Integration of hydrophilic membranes with amines for enrichment of carbon dioxide

Abstract

The present disclosure provides systems and methods for enriching CO2 from industrial exhaust streams using synergistic combinations of hydrophilic membranes and amine separation modules. In some instances, the industrial exhaust stream is from a process that utilizes H2, where the amine is stripped with a feed stream to the H2 production process. In another aspect, systems and methods are provided for enriching CO2 from industrial processes streams using a secondary solvent to strip an amine absorbent.

Description

INTEGRATION OF HYDROPHILIC MEMBRANES WITH AMINES FORENRICHMENT OF CARBON DIOXIDECROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of priority to U.S. Provisional Application 63 / 676,151 filed on July 26, 2024, U.S. Provisional Application 63 / 676,232 filed on July 26, 2024, and U.S. Provisional Application 63 / 676,215 filed on July 26, 2024, the entirety of each of which is incorporated herein by reference.BACKGROUND

[0002] Meaningfully mitigating the climate crisis and limiting global temperature increase to 1.5°C requires expanding beyond electrification and renewables to incorporate deep industrial decarbonization. Whereas some sectors have begun their shift to a carbon neutral future, industrial decarbonization has yet to make meaningful progress. All pathways toward a carbon neutral 2050 goal require Carbon Capture, Utilization and Sequestration (CCUS) on a massive scale in the industrial sector. The linchpin in such an effort is developing and deploying high efficiency and scalable gas separations that can successfully address the dilute nature of CO2 emissions.SUMMARY

[0003] It is difficult to achieve both low-energy consumption and low-cost CO2 capture, especially for low concentration streams. The incumbent technology, amines, requires a large amount of thermal energy to regenerate the amine. Columns must also become very large to achieve high CO2 recovery due to the low partial pressure of CO2 in the near atmospheric flue gas. Oxygen (O2) also degrades the amine, leading to operational difficulties and higher operational expense.

[0004] Described herein are systems and methods that synergistically use hydrophilic membranes to preconcentrate the flue gas before feeding it to the amine system. This increases the partial pressure of CO2 so that higher recovery can be achieved with a smaller absorption column. The driving force for mass transfer of CO2 into the liquid phase is increased and one is processing a smaller overall stream with the amines system.

[0005] This can be achieved with high-flux membranes that do not require high pressure, keeping power consumption low. Also, the systems and methods described herein remove some of the O2, alleviating oxidative degradation of the amine.

[0006] In another aspect, described herein are systems and methods that synergistically use hydrophilic membranes with amine separation to capture CO2 produced in hydrogen production processes, such as steam methane reforming (SMR) or autothermal reforming (ATR). The hydrogen can be used in various industrial processes, including the production of ammonia.

[0007] The present systems and methods are surprisingly both low-cost to construct and consume a low amount of energy. This can be achieved by reducing the thermal energy required by the amine system through the use of CO2 stripping. The CCT-lcan solution can be stripped with natural gas before being fed to the SMR (or fired heater and / or boiler in ATR-only schemes). With the highly efficient membranes described herein, one can do post-combustion carbon capture on a more highly concentrated flue stream (thereby decreasing energy consumption and capex).

[0008] In yet more embodiments, to provide low energy carbon capture in amine absorption systems, a large amount of heat is required to regenerate the solvent. These amine solvents are typically aqueous, so a large amount of this energy goes into re-boiling water. Although there have been many advances in selecting new amines (and combinations of amines) to lower the energy demand at the reboiler, this is still quite energy intensive and requires heat at temperatures in excess of 100 °C. This heat is typically supplied by low-pressure steam, but the generation of this steam also emits carbon that should be captured.

[0009] As described herein, using a secondary solvent that has a low boiling point and is immiscible with water, the energy demand of the system is lowered and allows for more waste heat to be utilized. This can be done by boiling up a secondary solvent to strip the CCh-rich solution. The secondary solvent is recovered in subsequent compression and re-used.

[0010] In an aspect, provided herein is a method for enriching CO2. The method can comprise (a) providing a feed gas stream having a pressure less than about 6 bara and a composition comprising (i) CO2 at a concentration less than about 25 mol%, (ii) O2 at a concentration of at least 2 mol %, and (iii) water at a concentration of at least 3 mol%; (b) using a hydrophilic membrane module to separate the feed gas stream into a retentate stream and a permeate stream, wherein the permeate stream is enriched in CO2 and carries less O2 relative to the gas stream; (c) contacting the permeate stream with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCT-dcpIctcd stream; (d) using heat to desorb CO2 from the solvent, thereby creating a CCT-cnrichcd stream; and (e) recycling at least a portion of the CCT-dcpIctcd stream back to the hydrophilic membrane module.

[0011] In some embodiments, the hydrophilic membrane is part of a membrane separation module which has a plurality of hydrophilic membranes configured in at least two steps and / or at least two stages.

[0012] In some embodiments, the hydrophilic membrane comprises an ionomer.

[0013] In some embodiments, the hydrophilic membrane is fluorinated.

[0014] In some embodiments, the hydrophilic membrane is a facilitated transport membrane.

[0015] In some embodiments, the hydrophilic membrane is a hollow-fiber membrane, a plate and frame membrane, or a spiral- wound membrane.

[0016] In some embodiments, the hydrophilic membrane is humidified.

[0017] In some embodiments, the hydrophilic membrane retains at least 80% of its original permeance for CO2 after exposure to 500 ppm SOx, NOx, or H2S for 2,000 hours at 60 °C.

[0018] In some embodiments, the hydrophilic membrane has a permeance for CO2 of at least 450 GPU at a pressure of 4 bara, temperature of 60 °C, and stage cut of 10%.

[0019] In some embodiments, the amine is monoethanolamine (MEA) or diethanolamine (DEO).

[0020] In some embodiments, the method uses less than 4,000 MJ of energy per ton of CO2 enriched.

[0021] In some embodiments, the permeate stream comprises at least about 20 mol% CO2.

[0022] In some embodiments, the permeate stream comprises less than 70% of the O2 that was present in the feed gas stream.

[0023] In another aspect, provided herein is a system for enriching CO2, the system comprising: (a) a hydrophilic membrane module configured to separate the feed gas stream into a retentate stream and a permeate stream, wherein the permeate stream is enriched in CO2 and carries less O2 relative to the gas stream, wherein the feed gas stream has a pressure less than about 6 bara and a composition comprising (i) CO2 at a concentration less than about 25 mol%, (ii) O2 at a concentration of at least 2 mol %, and (iii) water at a concentration of at least 3 mol%; and (b) an amine separation module configured to contact the permeate stream with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CO2- depleted stream.

[0024] In some embodiments, the system further comprising a desorption module configured to use heat to desorb CO2 from the solvent, thereby creating a CCE-cnrichcd stream and recycle at least a portion of the CCE-depleted stream back to the hydrophilic membrane module.

[0025] In another aspect, provided herein is a method for capturing CO2 from a H2 production process, the method comprising: (a) in a H2 production process, producing a synthesis gas comprising H2 and CO2; (b) contacting the synthesis gas stream comprising CO2 with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, therebycreating a CCE-rich amine and a H2 stream; (c) contacting the CCh-rich amine with a stripping agent, thereby desorbing CO2 from the CCE-rich amine to create (i) a CCh-lcan amine and (ii) a leaving gas stream comprising the stripping agent enriched in CO2; (d) heating the CCh-lcan amine to further desorb CO2 and regenerate the solvent; (e) feeding the leaving gas stream to the H2 production process and produce a flue stream; and (f) using a hydrophilic membrane module to separate the flue stream into a permeate comprising CO2 and a retentate.

[0026] In some embodiments, the permeate is sequestered or utilized.

[0027] In some embodiments, the retentate is vented.

[0028] In some embodiments, the H2 stream is converted to ammonia.

[0029] In some embodiments, the H2 production process is a steam methane reformer (SMR) or an autothermal reformer (ATR).

[0030] In some embodiments, the stripping agent is fed back to the process from which the synthesis gas was produced.

[0031] In some embodiments, the stripping agent is a fuel stream.

[0032] In some embodiments, the stripping agent is natural gas.

[0033] In some embodiments, the stripping agent is fuel gas for a steam methane reformer.

[0034] In some embodiments, the hydrophilic membrane is part of a membrane separation module which has a plurality of hydrophilic membranes configured in at least two steps and / or at least two stages.

[0035] In some embodiments, the hydrophilic membrane comprises an ionomer.

[0036] In some embodiments, the hydrophilic membrane is fluorinated.

[0037] In some embodiments, the hydrophilic membrane is a facilitated transport membrane.

[0038] In some embodiments, the hydrophilic membrane is a hollow-fiber membrane, a plate and frame membrane, or a spiral- wound membrane.

[0039] In some embodiments, the hydrophilic membrane is humidified.

[0040] In some embodiments, the hydrophilic membrane module operates at a pressure less than about 6 bara.

[0041] In some embodiments, the hydrophilic membrane retains at least 80% of its original permeance for CO2 after exposure to 500 ppm SOx, NOx, or H2S for 2,000 hours at 60 °C.

[0042] In some embodiments, the hydrophilic membrane has a permeance for CO2 of at least 450 GPU at a pressure of 4 bara, temperature of 60 °C, and stage cut of 10%.

[0043] In some embodiments, the amine is monoethanolamine (MEA) or diethanolamine (DEA).

[0044] In another aspect, provided herein is a system for capturing CO2 from a H2 production process, the system comprising: (a) a H2 production process configured to produce a synthesis gas comprising H2 and CO2; (b) an absorption module configured to contact the synthesis gasstream comprising CO2 with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCE-rich amine and a H2 stream; (c) a stripping module configured to contact the CCh-rich amine with a stripping agent, thereby desorbing CO2 from the CCE-rich amine to create (i) a CCh-lcan amine and (ii) a leaving gas stream comprising the stripping agent enriched in CO2; (d) a regeneration module configured to heat the CCh-lcan amine to further desorb CO2 and regenerate the solvent and feed the leaving gas stream to the H2 production process and produce a flue stream; and (e) a hydrophilic membrane module configured to separate the flue stream into a permeate comprising CO2 and a retentate.

[0045] In another aspect, provided herein is a method for enriching CO2, the method comprising: (a) contacting a feed gas stream comprising CO2 with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCE-rich amine; (b) desorbing CO2 from the CCE-rich amine into a secondary solvent vapor, wherein the secondary solvent (i) has a boiling point lower than the boiling point of water and (ii) is substantially immiscible with water; (c) condensing the secondary solvent vapor to create a three-phase system comprising (i) an aqueous phase comprising a CCE-depleted amine, (ii) a non-aqueous phase comprising the condensed secondary solvent, and (iii) a vapor phase comprising CO2 and residual secondary solvent vapor; (d) recycling the aqueous phase to provide the solvent for contacting with the feed gas stream; (e) vaporizing the non-aqueous phase to provide the secondary solvent vapor; and (f) removing residual secondary solvent vapor from the vapor phase to provide enriched CO2.

[0046] In some embodiments, residual water is removed from the vapor phase.

[0047] In some embodiments, the secondary solvent is hexane.

[0048] In some embodiments, the solvent is aqueous.

[0049] In some embodiments, the secondary solvent vapor is condensed by cooling and / or compressing.

[0050] In some embodiments, the residual secondary solvent is removed from the vapor phase using a functionalized pervaporation membrane.

[0051] In some embodiments, the residual secondary solvent is removed from the vapor phase using a mixed matrix membrane.

[0052] In some embodiments, the residual secondary solvent is removed from the vapor phase using a MOF.

[0053] In some embodiments, the membrane is part of a membrane separation module which has a plurality of membranes configured in at least two steps and / or at least two stages.

[0054] In some embodiments, the amine is monoethanolamine (MEA) or diethanolamine (DEA).

[0055] In another aspect, provided herein is a system for enriching CO2, the system comprising: (a) an absorption module configured to contact a feed gas stream comprising CO2 with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCh-rich amine; (b) a regeneration module configured to desorb CO2 from the CO2- rich amine into a secondary solvent vapor, wherein the secondary solvent (i) has a boiling point lower than the boiling point of water and (ii) is substantially immiscible with water; and (c) a condenser configured to condense the secondary solvent vapor to create a three-phase system comprising (i) an aqueous phase comprising a CC -depleted amine, (ii) a non-aqueous phase comprising the condensed secondary solvent, and (iii) a vapor phase comprising CO2 and residual secondary solvent vapor.

[0056] In some embodiments, the system further comprising a processing module configured to recycle the aqueous phase to provide the solvent for contacting with the feed gas stream, vaporize the non-aqueous phase to provide the secondary solvent vapor, and remove residual secondary solvent vapor from the vapor phase to provide enriched CO2.

[0057] Additional aspects and advantages of the present disclosure will become readily apparent to those skilled in this art from the following detailed description, wherein only illustrative embodiments of the present disclosure are shown and described. As will be realized, the present disclosure is capable of other and different embodiments, and its several details are capable of modifications in various obvious respects, all without departing from the disclosure. Accordingly, the drawings and description are to be regarded as illustrative in nature, and not as restrictive.INCORPORATION BY REFERENCE

[0058] All publications, patents, and patent applications mentioned in this specification are herein incorporated by reference to the same extent as if each individual publication, patent, or patent application was specifically and individually indicated to be incorporated by reference. To the extent publications and patents or patent applications incorporated by reference contradict the disclosure contained in the specification, the specification is intended to supersede and / or take precedence over any such contradictory material.BRIEF DESCRIPTION OF THE DRAWINGS

[0059] The novel features of the invention are set forth with particularity in the appended claims. A better understanding of the features and advantages of the present invention will be obtained by reference to the following detailed description that sets forth illustrativeembodiments, in which the principles of the invention are utilized, and the accompanying drawings (also “Figure” and “FIG.” herein), of which:

[0060] FIG. 1 schematically illustrates an example of a system using hydrophilic membranes in combination with an amine separation module to enrich CO2, as described herein.

[0061] FIG. 2 schematically illustrates an example of a system using hydrophilic membranes in combination with an amine separation module to enrich CO2 from a process that utilizes H2, as described herein.

[0062] FIG. 3 schematically illustrates an example of a system using an amine separation module using a secondary solvent to enrich CO2, as described herein.DETAILED DESCRIPTION

[0063] The systems and methods described herein can be used for capture of CO2 from industrial sources.

[0064] Whenever the term “at least,” “greater than,” or “greater than or equal to” precedes the first numerical value in a series of two or more numerical values, the term “at least,” “greater than” or “greater than or equal to” may apply to each of the numerical values in that series of numerical values. For example, greater than or equal to 1, 2, or 3 may be equivalent to greater than or equal to 1, greater than or equal to 2, or greater than or equal to 3.

[0065] Whenever the term “no more than,” “less than,” or “less than or equal to” precedes the first numerical value in a series of two or more numerical values, the term “no more than,” “less than,” or “less than or equal to” may apply to each of the numerical values in that series of numerical values. For example, less than or equal to 3, 2, or 1 may be equivalent to less than or equal to 3, less than or equal to 2, or less than or equal to 1.

[0066] The term “at least one of A and B” and "at least one of A or B" may be understood to mean only A, only B, or both A and B. The term "A and / or B" may be understood to mean only A, only B, or both A and B.

[0067] The term “about” as used herein, generally refers to a quantity that is within twenty percent (20%) of the stated quantity.

[0068] Unless indicated otherwise, all percentages when used in the context of concentration are expressed as mole fractions (i.e., mol%).Amine Systems

[0069] Amines can be used to remove CO2 in various areas ranging from natural gas production, power generation, steel production, and cement production to name a few. There are multiple classifications of amines, each of which has different characteristics relevant toC02capture. For example, monoethanolamine (MEA) reacts strongly with acid gases like CO2 and has a fast reaction time and an ability to remove high percentages of CO2, even at the low CO2 concentrations. Typically, monoethanolamine (MEA) can capture 85% to 90% of the CO2 from the flue gas of a coal-fired plant, which is one of the most effective solvent to capture CO2.

[0070] However, amine systems suffer from several challenges for carbon capture including (a) low pressure gas increases the difficulty of transferring CO2 from the gas into amine; (b) oxygen content of the gas can cause amine degradation and acid formation; (c) CO2 degradation of primary (and secondary) amines; (d) high energy consumption; (e) very large facilities; and (f) finding a suitable location (enhanced oil recovery, deep saline aquifers, basaltic rocks...) to dispose of the removed CO2.

[0071] The partial pressure is the driving force to transfer CO2 into the liquid phase. Under low pressure, this transfer is hard to achieve without increasing the reboilers' heat duty, which will result in higher costs.

[0072] Primary and secondary amines, for example, MEA and DEA, can react with CO2 and form degradation products. O2 from the inlet gas can cause degradation as well. The degraded amine is no longer able to capture CO2, which decreases the overall carbon capture efficiency.

[0073] Currently, a variety of amine mixtures are being synthesized and tested to achieve a more desirable set of overall properties for use in CO2 capture systems. One major focus is on lowering the energy required for solvent regeneration, which has a major impact on process costs. However, there are trade-offs to consider. For example, the energy required for regeneration is typically related to the driving forces for achieving high capture capacities. Thus, reducing the regeneration energy can lower the driving force and thereby increase the amount of solvent and size of absorber needed to capture a given amount of CO2, thus, increasing the capital cost.

[0074] The systems and methods described herein can unexpectedly alleviate this trade-off between energy and capital. Integration with a hydrophilic membrane as described herein can help enable an amine solvent that has a lower binding affinity by reducing the large capital expenditure that using such an amine would otherwise require. The systems and methods described herein can reduce the overall system footprint.Integration of Hydrophilic Membranes with Amine Systems

[0075] The systems and methods described herein use a high-flux hydrophilic membrane to preconcentrate the CO2 in a flue gas before feeding it to an amines absorption system. This increases the partial pressure of the CO2 in the absorption column and decreases the total amountof gas processed by the amines system. Some of the CO2 depleted gas from the amine absorption column can be recycled back to the membranes to aid recovery. This can be practiced in large emission sources with low CO2 concentrations such as fossil fueled power plants or industrial boilers.

[0076] In an aspect, provided herein is a method for enriching CO2. Turning to FIG. 1, shown here is a schematic diagram of the systems and methods described herein.

[0077] The method can include providing a feed gas stream 100 to the membrane 102. This feed gas stream can be derived from any suitable CO2 source 104 (such as exhaust gas) and can be pre-processed, e.g., by compression 106. The feed gas stream 100 can have a pressure less than about 6 bar absolute (bara), less than about 5 bara, less than about 4 bara, less than about 3 bara, less than about 2 bara, or less than about 1.5 bara. The feed gas stream 100 can have a composition comprising CO2 at a concentration less than about 25 mol%, less than about 20 mol%, less than about 15 mol%, or less than about 10 mol%. The feed gas stream 100 can have a composition comprising CO2 at a concentration greater than about 25 mol%, greater than about 20 mol%, greater than about 15 mol%, or greater than about 10 mol%. The feed gas stream 100 can have a composition comprising O2 at a concentration of at least 2 mol %, at least 4 mol %, at least 6 mol %, or at least 10 mol %. The feed gas stream 100 can have a composition comprising water at a concentration of at least 3 mol%, at least 5 mol%, at least 7 mol%, at least 10 mol%, or at least 15 mol%.

[0078] The method can further comprise using a hydrophilic membrane module 102 to separate the feed gas stream into a retentate stream 108 and a permeate stream 110, wherein the permeate stream is enriched in CO2 and carries less O2 relative to the gas stream. The method can further include contacting the permeate stream 110 with a (amine) solvent 112, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CO2- depleted stream 114. Heat can be used to desorb CO2 from the solvent, thereby creating a CO2- enriched stream 116. The method can include recycling 118 at least a portion of the CO2- depleted stream back to the hydrophilic membrane module (e.g., by combining with the flue gas stream 104 upstream of the compressor 106).

[0079] In one example, the flue gas can have a CO2 concentration in the range of 4-12%. It is slightly compressed to 1.4 to 4 bara. Then, flue gas (as feed gas stream 100) is fed to the membrane module. The membrane is chemically selective toward CO2. The retentate can be depleted of CO2 and may be emitted. The permeate will be enriched in CO2 and is fed to the amine system. Rather than a single membrane stage as shown in FIG. 1, a multistage structure may be employed to achieve higher separation, including reducing the O2 content in the permeate to reduce oxidative degradation of the amine. The permeate may also be under vacuumto increase the driving force for mass transfer across the membrane. The amine system gives a CO2-enriched stream which can be post-treated (e.g., final clean-up of O2 and / or N2, compression, water removal, etc.). The stream depleted in CO2 may be vented to the atmosphere and may also be partially recycled to the membrane process to aid CO2 recovery.

[0080] Since both the membrane and amine portions of the system can use water, water removal can be performed downstream in the process, or a much smaller stream than on the flue gas.

[0081] Furthermore, the CCE-depleted stream may be used to cool the flue gas coming from the process which is being decarbonized before or after it has been compressed.

[0082] In some embodiments, the hydrophilic membrane is part of a membrane separation module which has a plurality of hydrophilic membranes configured in at least two steps and / or at least two stages.

[0083] In some embodiments, the hydrophilic membrane comprises an ionomer. In some embodiments, the hydrophilic membrane is fluorinated. In some instances, the hydrophilic membrane is a facilitated transport membrane. In some embodiments, the hydrophilic membrane is a hollow-fiber membrane, a plate and frame membrane, or a spiral-wound membrane. In some embodiments, the hydrophilic membrane is humidified.

[0084] In some embodiments, the hydrophilic membrane retains at least 80% of its original permeance for CO2 after exposure to 500 ppm SOx, NOx, or H2S for 2,000 hours at 60 °C. In some embodiments, the hydrophilic membrane has a permeance for CO2 of at least 450 GPU at a pressure of 4 bara, temperature of 60 °C, and stage cut of 10%.

[0085] In some instances, the amine is monoethanolamine (MEA) or diethanolamine (DEO). In some embodiments, the method uses less than 4,000 MJ of energy per ton of CO2 enriched. In some cases, the permeate stream comprises at least about 20 mol% CO2. In some embodiments, the permeate stream comprises less than 70% of the O2 that was present in the feed gas stream.Hydrogen and Ammonia Production

[0086] Steam methane reformers (SMRs) and auto-thermal reformers (ATRs) are used to make H2 (for various uses, but primarily for ammonia synthesis).

[0087] The main difference between SMR and ATR is that SMR only uses air for combustion as a heat source to create steam, while ATR uses purified oxygen. The advantage of an ATR is that the FhiCO ratio can be varied, which can be useful for producing specialty products. Due to the exothermic nature of some of the additional reactions occurring within ATR, the process can essentially be performed at a net enthalpy of zero (AH = 0).

[0088] SMRs will result in more flue CO2, while ATRs produce more process CO2. Capturing CO2 from the process is more energy- and capex-efficient than capturing it from flue gas. It is conceptually easy to shift reforming duties from SMRs (primary reforming) to autothermal reforming (secondary reforming), thus changing the ratio of CO2 emissions.

[0089] Ammonia plants typically require a CO2 removal step in the process, regardless of the process scheme (because ammonia synthesis cannot tolerate any oxygenated compound). Typically, the process CO2 is removed / captured with amine absorption, typically a MDEA. Although the very high pressure of the process stream makes absorption favorable, regeneration takes a large amount of thermal energy. Thermal energy production generally results in further hard-to-abate CO2 emissions (i.e., from natural gas boilers). The systems and methods described herein can provide a solution to this problem.Integration of Hydrophilic Membranes with Amine Systems

[0090] The systems and methods described herein use a high-flux hydrophilic membrane in combination with an amine system to capture CO2 from processes that generate / use H2 such as a SMR for ammonia production.

[0091] Here, a stripping column is fed by the CCh-rich amine solution and the fuel gas (or some other stream, called the stripping agent) that is fed to the process being decarbonized. As the stripping agent bubbles through the CCh-rich amine solution, CO2 is liberated from the liquid phase into the gas phase. This is done without requiring thermal energy. The leaving liquid stream now has less CO2, resulting in lower thermal energy consumption to regenerate the amine solution. The leaving gas stream has the stripping agent and CO2. This stream may be fed to a high-performance membrane system to remove the CO2. If it is a fuel stream, the resulting flue as gas will now have a higher CO2 concentration, making post-combustion with an efficient membrane system easier.

[0092] The stripping agent is something that is fed back to the process (e.g., natural gas). The membranes have high separation efficiency at low pressure, otherwise the energy consumption of the membrane system would outweigh the benefit of stripping the CCh-rich amine solution.

[0093] In an aspect, provided herein is a method for enriching CO2. Turning to FIG. 2, shown here is a schematic diagram of the systems and methods described herein. A hydrogen (H2) production process 200 can include a steam methane reformer (SMR), autothermal reformer (ATR), including fired heaters and / or boilers, which can take various feedstocks 202 which are simplified here to be a single stream, but can include natural gas, combustion air, enriched air, or O2, and water. The H2 production process produces synthesis gas 204 (syngas) at a high pressure (including H2, CO2, and / or CO). The syngas can be fed to an absorber 206 of an amine systemwhere C02 is absorbed. A stream 208 having amine absorbed with CO2 can be dropped near atmospheric pressure 210, heated with a heat exchanger 212, and sent to a stripper 214. In the stripper, the stripping gas 216 can be a natural gas fuel stream. As this stream is bubbled through the column at low pressure and high temperature, CO2 desorbs from the amine into the gas phase. The CCh-rich fuel gas stream 218 can be fed to the H2 production process 200.

[0094] Continuing with FIG. 2, with much of the CO2 desorbed, the amine solution 220 is then pumped to the regeneration column 222. The regeneration column operates as is typically in an amine absorption system but will require less thermal energy to drive the reboiler 224 due to the much of the CO2 already being liberated in the stripping column. The CCh-lcan solution 226 is then processed by pumping through a heat exchanger for energy recovery, and cooled, to produce a stream 228 that is capable of being fed back to the absorption column 206. The exhaust 230 from the absorption column is depleted in CO2 and rich in H2 and can be used for other purposes. In the case of ammonia production, the exhaust 230 would be fed to a demethanizer and subsequently used in the ammonia synthesis.

[0095] The resulting flue stream 232 from H2 production now has a higher CO2 concentration and is fed to the membrane separation module 234. The membrane separation module produces concentrated CO2236 and a CCh-depleted flue 238 that may be released to the atmosphere.

[0096] In summary, the stripping column unloads the reboiler, reducing the thermal energy requirement of the amine system. Because the CO2 is stripped with the fuel gas, the flue gas CO2 concentration is higher, enabling capital expense and energy savings for the membrane separation. Using a fuel stream to strip the amine is synergistic because the liberated CO2 winds up being captured by the post-combustion membrane system.Integration of Hydrophilic Membranes with Amine Systems

[0097] The systems and methods described herein use a secondary solvent that meets the following criteria: (a) it has a lower boiling point than water, (b) it is immiscible with water, (c) it is condensable near room temperature, and (d) there is a treatment that can remove it down to ~1% to ppm levels. One such solvent is hexane.

[0098] The process described herein differs from traditional amine absorption in that the aqueous amine solution is not re-boiled. Instead, vapor of the secondary solvent provides the gas flow at the bottom of the column. The gas stream coming out of the top of the column is compressed with inter / aftercooling and three-phase separation. The aqueous liquid phase is recycled and used for make-up. The organic liquid phase is boiled and fed back to the regeneration column.

[0099] With reference to FIG. 3, the flue gas 300 is first pre-treated 302. This pre-treatment can include cooling, slight compression by fans, and treatment for contaminants such as SOx and NOx. The flue gas is then fed to the absorption column 304 and contacted with the aqueous amine solution. The CO2 rich solution 306 is then fed to the regeneration column 308. The stream can be pumped and may be feed to a cross exchanger for heat recovery. In the regeneration column, the CO2 rich solution can be contacted with the secondary solvent vapor. This causes the CO2 to be stripped from the aqueous solution. The vapor phase 310 is then compressed, cooled, and phase separated. The aqueous phase 312 is recycled to the lean solution 314. The organic phase 316 is vaporized (using waste heat if possible) and fed to the regeneration column. The vapor phase 318 is fed to the drying unit 320 to remove water. The dry stream 322 is fed to a secondary solvent treatment module 324. The solvent treatment module can be a functionalized membrane, a pervaporation membrane, or a metal organic framework (MOF). The resulting CO2 stream 326 is fed to compression 328 (and potentially liquefaction for final purification). If this process has any purge streams, these may be used in the regeneration of either of the previous two units. The CO2 stream 330 may be sequestered or utilized. Note that liquid-liquid phase separation may be necessary on the lean solvent 306 to separate out any secondary solvent that condensed in the regeneration column.

[0100] The systems and methods described herein does not require a large amount of nonwater solvent make-up, which could be expensive or practically difficult. Also, we should be able to utilize more waste heat because of the low boiling point of the secondary solvent.

[0101] The systems and methods described herein can be used in a large-scale postcombustion carbon capture application. For instance, in power generation. The system could be driven by low grade heat, reducing its parasitic load relative to the traditional process design.Hydrophilic Membranes

[0102] The systems and methods described herein can use hydrophilic membranes. The membrane can be a thin-film composite membrane having more than one layer. The layers can include a gas- separation layer, a support layer, and / or a gutter layer and / or a protective layer. Suitable gutter layers are described in PCT Patent Application Serial No. PCT / US2022 / 036284 or PCT Patent Application Serial No. PCT / US2016 / 031135, each of which are hereby incorporated by reference. Protective layer materials are similar to gutter layer materials.

[0103] In some cases, the hydrophilic membranes are facilitated transport membranes. The membrane may incorporate a carrier agent to increase the solubility of certain components in the gaseous feed stream (e.g., CO2) through reversible reaction or complexation mechanisms and thereby preferably "facilitate" their transport through the membrane. The carrier agents may becovalently or electrostatically bound within the membrane to prevent their migration or loss from the membrane during use. Hydrophilic membranes that are fabricated from polymer materials that are ionomers are highly useful in the separations described herein. A carrier agent such as an amine group for selective reversible reaction with CO2 may be bound within the ionomer.

[0104] The ionomer can be fluorinated or hydrocarbon based. Ionomers can be used for the gas- separation layer of the thin-film composite membranes. As used herein, an ionomer is a copolymer that contains covalently-bound ionic -pendant groups such as sulfonic acid, sulfonate, carboxylic acid, carboxylate, phosphate, phosphonium, or ammonium. As used herein, the ionomer equivalent weight is the weight of ionomer containing one mole of sulfonate group. The ionomer equivalent weight (EW) can be less than 5000 grams per mole, less than 2000, or between 500 and 800-g / mole.

[0105] Ionomers that are copolymers containing sulfonic acid or sulfonate groups can be useful for fabrication of the gas-separation layer. Suitable ionomers and membranes include those described in U.S. Pat. No. 5,191,151; U.S. Patent No. 10,639,591; and U.S. Patent No. 10,029,248, each of which are hereby incorporated by reference. Suitable ionomers can comprise repeat units A and B in which A is a polymerized derivative of a fluorinated monomer and B comprises sulfonate groups. The ionomers can contain 50% or more carbon-fluorine groups to carbon-fluorine groups plus carbon-hydrogen groups. Some ionomers are perfluoropolymers in which there are no carbon-hydrogen groups in the polymer-backbone repeating units. Examples of the latter ionomers include copolymers comprising polymerized repeat units of tetrafluoroethylene and a perfluorovinyl ether monomer, having a pendant sulfonate group such as for example Nafion® (Chemours, Wilmington Del.), and Aquivion® (Solvay, Houston Tex.).

[0106] The gas-separation layer thickness can have a significant influence on the membrane cost and productivity of the separation process per unit area. The gas-separation layer can be thin (0.01-pm to 5-pm). The gas-separation layer thickness can be optimized such that both the CO2 permeance through the thin-film composite membrane and the CO2 selectivity over other gases is high.

[0107] The porous-layer support may be in the form of a flat sheet, hollow fiber, or tube. The porous-layer support reinforces the thin gas-separation layer and helps to further mechanically strengthen the thin-film composite as a whole such that the membrane may be fabricated into more complex geometries such as spiral-wound or hollow-fiber membrane modules. In case of flat sheet, the porous-layer support may also comprise an even stronger backing material such as porous non-woven polyester or polypropylene. Suitable porous-layer support materials include but are not limited to polyvinylidine fluoride, expanded polytetrafluoroethylene, polyacrylonitrile, polysulfone, polyether ether ketone (PEEK), and poly ether sulfone. Porousinorganic substrates such as porous silica or alumina are also suitable support materials. Permeate gases should flow relatively unobstructed through the usually much thicker porous- layer support having a porosity that is 40% or greater. The porous-layer support average pore size can be less 0.1-pm, or between 0.01 and 0.03-pm.

[0108] The gas-separation layer in the thin-film composite membrane is coplanar and in direct contact with the porous-layer support. The gas-separation layer may also be predominantly laminar. By “predominantly laminar” is meant that the surface or interfaces of two or more distinct layers have 50% or more of at least one layer material not interpenetrating the pores of another layer.

[0109] The gas-separation layer in the thin-film composite membrane may be subjected to a thermal treatment step “annealed” to further improve mechanical durability, long-term separation permeance and selectivity, and resistance to degradation from contact with liquid water. The ionomer in the gas-separation layer can be annealed by heating the thin-film composite membrane (e.g., in some cases to near or above the glass transition temperature of the ionomer). The exact glass transition temperature will be dependent on the ionomer composition and the associated counter ion. Generally, annealing temperatures are between 50 and 200° C.

[0110] The thin-film composite membrane can be highly useful for the separation of CO2 from flue gas. The membrane feed-side can be exposed to a flowing gaseous composition comprising CO2. A driving force can be provided in which the CO2 partial pressure on the membrane feed-side is higher than on the membrane permeate side. Separation of the CO2 in the gaseous composition occurs through the membrane producing a composition at the membrane permeate-side having a higher concentration of CO2 than the membrane feed-side. Separation may also be enhanced by having water vapor in the composition and / or by using a sweep gas on the membrane permeate- side, which functions to reduce the CO2 partial pressure in the permeate. For example, a sweep gas may comprise an inert gas such as water vapor or nitrogen.Membrane Modules

[0111] The systems and methods described herein can use hollow-fiber membranes and / or a spiral- wound flat sheet membranes.

[0112] The composite, thin-film hydrophilic membrane can be formed into a practical module. Here, the flue gas containing CO2 and N2 can flow along the membrane, CO2 selectively permeates through the membrane to produce a (CCh-rich) permeate and (N2-rich) retentate. Materials and methods are provided herein for forming the membrane separation modules.

[0113] The selective membrane coating is applied to the hollow fiber substrate by immersing the fiber in coating solution and withdrawing it at a specified constant rate. The polymer layer isallowed to dry and additional layers can be applied using the same method. The coated fiber can go through an annealing process at a higher than ambient temperature if needed.

[0114] Small hollow-fiber modules that contain straight fibers in either a plastic or stainless- steel shell. The mini modules can contain any suitably large number of fibers. The packing factor for mini modules is typically low (e.g., <20%) which can allow for gas or liquid bypass if using shell feed. Methods are available to reduce bypass in the shell side feed. One option is to incorporate a mandrel and a wrap which directs fluid flow on the shell side of the module. An alternate option is to have the fiber bundle tighter and filling the extra space around the bundle with epoxy. Using more expensive parts can make the tube that contains the fibers smaller than the tube that contains the epoxy.

[0115] The straight fiber mini-module manufacturing process involves inserting the fibers into the shell without damaging the outside coating. There are several ways to do this, including:(a) putting a semi-rigid rod through the shell, tying the fibers to the rod and pulling them through; (b) if the fibers themselves are rigid enough, they can be pushed through the shell; or (c) an injection molded shell that comes in two halves can allow placing the fibers into the shell prior to gluing them together.

[0116] Once the fibers are inside the shell, epoxy can be injected into the ends of the shell to fill the space between the fibers and shell (i.e., to create a separation between the lumen and shell sides of the fibers). There are several options for this module potting operation including: (a) (e.g., for smaller modules) a viscous epoxy can be injected directly into the end of the module;(b) (e.g., for medium sized modules) a section of silicone tubing can be added to the ends of the shell and filled with epoxy along with a portion of the shell; (c) (e.g., for larger sized modules) silicone tubing can be attached to the ends, but the fiber ends are sealed to prevent epoxy from entering the lumens. A syringe containing the epoxy can be connected to the silicone tubing and epoxy is forced up and around the fibers and into the shell. Slits can be cut into the silicone tubing to allow injection of epoxy into voids if they develop. Typically, one end of the module is potted at one time using this method.

[0117] Once the epoxy is cured (this could take up to 18 hours), depending on the type of epoxy, the excess epoxy can be removed and the fiber lumens can be opened. This can be accomplished by slicing the epoxy and fibers with a sharp blade. This process needs to be done in a way that produces fully open fibers.

[0118] The description below concerns the manufacturing of large-scale hollow fiber modules. This involves continuous hollow fiber coating, bundle winding, and cartridge potting.

[0119] A number of factors need to be taken into account during hollow fiber coating. To produce a continuous coating, methods must be developed to remove and prevent dust depositionon the fiber, static needs to be eliminated, temperature and humidity of the coating chamber must be controlled, large fiber pores must be bridged with either the use of a gutter layer coating or addition of a temporary pore filler such as water. The coating thickness is controlled by polymer solution concentration, solvent system, coating solution viscosity, and coating speed. To prevent damage to the coating, drying temperature and drying residence time need to be optimized along with developing a system for maintaining minimum fiber tension. As the process is scaled up multiple fiber management and solvent recovery methods need to be added.

[0120] Several factors can be optimized when winding fibers including: the number of fibers in a wind ribbon; fiber tension; wind angle; number of fiber cross overs in a layer; spacing between fibers; spacing between fiber ribbons. Permeation and humidification fibers can be wound together to produce a module that incorporates in-situ humidification. Multiple wraps can be added inside the fiber bundle to improve residence time and contact with the fiber.Further expansion of winding involves multiple spindle winding and automated bundle cutting.

[0121] Methods are provided herein for potting. The ratio of resin to hardener can be adjusted for reduction of viscosity and delay of cure and exotherm to allow for epoxy penetration into larger fiber bundles.

[0122] The cure schedule can be modified for exotherm control and epoxy penetration. For potting large modules, the potting molds can initially be warmed up to 35°C. As the epoxy fills the mold its viscosity decreases. This improves the penetration of epoxy into the fiber bundle. Then, the mold can be allowed to cool back down to 30°C, which slows the reaction rate of the two-part epoxy. Slowing down the reaction allows for more time for epoxy penetration. When the epoxy is hard (e.g., after several hours), the final two cure stages can be performed to achieve maximum chemical resistance.

[0123] Modification of the filling procedure can reduce bubble formation in the epoxy. This is opposed to having a procedure for removing bubbles from the epoxy. The ends of the fibers can be sealed using a five-minute epoxy. Furthermore, the space between the plug and fibers can be sealed. This effectively prevents large air bubbles from forming during the filling process. In general, one only fills from one location to prevent trapping bubbles.

[0124] Several methods for sealing fiber ends to prevent epoxy from filling the lumens can include heat sealing, looping, or fast cure / high viscosity epoxy sealing. In heat sealing, a hot knife is used to cut the wound bundle to a precise length. Not only does this perform the cutting operation but it also melts the fibers closed. This prevents epoxy from filling the lumens during the potting operation.

[0125] The looping method is another way to prevent epoxy from getting into the lumens during potting. Here, one does not cut the fiber bundle. If the bundle is wound to the preciselength and cutting is not needed, the fiber lumens are not open. The loops end up being a significant larger outer diameter than the bundle itself.

[0126] A number of factors can be optimized when coating hollow fiber lumens including: straight fiber module design; polymer concentration; solvent system; solution viscosity; solution injection method; solution removal method; pore filling; and drying method.

[0127] There are several options for minimizing pressure drops on the feed side and permeate side of the module. Modules can be designed to be “short and fat” (e.g., for permeate side (lumen) pressure drop control). The fibers can be arranged in a loom configuration to reduce feed side pressure drop and optimize water vapor injection. Module design can be improved with CFD (computational fluid dynamics) analysis to optimize mass transfer within the module.Membrane Separation Module

[0128] The membranes described herein can be formed into membrane separation modules. These modules can have one or more membrane cartridges arranged in a plurality of steps and / or stages.

[0129] A single membrane stage (and incidentally, a single step) can be used. Here, the membrane accepts a feed stream, which is separated into a retentate stream (comprising molecules that do not pass through the membrane) and a permeate stream (comprising molecules that pass through the membrane). Permeate streams are enriched in CO2, whereas retentate streams are depleted in CO2 (i.e., because CO2 contained in the feed stream selectively permeates through the membrane). The feed stream can be compressed in a compressor. In some cases, a portion of the retentate can be recycled and / or a portion of the permeate can be recycled.

[0130] The one stage system is the simplest from an operations standpoint. The CO2 purities and recoveries are a function of the membrane selectivity. For high recovery (e.g., greater than 90%) systems, concentration increases of 8-30% can be achieved. Such a system can be used in some CO2 utilization applications or as a bulk separation step before another process. Partially recycling the permeate stream enables higher purities and partially recycling the retentate stream enables higher recoveries.

[0131] In some cases, a two-stage membrane separation module. A membrane that enriches a permeate stream is referred to as a stage. Additional stages generally help achieve higher CO2 purities. In some cases, it is possible to achieve high purity with fewer stages, but this can require large recycling rates. Adding additional stages can be cost and / or energy optimal as they reduce the size of recycle streams.

[0132] Here, the permeate from the first stage becomes the feed for the second stage. The final CO2 product is more concentrated than it would be without the second stage. Here, the retentate from the second stage can be recycled and added to the feed to the first stage.

[0133] This structure is generally cost-optimal for moderate (20-25%) starting CO2 concentrations with high purity and recovery requirements (e.g., about 90%). It is also effective for moderately low starting CO2 concentrations (e.g., 12-16%) with high recovery requirements but low purity requirements (e.g., about 60%). The second stage enables the system to achieve higher CO2 concentrations than the selectivity-driven single stage limit and recycling the second stage retentate enables the system to achieve high recovery.

[0134] In some cases, a three-stage membrane separation module. Here, the permeate from the second stage becomes the feed stream for the third stage. The final CO2 product is more concentrated (i.e., compared to the permeate from the first stage or the second stage). Here, the retentate from the third stage can be recycled and added to the feed to the second stage and / or the first stage.

[0135] This structure is generally cost-optimal for low to moderately low (e.g., 4-12%) starting CO2 concentrations with high to very high purity and recovery requirements (e.g., 90- 95% or greater). The extra stages enable large CO2 concentration lifts and recycling their retentates enables high recovery. For large concentration lifts, this system can become more cost / energy efficient than the two-step two-stage system (described below) as the recycle rates of the latter can increase asymptotically.

[0136] A membrane that enriches a retentate stream is referred to as a step. Additional steps generally enable higher CO2 recovery rates by recovering more CO2 from streams that would otherwise be vented and recycling it back to the process. A two-step membrane separation module can be used. Here, the retentate from the first step becomes the feed stream for the second step. The permeate from the second step can be recycled back to the feed to the first step. More CO2 is recovered from the flue gas when using a two-step system rather than a single step (i.e., the vented gas is more deprived in CO2).

[0137] This system is generally preferred for high (e.g., greater than 30%) starting CO2 purities with moderate (e.g., about 60%) to high (e.g., about 90%) purity and recovery requirements. It can also be used for moderate (e.g., 20-24%) starting purities with low to moderate purity and recovery requirements. Due to only having one stage, it is not preferred for large concentration lifts. Its second step enables it to achieve higher recoveries than the one-stage system.

[0138] The numbers of steps and stages can be varied. For example, a two-step, two-stage membrane separation module can be used. Here, the permeate from the second step can be fedback to the first stage / step (and / or the second stage). The retentate from the second stage can be fed back to the first stage / step (and / or the second step).

[0139] This system is generally cost optimal for moderately low (e.g., 12-16%) starting CO2 concentrations with high purity and recovery requirements (e.g., 90%) and for moderate starting CO2 concentrations with very high purity and recovery requirements (e.g., greater than 95%). The extra stage enables the system to reach higher purities and the second step enables the system to achieve higher recoveries. It is not typically cost or energy optimal to recycle streams to membranes other than the feed stage, but it may prove useful.

[0140] A three-stage, two-step membrane separation module can be used. This design can be used with low (e.g., 4-8%) starting CO2 concentrations and very high (e.g., greater than 95%) purity and recovery requirements. The extra stages enable large concentration lifts with low recycle rates. The additional steps enables high CO2 recovery. It can also help reduce the stage cut demanded of the third stage.

[0141] Each design also includes the option to incorporate permeate vacuum. Like feed compression, permeate vacuum increases the pressure difference across the membrane. However, as the permeate stream is smaller than the feed stream, this will typically require less energy. Due to various tradeoffs, it may be cost and / or energy optimal incorporate permeate vacuum on some, or all membranes.Humidification

[0142] The hydrophilic membranes used herein can be humidified. The humidification can be provided by hydrating the permeate side of a housing that contains the membrane, as described in U.S. Patent Application No. 17 / 276,639, which is incorporated herein by reference. In some embodiments, the module combines continuous addition of water vapor to the reactor purge stream to form a humidified reactor purge stream and selective permeation of the CO2 using the membrane as described in U.S. Patent Application No. 17 / 772,247, which is incorporated herein by reference.

[0143] A suitable method for humidification of a membrane includes a method in which a hydration fluid comprising liquid water is brought within the permeate side of a pressure vessel that contains the membrane (permeate-side humidification). This is unlike humidification of a permeate-gas sweep in which a gas or gas composition that is different than the permeate gas is separately humidified and subsequently passed through the permeate side of the pressure vessel. Here, the hydration fluid comprising liquid water and the permeate-side interface of the membrane are in communication within the pressure vessel (i.e., liquid water or water vapor from the hydration fluid is contacting the permeate-side interface of the membrane). Themembrane may be in the form of a flat sheet, hollow fiber, or spiral-wound membrane module. The membrane can be non-porous and may also comprise other layers such as a high-diffusion rate (gutter) layer and a porous support in a composite membrane construction.

[0144] Permeate-side humidification at high operating feed-pressures can be less complex than traditional feed-gas humidification. That is, requirements for precise temperature control between a separate humidification unit-operation of a large feed-gas flow and the membrane may be minimized with use of the hydration-fluid comprising liquid water within the permeate-side of the pressure vessel. The hydration fluid may also be at an equivalent or slightly lower pressure than the permeate gas and may also function as a permeate sweep to reduce the permeate concentration at the permeate- side interface and enhance overall membrane selectivity. The permeate gases form bubbles within the hydration fluid that either move away from the permeate-side interface due to buoyancy or are swept away in a flowing or recirculating hydration-fluid system. The hydration fluid may be replenished as it diffuses into the membrane, evaporates, or moves away from the membrane with the permeate bubbles.

[0145] The systems and methods described herein can use a module for separation of a gaseous feed stream that combines concurrent humidification and selective permeation within the same unit of operation. The humidification and selective permeation module can comprise two sets of hollow fibers; humidification hollow fibers containing fluid comprising liquid water within their hollow cores, and hollow fibers that comprise a nonporous membrane. Continuous humidification of the feed stream within the module can be provided by the humidification hollow fibers while selective permeation of components in the feed stream occurs through the membrane of the hollow fibers. The humidity level in the gaseous feed stream can be maintained along the flow path of the feed stream and continuously replenished due to the humidification hollow fibers and hollow fibers that may be closely overlapping, aligned, intermingled, layered, or interlaced with each other. Furthermore, humidification within the selective-permeation module is less complex than traditional feed-gas humidification since requirements for precise temperature control of a gaseous feed stream between separate unit operations can be eliminated or reduced. The humidification hollow fibers can provide a more uniform hydration of the membrane of the hollow fibers and result in more consistent permeability and selectivity throughout the length of the module.

[0146] The humidification hollow fibers can be porous (e.g., microporous). The hollow fibers may be constructed of the same or different materials. The humidification hollow fibers contain fluid comprising liquid water in their lumen as the source of the humidification. The walls of the humidification hollow fibers permeate water vapor but also function as a barrier preventing liquid water from entering the flow path of the gaseous feed stream and contactingthe membrane, which may be detrimental to overall performance. The hollow fibers are also permeable and function as a porous support for a nonporous membrane in a composite construction. The composite construction may include additional layers such as a high-diffusion rate (gutter) layer which can help to reduce interfacial resistance between the hollow fibers and the non-porous membrane and help increase overall permeance and selectivity.

[0147] The humidification and selective permeation module as described herein may be used where humidification is desirable or required for better gas-separation efficiency using a membrane, especially when operating at higher stage cuts where a larger fraction of the feed stream permeates the membrane.Process Conditions

[0148] In an aspect, provided herein is a method for enriching CO2. The method includes providing a feed stream comprising CO2 and an impurity, wherein the impurity is O2, SOX, NOX, H2, H2S, or any combination thereof. The method can further include contacting the feed stream with a membrane to produce a permeate stream and a retentate stream, wherein the permeate stream comprises CO2 and the impurity. The method can further include treating the permeate stream to remove the impurity. The retentate stream can be vented to the atmosphere.

[0149] In another aspect, provided herein is a system for enriching CO2. The system can include a membrane separation module comprising a membrane, wherein the membrane separation module is configured to accept a feed stream and produce a permeate stream and a retentate stream, wherein the feed stream comprises CO2 and an impurity, wherein the impurity is O2, SOX, NOx, H2, H2S, or any combination thereof, and wherein the permeate stream comprises CO2 and the impurity. The system can further include a treatment module configured to treat the permeate stream to remove the impurity. In some cases, the system further includes a humidification module configured to humidify the membrane.

[0150] The membrane can be operated for any suitably long period of time before being replaced or serviced. In some cases, the membrane is operated for at least 3 months, at least 6 months, at least 1 year, at least 1.5 years, at least 2 years, at least 3 years, at least 4 years, at least 5 years, or at least 10 years.

[0151] The membrane separation module can produce any suitably large amount of permeate in a year. In some cases, a membrane separation module (e.g., as a multi-step or multi-stage configuration) can produce at least about 10,000 tons, at least about 50,000 tons, at least about 100,000 tons, at least about 500,000 tons, or at least about 1,000,000 tons of the permeate stream in 1 year.

[0152] The feed stream (e.g., flue gas) can have any suitable concentration of CO2. In some cases, the feed stream has between about 4 mol% and about 50 mol% CO2, or between about 0 mol% and about 15 mol% O2. In some cases, the feed stream has at least about 2 mol%, at least about 4 mol%, at least about 7 mol%, at least about 10 mol%, at least about 20 mol%, at least about 30 mol%, at least about 40 mol%, at least about 50 mol% CO2. In some cases, the feed stream has at most about 2 mol%, at most about 4 mol%, at most about 7 mol%, at most about 10 mol%, at most about 20 mol%, at most about 30 mol%, at most about 40 mol%, at most about 50 mol% CO2.

[0153] The feed stream can have any suitable amount of SOX. In some cases, the feed stream has about 10 ppm, about 50 ppm, about 100 ppm, about 500 ppm, about 1,000 ppm, about 5,000 ppm, about 10,000 ppm, or about 50,000 ppm SOX. In some cases, the feed stream has less than about 10 ppm, less than about 50 ppm, less than about 100 ppm, less than about 500 ppm, less than about 1,000 ppm, less than about 5,000 ppm, less than about 10,000 ppm, or less than about 50,000 ppm SOX. In some cases, the feed stream has more than about 10 ppm, more than about 50 ppm, more than about 100 ppm, more than about 500 ppm, more than about 1,000 ppm, more than about 5,000 ppm, more than about 10,000 ppm, or more than about 50,000 ppm SOX.

[0154] The feed stream can have any suitable amount of NOX. In some cases, the feed stream has about 10 ppm, about 50 ppm, about 100 ppm, about 500 ppm, about 1,000 ppm, about 5,000 ppm, about 10,000 ppm, or about 50,000 ppm NOX. In some cases, the feed stream has less than about 10 ppm, less than about 50 ppm, less than about 100 ppm, less than about 500 ppm, less than about 1,000 ppm, less than about 5,000 ppm, less than about 10,000 ppm, or less than about 50,000 ppm NOX. In some cases, the feed stream has more than about 10 ppm, more than about 50 ppm, more than about 100 ppm, more than about 500 ppm, more than about 1,000 ppm, more than about 5,000 ppm, more than about 10,000 ppm, or more than about 50,000 ppm NOX.

[0155] The feed stream (e.g., flue gas) can have any suitable amount of H2. In some cases, the feed stream has between about 0 mol% and about 5 mol% H2. In some cases, the feed stream has about 0 mol%, about 1 mol%, about 3 mol%, about 5 mol%, about 10 mol%, about 15 mol%, about 20 mol%, or about 30 mol% H2. In some cases, the feed stream has at least about 0 mol%, at least about 1 mol%, at least about 3 mol%, at least about 5 mol%, at least about 10 mol%, at least about 15 mol%, at least about 20 mol%, or at least about 30 mol% H2. In some cases, the feed stream has at most about 0 mol%, at most about 1 mol%, at most about 3 mol%, at most about 5 mol%, at most about 10 mol%, at most about 15 mol%, at most about 20 mol%, or at most about 30 mol% H2.

[0156] The feed stream can have any suitable amount of H2S. In some cases, the feed stream has about 10 ppm, about 50 ppm, about 100 ppm, about 500 ppm, about 1,000 ppm, about 5,000ppm, about 10,000 ppm, or about 50,000 ppm H2S. In some cases, the feed stream has less than about 10 ppm, less than about 50 ppm, less than about 100 ppm, less than about 500 ppm, less than about 1,000 ppm, less than about 5,000 ppm, less than about 10,000 ppm, or less than about 50,000 ppm H2S. In some cases, the feed stream has more than about 10 ppm, more than about 50 ppm, more than about 100 ppm, more than about 500 ppm, more than about 1,000 ppm, more than about 5,000 ppm, more than about 10,000 ppm, or more than about 50,000 ppm H2S.

[0157] The feed stream can be a combustion flue gas. The feed stream can be complex (e.g., having several impurities). The feed stream can comprise at least two, at least 3, at least 4, or all five of O2, SOX, NOx, H2, and H2S. The feed stream can further include N2.

[0158] The feed stream can have water vapor, and can be saturated with water vapor. The feed stream can have between about 0 mol% and about 20 mol% H2O. In some instances, the feed stream has about 0 mol%, about 1 mol%, about 3 mol%, about 5 mol%, about 10 mol%, about 15 mol%, about 20 mol%, about 25 mol%, about 30 mol%, or about 35 mol% H2O. In some cases, the feed stream has at least about 0 mol%, at least about 1 mol%, at least about 3 mol%, at least about 5 mol%, at least about 10 mol%, at least about 15 mol%, at least about 20 mol%, at least about 25 mol%, at least about 30 mol%, or at least about 35 mol% H2O. In some cases, the feed stream has at most about 0 mol%, at most about 1 mol%, at most about 3 mol%, at most about 5 mol%, at most about 10 mol%, at most about 15 mol%, at most about 20 mol%, at most about 25 mol%, at most about 30 mol%, or at most about 35 mol% H2O.

[0159] The feed stream can have any suitable temperature. In some instances, the feed stream has a temperature between about 80°C and about 300°C. In some instances, the feed stream has a temperature of about 20°C, about 30°C, about 40°C, about 60°C, about 80°C, about 100°C, about 120°C, about 140°C, about 160°C, about 180°C, about 200°C, about 250°C, about 300°C, about 350°C, or about 400°C. In some instances, the feed stream has a temperature of at least about 20°C, at least about 30°C, at least about 40°C, at least about 60°C, at least about 80°C, at least about 100°C, at least about 120°C, at least about 140°C, at least about 160°C, at least about 180°C, at least about 200°C, at least about 250°C, at least about 300°C, at least about 350°C, or at least about 400°C. In some cases, the feed stream has a temperature of at most about 20°C, at most about 30°C, at most about 40°C, at most about 60°C, at most about 80°C, at most about 100°C, at most about 120°C, at most about 140°C, at most about 160°C, at most about 180°C, at most about 200°C, at most about 250°C, at most about 300°C, at most about 350°C, or at most about 400°C.

[0160] The systems and methods described herein can further comprise pressurizing the feed stream and / or applying a vacuum pressure to the permeate stream (e.g., prior to contacting the feed stream with the membrane). The pressure difference across the membrane (e.g., feed streampressure and / or or vacuum pressure of permeate) can be about 2 pounds per square inch gauge (psi(g)), about 4 psig, about 6 psig, about 8 psig, about 10 psig, about 15 psig, about 20 psig, about 30 psig, about 40 psig, about 60 psig, about 80 psig, about 100 psig, about 120 psig, about 140 psig, or about 160 psig. The pressure difference across the membrane can be at least about 2 pounds per square inch gauge (psi(g)), at least about 4 psig, at least about 6 psig, at least about 8 psig, at least about 10 psig, at least about 15 psig, at least about 20 psig, at least about 30 psig, at least about 40 psig, at least about 60 psig, at least about 80 psig, at least about 100 psig, at least about 120 psig, at least about 140 psig, or at least about 160 psig. The pressure difference across the membrane can be at most about 2 pounds per square inch gauge (psi(g)), at most about 4 psig, at most about 6 psig, at most about 8 psig, at most about 10 psig, at most about 15 psig, at most about 20 psig, at most about 30 psig, at most about 40 psig, at most about 60 psig, at most about 80 psig, at most about 100 psig, at most about 120 psig, at most about 140 psig, or at most about 160 psig.

[0161] The systems and methods described herein can simplify the handling of impurities. In some cases, the impurity is not removed from the feed stream prior to contacting the feed stream with the membrane. In some instances, the water vapor is not removed from the feed stream prior to contacting the feed stream with the membrane. In some embodiments, particulates are not removed from the feed stream prior to contacting the feed stream with the membrane. The systems and methods can further comprise removing the impurity from the permeate stream to produce a CCT-rich stream. The SOXcan be removed using a lime scrubber. The SOXcan be removed using a spray dryer absorber, a circulating dry scrubber, or a dry sorbent injector. The O2 can be removed using catalytic oxidation or chemisorption. The NOXcan be removed using selective catalytic reduction (SCR) or non-catalytic reduction (NSCR). The H2 can be removed using separation or reaction. The H2S can be removed using separation or reaction. A carbon bed can be used to remove organic molecules.

[0162] An advantage of the systems and methods described herein is that the mass flow rate of the permeate stream is smaller than the mass flow rate of the feed stream. The mass flow rate of the permeate stream can be at least about 4-10 times less than a mass flow rate of the feed stream. In some cases, the mass flow rate of the permeate stream can be at least about 2 times, at least about 3 times, at least about 4 times, at least about 6 times, at least about 8 times, at least about 10 times, at least about 20 times, or at least about 50 times less than a mass flow rate of the feed stream.

[0163] The permeate stream can be utilized for the production of an end-product. The permeate stream can be sequestered.

[0164] The CO2-rich stream can have any suitably high concentration of CO2. In some embodiments, it comprises about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 85%, about 90%, about 95%, about 97%, about 99%, about 99.5%, or about 99.9% CO2. In some embodiments, it comprises at least about 20%, at least about 30%, at least about 40%, at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 85%, at least about 90%, at least about 95%, at least about 97%, at least about 99%, at least about 99.5%, or at least about 99.9% CO2.

[0165] The CO2-rich stream can have any suitably low concentration of one or more impurities. In some cases, the CC -rich stream has less than about 12 mol% O2, less than about 10 mol% O2, less than about 8 mol% O2, less than about 6 mol% O2, less than about 4 mol% O2, less than about 2 mol% O2, less than about 1 mol% O2, less than about 0.5 mol% O2, less than about 0.1 mol% O2, less than about 0.05 mol% O2, or less than about 0.001 mol% O2.

[0166] The CO2-rich stream can have any suitable amount of SOX. In some cases, the feed stream has about 10 ppm, about 50 ppm, about 100 ppm, about 500 ppm, about 1,000 ppm, about 5,000 ppm, about 10,000 ppm, or about 50,000 ppm SOX. In some cases, the CC -rich stream has less than about 10 ppm, less than about 50 ppm, less than about 100 ppm, less than about 500 ppm, less than about 1,000 ppm, less than about 5,000 ppm, less than about 10,000 ppm, or less than about 50,000 ppm SOX. In some cases, the CCT-rich stream has more than about 10 ppm, more than about 50 ppm, more than about 100 ppm, more than about 500 ppm, more than about 1,000 ppm, more than about 5,000 ppm, more than about 10,000 ppm, or more than about 50,000 ppm SOX.

[0167] The CO2-rich stream can have any suitable amount of NOX. In some cases, the CO2- rich stream has about 10 ppm, about 50 ppm, about 100 ppm, about 500 ppm, about 1,000 ppm, about 5,000 ppm, about 10,000 ppm, or about 50,000 ppm NOX. In some cases, the CC -rich stream has less than about 10 ppm, less than about 50 ppm, less than about 100 ppm, less than about 500 ppm, less than about 1,000 ppm, less than about 5,000 ppm, less than about 10,000 ppm, or less than about 50,000 ppm NOX. In some cases, the CCT-rich stream has more than about 10 ppm, more than about 50 ppm, more than about 100 ppm, more than about 500 ppm, more than about 1,000 ppm, more than about 5,000 ppm, more than about 10,000 ppm, or more than about 50,000 ppm NOX.

[0168] The CO2-rich stream can have any suitable amount of H2. In some cases, the CC -rich stream has between about 0 mol% and about 5 mol% H2. In some cases, the CCT-rich stream has about 0 mol%, about 1 mol%, about 3 mol%, about 5 mol%, about 10 mol%, about 15 mol%, about 20 mol%, or about 30 mol% H2. In some cases, the CC -rich stream has at least about 0 mol%, at least about 1 mol%, at least about 3 mol%, at least about 5 mol%, at least about 10mol%, at least about 15 mol%, at least about 20 mol%, or at least about 30 mol% H2. In some cases, the CCh-rich stream has at most about 0 mol%, at most about 1 mol%, at most about 3 mol%, at most about 5 mol%, at most about 10 mol%, at most about 15 mol%, at most about 20 mol%, or at most about 30 mol% H2.

[0169] The CO2-rich stream can have any suitable amount of H2S. In some cases, the CO2- rich stream has about 10 ppm, about 50 ppm, about 100 ppm, about 500 ppm, about 1,000 ppm, about 5,000 ppm, about 10,000 ppm, or about 50,000 ppm H2S. In some cases, the CCh-rich stream has less than about 10 ppm, less than about 50 ppm, less than about 100 ppm, less than about 500 ppm, less than about 1,000 ppm, less than about 5,000 ppm, less than about 10,000 ppm, or less than about 50,000 ppm H2S. In some cases, the CC -rich stream has more than about 10 ppm, more than about 50 ppm, more than about 100 ppm, more than about 500 ppm, more than about 1,000 ppm, more than about 5,000 ppm, more than about 10,000 ppm, or more than about 50,000 ppm H2S.

[0170] The performance of the hydrophilic membranes can be characterized in terms of permeance and selectivity. Permeance is the rate at which one component travels through a membrane surface area for a given driving force and is effectively a measure of separation processing volume. Increased permeance enables the processing of large streams with minimal surface area. This performance metric is typically expressed in GPU (gas permeation unit). The selectivity of one component to another is the ratio of the permeance of the two components and is a measure of separation quality. This tells you how much CO2 is passing through the membrane as compared to N2. Both metrics are a function of the membrane operating conditions and are only useful when measured at realistic field conditions (e.g., pressure, temperature, stage cut).

[0171] While preferred embodiments of the present invention have been shown and described herein, it will be obvious to those skilled in the art that such embodiments are provided by way of example only. It is not intended that the invention be limited by the specific examples provided within the specification. While the invention has been described with reference to the aforementioned specification, the descriptions and illustrations of the embodiments herein are not meant to be construed in a limiting sense. Numerous variations, changes, and substitutions will now occur to those skilled in the art without departing from the invention. Furthermore, it shall be understood that all aspects of the invention are not limited to the specific depictions, configurations or relative proportions set forth herein which depend upon a variety of conditions and variables. It should be understood that various alternatives to the embodiments of the invention described herein may be employed in practicing the invention. It is therefore contemplated that the invention shall also cover any such alternatives, modifications, variationsor equivalents. It is intended that the following claims define the scope of the invention and that methods and structures within the scope of these claims and their equivalents be covered thereby.

Claims

CLAIMSWHAT IS CLAIMED IS:

1. A method for enriching CO2, the method comprising: a. providing a feed gas stream having a pressure less than about 6 bara and a composition comprising (i) CO2 at a concentration less than about 25 mol%, (ii) O2 at a concentration of at least 2 mol %, and (iii) water at a concentration of at least 3 mol%; b. using a hydrophilic membrane module to separate the feed gas stream into a retentate stream and a permeate stream, wherein the permeate stream is enriched in CO2 and carries less O2 relative to the gas stream; c. contacting the permeate stream with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCL-depleted stream; d. using heat to desorb CO2 from the solvent, thereby creating a CO2- enriched stream; and e. recycling at least a portion of the CCL-depleted stream back to the hydrophilic membrane module.

2. The method of Claim 1, wherein the hydrophilic membrane is part of a membrane separation module which has a plurality of hydrophilic membranes configured in at least two steps and / or at least two stages.

3. The method of Claim 1, wherein the hydrophilic membrane comprises an ionomer.

4. The method of Claim 1, wherein the hydrophilic membrane is fluorinated.

5. The method of Claim 1, wherein the hydrophilic membrane is a facilitated transport membrane.

6. The method of Claim 1, wherein the hydrophilic membrane is a hollow-fiber membrane, a plate and frame membrane, or a spiral-wound membrane.

7. The method of Claim 1, wherein the hydrophilic membrane is humidified.

8. The method of Claim 1, wherein the hydrophilic membrane retains at least 80% of its original permeance for CO2 after exposure to 500 ppm SOx, NOx, or H2S for 2,000 hours at 60 °C.

9. The method of Claim 1, wherein the hydrophilic membrane has a permeance for CO2 of at least 450 GPU at a pressure of 4 bara, temperature of 60 °C, and stage cut of 10%.

10. The method of Claim 1, wherein the amine is monoethanolamine (MEA) or diethanolamine (DEO).

11. The method of Claim 1, wherein the method uses less than 4,000 MJ of energy per ton of CO2 enriched.

12. The method of Claim 1, wherein the permeate stream comprises at least about 20 mol% CO2.

13. The method of Claim 1, wherein the permeate stream comprises less than 70% of the O2 that was present in the feed gas stream.

14. A system for enriching CO2, the system comprising: a. a hydrophilic membrane module configured to separate the feed gas stream into a retentate stream and a permeate stream, wherein the permeate stream is enriched in CO2 and carries less O2 relative to the gas stream, wherein the feed gas stream has a pressure less than about 6 bara and a composition comprising (i) CO2 at a concentration less than about 25 mol%, (ii) O2 at a concentration of at least 2 mol %, and (iii) water at a concentration of at least 3 mol%; and b. an amine separation module configured to contact the permeate stream with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCE-depleted stream.

15. The system of Claim 14, further comprising a desorption module configured to use heat to desorb CO2 from the solvent, thereby creating a CCE-enriched stream and recycle at least a portion of the CCE-depleted stream back to the hydrophilic membrane module.

16. A method for capturing CO2 from a H2 production process, the method comprising: a. in a H2 production process, producing a synthesis gas comprising H2 and CO2; b. contacting the synthesis gas stream comprising CO2 with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCri-rich amine and a H2 stream; c. contacting the CCri-rich amine with a stripping agent, thereby desorbing CO2 from the CCri-rich amine to create (i) a CCri-lcan amine and (ii) a leaving gas stream comprising the stripping agent enriched in CO2; d. heating the CCri-lcan amine to further desorb CO2 and regenerate the solvent; e. feeding the leaving gas stream to the H2 production process and produce a flue stream; and f. using a hydrophilic membrane module to separate the flue stream into a permeate comprising CO2 and a retentate.

17. The method of Claim 16, wherein the permeate is sequestered or utilized.

18. The method of Claim 16, wherein the retentate is vented.

19. The method of Claim 16, wherein the H2 stream is converted to ammonia.

20. The method of Claim 16, wherein the H2 production process is a steam methane reformer (SMR) or an autothermal reformer (ATR).

21. The method of Claim 16, wherein the stripping agent is fed back to the process from which the synthesis gas was produced.

22. The method of Claim 16, wherein the stripping agent is a fuel stream.

23. The method of Claim 16, wherein the stripping agent is natural gas.

24. The method of Claim 16, wherein the stripping agent is fuel gas for a steam methane reformer.

25. The method of Claim 16, wherein the hydrophilic membrane is part of a membrane separation module which has a plurality of hydrophilic membranes configured in at least two steps and / or at least two stages.

26. The method of Claim 16, wherein the hydrophilic membrane comprises an ionomer.

27. The method of Claim 16, wherein the hydrophilic membrane is fluorinated.

28. The method of Claim 16, wherein the hydrophilic membrane is a facilitated transport membrane.

29. The method of Claim 16, wherein the hydrophilic membrane is a hollow-fiber membrane, a plate and frame membrane, or a spiral-wound membrane.

30. The method of Claim 16, wherein the hydrophilic membrane is humidified.

31. The method of Claim 16, wherein the hydrophilic membrane module operates at a pressure less than about 6 bara.

32. The method of Claim 16, wherein the hydrophilic membrane retains at least 80% of its original permeance for CO2 after exposure to 500 ppm SOx, NOx, or H2S for 2,000 hours at 60 °C.

33. The method of Claim 16, wherein the hydrophilic membrane has a permeance for CO2 of at least 450 GPU at a pressure of 4 bara, temperature of 60 °C, and stage cut of 10%.

34. The method of Claim 16, wherein the amine is monoethanolamine (MEA) or diethanolamine (DEA).

35. A system for capturing CO2 from a H2 production process, the system comprising: a. a H2 production process configured to produce a synthesis gas comprisingH2 and CO2;b. an absorption module configured to contact the synthesis gas stream comprising CO2 with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCh-rich amine and a H2 stream; c. a stripping module configured to contact the CCh-rich amine with a stripping agent, thereby desorbing CO2 from the CCh-rich amine to create (i) a CCh-lcan amine and (ii) a leaving gas stream comprising the stripping agent enriched in CO2; d. a regeneration module configured to heat the CCh-lcan amine to further desorb CO2 and regenerate the solvent and feed the leaving gas stream to the H2 production process and produce a flue stream; and e. a hydrophilic membrane module configured to separate the flue stream into a permeate comprising CO2 and a retentate.

36. A method for enriching CO2, the method comprising: a. contacting a feed gas stream comprising CO2 with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CO2- rich amine; b. desorbing CO2 from the CCh-rich amine into a secondary solvent vapor, wherein the secondary solvent (i) has a boiling point lower than the boiling point of water and (ii) is substantially immiscible with water; c. condensing the secondary solvent vapor to create a three-phase system comprising (i) an aqueous phase comprising a CC -depleted amine, (ii) a non-aqueous phase comprising the condensed secondary solvent, and (iii) a vapor phase comprising CO2 and residual secondary solvent vapor; d. recycling the aqueous phase to provide the solvent for contacting with the feed gas stream; e. vaporizing the non-aqueous phase to provide the secondary solvent vapor; and f. removing residual secondary solvent vapor from the vapor phase to provide enriched CO2.

37. The method of Claim 36, wherein residual water is removed from the vapor phase.

38. The method of Claim 36, wherein the secondary solvent is hexane.

39. The method of Claim 36, wherein the solvent is aqueous.

40. The method of Claim 36, wherein the secondary solvent vapor is condensed by cooling and / or compressing.

41. The method of Claim 36, wherein the residual secondary solvent is removed from the vapor phase using a functionalized pervaporation membrane.

42. The method of Claim 36, wherein the residual secondary solvent is removed from the vapor phase using a mixed matrix membrane.

43. The method of Claim 36, wherein the residual secondary solvent is removed from the vapor phase using a MOF.

44. The method of Claims 41-42, wherein the membrane is part of a membrane separation module which has a plurality of membranes configured in at least two steps and / or at least two stages.

45. The method of Claim 36, wherein the amine is monoethanolamine (MEA) or diethanolamine (DEA).

46. A system for enriching CO2, the system comprising: a. an absorption module configured to contact a feed gas stream comprising CO2 with a solvent, wherein the solvent comprises molecules having an amine group which absorb CO2, thereby creating a CCE-rich amine; b. a regeneration module configured to desorb CO2 from the CCh-rich amine into a secondary solvent vapor, wherein the secondary solvent (i) has a boiling point lower than the boiling point of water and (ii) is substantially immiscible with water; and c. a condenser configured to condense the secondary solvent vapor to create a three-phase system comprising (i) an aqueous phase comprising a CCE-depleted amine, (ii) a non-aqueous phase comprising the condensed secondary solvent, and (iii) a vapor phase comprising CO2 and residual secondary solvent vapor.

47. The system of Claim 46, further comprising a processing module configured to recycle the aqueous phase to provide the solvent for contacting with the feed gas stream,vaporize the non-aqueous phase to provide the secondary solvent vapor, and remove residual secondary solvent vapor from the vapor phase to provide enriched CO2.

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