CO2 Separation System and Method

Abstract

A system for separating CO2 from a flue gas source is provided. The system can include a liquefaction component operably coupled to the separation component and configured to receive the separated CO2 from the separation component and reduce the temperature of the separated CO2 by exchanging heat of the separated CO2 with CO2 vapor generated by the liquefaction component and / or the storage component, the storage component operably coupled to the liquefaction component and configured to receive liquid CO2 from the liquefaction component. A method for separating CO2 from a flue gas source is provided. The method can include liquefying a CO2 stream to form both CO2 liquid and CO2 vapor, and using at least a portion of the CO2 vapor during liquefaction to form the CO2 liquid.

Description

[Technical field]

[0001] [CROSS REFERENCE TO RELATED APPLICATIONS] This application is a joint venture of "CO 2 This application claims priority to and benefit of U.S. Provisional Patent Application No. 63 / 335,821, entitled "Microseparation Systems and Methods," which is incorporated herein by reference in its entirety.

[0002] The field of the invention is CO 2 In certain embodiments, the system and / or method comprises: 2 The combustion products, which are the only source of flue gas, can be treated to separate the CO from the combustion products. 2 In addition, CO can be separated from the air. 2 In addition, CO can be separated from the combustion products and / or air. 2 While isolating the above, power can be generated in the form of electricity. [Background technology]

[0003] Carbon dioxide generation in buildings, especially in metropolitan areas, is a large contributor to overall carbon dioxide generation. Carbon dioxide is currently listed as a global warming compound that is being sought to be reduced globally. Carbon dioxide generation is an essential part of breathing and a necessary part of life, but limiting the free distribution of carbon dioxide is important in efforts to combat climate change. The present disclosure provides a method for the extraction of CO from flue gases. 2 The present invention provides a system and method for separating CO 2 For sequestration and / or treatment to limit the free distribution of CO 2The present disclosure also provides a power system and a power system and method for constructing an emission treatment and sequestration system that can address the generation and spread of carbon dioxide from the combustion of fossil fuels in metropolitan areas. 2 The systems and methods for separating CO from combustion products and / or air 2 can be separated and, in some embodiments, generate power in the form of electricity. Summary of the Invention

[0004] CO from flue gas sources 2 A system for separating at least CO 2 and N 2 a flue gas source operatively coupled to the flue gas source, 2 N 2 Separated from CO 2 and a recuperative heat exchanger operatively coupled to the separation component, the recuperative heat exchanger configured to generate a CO 2 Receives and separates CO 2 of heat from the CO generated by the liquefaction and / or storage components 2 The separated CO is exchanged with steam. 2 wherein the storage component is operably coupled to the liquefaction component and configured to extract liquid CO from the liquefaction component. 2 a liquefaction component configured to receive CO; 2 Storage vessel and / or CO 2 and a storage component comprising a transport vehicle, wherein one or both of the liquefaction component and / or the storage component are operatively coupled to a recuperative heat exchanger to absorb CO generated during liquefaction and / or storage. 2 At least a portion of the steam is fed to a recuperator to recover the separated CO 2 Cool.

[0005] CO from flue gas sources 2 A method for separating CO 2 and N 2 receiving a flue gas source stream comprising CO 2 N 2 Separated from the main CO 2 forming a flow of CO 2 Stream is liquefied to produce CO 2 Liquids and CO 2 During liquefaction, at least some of the CO 2 Using steam to 2 forming a liquid. [Brief description of the drawings]

[0006] Embodiments of the present disclosure are described below with reference to the accompanying drawings, in which: [Figure 1] 1 is a CO2 separation system and / or method according to one embodiment of the present disclosure. [Diagram 2] FIG. 2 is a diagram of a flue gas source that can supply flue gas for separation using a CO2 separation system and / or method according to an embodiment of the present disclosure. [Figure 3A] 1 is an example of a combustion boiler equipped with a free oxygen sensor according to one embodiment of the present disclosure. [Figure 3B] FIG. 2 is a block diagram of an example of a fired boiler operably coupled to a plenum, according to one embodiment of the present disclosure. [Figure 3C] 1 is an example of a combustion boiler equipped with a free oxygen sensor according to one embodiment of the present disclosure. [Figure 4A] 1 is a portion of a CO2 separation system and / or method according to one embodiment of the present disclosure. [Figure 4B] 1 is a portion of a CO2 separation system and / or method according to another embodiment of the present disclosure. [Figure 4C] 1 is a portion of a CO2 separation system and / or method according to another embodiment of the present disclosure. [Figure 5A]1 is an example of a configuration of CO2 separation system components and / or methods according to one embodiment of the present disclosure. [Figure 5B] 1 is another example configuration of a CO2 separation system and / or method according to an embodiment of the present disclosure. [Figure 6] 1 is a portion of a CO2 separation system and / or method according to one embodiment of the present disclosure. [Figure 7] 1 is a portion of a CO2 separation system and / or method according to one embodiment of the present disclosure. [Figure 8] 1 is an example of a configuration of CO2 separation system components and / or methods according to one embodiment of the present disclosure. [Figure 9A] 1 is an example of a CO2 separation system according to one embodiment of the present disclosure. [Figure 9B] 1 is an example of a CO2 separation system component and / or method according to an embodiment of the present disclosure configured to operate as a carbonate ion pump. [Figure 9C] 1 is an example of a CO2 separation system component and / or method according to one embodiment of the present disclosure configured to receive CO2 and N2 from a flue gas source and operate as a carbonate fuel cell. [Figure 9D] 1 is an example of a CO2 separation system and / or method 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 10A] 1 is a portion of a CO2 separation system and / or method according to one embodiment of the present disclosure. [Figure 10B] 2 is another portion of a CO2 separation system and / or method according to another embodiment of the present disclosure. [Figure 11] 1 is a portion of a CO2 separation system and / or method according to another embodiment of the present disclosure. [Figure 12] 1 is a portion of a CO2 separation system and / or method according to one embodiment of the present disclosure. [Figure 13A] 1 is a portion of a CO2 separation system and / or method according to one embodiment of the present disclosure. [Figure 13B] 13B is another portion of the CO2 separation system and / or method of FIG. 13A according to one embodiment of the present disclosure. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0007] The present disclosure will be described with reference to Figures 1-13B. The systems and methods of the present disclosure can be operated unattended and / or continuously in buildings for up to 10 years with only minor routine maintenance. According to other embodiments, the CO 2 The separation system and / or method may be operated outdoors and may be configured to receive flue gas from one or more flue gas sources. Referring initially to FIG. 1, a system 10 is provided that includes a flue gas source 11, such as a boiler, that combusts air and fuel to generate flue gas. Other flue gas sources may include, but are not limited to, cogeneration units, and / or adsorption chillers (absorbent or adsorbent). The flue gas 12 may include typical combustion products from a building's heating and / or cooling system. These buildings may be considered commercial, residential, industrial, and / or mixed-use buildings. The building's system may include, for example, CO2, CO2 from the flue gas, and / or CO2 from the flue gas, in sequential portions 14, 16, 18, and / or 19 of the system and / or method. 2 The flue gas may be fed to a cooling tower for separation and / or collection of

[0008] The system 10 may rely on the combustion of fuels, such as fossil fuels and / or synthetic fuels, which may include oxyfuels, with enriched air. These fossil fuels may include oil and / or natural gas. When the fuel is burned, CO is released as part of the flue gas. 2 In the case of natural gas combustion, the system 10 may produce at least about 10% CO 2 and about 18% water. The systems and / or methods of the present disclosure may produce CO 2The system may include a separation section 14, a liquefaction section 16, a storage section 18, and a transport section 19.

[0009] In accordance with an exemplary implementation, at least about 600 standard cubic feet per minute of building flue gas may be diverted to a flue gas process stream and CO 2 emissions may be reduced in component 14 of system 10. 2 is separated and purified. The separation / purification component may be an adsorption purification system operating under pressure swing (PSA), vacuum pressure swing adsorption (VPSA), temperature swing (TSA) or electric swing (ESA) conditions, or any combination thereof. According to an implementation, it is a multi-component adsorption system including multiple vessels, which together are charged with more than 85% CO 2 The adsorption system may be a pressure swing adsorption system that includes layered solid-phase adsorbent materials (e.g., structural materials) bonded and / or configured to achieve the recovery of carbon dioxide. 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 can then be liquefied and phase changed in liquefaction component 16 by successive cooling and compression steps to form liquid carbon dioxide, which can then be delivered to storage component 18 for planned removal as desired. According to implementations, this liquefied carbon dioxide can be transported away in transportation component 19 to another source, such as a storage facility that can distribute the carbon dioxide for use in applications such as concrete curing, wastewater treatment, other carbon dioxide sequestration methods, recycling for fire suppression systems, industrial specialty gases, consumables in the production of hybrid fuels and organic intermediate chemicals, or food and beverage quality standard applications such as beverage carbonation, among many others.

[0010] Referring now to FIG. 2, examples of flue gas sources are provided. One or more of these flue gas sources can be used to generate CO 2A flue gas source can be provided for separation. For example, an adsorption chiller (SC) 20 can include an industrial adsorption chiller that is directly fired or operated using steam. As another example, a combined heat and power (CHP) unit 22 can be a flue gas source. Additionally, a combustion boiler 24 can be a flue gas source.

[0011] 3A-3C, example boiler block diagrams are 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 produces flue gases 44 that are fed to a boiler exhaust 45. Referring to FIG. 3B, the boiler exhaust is operatively coupled to a plenum 48. In this illustrated configuration, multiple boilers are shown, each having, for example, exhaust conduits 45 and 46, with each exhaust operatively coupled to the plenum 48.

[0012] 3C, a boiler configured in accordance with the disclosed systems and / or methods is illustrated. According to this, air 60 and fuel 62 may be supplied to a combustion burner, the mixture, and therefore the combustion, being controlled by a combustion controller 66 operatively connected to the free oxygen sensor 43. Thus, boiler feedwater 52 is received by the combustion boiler and heated to hot water or steam 50, which 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 potable water for heating and / or industrial process water for space heating.

[0013] In an example implementation, the control 66 can utilize the sensor 43 to monitor the amount of free oxygen in the combustion burner and maintain the amount of free oxygen at about 3%. About 3% free oxygen can include 3-7% free oxygen. In an example implementation, the combustion can produce a flue gas 44. The composition of the (wet) flue gas 44 can be controlled to include at least about 8% carbon dioxide. About 10% carbon dioxide can include 9-11% carbon dioxide of flue gas (dry basis) from the combustion of natural gas. The system 10 can be configured to optimize the amount of free oxygen in the combustion burner and maintain the amount of free oxygen at about 3%. In an example implementation, the combustion can produce a flue gas 44. The composition of the (wet) flue gas 44 can be controlled to include at least about 8% carbon dioxide. About 10% carbon dioxide can include 9-11% carbon dioxide of flue gas (dry basis) from the combustion of natural gas. 2 Fuels other than natural gas for which flue gas concentrations can be determined may be utilized for combustion, and thus, the system 10 may be configured to utilize multiple fuels.

[0014] 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.

[0015] With reference to both FIG. 3B and FIG. 3C, a system and / or method for operating a combustion boiler in a building is provided that may include combusting air and fuel in a burner to generate flue gas 44 (having some oxygen concentration) and restricting air from the flue gas by substantially eliminating tramp air in a conduit operatively aligned to convey the flue gas from the burner. According to an implementation, in the case of multiple boilers as shown in FIG. 3B, exhaust outlets 45 and 46 may be operatively aligned with a plenum 48. Unused exhaust outlets such as 46 may be a source of tramp air to the plenum. According to an implementation, the disclosed system and / or method may include providing fluid communication between the operating burners of one boiler and the plenum on the one hand, and controlling fluid communication between the plenum and unused burners of the other operating boiler. In at least one configuration, a door or divider 47 may be provided and operable to exclude tramp air from the exhaust outlets of unused burners.

[0016] According to at least one embodiment of the present disclosure, real-time control of a combustion source or boiler can achieve greater efficiency, for example, to increase the concentration of carbon dioxide in the flue gas while reducing the consumption of natural gas or fuel. This may seem counterintuitive when utilizing the systems and / or methods of the present disclosure to reduce carbon emissions from buildings. However, increasing the concentration of carbon dioxide can provide the benefit of reducing fuel consumption by reducing heat loss through exhaust. Adjusting the combustion to control free oxygen to 3% can result in a highly efficient burn. According to an implementation, controlling the combustion can reduce the CO2 concentration to 12% when burning natural gas. 2and achieving a carbon dioxide concentration of at least about 10% in the flue gas (dry basis), which is at least one feature of the disclosed building emissions treatment systems and / or methods and can be utilized as one of the initial steps in carbon capture.

[0017] In a building, boiler operation can be dictated in response to hot water or steam needs by controlling the combustion burners to various predetermined firing rates; 1) off, 2) low firing rate, and / or 3) high firing rate. These rates may have been established in older boilers, for example, through coordinated mechanical linkages. Recognizing that circulating boiler operation varies widely from hour to hour, day to day, and season to season, it is desirable to establish automatic control of the flame rate over the entire boiler load range, while also controlling free oxygen as described above. The disclosed systems and / or methods can be configured to extend the boiler's operating time at a reduced firing rate, increasing the period at the boiler and providing more continuous flow of flue gas to the disclosed separation, liquefaction, storage, and / or transportation systems and / or methods, thereby reducing on / off cycles.

[0018] Thus, the boiler and system controls (eg, FIG. 12) can achieve higher building thermal efficiency while providing optimal conditions for flue gas supply to the systems and methods of the present disclosure.

[0019] 4A-C, portions of a system and method for separating water from flue gas and cooling the flue gas are illustrated. Referring first to FIGS. 4A-4C, three different configurations of a system and / or method for cooling flue gas from a combustion boiler in a building are illustrated. Referring first to FIG. 4A, the flue gas 44 can proceed to a combined non-condensing and condensing economizer 60a. The flue gas 44 first proceeds to the non-condensing configuration, where the flue gas is cooled and the boiler feedwater is heated through a conduit, conduit set, and / or coil to provide the boiler feedwater 52. Thus, a method is provided for cooling flue gas from a combustion boiler in a building. Once the boiler feedwater is heated, it can be fed to the boiler, thus lowering the energy required to heat the feedwater to hot water and / or steam.

[0020] In addition, the economizer may be configured to condense. Thus, the conduit, conduit set, or coil 54 may be configured to convey drinking water or industrial process water received, for example, from a utility company. This water may have a temperature close to that of groundwater, as it is typically conveyed through buried 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. By supplying flue gas to these conduits, water may be removed from the flue gas and condensed waste water 53 may be produced. This water traveling through the conduits may be heated and supplied to a water heating system 58 (FIG. 3C) (water heating system intake 54), heated, and received through an outlet 56. Thus, the amount of energy required to heat the water in the water heating system 58 is less, at least because the water received for heating does not need to be heated from the low temperatures associated with normal water use, but rather is preheated. According to an alternative configuration, referring to FIG. 4B, one coil set 52 may be associated with one economizer 60b and the other coil set 54 may be associated with the other economizer 65a. In this configuration, the economizer 60b may be a non-condensing economizer and the economizer 65a may be configured as a condensing economizer. According to another embodiment of the present disclosure, a diverter 64 may be operatively coupled to the economizer as shown in FIGS. 4A-4C. According to an implementation, cooled flue gas may be provided from the diverter 64 using a blower. The system and / or method may control the amount of flue gas treated using the diverter. According to an implementation, the current system according to FIG. 4C may receive 450 to 500 Standard Cubic Feet per Minute (SCFM) of wet flue gas 44. The diverter may be controlled by an overall master system (FIG. 12) that may control a motor-operated butterfly valve in the diverter. The master system also collects gas temperature and flow data and can operate the blower shown in FIG.

[0021] Thus, if the economizer is a process stream downstream from a diverter, a blower may precede the economizer. According to an 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 utilize an economizer configured, for example, as shown in Figures 5A and 5B, and the method may include additional separation, as well as liquefaction, storage, and transportation.

[0022] It has been determined that flue gas from a boiler can have a moisture content of approximately 18% and a temperature ranging up to 350° F. 2 This water can be substantially removed from the flue gas prior to separation of the water from the flue gas. This involves lowering the temperature of the flue gas below its dew point, causing the water to condense into a liquid. As the water content of the flue gas decreases, the dew point also decreases, but additional cooling is required to continue removing the water. This cooling can result in a flue gas condensate.

[0023] Flue gas condensate tends to be slightly acidic (pH≦5), a condition that can damage some building plenums due to non-acid-resistant building materials (such as carbon steel). In such 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 microdroplets may remain in the gas stream. These microdroplets can be referred to as acid aerosols, which can be present at ppm levels. The present disclosure contemplates the removal of acid aerosols. These systems and / or methods include, for example, wetted wall heat exchangers, impingers or mist eliminators with inert reticulated carbon or metal foams, and precipitators.

[0024] In accordance with the above, a non-condensing economizer can operate at temperatures above the dew point and prevent the formation of all liquid condensate. Without condensation, the economizer can be compatible with most plenum building materials.

[0025] As mentioned above, a condensing economizer can be provided downstream of a diverter (FIG. 4C) that extracts the flue gas from the plenum and directs it to the condensing economizer. The condensate from this condensing economizer can be chemically neutralized before proceeding to the building drain, as shown at 75 in FIG. 6.

[0026] 6, drying of the flue gas may continue with a blower 68 to increase the pressure of the flue gas from the diverter. This blower 68 may support flow through a heat exchanger / condenser 70, which may include a water outlet 71 operably coupled to an acid neutralization assembly 75. The heat exchanger 70 may be configured to cool the gas below the dew point and condense most of the water, leaving less than about 3% water, or as little as about 0.2% water.

[0027] 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 the building's cooling tower. As shown, it is envisioned that the water removed from the system at the heat exchanger 70 may be slightly acidic and may be neutralized before proceeding to a Publicly Owned Treatment Works (POTW) or through a sewer system. Additionally, some water remains in the process stream as fine droplets, mist, or acid aerosols, which are minimized or removed with special heat exchanger designs, mist eliminators, impingement devices, or possibly precipitators. These components may generate additional condensate or waste liquid, which may be treated before proceeding to the POTW.

[0028] After most of the water has been removed and the acid aerosols have been mitigated, the cooled flue gas 72 continues to a compressor which can increase the pressure of the flue gas to an optimum level, up to about 100 psig, as dictated by the PSA system specifications. Because compression increases the dew point of the process gas, the compressor may generate additional condensate or waste liquid.

[0029] 7, a compressor 74 may receive the treated flue gas 72. The compressor 74 may be an "oil-free" compressor to eliminate contamination of downstream products, and may be configured with a variable frequency drive (VFD) to respond to variable gas flows. Compression may increase the temperature and dew point of the flue gas, so a second heat exchanger 76 may be utilized to reduce the temperature of the flue gas to below 40°C. At this stage, the gas may have less than about 0.2% water present as steam, the gas may be at a temperature below 40°C, and the pressure may be about 100 psig.

[0030] Referring to FIG. 7 , a system and / or method for separating carbon dioxide from flue gas may include providing flue gas 72 having less than about 3% water, compressing the flue gas, cooling the compressor 74 with a heat transfer fluid 90, and providing the heat transfer fluid to / from a chiller and / or cooling tower.

[0031] According to another implementation, a mist eliminator subsystem 89 may be provided that may generate a waste liquid 53. During the removal of water from the flue gas, condensate may be generated as a waste liquid at other points in the process or system. This waste liquid may be slightly acidic (approximately 5 pH) and may be neutralized before being delivered to the building drain.

[0032] Very small amounts of this slightly acidic condensate remain entrained in the process gas as mist or acid aerosols. To remove these liquid microdroplets, a mist eliminator subsystem 89 can be added just before the compressor inlet. This subsystem can be an electrostatic unit, a wetted wall heat exchanger, or a passive impinger device constructed of reticulated metal or carbon foam, wire mesh pads, or other materials designed with a serpentine gas path that causes mist particles to impact a surface area, nucleate, and exit the system by gravity. By reducing or eliminating the acid aerosols, the mist eliminator solution can significantly prevent harmful corrosion in downstream components of the process gas stream. Thus, the mist eliminator can generate a waste liquid 53 that can be neutralized and fed to a drain.

[0033] An example of a compressor is shown in FIG. 8. The heat transfer fluid may be, for example, water, and the chiller water may be cooled in a building's cooling tower before returning the spent heat transfer fluid to the chiller. Thus, the disclosed system and / or method may include additional separation, liquefaction, storage, and / or transportation. This is just one example of a heat generating component of the system that may 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 may come from heat generated in the compressor and / or pump, as well as from heat exchangers on the liquefaction skid. Each of these components may have a water cooling circuit that is supplied from a local chiller or directly from a central chiller. The local chiller may be water cooled with a water loop that originates from the central chiller or from cooling water from the building's cooling tower. The central chiller may be designed to prioritize heat transfer in the following order, for example: a) general domestic hot water make-up, b) cooling tower, c) exchange with outside air.

[0034] Referring again to FIG. 7, after compression, the flue gas can be fed to a dryer 78, such as a desiccant dryer. The dryer 78 can be operatively associated with a nitrogen feed, such as a sweep feed, and is configured to regenerate the spent desiccant. Typically, the dryer is a two-chamber cycle device, where one chamber is dried and the other chamber is regenerated for drying, and the cycle continues. 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 for separating carbon dioxide from flue gas generated from a combustion boiler in a building is provided, which can include drying the flue gas using nitrogen recovered during the separation of the carbon dioxide recovered from the flue gas. The recovered nitrogen can be conveyed from the pressure swing adsorption assembly 80 to the dryer 78 via conduit 92 and then exhausted through the stack 86. According to an implementation, the dried flue gas can be fed for further separation, liquefaction, storage, and / or transportation.

[0035] The treated flue gas 79 (containing less than 10 ppm water) can proceed from the dryer to a pressure swing adsorption (PSA) assembly 80. The PSA assembly produces >95% pure, >85% CO2 at ambient to about 100° C. under 1 psig. 2 At this point, the maximum CO 2The output may be about 40 SCFM. The remaining flue gas (mostly nitrogen) may remain under pressure and / or be split with a portion returning to the dryer 78. The other portion of the nitrogen may go to a turbine expander 82 and a generator or compressor 93. The generator may provide electrical energy 94 and cooled output gas at near ambient pressure. The electrical energy 94 may be tied to the grid or returned to the system. The compressor may be operatively positioned to compress as desired. Additionally, a control valve 84 with a silencer may be operatively positioned in parallel with the expander 82 and / or the generator and / or the compressor 93.

[0036] Thus, a method of separating carbon dioxide from a flue gas can include removing at least a portion of the nitrogen from the flue gas using a pressure swing adsorption assembly 80 to produce greater than about 95% carbon dioxide 78. The nitrogen removed from the flue gas can be used to remove water from the flue gas, for example, in a dryer 78, before the flue gas is fed to the pressure swing adsorption assembly. Alternatively or additionally, at least a portion of the nitrogen removed from the flue gas can be fed to a gas expander / generator. Alternatively or additionally, a portion of the nitrogen from the PSA can be fed to a control valve with a silencer and another portion can be fed to the expander / generator. According to implementations, the disclosed systems and / or methods can include separating and subdividing the nitrogen and feeding one portion to the dryer and another portion to the expander / generator. In one implementation, the one portion is about one-third of the nitrogen from the pressure swing adsorption assembly.

[0037] According to the implementation example, during the PSA process, CO 2 A small amount of reject gas containing both CO and nitrogen may be produced. Rather than purging this gas, 2 To improve overall recovery of the refrigerant, it can be recycled by passing it back through the compressor via recycle line 81.

[0038] Systems and / or methods are also provided for using the nitrogen output of the PSA to cool carbon dioxide separated from flue gas produced from a combustion boiler in a building. The systems and / or methods can include separating the 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 the fluid in the heat exchanger 92, and transporting the cooled fluid to another heat exchanger 100 operatively 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 can be provided to cool the exchanger 92.

[0039] Typically, the nitrogen gas exiting the PSA may be at least 85 psig, a flow rate greater than 80% of the rated system flow rate. Depending on the implementation, the nitrogen may be processed and stored as a commodity. For power generation, grid-compatible power conversion may be required. Turbogenerators have a 500Hz output and do not fit into a 60Hz grid. It is therefore envisioned that a suitable power conversion will be specified. This may be rectification followed by a DC-AC polyphase inverter with appropriate safety features in case of a building power outage. Turbogenerators and CO 2 After use in the heat exchanger, the nitrogen exhaust gas may be returned to the stack or plenum.

[0040] 9A-9B, different embodiments of CO 2 A separation system and / or method is provided.

[0041] For example, referring to FIG. 9A, CO 2 and O 2 An electrochemical cell is shown that includes a cathode configured to receive CO. 2 and O2 can be received from the same or different streams. For example, CO 2 may be received from a flue gas stream or may be received from an air stream. The flue gas stream may include a CO 2 and N 2 O may be 2 may also contain a range of concentrations of H 2 For example, a stream may be considered wet or dry, with wet streams including H2O from the combustion process that generated the flue gas. 2 It contains O. 2 is a portion of the flue gas stream, the air stream, and / or O 2 It can be taken as part of the flow.

[0042] What comes out of the cathode side of the cell is N 2 This N 2 The flow reacts to produce carbonate ions (CO 3 2- ) was not formed CO 2 For example, CO 2 , H 2 O, and / or O 2 This N may include 2 The flow emits less CO than the flow exposed to the cathode. 2 Contains:

[0043] When exposed to the cathode and electrical coupling, CO 2 reacts to form carbonate ions, which are transported through the carbonate electrolyte to the anode, where they are converted by electrical coupling into CO 3 2- CO 2 and O 2 Return to 2 As described in more detail below, the system can be implemented in a variety of ways, for example, as a carbonate ion pump (FIG. 9B), as a flue gas carbonate fuel cell (FIG. 9C), and / or as a fuel cell (FIG. 9D). In one or more of these implementations, CO 2 can be removed / separated / isolated from one or more streams.

[0044] For example, referring to Figure 9B, a portion of a carbon dioxide capture method and / or system configured with 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 with oxygen (from air) in the presence of electrons. 2 can be obtained from flue gas in wet or dry form, and O 2 is part of the flue gas or O 2 The flue gas can be supplied from a source (e.g., air). The flue gas contains N 2 and any other components that did not react (e.g., H 2 O, O 2 , CO 2 ) and proceed to the exhaust stack.

[0045] The electrochemical formula is:CO 2 +1 / 2O 2 +2e - →CO 3 -- Multiple cells can be arranged in a stack, which 2 and O 2 is fed through each manifold.

[0046] Once carbonate ions are produced at the cathode, a solid or liquid electrolyte can be placed in ionic communication with the cathode to provide a pathway for the transport of the carbonate ions to the associated anode. This electrochemical process involves the formation and transport of carbonate ions and the removal of CO from the original cathode gas mixture. 2 This is the basis for the separation of

[0047] Upon reaching the anode, an electron is removed from the carbonate ion, which dissociates to form CO 2 and 1 / 2O 2 can be returned to.

[0048] According to another implementation of the present disclosure, membranes can be used alone or in combination with other separation techniques to separate CO from flue gas.2 Membrane separation can separate CO 2 Solvent absorbing and / or polymeric membranes with appropriate permeability and selectivity to CO can be utilized. Polymeric membranes can also include mixed polymeric membranes. Additional membranes can include carbon and / or inorganic membranes. 2 Separation can be performed using membranes configured to perform Knudsen diffusion, molecular sieving, solution diffusion separation, surface diffusion and / or capillary condensation.

[0049] As shown in Figures 9B-9D, for example, during liquefaction, CO 2 O from the product stream 2 This O 2 O 2 The O supplied to the cathode can be used as part of the O source. 2 The amount of CO can be monitored and / or adjusted as desired to obtain optimal 2 The cell can be operated for separation.

[0050] According to one embodiment of the present disclosure, and referring to FIGS. 9C-9D, a synthesis gas (H 2 A carbonate fuel cell configuration can be provided that can include a fuel, particularly a hydrocarbon fuel, sufficient to produce a synthesis gas (CO). Syngas can be natural gas (CH), 4 →H 2 The cathode can be formed from other hydrocarbon materials, including, but not limited to, carbon monoxide (CO) and CO, and / or coal. The cathode can be formed from CO, as described above. 2 and O 2 at the anode to form carbonate ions, which are then exposed to syngas at the anode to form CO 2 and H 2 O and electrons can be formed to provide power output in the form of heat and electricity. The system may be part of a building design replacing generators or boilers in the building and / or may be a stand-alone system providing heat and power.

[0051] Natural gas can be supplied as part of the fuel cell, and this natural gas can enter an existing building through an intake. Thus, heat and power can be electrochemically produced using natural gas that can be reformed directly into syngas under operating temperatures, and this heat and power can be supplied to the building, offsetting some or all of the building's heat and power needs without burning natural gas, thus reducing CO2 emissions. 2 Emissions can be dramatically reduced.

[0052] For example, the system can be paired with a typical boiler system that is configured to burn natural gas. Thus, both the boiler and fuel cell systems can be configured to receive natural gas. Thus, the system of FIG. 9C can provide heat and power while the boiler produces thermal electricity in the form of steam. The system of FIG. 9C can also be used to generate CO 2 It may also be operatively aligned with a collection and purification system.

[0053] Thus, the fuel cell can receive flue gas at the cathode and produce CO 2 The CO is electrochemically purified and made available for separation and liquefaction. As shown, the flue gas is transferred to the cathode electrode surface area. 2 The flue gas may be fed through a serpentine path to maximize exposure. This flue gas may be fed directly from a combustion boiler or may be treated prior to exposure to the cathode side of the fuel cell as described with reference to Figures 4-6. Multiple cells may be arranged in a stack with appropriate gas manifolds. This particular embodiment is advantageous in that it provides a higher CO 2 Performance can be improved with CO concentration. 2 Less pre-treatment of the flue gas prior to separation is required.

[0054] Upon reaching the anode, electrons are removed from the carbonate ions, producing CO 2 and O 2 According to Figures 9A to 9D, CO 2 and O2 The stream containing oxygen may be fed to liquefaction, for example as described herein with reference to Figure 10. The non-condensable oxygen may be separated and returned to the cathode side of the pump. As shown, electrical energy may be provided to operate the pump. The pump may also utilize heat from the flue gas.

[0055] Thus, heat and power can be electrochemically generated using natural gas that is reformed directly into syngas at operating temperatures, and this heat and power can be supplied to a building to offset some or all of the building's heat and power needs without burning natural gas.

[0056] Therefore, syngas can be introduced at the anode, and the carbonate ions will react exothermically to produce more CO 2 At this stage, a significant amount of the resulting gas is converted into purified CO 2 This concept is based on the condensation and subsequent CO 2 Removal of water vapor by liquefaction is further taught.

[0057] Thus, the combustion product stream may include CO 2 A system is provided for separating the combustion product stream from the CO 2 and N 2 , or for example CO 2 , O 2 , H 2 O and / or N 2 The system may be operatively aligned with the combustion stream and may be configured to extract CO from the combustion product stream. 2 and O 2 to form carbonate ions, and to react with CO 2 A carbonate ion pump or carbonate electrochemical cell configured to form the product stream may be included.

[0058] The carbonate electrochemical cell receives electrons from a power source and converts the electrons into CO from the combustion product stream.2 and O 2 The cathode may include a cathode configured to react with, for example, CO 3 2- The cell may also react carbonate ions to produce CO 2 , O 2 and an anode configured to generate electrons. Thus, the system can include a cathode and an anode around a carbonate electrolyte.

[0059] According to a further embodiment, O 2 The source may be operably coupled to the cathode of a carbonate electrochemical cell. In this configuration, the cathode is adapted to receive CO from a combustion stream. 2 and O 2 O from source 2 Further embodiments can utilize a syngas source operably coupled to the anode to provide a carbonate fuel cell. In this configuration, the anode receives carbonate ions and syngas and produces CO 2 The device may be configured to form a product stream.

[0060] The system is 2 a catalytic burner operably coupled to the product stream; and a CO 2 O from the product stream 2 and a heat exchanger configured to remove CO from the cathode. 2 The heat recovery loop may be operably coupled with an additional conduit configured to supply

[0061] CO from combustion product streams 2 The method for separating CO 2 and N 2 receiving a combustion product stream comprising: 2and forming a product stream. Electrons can be provided to form carbonate ions and electrons can be removed to form CO 2 A product stream can be formed.

[0062] In addition, synthesis gas is supplied to react with carbonate ions to produce CO 2 A product stream can be formed, and natural gas can be provided to form a synthesis gas. 2 In forming the product stream, a net positive electrical potential can be generated.

[0063] Referring to FIG. 9D, 2 A system is provided for separating CO from air. The system comprises at least 2 and N 2 an air flow including: 2 and O 2 to form carbonate ions, and to react with CO 2 and a carbonate fuel cell configured to form a product stream. 2 The source may be operably coupled to a cathode of a carbonate fuel cell, the cathode consuming CO from a combustion stream. 2 and / or O from the source 2 As shown in the figure, this O 2 Source: CO 2 The natural gas source may be from a liquefaction process. The natural gas source may be operably coupled to an anode of a carbonate fuel cell, the anode receiving carbonate ions and natural gas to produce CO 2 A product stream is formed.

[0064] In some implementations, some CO 2 can be returned to the cathode as needed, and the remaining CO 210-13B. According to example implementations, the systems and / or methods of FIGS. 9A-9C may be used in combination with or in place of the PSA 80 of FIG. 7. As shown in FIG. 7, according to alternative embodiments, additional CO may be sent to liquefaction and / or storage, for example, from the liquefaction and / or storage portion of the system or method shown in FIG. 2 can be provided to the PSA 80 and / or one or more of the cells of FIGS. 9A-9C.

[0065] Referring now to FIG. 10A, in another series of components of the present disclosure, CO of purity >95% is produced in successive steps shown in heat exchanger 104, compressors 106 and 108 (the compressors are in operative association with cooling transfer fluid 90), and heat exchanger 110A. 2 (78) can be cooled and compressed to approach the phase change state for liquefaction. Implementations have shown that CO with purity >95% 2 The CO may have a temperature exiting the PSA as high as 100° C. As described, a heat exchanger may be provided to reduce the temperature of the gas to a sufficient temperature and then compress the gas to a higher pressure. 2 The heat removed from the stream can be returned through an external water / glycol cooling loop to the thermal management system, shown in FIG. 10A, to assist in pre-heating the make-up water. This can also be provided to increase the temperature of the nitrogen gas coming out of the PSA before it expands through the turbine. This can improve turbine efficiency by allowing full use of the nitrogen stream before it exceeds 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 make the overall system more efficient. As shown in FIG. 10A, CO2 can be added prior to heat exchanger 110A in accordance with the system and / or method of FIG. 10B. 2 can be transported and processed. The systems and / or methods of Figure 10A and / or Figure 10B can be operated separately, with only one of the systems and / or methods being in operation.

[0066] Referring to FIG. 10B, CO 2 FIG. 1 shows a portion of a system for separating CO 2 and N 2 The flue gas source may include a flue gas source 11 that is operatively coupled to the flue gas source to process the flue gas source, for example to remove water, and to generate a CO 2 N 2 Separated from CO 2 7 and 9A-C) for a separation component (see, for example, FIG. 7 and FIG. 9A-C) using a separation component configured to form (78). 2 and N 2 The liquefaction components of FIG. 10B (collectively 110B, 132, 134, and / or 136) can be operatively coupled to a separation component and can include a recuperative heat exchanger 110B. The heat exchanger 110B can receive the CO 2 separated from the separation component and can include a recuperative heat exchanger 110B. 2 Receives and separates CO 2 of heat generated by the liquefaction component and / or the storage component (collectively 180, 182, and / or 184) to CO 2 Steam (CO 2 (v)) by exchanging it with separated CO 2 The storage component may be operably coupled to a liquefaction component (e.g., heat exchanger 110B) and configured to reduce the temperature of the liquid CO from the liquefaction component (e.g., flash vessel 136). 2 and provides the same heat exchange fluid for the heat exchanger 110B. For example, cooling CO 2 (v) is the CO separated when thermally exposed in exchanger 110B. 2 Cooling the CO 2 (v) is the separated CO 2 It is substantially cooler than CO 2 (v) is cooled by expansion cooling from JT valve 186 and may contain non-condensable gases.

[0067] As shown, the storage component is 2 Storage vessel 180 and / or CO 2 The liquefaction component and / or the storage component may include a transport vehicle 200. One or both of the liquefaction component and / or the storage component may be operatively coupled to the recuperative heat exchanger 110B to generate the separated CO 2 CO generated during liquefaction and / or storage to cool the 2 At least a portion of the gas may be fed to recuperative heat exchanger 110B.

[0068] As shown, the liquefaction component can include a flash vessel 136 operably aligned between the liquefaction component (e.g., heat exchanger 110B or 132) and a storage component (e.g., storage vessel 180). A conduit can be extended to allow for the CO 2 (v) can be conveyed from the flash vessel 136 to the recuperative heat exchanger 110B. The flash vessel is configured to be operatively aligned to separate both the CO2(v) and non-condensable gases.

[0069] CO 2 The condensing heat exchanger 132 may be operatively positioned between the recuperative heat exchanger 110B and the flash vessel 136. 2 The condensing heat exchanger receives the CO from the recuperator. 2 Lower the temperature and CO 2 It may be configured to form a liquid.

[0070] The Joule-Thomson valve 134 transfers the liquid CO from the heat exchanger 132. 2 Receives liquid CO 2 The Joule-Thomson valve 134 may be operatively positioned to deliver CO generated during liquefaction to the flash vessel 136. 2 Receives liquid CO 2to the flash vessel 136. Valves 134 and / or 186 may be configured as throttling valves to provide cooling and pressure reduction of the CO2.

[0071] The storage component is CO 2 The transport vehicle 200 may also include a conduit configured to convey the steam to the recuperator 110B. 2 The transport vehicle 200 may be coupled to a conduit configured to carry the steam to the recuperative heat exchanger 110B. 2 The storage component 180 may be operatively associated with the storage component 180 via a pressure differential device (pump) 184 configured to supply liquid.

[0072] As shown, one or more conduits may extend between a portion of the liquefaction component and / or the storage component and the recuperative heat exchanger 110B of the liquefaction component. These one or more conduits may extend between a portion of the liquefaction component and / or the storage component and the recuperative heat exchanger 110B of the liquefaction component. 2 The Joule-Thomson valve 186 may be configured to convey the CO steam from one or more conduits to the recuperator 110B. 2 The steam is received and cooled by the recuperator 110B. 2 The steam supply may be operatively positioned to supply steam.

[0073] Additionally, the recuperative heat exchanger 110B is operatively connected via a conduit to transmit the heat exchanged CO from the recuperative heat exchanger to a separation component (e.g., FIG. 7 and / or FIG. 9A-C). 2 Steam can be provided.

[0074] The system of the present disclosure can be used to extract CO from a flue gas source. 2 The method for separating CO 2 and N 2 The method may include receiving a flue gas source stream including (e.g., according to FIG. 7 and / or FIG. 9A-C). 2 N 2Separated from the main CO 2 A flow of CO can be formed. 2 The stream is liquefied according to either FIG. 10A or FIG. 10B and CO 2 Liquids and CO 2 The method can form both CO2 and CO vapor during liquefaction, e.g., from one or more of the flash vessel, storage vessel, and / or vehicle. 2 The separated CO 2 By lowering the temperature of the gas, 2 Use at least a portion of the vapor to produce liquid CO 2 The method can include forming

[0075] Thus, the method comprises: 2 Flow and CO 2 Heat is exchanged between steam and CO 2 Cooling the stream and / or CO 2 Flow and CO 2 After exchanging heat with steam, the heat-exchanged CO is separated and / or removed non-condensables. 2 According to at least one implementation, the method may include providing a CO 2 (v) is fed to a PSA which removes at least a portion of the non-condensable gases as part of the separation process. 2 By returning steam (feedback) to the separator component (PSA), 2 The steam is substantially retained, thus reducing the overall CO 2 Recovery is improved.

[0076] According to Figure 11, a series of CO 2 The gas is cooled and compressed in stages toward its final state of 311 psig and 0°F, at which point a phase change occurs and CO 2 becomes liquid.

[0077] Referring now to FIG. 2 Gas 112 is sparged into a vessel 113, such as an insulated vessel.2 A system and / or method for liquefying and storing gas 112 is shown. An example of an insulated vessel can include, but is not limited to, a vacuum jacketed liquid storage tank. Within the vessel, gas 112 can be converted to liquid 114. According to an example implementation, gas 112 can be provided to a sparge assembly 118 where it is provided as sparge gas 120 and liquefied to liquid 114 upon sparging.

[0078] The vapor 116 at the top of the vessel 113 is managed by a refrigeration system 122 that cools the vapor 116 so that it condenses back into liquid 114 and flows back into the vessel 113. According to an example configuration, the system 122 converts the vapor CO 2 (116) enters the system 122 and liquid CO 2 The system 122 may be configured as a loop in fluid communication with the vessel 113, returning to the vessel 113 as (114). In at least one configuration, the system 122 is configured as a low temperature condenser with an evaporator.

[0079] According to an additional embodiment, the container 113 contains CO 2 The system may be configured with a controlled venting subsystem to facilitate removal of non-condensable gases while minimizing loss of CO. 2 The inlet gas to the liquefaction system contains high concentrations of CO 2 , preferably >95%. The remaining gases (such as nitrogen and oxygen) can be considered non-condensable gases in the liquefaction process. In addition, liquid CO 2 There remains a very small subset of impurity gases that are miscible with CO2. These impurities are filtered out according to commercial standards such as the international beverage guideline ISBT. 2 It must be accurately measured in order to qualify the product. Both the controlled venting subsystem and the purity analysis system can reveal non-condensable gases that may dissolve in the liquid.

[0080] Without pretreatment by the distillation column, non-condensable gases in the continuous feed to the liquefaction can build up in the vapor space 116 of the storage system. If not removed, these non-condensable gases will continue to increase the pressure in the vapor space of the storage tank, thereby dissolving some of the gas into the liquid and potentially contaminating the liquid. Additionally, excess pressure in the tank can cause problems for the gas supply system and the equipment that manages the vapor and CO2 emissions. 2 This can disrupt both the refrigeration system, which recondenses the CO2 and returns it to the tank as a liquid, and the venting system. 2 The tank vapor space can be managed in conjunction with a refrigeration unit to vent non-condensable gases and reduce pressure build-up while minimizing vapor loss. The tank's instrumentation (see, e.g., FIG. 11) can be configured to acquire data regarding vapor pressure, dissolved gases, vapor composition, gas flow, etc., and provide that data to a processor that can operate a solenoid valve on the vent line to effect controlled release of tank vapor within strict parameters.

[0081] In the event of a building power loss, for example, the superior insulation of the vacuum jacketed tanks allows for the storage of liquid CO 2 According to an implementation example, the building itself can be protected from fire (e.g., fire is a CO 2 CO to extinguish fires (related to electronic components requiring fire extinguishing methods) 2 A container 113 can be utilized for the supply of

[0082] Referring to Figures 1, 12, 13A, and 13B, in another implementation, the CO 2 CO that can include offtake management using one or more vehicles provided for removal and / or delivery needs 2 A removal and / or delivery system is provided. For example, CO 2 can be delivered via a transfer pump 202. 2 The liquid CO 2A removal and / or delivery truck 200 can be provided to transport the CO2 from the tank to the system 10. 2 Numerous parameters such as the date / time of the generation, pick-up window, and / or CO 2 CO based on delivery needs 2 It may be configured to generate a pick-up time. 2 Regarding the need for delivery, such high purity CO 2 It is contemplated that the product may be delivered directly to the user without being warehoused or requiring additional purification. The only example of a direct delivery would be delivery to a wastewater treatment facility. However, in either case, an off-take analysis may be provided to certify the product prior to shipment for which a Certificate of Analysis can be issued.

[0083] Referring now to Figure 12, the plant, process and field level components of the control system are shown. According to an example implementation, there are: Flare Vent and Control, MASTER PLC Controller, Diverter, Compression, Dryer, Separation, Cooling and Compression, Refrigeration / Storage, and Food Grade CO 2 Examples of overall control systems are provided that show the provision of. These systems also interface with the utility systems for electricity, natural gas, and water. These control systems illustrate the network architecture diagram. The MASTER PLC controls the entire plant using an Ethernet loop connection and Internet IP protocol communication to local packaged controllers, as well as through direct connection and control to digital and analog I / O field instrumentation levels. 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.

[0084] With reference to Figures 13A and 13B, an implementation of the system and / or method is disclosed that details a series of different components and processes described herein, as well as additional thermal management components associated with a building. As can be seen throughout the figures and accompanying description, there are multiple locations for heat to be transferred from various components of the disclosed system to existing building systems. For example, as shown, there may be a chiller in the building and an existing cooling tower. These active cooling components can be operatively coupled with heat removed from the process components via individual cooling loops. According to the implementation, heat, sometimes referred to as waste heat, can be transferred to building systems that can use the excess heat to operate more efficiently. Thus, with respect to waste heat from the disclosed system, the design preference is to transfer the waste heat first to the building's steam and hot water make-up system, second to the building's cooling tower, and finally to a suitable chiller with heat exchange with air.

[0085] As shown in FIG. 12 and FIG. 13A-B, the thermal management system (see, e.g., MASTER PLC, controller, etc.) conserves the use of fuels such as natural gas in the boiler by optimizing combustion with a combustion controller, controls the removal of water from the flue gas with a front-end controller, provides additional separation with a dryer and PSA (with a separation controller), and reduces CO2 emissions with a liquefaction / storage controller. 2 may be liquefied and stored and offtake directed by an offtake controller to pickup and / or delivery trucks. These and additional controllers may 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. Flue gases may be cooled accordingly for water knockout, as may heat generating electrical components such as compressors, blowers, pumps, and fans.

[0086] In addition, localized gas analysis instruments provide near real-time localized CO 2 and O 2 It can be configured to provide concentration measurements. By placing the gas sampling instrument / sensor directly at the sampling point within a subsystem, such as a PSA subsystem, a small sample gas stream can be pumped through a sensor cap just a few inches away from the process gas being measured. This innovation provides near instantaneous measurements from multiple devices simultaneously, with sampling rates of less than one second. 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 a common hardwire connection (Ethernet, RS232, RS485, etc.).

[0087] As mentioned above, liquid CO 2 To meet commercial requirements for transporting and marketing the removed liquid CO, off-take analysis can be provided that is integrated within the system. 2 of offtake weight is certified and within the required commercial standards 2 The offtake analytical system certifies product purity. The offtake analytical system measures product CO2 as it is transported outside the building or from an intermediate storage and treatment facility. 2 In addition, the offtake analysis system can be configured to document all information to formally account for all offtake transactions.

[0088] According to an example implementation, a set of electronic load cells can be placed under each storage tank to accurately measure the weight of the tank and its contents. The system can then perform a differential calculation to determine the amount of removed liquid CO2. 2 Prove the weight of.

[0089] According to another implementation, the analytical system may be configured to measure product impurities within strict specifications. Just before the product is transported, the analytical system extracts a small amount of liquid CO from the storage tank.2 It automatically collects a sample, vaporizes it, and then passes the sample gas through a state-of-the-art FTIR spectrometer or field-grade gas chromatograph system. The FTIR spectrometer uses liquid CO 2 The FTIR analytical system is equipped with sufficient procedures and chemical spectral libraries to identify and measure all the "impurities" indicated in the contractual purity specifications with customers for the beverage. Such specifications usually specify 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 achieving measurement fidelity several times higher than required by the ISBT guidelines. It is generally understood that FTIR systems cannot measure compounds that do not exhibit a molecular dipole. This is not the case for the impurities of interest, because all of the impurities exhibit a molecular dipole and have some degree of motion (observable frequency).

[0090] Additionally, in another embodiment, an FTIR system can also be connected to the "front end" to accurately measure impurities in the flue gas from the boiler system.

[0091] According to implementations, 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. As an example, energy can be generated by turbine expansion of nitrogen, and this energy can be transformed and stored within the building. The energy can be transformed and fed directly to a system component, such as a compressor, and / or stored and then fed to a system component, thus lowering the energy demand of the building. Additionally, the energy can be fed to a power grid associated with the building itself.

[0092] According to an example implementation, using the MASTER PLC, energy generated by the system can 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 alter carbon dioxide separation, liquefaction, storage, and / or transportation to reduce energy consumption during "peak demand" and thus save on energy costs.

[0093] Implementations of the disclosed systems and / or methods can provide not only a carbon capture system, but also a CO 2 The overall energy efficiency of a building (both thermal and electrical) can also be improved while reducing emissions. Example implementations can include reducing carbon fuel consumption through boiler firing optimization, providing higher temperature boiler feedwater to reduce the energy required to heat the boiler feedwater, warming potable or process water and therefore reducing the energy required to heat the potable or process water, generating electrical energy and using it for power system components, and / or using building cooling towers to reduce the building's heat load, etc., which individually and / or collectively can be part of a system that dramatically improves the efficiency of a building.

Claims

1. CO from flue gas source ２ 1. A system for separating At least CO ２ and N ２ a flue gas source comprising: operatively coupled to the flue gas source; ２ N ２ Separated from the CO ２ a separation component configured to form a liquefaction component operably coupled to the separation component and comprising a recuperative heat exchanger, the recuperative heat exchanger adapted to condense the separated CO from the separation component; ２ and receiving the separated CO ２ of heat from the CO generated by the liquefaction component and / or the storage component. ２ The separated CO is exchanged with steam. ２ wherein the storage component is operably coupled to the liquefaction component and configured to extract liquid CO from the liquefaction component. ２ a liquefaction component configured to receive the CO ２ Storage vessel and / or CO ２ a storage component including a transport vehicle; Equipped with One or both of the liquefaction component and / or the storage component are operatively coupled to the recuperative heat exchanger to absorb CO generated during liquefaction and / or storage. ２ At least a portion of the steam is supplied to the recuperative heat exchanger to remove the separated CO ２ Cooling the system.

2. The system of claim 1 , wherein the flue gas source comprises one or more of a fired boiler, a cogeneration unit, and / or an adsorption chiller.

3. The system of claim 1 , wherein the separation component comprises one or more of a pressure swing adsorption assembly, a membrane assembly, and / or an electrochemical cell.

4. The liquefaction component further includes a flash vessel operatively aligned between the liquefaction component and the storage component, the flash vessel configured to circulate CO ２ The system of claim 1 including a conduit configured to convey steam to the recuperative heat exchanger.

5. A CO 2 exchanger operably positioned between the recuperator and the flash vessel. ２ The CO ２ The condensing heat exchanger receives the CO ２ Lowering the gas temperature ２ The system of claim 4 configured to form a liquid.

6. The CO ２ The CO ２ Receive the liquid and ２ The system of claim 5 further comprising a Joule-Thompson valve operably positioned to supply liquid to the flash vessel.

7. CO produced during liquefaction ２ Receive liquid CO ２ 5. The system of claim 4, further comprising a Joule-Thompson valve operably positioned to supply the refrigerant to the flash vessel.

8. The storage component is ２ The system of claim 1 , further comprising a conduit configured to convey steam to the recuperative heat exchanger.

9. The transport vehicle ２ The system of claim 1 , further comprising a conduit configured to convey steam to the recuperative heat exchanger.

10. The transport vehicle is provided with pressurized CO ２ The system of claim 9 , operatively associated with the storage component via a pressure differential device configured to supply liquid.

11. and one or more conduits extending between a portion of the liquefaction component and / or a storage component and the recuperative heat exchanger of the liquefaction component, the one or more conduits being configured to ２ The system of claim 1 configured to convey steam to the recuperative heat exchanger.

12. CO from said one or more conduits. ２ The steam is received and the cooling CO ２ The system of claim 11 , further comprising a Joule-Thomson valve operably positioned to supply steam.

13. operatively associated with the recuperative heat exchanger via a conduit, and CO 2 exchanged from the recuperative heat exchanger to the separation component. ２ The system of claim 12 further comprising providing steam.

14. The system of claim 13 , wherein the separation component comprises one or more of a pressure swing adsorption assembly, a membrane assembly, and / or an electrochemical cell.

15. CO from flue gas source ２ 1. A method for separating CO ２ and N ２ receiving a source flue gas stream comprising: The CO ２ The N ２ Separated from the main CO ２ forming a flow; The CO ２ The stream is liquefied to produce CO ２ Liquid and CO ２ forming both a vapor and a gas; During liquefaction, at least a portion of the CO ２ Using steam, CO ２ forming a liquid; A method comprising:

16. The liquefying step comprises: ２ The CO ２ Heat is exchanged between the CO ２ The method of claim 15 comprising cooling the stream.

17. The CO ２ The CO ２ After exchanging heat with steam, the CO ２ The method of claim 16 further comprising providing steam.

18. The CO ２ The steam comprises a non-condensable gas, ２ 16. The method of claim 15, further comprising the step of supplying steam to a PSA assembly to remove at least a portion of the non-condensable gases.

19. The liquid CO ２ The method of claim 15 further comprising the step of storing and / or transporting the

20. Additional CO during storage and / or transportation ２ generating steam; ２ To form a liquid, the additional CO ２ The method of claim 19 , further comprising the step of: providing steam.

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