsorption of carbon dioxide during that step cycle.
  • hot nitrogen 56 can be provided to warm the adsorbent to desorb the carbon dioxide.
  • the system can utilize the hot and/or cold nitrogen that is provided from the pressurized nitrogen of the PSA as thermal energy to facilitate a more efficient PSA separation.
  • FIG. 13 An example a vortex tube assembly 300 is depicted in Fig. 13 that includes an input 302 that is configured to receive compressed nitrogen and provide cold nitrogen at exit 304 and hot nitrogen at exit 306.
  • a more detailed view of a thermal exchange is shown wherein the cold nitrogen can be provided to a heat exchanger as part of a portion of a PSA, and the hot nitrogen can be provided to another portion. These portions can be regulated to provide thermal energy during the in-sync step cycle of the Pressure Swing Adsorption to separate carbon dioxide from the incoming gas.
  • portions of the PSA adsorbent can be in thermal communication with a heat exchange assembly that is configured to receive either or both of cold nitrogen or hot nitrogen from the vortex assembly (e.g., as part of the step-cycling of PSA).
  • vortex exits can be provided with valves to control the flow of hot or cold nitrogen to the heat exchangers that are in thermal communication with the adsorbent.
  • the heat transfer fluid can be water for example, and the water of the chiller can be cooled within a cooling tower of the building before returning spent heat transfer fluid to the chiller.
  • the systems and/or methods of the present disclosure can include additional separation, liquefaction, storage, and/or transport. This is just one example of the heat generating components of the system that can be cooled with chiller and/or cooling tower heat transfer fluid. Over 70% of the cooling requirement for the systems and/or methods of the present disclosure can come from heat generated in compressors and/or pumps, and from heat exchangers on the liquefaction skid. Each of these components can be provided with a water cooling circuit supplied from a local chiller or directly from the 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: a) domestic hot water makeup; b) cooling tower; c) exchange with outside air, for example.
  • the flue gas can be provided to a dryer 78, such as a desiccant dryer.
  • Dryer 78 can be operatively engaged with a nitrogen feed, such as a sweep feed, configured to regenerate spent desiccant.
  • the dryer is a two- chamber cycling device, wherein one chamber is drying while the other chamber is re-generated for drying, and those cycles continue.
  • the nitrogen can be provided to spent desiccant in one chamber while the other chamber is drying flue gas.
  • systems and/or methods for separating carbon dioxide from flue gas generated from a combustion boiler within a building are provided that can include drying the flue gas using nitrogen recovered during separation of carbon dioxide recovered from the flue gas.
  • This recovered nitrogen can be conveyed from the pressure swing adsorption assembly 80 via conduit 92 to dryer 78 and then exhausted through the stack 86.
  • the dried flue gas can be provided for additional separation, liquefaction, storage, and/or transport.
  • the flue gas 79 can proceed to pressure swing adsorption (PSA) assembly 80.
  • PSA pressure swing adsorption
  • This pressure swing adsorption assembly can provide greater than 85% CO2 recovery, at greater than 95% purity, at 1 psig, from ambient to about 100 Q C. Maximum CO2 output flow at this point can be approximately 40 SCFM.
  • the remainder of the flue gas, mostly nitrogen may continue under pressure, and/or be split with a portion returning to dryer 78. Another portion of the nitrogen can proceed to a turbine expander 82/generator 93 which can provide electrical energy 94 and a cold output gas, at near ambient pressure.
  • a control valve 84 equipped with a silencer can be operationally aligned in parallel with expander 82/generator 93.
  • methods for separating carbon dioxide from flue gas generated from a combustion boiler within a building can include removing at least some of the nitrogen from the flue gas to produce greater than about 95% carbon dioxide 78 using a pressure swing adsorption assembly 80.
  • Nitrogen removed from the flue gas can be used to remove water from the flue gas before providing the flue gas to the pressure swing adsorption assembly, in dryer 78, for example.
  • at least some of the nitrogen removed from the flue gas can be provided to a gas expander/generator.
  • one part of the nitrogen from the PSA can be provided to a control valve equipped with a silencer and providing another part to the expander/generator.
  • the systems and/or methods of the present disclosure can include separating the nitrogen into parts and providing one part to the dryer and another part to the expander/generator.
  • the one part is about a third of the nitrogen from the pressure swing adsorption assembly.
  • a small amount of rejected gas can be produced containing both CO2 and nitrogen. Rather than purging this gas it can be recycled back through the compressor via recycle line 81 in order to enhance the overall recovery of CO2.
  • Systems and/or methods are also provided for cooling carbon dioxide separated from flue gas generated from a combustion boiler within a building using the nitrogen exhaust of a PSA.
  • the systems and/or methods can include separating nitrogen from flue gas using pressure swing adsorption assembly 80, and expanding the nitrogen through a turbine within the presence of a heat exchanger 92 to cool fluid within heat exchanger 92; and transferring that cooled fluid to another heat exchanger 100 operably aligned with the carbon dioxide product of the pressure swing adsorption assembly to cool the carbon dioxide product 78.
  • the turbine can be part of a generator 93, for example, or may be provided to cool exchanger 92.
  • the nitrogen gas exiting the PSA can be at least 85 psig. with a flow exceeding 80% of the rated system flow.
  • the nitrogen may be processed and saved as a marketable product.
  • grid compatible power conversion will be needed.
  • the turbine generator will have a 500 Hz output which is not compatible with a 60Hz grid. Therefore, it is envisioned that appropriate power conversion will be specified. This can be rectification followed by DC to AC multi phase inverter with proper safety features in case of a building power outage. After use in the turbine generator, and in the CO2 heat exchanger, the nitrogen waste gas can proceed back to the exhaust stack or plenum.
  • FIGs. 16A-16D different embodiments of CO2 separation systems and/or methods are depicted that can be used alone or in combination with some or all of the components of the systems and/or methods of Fig. 1.
  • an electrochemical cell that includes a cathode configured to receive for reaction CO2 and O2.
  • This CO2 and O2 may be received from the same or different streams.
  • the C02 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, it may also contain O2, it may also contain H2O in a range of concentrations.
  • the stream may be considered wet or dry, with a wet stream containing H2O from the combustion process that generated the flue gas.
  • the O2 may be received as part of a flue gas stream, an air stream and/or as part of an O2 stream.
  • Exiting the cathode side of the cell can be an N2 stream.
  • This N2 stream may also contain CO2 that did not react to form carbonate ion (CO3 2 ). For example, it may contain CO2, H2O, and/or O2. This N2 stream will contain less CO2 than the stream exposed to the cathode.
  • CO2 Upon exposure to the cathode and electrical coupling, the CO2 is reacted to form the carbonate ion which is conveyed through the carbonate electrolyte to the anode where the electrical coupling returns the CO3 2 to CO2 and O2 as a CO2 product.
  • this system can be implemented in a variety of ways; for example, as a carbonate ion pump (Fig. 16B), as flue gas carbonate fuel cell (Fig. 16C), and/or as fuel cell (Fig. 16D).
  • CO2 can be removed/separated/sequestered from one or more streams.
  • a portion of a carbon dioxide capture method and/or system configured with a carbonate ion pump.
  • the carbonate ion can be produced electrochemically on the surface of a cathode electrode by reacting carbon dioxide and oxygen from the air in the presence of electrons.
  • the CO2 can be obtained from flue gas in wet or dry form, and the O2 can be part of the flue gas or provided from an O2 source, from air for example.
  • the flue gas can contain N2 which will not react at the cathode and proceed to the gas stack along with any other components that did not react (e.g., FI2O, O2, CO2).
  • the electrochemical equation is: CO2 +I/2O2 + 2e >>, CO3 .
  • Multiple cells can be configured into stacks whereby CO2 and O2 are supplied through respective manifolds.
  • a solid or liquid electrolyte can be in ionic communication with the cathode providing a pathway for carbonate ions to move to the associated anode.
  • This electrochemical activity is the basis for forming and transporting carbonate ions and for separating CO2 from the original cathode gas mixture.
  • CO2 can be separated from flue gas using a membrane alone or in combination with other separation techniques.
  • the membrane separation can utilize solvent absorption and/or polymeric based membranes with appropriate permeability and selectivity for CO2.
  • the polymeric membranes can include mixed polymeric membranes as well. Additional membranes can include carbon and/or inorganic membranes.
  • CO2 separation can be performed using membranes configured to perform Knudson diffusion, molecular sieving, solution-diffusion separation, surface diffusion and/or capillary condensation.
  • O2 can be generated from the CO2 product stream, for example during liquefaction.
  • This O2 can be provided to the cathode as part of the O2 source.
  • the amount of the O2 being provided to the cathode can be monitored and/or adjusted as desired to operate the cell for optimal CO2 separation.
  • a carbonate fuel cell configuration can be provided with fuel, particularly hydrocarbon fuel sufficient to form syngas (H2 and CO).
  • the syngas can be formed from natural gas (CFl4- Fl2 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 the carbonate ion which can be exposed to the syngas at the anode to form CO2 and FI2O as well as electrons to provide power output in the form of heat and electricity.
  • This system can be part of a building design, replacing a power generator or boiler within a building, and/or as a stand alone system to provide heat and power.
  • the natural gas can be provided as part of the fuel cell and this natural gas can be tapped into from the intake to an existing building. Accordingly, while using natural gas which can be directly reformed to syngas at operational temperatures, heat and power can be generated electrochemically and this heat and power can be provided to the building thereby offsetting part or all of the building’s thermal and power needs without natural gas combustion, thus, drastically reducing CO2 emissions.
  • the system can be paired with a common boiler system that is configured to combust natural gas. Accordingly, both the boiler and the system of the ion pump can be configured to receive natural gas. Therefore, the system of Fig. 16C can provide heat and electrical power while the boiler provides thermal power in the form of steam.
  • the system of Fig. 16C can be operationally aligned with CO2 capture and purification systems as well.
  • the fuel cell can receive flue gas at the cathode and CO2 is electrochemically purified and made available for separation and liquefaction.
  • flue gas can be provided though a tortuous path to maximize CO2 exposure to the cathode electrode surface area.
  • This flue gas may be provided directly from the combustion boiler or it may be treated as described with reference to Figs. 8-11 prior to being exposed to the cathode side of the fuel cell.
  • Multiple cells can be configured in stacks with appropriate gas manifolds. This particular embodiment can offer increased performance in higher CO2 concentrations thus allowing for less pretreatment of flue gas before CO2 separation.
  • the stream comprising CO2 and O2 can be provided to liquefaction as described, for example, herein with reference to Fig. 1.
  • Non condensable oxygen can be separated and fed back 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.
  • syngas can be introduced at the anode and carbonate ions react exothermically to form more CO2 and water vapor.
  • a large substantial amount of the resulting gas can be purified CO2.
  • the concept further teaches removal of water vapor through condensation followed by CO2 liquefaction.
  • systems for separating CO2 from a combustion product can include a combustion product stream.
  • This combustion product stream can be a wet stream or a dry stream that contains CO2 and N2, or for example CO2, O2, H2O, and/or N2.
  • the system can include a carbonate ion pump or 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 ion and react the carbonate ion to form a CO2 product stream.
  • the carbonate electrochemical cell can include a cathode configured to receive electrons from a power supply and react those electrons with the CO2 and O2 of the combustion product stream to form the carbonate ion.
  • This carbonate ion can be CO3 2 , for example and can be a component of a carbonate electrolyte.
  • the cell can also include an anode configured to react the carbonate ion and form CO2, O2 and electrons. Accordingly, the system can include a cathode and anode about a carbonate electrolyte.
  • an O2 source can be operatively coupled to the cathode of the carbonate electrochemical cell.
  • 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 operatively coupled to the anode to provide a carbonate fuel cell.
  • the anode can be configured to receive the carbonate ion and the syngas and form the CO2 product stream.
  • the system can include a catalytic burner operatively coupled to the CO2 product stream as well as a heat exchanger operatively coupled to the catalytic burner and configured to remove H2O from the CO2 product stream.
  • the heat exchanger can be operatively coupled to a heat recovery loop with an additional conduit configured to provide CO2 to the cathode.
  • Methods for separating CO2 from a combustion product stream can include receiving a combustion product stream comprising CO2 and N2; reacting the combustion product stream to form carbonate ion; and reacting the carbonate ion to form a CO2 product stream. Electrons can be provided to form the carbonate ion, and electrons can be removed to form the CO2 product stream.
  • syngas can be provided to react with the carbonate ion to form the CO2 product stream, and natural gas can be provided to form the syngas.
  • Embodiments of this method can generate a net positive electrical potential upon forming the CO2 product stream.
  • a system for separating CO2 from air 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 the CO2 from the air stream and O2 to form carbonate ion and react the carbonate ion to form a CO2 product stream.
  • An O2 source can be operatively coupled to the cathode of the carbonate fuel cell, with the cathode being configured to react CO2 from the combustion stream and/or O2 from the source. As shown, this O2 source can be from the CO2 liquefaction process.
  • a natural gas source can be operatively coupled to the anode of the carbonate fuel cell, with the anode configured to receive the carbonate ion and the natural gas and form the CO2 product stream.
  • a portion of CO2 can be returned to the cathode as required, with remaining CO2 sent to liquefaction as described with reference to Figs. 22-25B.
  • a portion of system 10 is shown that includes separation assembly 14.
  • Entering separation assembly 14 can be a fluid mixture 12 that is typically in a gas phase.
  • Mixture 12 can include flue gas that may have been processed to remove water.
  • the mixture can typically include an amount of carbon dioxide from 8% to about 16%, and nitrogen from 86% to 82%; balance of oxygen and other trace materials.
  • Exiting separation assembly 14 can be at least one separated mixture 78 that can have a higher concentration of carbon dioxide than the carbon dioxide concentration of mixture 12.
  • a membrane separation assembly 1000 is shown that can receive mixture 12 and provide at least two separated streams, a retentate stream 1018 and a permeate stream 1020.
  • Separation assembly 540 can be configured as a bundled hollow fiber membrane.
  • Example membrane assemblies can include SEPURAN® (Evonik Industries AG, Rellinghauser StraBe 1 — 11 45128 Essen Germany) and/or custom assemblies (UniSieve Ltd, Regina-Kagi-Strasse 11 , CH- 8050 Zurich, Switzerland).
  • membrane separation assembly 540 can have multiple components and multiple configurations that include configurations of flow, temperature, pressure, membranes, and/or stages.
  • the stages can include stages in series, stages that return to stages, and/or stages that allow for the separation to occur at certain flows, pressures and/or temperatures.
  • this configuration can include a back pressure regulator or control valve 1022 to maintain back pressure on membrane separation assembly 540.
  • Figs. 19-21 multiple configurations of the membrane separation assemblies 540A and 540B are shown in the context of systems 1100, 1200, and 1300, for example.
  • mixture 12 can be provided to assembly 540A.
  • assembly 540A can have one or more membranes
  • assembly 540B can have one or more membranes.
  • assembly 540A can provide a retentate mixture 1018 A that can proceed to optional assembly 540 B while also providing a permeate mixture 1020A.
  • mixture 1018A can be provided to other points of a separation and purification system as appropriate.
  • Permeate mixture 1020A can have a percentage of carbon dioxide from about 60% to about 70%.
  • the stages can be operated at different configurations to provide a yield of carbon dioxide that is greater than 90%, for example, as well as a purity of the carbon dioxide exiting the system that can be as high as 70%.
  • assembly 540B can provide retentate mixture 1018B and permeate mixture 1020B.
  • vacuum pump 600 can be provided. Vacuum pump 600 can provide a pressure differential to facilitate permeate mixture 1020A production. Accordingly, operating the removal of the permeate mixture from the membrane assembly under reduced pressure can provide additional yield and/or purity of the carbon dioxide in the permeate mixture.
  • assembly 540A can include one or more membranes
  • assembly 540B can include one or more membranes.
  • Mixture 1020B can be provided together with mixture 12 as enriched mixture 1700 to assembly 540A and pressurized at compressor 400.
  • mixture 1700 can have a higher concentration of carbon dioxide than mixture 12.
  • the carbon dioxide yield may increase to as high as 90% and the carbon dioxide can be maintained at a purity of greater than 70%.
  • FIG. 21 another configuration includes assemblies 540A and 540B with assembly 540B receiving permeate mixture 1020A.
  • the assemblies can have mixtures provided under pressure with compressors 400 and 420 as shown.
  • the present disclosure provides membrane separation technology that can be used as part of the carbon dioxide separation systems and alternative systems, including but not limited to that in U.S. Patent Application Publication No. US 2020/0340665 which was published October 29, 2020, the entirety of which is incorporated by reference herein.
  • the >95% pure CO2 78 can be cooled and compressed in sequential steps as shown in heat exchangers 104, compressors 106 and 108, and heat exchanger 110 with compressors operatively engaged with cooling transfer fluid 90 to approach the phase change state for liquefaction.
  • the >95% pure CO2 can have a temperature coming out of the PSA of as high as 100 Q C.
  • a heat exchanger can be provided to lower the temperature of the gas to a sufficient temperature and then compress the gas to a higher pressure.
  • heat removed from this CO2 stream can be transferred through external water / glycol cooling loops back to a heat management system which will support preheating of makeup water as shown in Fig. 22. It can also be provided to raise the temperature of nitrogen gas coming off of the PSA prior to expansion through the turbine. This can improve turbine efficiency by allowing full use of nitrogen flow before exceeding the COLD temperature output limit. This is just one of several examples of utilizing heat from system components at other portions of the system to derive a more efficient overall system. In accordance with Fig 23, there is a stepwise cooling and compression sequence of the CO2 gas, which drives towards a final state of 311 psig and 0 °F, at which point phase change occurs and the CO2 becomes a liquid.
  • a CO2 liquefaction and storage system and/or method is shown wherein C02gas 112 is sparged inside a vessel 113 such as an insulated vessel.
  • Example insulated vessels can include but are not limited to vacuum jacketed liquid storage tanks.
  • gas 112 can be converted to a liquid 114.
  • gas 112 can be provided to sparge assembly 118 where it is provided as sparged gas 120 which liquefies upon sparging into liquid 114.
  • Vapor 116 at the top of vessel 113 is managed by a refrigeration system 122 which cools vapor 116, which condenses back to liquid 114, which returns back into vessel 113.
  • system 122 can be configured as a loop in fluid communication with vessel 113 wherein vapor CO2 116 enters system 122 and returns to vessel 113 as a liquid CO2 114.
  • system 122 is configured as a low temperature condenser equipped with an evaporator.
  • vessel 113 can be configured with a controlled venting subsystem to facilitate removal of non-condensable gases while minimizing loss of CO2.
  • Inlet gas to the CO2 liquefaction system can be a high concentration of CO2 preferably >95%.
  • Remaining gases such as nitrogen and oxygen, can be considered as non-condensable gases in the liquefaction process.
  • impurity gases remain which are miscible with liquid CO2. These impurities must be measured accurately in order to qualify the liquid CO2 product in accordance with commercial standards, such as ISBT, the international beverage guideline.
  • Both the controlled venting subsystem and the purity analytical system can account for non-condensable gases which can dissolve into the liquid.
  • non-condensable gases in the continuous feed to liquefaction can build up in the storage system vapor space 116. Without removal, these non-condensable gases can continue to build pressure in the vapor space of the storage tank causing some of the gas to dissolve into the liquid, thus contaminating the liquid.
  • excessive pressure in the tank can inhibit both the gas feed system and the refrigeration system which manages vapor and re-condenses CO2 as liquid back into the tank.
  • the venting system can be controlled to manage tank vapor space in conjunction with the refrigeration unit to release non-condensable gases, reduce pressure buildup, while minimizing loss of CO2 vapor.
  • Instrumentation (see for example, Fig. 11 ) at the tank can be configured to acquire and provide data regarding vapor pressure, dissolved gas, vapor composition, gas flow, etc. to the processor which can operate solenoid valves on vent lines to enact controlled release of tank vapor within strict parameters.
  • the superior insulation of a vacuum jacketed tank may maintain liquid C02 for at least 30 days.
  • the building itself may be able to tap into vessel 113 for a supply of CO2 to extinguish fires; for example, fires related to electronic components that require CO2 extinguishing methods.
  • a CO2 removal and/or delivery system can include off-take management using one or more vehicles provided in concert with CO2 removal and/or delivery needs as provided by system control.
  • a removal and/or delivery truck 200 can be provided which transfers CO2 directly from vessel 113 via a transfer pump 202 into a liquid CO2 tank affixed to truck 200.
  • the system can be configured to generate CO2 pick up times based on numerous parameters, such as: vessel 113 capacity, system 10 CO2 generation, legal date/time pickup windows; and/or CO2 delivery needs.
  • CO2 delivery needs it is contemplated that such high purity CO2 can be delivered to a user directly without being warehoused or the need for additional purification.
  • Just one example of direct delivery can be delivery to a wastewater treatment plant.
  • offtake analytics can be provided to qualify the product with the ability to issue a Certificate of Analysis before transport.
  • FIG. 24 plant, process and field level components of a control system are shown.
  • an example overall control system is provided that shows combustion emission and control, MASTER PLC controller, the diverter, the compression, dryer, separation, cooling and compression, refrigeration / storage, and the providing of food grade CO2.
  • These systems are also coupled to utility systems of electricity, natural gas, and water.
  • These control systems exemplify a basic Network Architecture Diagram.
  • the MASTER PLC controls the entire plant with Ethernet loop connections and with Internet IP protocol communications to the Local Packaged controllers, and through direct connection and control to the digital and analog I/O field instrumentation level.
  • the HMI server gathers data from the MASTER PLC, manages plant real time displays, executes logging, data management applications, and communicates through the secure firewall to external users. Also implied is the Engineering Development workstation which maintains all operational software and updates which are periodically downloaded to the MASTER PLC.
  • FIGs. 25A and 25B an example implementation of the systems and/or methods is disclosed which details the sequence of the different components and processes described herein, as well as additional thermal management components that are associated with the building.
  • heat can be transferred from different components of the disclosed system to existing building systems.
  • chillers can be in the building, as well as existing cooling towers.
  • These active cooling components can be operably coupled with heat being removed from process components via individual cooling loops.
  • heat sometimes referred to as waste heat
  • waste heat can be transferred to building systems which can use extra heat to operate more efficiently. Therefore, regarding waste heat from the disclosed system, design preference is to transfer waste heat, firstly to building steam and hot water makeup systems, secondly to the building cooling tower, and finally to an appropriate chiller with heat exchange to air.
  • a thermal management system can conserve use of fuel such as natural gas in the boiler by optimizing the combustion with the combustion controller, control water removal from the flue gas with the front end controller, perform additional separation with the dryer and PSA with the separation controller, liquefy and store CO2 with the liquefaction/storage controller, and dictate off-take to a pickup and/or delivery truck with the off-take controller.
  • These and additional controllers can work 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 loads in the system. Accordingly, flue gas can be cooled for water knockout, and heat generating electrical components such as compressors, blowers, pumps, and fans can be cooled as well.
  • localized gas analytic instruments can be configured to provide localized CO2 and O2 concentration measurements in near real time.
  • gas sampling instruments / sensors directly at sampling points within subsystems like the PSA subsystem, small streams of sample gas can be pumped through sensor caps just inches away from the process gas to be 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 the master controller using standard communication protocols. Individual sensor devices can be uniquely addressed by the master controller over a common hardwire connection (ethernet, RS232, RS485, etc.).
  • off-take analytics can be provided that are integrated into the system in order to certify off-take weight of liquid CO2 removed, and to qualify CO2 product purity within required commercial standards.
  • This off-take analytical system can be configured to issue a Certificate of Analysis for the product CO2 at the time it is transferred out of the building, or from an intermediate storage and processing facility.
  • the off-take analytical system can be configured to document all information to officially account for all off-take transactions.
  • a set of electronic load cells can be placed underneath each storage tank to accurately measure weight of the tank and its contents. The system will make a difference calculation to certify weight of liquid CO2 removed.
  • the analytical system can be configured to measure product impurities within exacting standards. Just before product transfer the analytical system will automatically take a small liquid CO2 sample from the storage tank, vaporize it, and then flow the sample gas to a state of the art FTIR spectrum analyzer or to a field grade gas chromatograph system.
  • the FTIR spectrum analyzer will be equipped with procedures and chemical spectral libraries sufficient to identify and measure all “impurities” shown on the customers contractual purity specification for liquid CO2. Such specifications usually stipulate the ISBT beverage guideline along with one or more additional compounds of importance to the customer.
  • At least one advantage of the FTIR analytical system is that it will be configured to operate automatically, not requiring manual assistance, while providing several times more measurement fidelity than required by the ISBT guideline. It is generally understood that FTIR systems cannot measure chemical compounds which do not exhibit a molecular dipole. This does not apply to impurities of interest, since they all exhibit molecular dipoles, with several degrees of motion (observable frequencies).
  • the FTIR system can also be connected to the “front end” to accurately measure impurities of flue gas from the boiler system.
  • the systems and/or methods of the present disclosure can include an energy storage system that can be configured to include a power conversion component and/or a battery or battery bank component.
  • energy can be generated via turbine expansion of the nitrogen and this energy can be converted and stored within the building.
  • the energy may be converted and provided directly to system components, for example compressors, and/or provided to the system components after storage, thus lowering building energy demand. Additionally, the energy may be provided to the power grid associated with the building itself.
  • energy generated with the system can be utilized during “peak demand” times (when, for example electricity rates are higher) and/or when the building is utilizing a “peak” amount of power.
  • the MASTER PLC is monitoring building demand and then modify the system parameters to efficiently use energy storage and/or change carbon dioxide separation, liquefaction, storage, and/or transport to lower energy consumption during “peak demand” thus providing energy cost savings.
  • Example implementations of the systems and/or methods of the present disclosure can provide not only a carbon capture system but also an improvement in overall building energy efficiency (both thermal and electrical) while lessening CO2 emissions.
  • Example implementations can include lowering carbon fuel consumption through optimizing boiler combustion, providing warmer boiler feed water thus requiring less energy to heat the boiler feed water, warming potable or process water thus requiring less energy to the heat the potable or process water, generating electrical energy and using same to power system components, and/or using building cooling towers to reduce building thermal load, etc., which individually and/or collectively can be part of systems that dramatically improve building efficiency.

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  • Engineering & Computer Science (AREA)
  • Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Analytical Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Physics & Mathematics (AREA)
  • Combustion & Propulsion (AREA)
  • Thermal Sciences (AREA)
  • Treating Waste Gases (AREA)
  • Carbon And Carbon Compounds (AREA)
  • Gas Burners (AREA)
  • Separation Of Gases By Adsorption (AREA)
  • Separation By Low-Temperature Treatments (AREA)

Abstract

L'invention concerne des systèmes de combustion qui peuvent comporter un ensemble de combustion en prise fonctionnelle avec une admission d'air, l'admission d'air réalisant un enrichissement en air. L'invention concerne également des procédés d'enrichissement en air dans un ensemble de combustion. L'invention concerne également des systèmes et des procédés de séparation de CO2 à partir de gaz de combustion. L'invention concerne également des procédés de chauffage ou de refroidissement de composants d'un système de séparation de CO2 à partir de gaz de combustion.
EP22782222.8A 2021-03-31 2022-03-31 Systèmes et procédés de séparation de co2 Pending EP4314535A1 (fr)

Applications Claiming Priority (3)

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US202163168794P 2021-03-31 2021-03-31
US202163168825P 2021-03-31 2021-03-31
PCT/US2022/022853 WO2022212719A1 (fr) 2021-03-31 2022-03-31 Systèmes et procédés de séparation de co2

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JP (1) JP2024514378A (fr)
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* Cited by examiner, † Cited by third party
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US6745573B2 (en) * 2001-03-23 2004-06-08 American Air Liquide, Inc. Integrated air separation and power generation process
US7128064B2 (en) * 2004-02-20 2006-10-31 Heider James E Method and apparatus to provide oxygen enriched air to the intake manifold of an internal combustion engine
KR101038439B1 (ko) * 2008-07-30 2011-06-01 한국에너지기술연구원 이산화탄소 분리시스템 적용을 위한 볼텍스 튜브 장치
EP3963269A4 (fr) * 2019-04-29 2023-07-05 Carbonquest, Inc. Systèmes et procédés de traitement et/ou de séquestration d'émission de bâtiment
EP4267517A1 (fr) * 2020-10-28 2023-11-01 Carbonquest, Inc. Systèmes et procédés de séparation de co2

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WO2022212719A1 (fr) 2022-10-06
CA3200483A1 (fr) 2022-10-06

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