Patent Publication Number: US-9901863-B2

Title: Process for the separation of carbon dioxide from flue gas

Description:
PRIORITY 
     This application is a divisional of co-pending U.S. patent application Ser. No. 12/930,207 filed Dec. 30, 2010, the contents of which are incorporated herein by reference. 
    
    
     BACKGROUND 
     1. Technical Field 
     The present invention generally relates to a process for separating CO 2  from flue gas using amine-functionalized ionic absorbents. 
     2. Description of the Related Art 
     One major source of carbon dioxide (CO 2 ) emission is the flue gas that is exhausted as a result of a large industrial combustion process, e.g., refinery heaters and boilers, steam generators, gas turbines, power plants, etc., in large energy consuming industries such as cement, iron and steel and chemical production and oil refining. Accordingly, it is desirable to develop a cost-effective process for separating CO 2  from flue gases for the purpose of CO 2  capture and sequestration (CCS). This approach is known as “post-combustion” CO 2  capture and is applicable to both retrofits and new builds. 
     Before CO 2  can be sequestered from a large industrial source, it must be captured in a relatively pure form. CO 2  is routinely separated and captured as a by-product of industrial processes such as synthetic ammonia production, hydrogen (H 2 ) production or limestone calcination. Existing CO 2  capture technologies, however, are not cost-effective when considered in the context of sequestering CO 2  from large point sources. Most large point sources use air-fired combustors, a process that exhausts CO 2  diluted with nitrogen. For efficient carbon sequestration, the CO 2  in these exhaust gases must be separated and concentrated. 
     Currently, the only commercially-proven method of post-combustion capture is through absorption of flue gas with aqueous amine solvents in a packed or trayed absorber column. CO 2  is recovered at high purity from the aqueous amine solvents by stream stripping in a packed or trayed regenerator column, and then cooled, dried, and compressed to supercritical pressures for pipeline transport and eventual geologic sequestration. There are many challenges associated with using aqueous amines in “post-combustion” mode. 
     One such solvent is 30 wt % monoethanolamine (MEA) in water. Solvent chemistry, corrosion, and viscosity considerations limit the amine strength to about 30 wt. % MEA. At flue-gas CO 2  partial pressures (e.g., 0.04 to 0.15 atm), the CO 2 -rich (“rich”) solvent loading is about 0.42 to 0.45 mol CO 2 /mol MEA and the CO 2 -lean (“lean”) solvent loading is about 0.15 to 0.17 mol CO 2 /mol MEA. The difference in loading (0.25 to 0.3 mol CO 2 /mol MEA) sets the circulation rate of the amine and influences capital and operating costs. 
     MEA also has disadvantages in that it has several mechanisms of loss, and a continuous makeup of MEA is required by post-combustion processes. For example, MEA degrades in the presence of oxygen from the flue gas. Thus, to limit the oxidative degradation, corrosion inhibitors may be used. MEA also degrades into heat-stable salts (HSS) from reaction with CO 2 . To solve this problem, a reclaimer would be added on the regenerator to separate the HSS from the amine solution to provide suitable makeup MEA. Lastly, the volatility of MEA results in the treated flue gas to contain in excess of 500 ppmv MEA when leaving the absorber to the vent. To address this, a wash section is added at the top of the absorber and makeup water is added to scrub the MEA from the treated flue gas. The mixture is then sent down the column along with the remaining lean solvent to absorb CO 2  from the incoming flue gas. Water washing can cut the MEA emissions to about 3 ppmv. 
     MEA may also degrade over time thermally, thereby limiting the temperature of operation in the absorber and regenerator. With a cooled flue gas inlet temperature of about 56° C., the absorber column may operate at a bottoms temperature of 54° C. and a pressure of 1.1 bar while the regenerator may operate at a bottoms temperature of 121° C. (2 bar saturated steam) at 1.9 bar. For 30 wt. % MEA, the amine reboiler steam temperature is kept at less than 150° C. (4.7 bar saturated steam) to limit thermal degradation. 
     MEA also degrades in the presence of high levels of NOx and SOx which are common in facilities that burn coal and fuel oil. However, if CO 2  removal from a high NOx and SOx containing flue gas is desired, separate process facilities such as SCR (Selective Catalytic Reduction) and FGD (Flue Gas Desulfurization) are needed for removal of NOx and SOx, respectively. In order to have a superior, post-combustion CO 2  removal technology that is better than those known in the art (30 wt. % MEA and similar aqueous amines), an improved CO 2 -removal solvent and process using the solvent is required. 
     Ionic Liquids (IL) are a class of compounds that are made up entirely of ions and are liquid at or below process temperatures. ILs are known in the art to have vanishingly low or negligible vapor pressure, and are often studied as candidates for environmentally-benign solvents, catalysts, and gas and liquid-phase separation agents. Many ILs known in the art behave as physical solvents, meaning that the loading capacity of CO 2  is linear with the equilibrium partial pressure of CO 2 . These ILs are unsuitable for flue-gas applications since the partial pressure of CO 2  is from about 0.04 to about 0.15 atm and are better suited for highly-concentrated CO 2  applications such as syngas. Other ILs appear more active for CO 2  at lower partial pressures and have non-linear loading curves, for example, bmim acetate as disclosed in U.S. Pat. No. 7,527,775. The anions of this type of ILs are able to interact favorably with CO 2  and thereby have higher loadings at low partial pressure. 
     More recently, researchers have developed task-specific IL (TSIL) and other forms of functionalized ILs that have chemical functional group designed to interact even more strongly and/or specifically with CO 2 . Although these amine-functionalized ILs are known to have a high capacity for CO 2 , they are also known to be far more viscous compared to non-functionalized ILs. However, a high viscosity is undesirable on a commercial scale, because it means that pumping costs are higher, mass transfer kinetics between gas and liquid are lower (resulting in taller columns and more packing material), and the efficiency of heat transfer is reduced (needed for eventual regeneration). 
     Accordingly, there is a continued need for improved systems and processes for removing CO 2  from flue gases that can be carried out in a simple, cost-effective manner. 
     SUMMARY 
     In accordance with one embodiment of the present invention, a process for separating carbon dioxide (CO 2 ) from a flue gas stream, the process comprising (a) contacting a flue gas stream containing water vapor and CO 2  with an ionic absorbent under absorption conditions to absorb at least a portion of the CO 2  from the flue gas stream and form a CO 2 -absorbent complex; wherein the ionic absorbent comprises a cation and an anion comprising an amine moiety; and (b) recovering a gaseous product having a reduced CO 2  content. 
     In accordance with a second embodiment of the present invention, a system is provided which comprises: 
     (a) a supply of a flue gas stream containing water vapor and CO 2 ; 
     (b) a supply of an ionic absorbent comprising a cation and an anion comprising an amine moiety; and 
     (c) an absorption unit for contacting the flue gas stream and the ionic absorbent under absorption conditions to absorb at least a portion of the CO 2  from the flue gas stream and form a CO 2 -absorbent complex and a gaseous product having a reduced CO 2  content. 
     The process of the present invention employs amine-functionalized ionic absorbent for post-combustion CO 2  capture from a flue gas stream. The process can be carried out without cooling the flue gas stream and at relatively low pressures. This is a significant advantage which allows for the process to be carried out in a simple, cost effective manner. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIGS. 1-4  shows generic synthetic schemes for preparing an ionic absorbent in accordance with the present invention. 
         FIG. 5  shows a process flow diagram scheme for the removal of CO 2  from a flue gas stream in accordance with one embodiment of the present invention. 
         FIG. 6  shows the CO 2  loading results at various temperature for amine-functionalized ionic absorbents in accordance with the present invention. 
         FIG. 7  shows the CO 2  loading results at various temperature for monoethanolamine in 70 wt. % water. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention is directed to a process for separating CO 2  from a flue gas stream. In one embodiment, the process involves (a) contacting a flue gas stream containing water vapor and CO 2  with an ionic absorbent under absorption conditions to absorb at least a portion of the CO 2  from the flue gas stream and form a CO 2 -absorbent complex; wherein the ionic absorbent comprises a cation and an anion comprising an amine moiety; and (b) recovering a gaseous product having a reduced CO 2  content. 
     The Flue Gas Stream 
     The flue gas stream for use in the process of the present invention may be any flue gas stream that is generated from a combustion apparatus such as a refinery plant, industrial power plant, etc. In one embodiment, the flue gas stream is from a stack that removes flue gas discharged from an industrial facility to the outside. Representative examples of such flue gas streams includes a gas turbine flue gas, a furnace flue gas, a hot oil furnace flue gas, a steam generator flue gas, a preheater flue gas, a reformer flue gas, steam methane reformer flue gas, FCC (fluid catalytic cracker) regenerator flue gas, CFB (circulating fluid bed boiler) and the like. The flue gas stream contains at least some amount of water vapor and CO 2 . In one embodiment, the flue gas stream contains fully saturated water. In another embodiment, the flue gas stream contains about 50% up to 100% humidity. In general, the amount of CO 2  present in the flue gas will depend from its source. For example, for a flue gas from a combined cycle gas turbine, the flue gas stream contains about 3.5 mol % CO 2 . Alternatively, for a flue gas from steel production or cement kilns, the flue gas stream contains about 30 mol % CO 2 . Accordingly, in one embodiment, the flue gas stream contains from about 3.5 mol % to about 30 mol % CO 2 . In another embodiment, the flue gas stream contains from about 4 mol % to about 15 mol % CO 2 . In another embodiment, the flue gas stream contains from about 10 mol % to about 15 mol % CO 2 . 
     In general, the flue gas stream is typically a hot flue gas stream, i.e., a flue gas stream having a temperature of at least about 80° C. (175° F.). In another embodiment, the flue gas stream has a temperature ranging from about 80° C. to about 150° C. (300° F.). While the temperature of the flue gas stream can always be higher, for practical reasons this is generally not the case unless the original combustion device (e.g., heater, boiler, etc.) was poorly designed and highly in-efficient. In addition, the flue gas stream can have a lower temperature in the case where a configuration that includes pre-cooling of the flue gas or input from a cooled gas sources such as wet FGD effluent is used. 
     The Ionic Absorbent 
     The ionic absorbent is generally composed of a cation and an anion. In one embodiment, the ionic absorbent is a liquid ionic absorbent and includes a category of compounds which are made up entirety of ions and are liquid at or below process temperatures including room temperature. The ionic liquids may have low melting points, for example, from −100° C. to 200° C. They tend to be liquid over a very wide temperature range, with a liquid range of up to about 500° C. or higher, ionic liquids are generally non-volatile, with effectively no vapor pressure. Many are air and water stable, and can be good solvents for a wide variety of inorganic, organic, and polymeric materials. In another embodiment, the ionic absorbent is a solid ionic absorbent and includes a category of compounds which are made up entirely of ions and are solid in an anhydrous state at room temperature. 
     The properties of the ionic absorbent can be tailored by varying the cation and anion pairing. The ionic absorbent for use in the system and process of the present invention includes a cation and an anion comprising an amine moiety. The amine moiety advantageously provides selectivity for the ionic absorbent to complex with CO 2 , especially at the low partial pressure of CO 2  typical in flue gas. The presence of this amine moiety on the anion rather than the cation of the ionic absorbent facilitates reaction of the ionic liquid with CO 2  at ratios of one mol of CO 2  per mol of ionic absorbent. 
     It is believed that the cation group of the ionic absorbent has little impact on the molar CO 2  absorption capacity. Accordingly, the molecular weight of the cation can be as low as possible thereby lowering the overall molecular weight of the ionic absorbent. In one embodiment, the molecular weight of the cation can range from about 18 to about 500 atomic mass unit (AMU) (g/mole). In another embodiment, the molecular weight of the cation can range from about 18 to about 400 atomic mass unit (AMU) (g/mole). 
     In one embodiment, a cation is a secondary, tertiary or quaternary phosphonium cation represented by the general formula: 
                         
wherein R is the same or different and is hydrogen, a substituted or unsubstituted alkyl group, a substituted or unsubstituted fluoroalkyl group, a substituted or unsubstituted cycloalkyl group, a substituted or unsubstituted aryl group, a substituted or unsubstituted heteroaryl group, a substituted or unsubstituted arylalkyl group, a substituted or unsubstituted heteroarylalkyl group, or —(CH 2 ) n —R′, wherein R′ represents independently for each occurrence a substituted or unsubstituted cycloalkyl group, a substituted or unsubstituted aryl group, or a substituted or unsubstituted heteroaryl group; and n represents independently for each occurrence an integer in the range 1 to 10 inclusive.
 
     In one embodiment, a cation is a secondary, tertiary or quaternary ammonium cation represented by the general formula: 
                         
wherein R is the same or different and is hydrogen, a substituted or unsubstituted alkyl group, a substituted or unsubstituted fluoroalkyl group, a substituted or unsubstituted cycloalkyl group, a substituted or unsubstituted aryl group, a substituted or unsubstituted heteroaryl group, a substituted or unsubstituted arylalkyl group, a substituted or unsubstituted heteroarylalkyl group, or —(CH 2 ) n —R′, wherein R′ represents independently for each occurrence a substituted or unsubstituted cycloalkyl group, a substituted or unsubstituted aryl group, or a substituted or unsubstituted heteroaryl group, or three R groups together with the nitrogen, atom to which they are bonded can be taken together to represent pyridinium, imidazolium, benzimidazolium, pyrazolium, benzpyrazolium, indazolium, thiazolium, benzithiazolium, oxazolium, benzoxazolium, isoxazolium, isothiazolium, imdazolidenium, guanidinium, quinuclidinium, triazolium, tetrazolium, quinolinium, isoquinolinium, piperidinium, pyrrolidinium, morpholinium, pyridazinium, pyrazinium, piperazinium, triazinium, azepinium, or diazepinium; and n represents independently for each occurrence an integer in the range 1 to 10 inclusive.
 
     In one embodiment, the cation is a Group 1 or Group 2 metal of the Periodic Table. Representative examples of Group 1 metals include lithium, sodium, potassium, rubidium, cesium and the like. Representative examples of Group 2 metals include calcium, barium, magnesium, or strontium and the like. 
     In one embodiment, a cation includes, but is not limited to, a Group 1 or Group 2 metal of the Periodic Table, an ammonium cation, phosphonium cation, an imidazolium cation, a pyridinium cation, a pyrazolium cation, an oxazolium cation, a pyrrolidinium cation, a piperidinium cation, an alkyl thiazolium cation, an alkyl guanidinium cation, a morpholinium cation, a trialkylsulfonium cation, a triazolium cation, and the like. 
     In one embodiment, a cation is a trialkyl or a tetraalkyl ammonium cation or phosphonium cation in which the alkyl group of the trialkyl or tetraalkyl is the same or different and is a C 1  to C 30  straight or branched, substituted or unsubstituted alkyl group. In another embodiment, a cation is a tetraalkyl ammonium cation or a tetraalkyl phosphonium cation in which the alkyl group of the tetraalkyl is the same or different and is a C 1  to C 6  straight or branched, substituted or unsubstituted alkyl group. The cation may contain ring structures where the N or P atom is a part of the ring structure. 
     Suitable anions for the ionic absorbent include those represented by the general formula:
 
R 1 —N(R 1 )-(L)-A − 
 
wherein R 1  is the same or different and includes hydrogen, a straight or branched C 1  to C 30  substituted, or unsubstituted alkyl group, a C 1  to C 20  ester-containing group, a substituted, or unsubstituted C 3  to C 30  cycloalkyl group, a substituted or unsubstituted C 3  to C 30  cycloalkylalkyl group, a substituted or unsubstituted C 3  to C 30  cycloalkenyl group, a substituted or unsubstituted C 5  to C 30  aryl group, a substituted or unsubstituted C 5  to C 30  arylalkyl group, a substituted or unsubstituted C 5  to C 30  heteroaryl group, a substituted or unsubstituted C 3  to C 30  heterocyclic ring, a substituted or unsubstituted C 4  to C 30  heterocyclolalkyl group, a substituted or unsubstituted C 5  to C 30  heteroarylalkyl group, or R and R 1  together with the nitrogen atom to which they are bonded are joined together to form a heterocyclic group; L is a linking group, which can be a bond, or a divalent group selected from the group consisting of a straight or branched C 1  to C 30  substituted or unsubstituted alkyl group, a C 1  to C 20  ester-containing group, a substituted or unsubstituted C 3  to C 30  cycloalkyl group, a substituted or unsubstituted C 3  to C 30  cycloalkylalkyl group, a substituted or unsubstituted C 3  to C 30  cycloalkenyl group, a substituted or unsubstituted C 5  to C 30  aryl group, a substituted or unsubstituted C 5  to C 30  arylalkyl group, a substituted or unsubstituted C 5  to C 30  heteroaryl group, a substituted or unsubstituted C 3  to C 30  heterocyclic ring, a substituted or unsubstituted C 4  to C 30  heterocyclolalkyl group, a substituted or unsubstituted C 6  to C 30  heteroaryl alkyl group and the like; and A −  is an anionic moiety.
 
     In one embodiment, A −  is SO 3   −  or PO 4   −  or a conjugate base of multivalent acid. 
     In one embodiment, R 1  are the same or different and include hydrogen, or a straight or branched C 1  to C 6  substituted or unsubstituted alkyl group, L is a divalent straight or branched C 1  to C 6  substituted or unsubstituted alkyl group and A −  is SO 3   − . 
     Representative examples of alkyl groups for use herein include, by way of example, a straight or branched alkyl chain containing carbon and hydrogen atoms of from 1 to about 30 carbon atoms and preferably from 1 to about 6 carbon atoms with or without unsaturation, to the rest of the molecule, e.g., methyl, ethyl, n-propyl, 1-methylethyl (isopropyl), n-butyl, n-pentyl, etc. and the like. 
     Representative examples of fluoroalkyl groups for use herein include, by way of example, a straight or branched alkyl group as defined herein having one or more fluorine atoms attached to the carbon atom, e.g., —CF 3 , —CF 2 CF 3 , —CH 2 C 3 , —CH 2 CF 2 H, —CF 2 H and the like. 
     Representative examples of substituted or unsubstituted cycloalkyl groups for use herein include, by way of example, a substituted or unsubstituted non-aromatic mono or multicyclic ring system of about 3 to about 20 carbon atoms such as, for example, cyclopropyl, cyclobutyl, cyclopentyl, cyclohexyl, bridged cyclic groups or sprirobicyclic groups, e.g., spiro-(4,4)-non-2-yl and the like, optionally containing one or more heteroatoms, e.g., O and N, and the like. 
     Representative examples of substituted or unsubstituted cycloalkylalkyl groups for use herein include, by way of example, a substituted or unsubstituted cyclic ring-containing group containing from about 3 to about 20 carbon atoms directly attached to the alkyl group which are then attached to the main structure of the monomer at any carbon from the alkyl group that results in the creation of a stable structure such as, for example, cyclopropylmethyl, cyclobutylethyl, cyclopentylethyl and the like, wherein the cyclic ring can optionally contain one or more heteroatoms, e.g., O and N, and the like. 
     Representative examples of substituted or unsubstituted cycloalkenyl groups for use herein include, by way of example, a substituted or unsubstituted cyclic ring-containing group containing from about 3 to about 20 carbon atoms with at least one carbon-carbon double bond such as, for example, cyclopropenyl, cyclobutenyl, cyclopentenyl and the like, wherein the cyclic ring can optionally contain one or more heteroatoms, e.g., O and N, and the like. 
     Representative examples of substituted or unsubstituted aryl groups for use herein include, by way of example, a substituted or unsubstituted monoaromatic or polyaromatic group containing from about 5 to about 20 carbon atoms such as, for example, phenyl naphthyl, tetrahydronapthyl, indenyl, biphenyl and the like, optionally containing one or more heteroatoms, e.g., O and N, and the like. 
     Representative examples of substituted or unsubstituted arylalkyl groups for use herein include, by way of example, a substituted or unsubstituted aryl group as defined herein directly bonded to an alkyl group as defined herein, e.g., —CH 2 C 6 H 5 , —C 2 H 5 C 6 H 5  and the like, wherein the aryl group can optionally contain one or more heteroatoms, e.g., O and N, and the like. 
     Representative examples of fluoroaryl groups for use herein include, by way of example, an aryl group as defined herein having one or more fluorine atoms attached to the aryl group. 
     Representative examples of ester groups for use herein include, by way of example, a carboxylic acid ester having one to 20 carbon atoms and the like. 
     Representative examples of heterocyclic ring groups for use herein include, by way of example, a substituted or unsubstituted stable 3 to about 30 membered ring group, containing carbon atoms and from one to five heteroatoms, e.g., nitrogen, phosphorus, oxygen, sulfur and mixtures thereof. Suitable heterocyclic ring groups for use herein may be a monocyclic, bicyclic or tricyclic ring system, which may include fused, bridged or spiro ring systems, and the nitrogen, phosphorus, carbon, oxygen or sulfur atoms in the heterocyclic ring group may be optionally oxidized to various oxidation states. In addition, the nitrogen atom may be optionally quaternized; and the ring radical may be partially or fully saturated (i.e., heteroaromatic or heteroaryl aromatic). Examples of such heterocyclic ring functional groups include, but are not limited to, azetidinyl, acridinyl, benzodioxolyl, benzodioxanyl, benzofurnyl, carbazolyl, cinnolinyl, dioxolanyl, indolizinyl, naphthyridinyl, perhydroazepinyl, phenazinyl, phenothiazinyl, phenoxazinyl, phthalazinyl, pyridyl, pteridinyl, purinyl, quinazolinyl, quinoxalinyl, quinolinyl, isoquinolinyl, tetrazoyl, imidazolyl, tetrahydroquinolinyl, tetrahydroisoquinolinyl, piperidinyl, piperazinyl, 2-oxopiperazinyl, 2-oxopiperidinyl, 2-oxopyrrolidinyl, 2-oxoazepinyl, azepinyl, pyrrolyl, 4-piperidonyl, pyrrolidinyl, pyrazinyl, pyrimidinyl, pyridazinyl, oxazolyl, oxazolinyl, oxazolidinyl, triazolyl, indanyl, isoxazolyl, iso-oxazolidinyl, morpholinyl, thiazolyl, thiazolinyl, thiazolidinyl, isothiazolyl, quinuclidinyl, isothiazolidinyl, indolyl, isoindolyl, indolinyl, isoindolinyl, octahydroindotyl, octahydroisoindolyl, quinolyl, isoquinolyl, decahydroisoquinolyl benzimidazolyl, thiadiazolyl, benzopyranyl, benzothiazolyl, benzooxazolyl, furyl, tetrahydrofurtyl, tetrahydropyranyl, thienyl, benzothienyl, thiamorpholinyl, thiamorpholinyl sulfoxide, thiamorpholinyl sulfone, dioxaphospholanyl, oxadiazolyl, chromanyl, isochromanyl and the like and mixtures thereof. 
     Representative examples of heterocycloalkyl groups for use herein include, by way of example, a substituted or unsubstituted heterocyclic ring group as defined herein directly bonded to an alkyl group as defined herein. The heterocycloalkyl moiety may be attached to the main structure at carbon atom in the alkyl group that results in the creation of a stable structure. 
     Representative examples of heteroaryl groups for use herein include, by way of example, a substituted or unsubstituted heterocyclic ring group as defined herein. The heteroaryl ring radical may be attached to the main structure at any heteroatom or carbon atom that results in the creation of a stable structure. 
     Representative examples of heteroarylalkyl groups for use herein include, by way of example, a substituted or unsubstituted heteroaryl ring group as defined herein directly bonded to an alkyl group as defined herein. The heteroarylalkyl moiety may be attached to the main structure at any carbon atom from the alkyl group that results in the creation of a stable structure. 
     It will be understood that the term “substituted with” includes the implicit proviso that such substitution is in accordance with permitted valence of the substituted atom and the substituent, and that the substitution results in a stable compound, e.g., which does not spontaneously undergo transformation such as by rearrangement, cyclization, elimination, or other reaction. Representative examples of such substituents include, but are not limited to, hydrogen, fluorine, hydroxyl groups, halogen group, carboxyl groups, cyano groups, nitro groups, oxo (═O), thio(═S), substituted or unsubstituted alkyl, substituted or unsubstituted fluoroalkyl substituted or unsubstituted alkoxy, substituted or unsubstituted alkenyl, substituted or unsubstituted alkynyl, substituted or unsubstituted aryl, substituted or unsubstituted arylalkyl, substituted or unsubstituted cycloalkyl, substituted or unsubstituted cycloalkenyl, substituted or unsubstituted amino, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted heterocycloalkyl ring, substituted or unsubstituted heteroarylalkyl, substituted or unsubstituted heterocyclic ring, and the like. 
     Representative examples of ionic absorbents for use in the aqueous ionic absorbent solutions of the present invention includes tetrabutylammonium N-propyl-N-(3-sulfopropyl)amine, tetrabutylphosphonium N-isopropyl-N-(3-sulfopropyl)amine, tetraethylammonium N-isopropyl-N-(3-sulfopropyl)amine and the like and mixtures thereof. 
     The ionic absorbents for use in the process of the present invention are known and can be prepared by methods known in the art, e.g., as disclosed in U.S. Pat. Nos. 7,208,605 and 7,744,838 and WO 2008/122030, the contents of which are incorporated by reference herein. For example, in one embodiment, the ionic absorbents can be prepared in accordance with the synthetic schemes generally represented in  FIGS. 1 and 2  (reactions with primary amines, secondary amines or diamines) via a zwitterionic intermediate. In one embodiment, the ionic absorbents can be prepared in accordance with the synthetic scheme generally represented in  FIG. 3  in which the zwitterionic intermediate can be reacted with an epoxide. In one embodiment, the ionic absorbents can be prepared in accordance with, the synthetic scheme generally represented in  FIG. 4 . 
     While the above examples have shown the reaction of the zwitterionic intermediates with ammonium hydroxide salts, as the base, one may also use other cations as described above, e.g., a phosphonium cation, a heterocyclic (e.g., imidazolium or pyridinium) cation, alkali metal cation or an alkaline earth metal cation as the counterion. In certain embodiments, the cations can be metal cations, such as Na, K, Ca, Ba, etc. 
     While the selected synthetic routes described above have all suggested reacting hydroxide salts of various cations with the zwitterions, other synthetic approaches can be envisioned as well, such as zwitterion deprotonation with strong bases like NaH or BuLi, followed by an ion metathesis step to exchange the Na or Li for a different cation. 
     As one skilled in the art will readily appreciate, in the case where the flue gas contains sufficient water vapor, the ionic absorbent can be used as is, i.e., neat. In other words, when there is a sufficient amount of water vapor in the flue gas, the sufficient amount of water and ionic absorbent will form an aqueous ionic absorbent solution having a viscosity suitable for use in the process of the present invention. A suitable viscosity for the aqueous ionic absorbent solution containing the ionic absorbent in the process of the present invention will ordinarily be from about 0.1 to about 100 centistoke (cSt). In one embodiment, a suitable viscosity for the aqueous ionic absorbent solution containing the ionic absorbent in the process of the present invention can range from about 0.5 to about 40 cSt. 
     Alternatively, in the case where the flue gas does not contain sufficient water vapor, a sufficient amount of a diluent can be added to the aqueous ionic absorbent solution containing the ionic absorbent to reduce its viscosity to the suitable viscosity discussed above. A suitable diluent includes, by way of example, inert diluents such as water, monohydric alcohols, polyols, and the like and mixtures thereof. Representative examples of suitable monohydric alcohols include C 1  to C 12  alcohols such as methanol, ethanol, isopropanol, 1-propanol, 1-butanol, 2-butanol, t-butanol, 2-methyl-1-propanol, 1-pentanol, 1-hexanol, 1-heptanol, 4-heptanol, 1-octanol, 1-nonyl alcohol, 1-decanol, 1-dodecanol and the like and mixtures thereof. 
     The polyols for use as a diluent include those having from 2 to about 10 carbon atoms and from two to six hydroxyl groups. Representative examples of suitable polyols include glycerol, triethylene glycol, 2-ethylene glycol, diethylene glycol, 1,2-propylene glycol, 1,3-propylene glycol, tetraethylene glycol, hexylene glycol and the like and mixtures thereof. In one preferred embodiment, the diluent is water. 
     In order for the aqueous solutions containing the ionic absorbent to have a larger volumetric absorption capacity for CO 2  (mol CO 2 /cm 3  solvent) over an aqueous solution of 30 wt. % water and MEA, the molecular weight of the neat ionic absorbent should be as low as possible, e.g., a molecular weight of no more than about 700 atomic mass unit (AMU) (g/mole). In one embodiment, the molecular weight of the neat ionic absorbent is from about 75 to about 700 AMU (g/mole). In one embodiment, the molecular weight of the neat ionic absorbent is below about 600 AMU (g/mole). In another embodiment, the molecular weight of the neat ionic absorbent is from about 75 to about 600 AMU (g/mole). In one embodiment, the molecular weight of the neat ionic absorbent is below about 500 AMU (g/mole). In another embodiment, the molecular weight of the neat ionic absorbent is from about 75 to about 500 AMU (g/mole). 
     The amount of water and optional diluent to achieve sufficient viscosity and to provide enough stripping stream in regenerator (H), as discussed below, should be no more than about 80 wt. %, based on the total weight of the aqueous solution. In another embodiment, the amount of water and optional diluent can range from about 15 to about 80 wt. %, based on the total weight of the aqueous solution. 
     It is believed that the ionic absorbents are stable under the O 2 , NO x  and SO x  which may be present in the flue gas Therefore, the use of the ionic absorbent according to the present invention may avoid the need for SCR (Selective Catalytic Reduction) and/or FGD (Flue Gas Desulfurization) especially in refinery sources. In addition, the overall process may operate in a multi-pollutant mode where the aqueous solutions containing the ionic absorbent co-absorb one or more of SO 2 , COS, NO x , COS, and SO x  in the flue gas. Thus, the aqueous solutions containing the ionic absorbent for use herein may be employed to capture all or some of the pollutants in addition to CO 2  which are present in the flue gas. 
     Process 
       FIG. 5  illustrates a process scheme according to one embodiment of the present invention. In general,  FIG. 5  includes a carbon dioxide (CO 2 ) separation system for recovering high purity CO 2  from flue gas stream (A). First, flue gas stream (A) enters blower (B), which blows flue gas stream (A) to absorber (D). Blower (B) can be any type of blower known to one skilled in the art. Generally, the pressure of flue gas stream (A) is around 1 bar. Blower (B) raises the pressure of the flue gas stream to a pressure ranging from 1.1 to about 1.5 bar. The pressure is typically raised to overcome the pressure drop associated with flowing the gas through the absorber tower. 
     In one embodiment, absorber (D) is a packed tower. The packing may be random packing, structured packing or any combination thereof. The randomly packed material can include, but is not limited to, Raschig rings, saddle rings, Pall rings, or any other known type of packing ring, or combination of packing rings. The structured packed material can include, but is not limited to, corrugated sheets, crimped sheets, gauzes, grids, wire mesh, monolith honeycomb structures, or any combination thereof. Examples of structured packing include Sulzer DX™, Mellapak™, Mellapak Plus™, Katapak™, and the like. 
     As discussed above, water present in the flue gas stream will form an aqueous solution containing the ionic absorbent. If the viscosity of the aqueous solution is not sufficient for use in the process of the present invention, then it may be necessary to add one or more diluents to the aqueous solution to further reduce its viscosity to a viscosity suitable for the process of the present invention. Accordingly, a diluent stream (G) is present at the top of the column to further hydrate the incoming ionic liquid stream (C) and reduce its viscosity as discussed above. In addition, diluent stream (G) can scrub any additional diluent that maybe carried over into treated flue gas stream (A 1 ) leaving the absorber (D) to partly or completely remove any unwanted impurities. Typically, the total amount of water and diluents, when present, in the ionic absorbent is largely dictated by viscosity requirements, and is generally less than about 80 wt. %. In one embodiment, the total amount of water present is from about 15 wt. % to about 80 wt. %. 
     The flue gas stream (A) and ionic absorbent stream (C) are contacted in absorber (D). In general, fine gas stream (A) is introduced into chemical absorber (D) and during the process of flow from the bottom up, the carbon dioxide in flue gas stream (A) is absorbed by ionic absorbent (C) flowing from the top down. The end gas, i.e., treated flue gas stream (A 1 ), which is essentially depleted of carbon dioxide, is introduced out of the absorber, for example, through a vent from the top of the absorber after contacting (or being scrubbed) by diluent stream G. In one embodiment, from about 80 to about 95% of CO 2  in stream A has been removed to form stream A 1 . 
     The ionic absorbent stream (E), which has absorbed carbon dioxide (CO 2 -rich aqueous ionic absorbent solution stream), comes out of absorber (D) from the bottom and is pumped to cross exchanger (K), where its temperature is raised; and then the preheated stream (F) may be pumped through pump (W 2 ). Pump (W 2 ) raises the pressure of ionic absorbent stream (E) to greater than about 1.9 bar to provide pressurized ionic absorbent stream (F 1 ). In one embodiment, the pressure of ionic absorbent stream (E) is raised to a pressure of greater than about 1.9 bar to about 10 bar. In one embodiment, the pressure is raised to about 4 bar to about 8 bar. Pump (W 2 ) can be any apparatus capable of raising the pressure of preheated stream (F) such as, for example, a centrifugal pump, a reciprocating pump, a gear pump, etc. 
     Next, pressurized ionic absorbent stream (F 1 ) is sent to the top of regenerator (H) (i.e., stripper) to flow down through the regenerator where it is former heated to a temperature ranging from, about 90° C. to about 200° C. by, for example, steam-heated or hot-oil heated reboiler and under vacuum, atmospheric or high pressure conditions. In one embodiment, pressurized ionic absorbent stream (F 1 ) is sent to the top of regenerator (H) to flow down through the regenerator where it is further heated to a temperature of about 120° C. to about 180° C. In this manner, most of the carbon dioxide in the ionic liquid (F 1 ) is released as a wet carbon dioxide gas stream (L) and emitted out from the top of regenerator (H). Regenerator (H) is a packed tower and can be any random or structure packing as discussed above with absorber (D). The high temperature regeneration allows for greater flexibility in using different levels of steam and/or waste heat resources in reboiler (Q), as discussed below. The regenerator (H) is typically run at relatively high pressure, e.g., a pressure from about 1.9 bar to about 10 bar. By running regenerator (H) at a relatively high pressure, carbon dioxide stream (L) may be recovered at higher pressure thereby reducing the capital and operating costs associated with carbon dioxide compression (Y), discussed below. The ionic absorbent depleted of carbon dioxide, i.e., ionic absorbent stream (S), is emitted out from the bottom of regenerator (H). 
     In one embodiment, when flue gas stream (A) is first pre-cooled to a temperature of about 40° C. to about 60° C. and then sent to the absorber and contacted with ionic absorbent stream (C), the desorption conditions for removing carbon dioxide from ionic absorbent stream (F 1 ) may include heating stream (F 1 ) to a temperature of greater than 60° C. to about 80° C. in the case where the regenerator (i.e., stripper) is run at vacuum conditions. In another embodiment, when flue gas stream (A) is first pre-cooled to a temperature of about 40° C. to about 60° C. and then sent to the absorber and contacted with ionic absorbent stream (C), the desorption conditions for removing carbon dioxide from pressurized ionic absorbent stream (F 1 ) may include heating stream (F 1 ) to a temperature of greater than 100° C. to about 120° C. in the case where the regenerator is run at atmospheric conditions. In yet another embodiment, when flue gas stream (A) is first pre-cooled to a temperature of about 40° C. to about 60° C. and then sent to the absorber and contacted with ionic absorbent stream (C), the desorption conditions for removing carbon dioxide from pressurized ionic absorbent stream (F 1 ) may include heating stream (F 1 ) to a temperature of about 120° C. to about 200° C. in the case where the regenerator is run at high-pressure conditions (i.e., 1.9 to 10 bar). 
     In one embodiment, when flue gas stream (A) is sent to the absorber at a temperature of about 60° C. to about 80° C., the desorption conditions for removing carbon dioxide from pressurized ionic absorbent stream (F 1 ) may include heating stream (F 1 ) to a temperature of about 100° C. to about 200° C. in the case where the regenerator is run at atmospheric or high-pressure conditions. 
     In one embodiment, when flue gas stream (A) is sent to the absorber at a temperature of about 80° C. to about 100° C. the desorption conditions for removing carbon dioxide from pressurized ionic absorbent stream (F 1 ) may include heating stream (F 1 ) to a temperature of about 120° C. to about 200° C. in the case where the regenerator is run at atmospheric or high-pressure conditions. 
     The wet carbon dioxide gas stream (L) coming from the top of regenerator (H) is then passed through cooler (M), such as a condenser, where it is cooled to provide cooled carbon dioxide gas stream (N). The temperature of carbon dioxide gas stream (L) is generally decreased to about 30° C. to about 50° C. The cooled carbon dioxide gas stream (N) is sent to separator (O) where condensed water and trace amounts of ionic absorbent and optional diluents is separated and returned to regenerator (H) as reflux (P1). The gas stream (R), as the carbon dioxide product, is sent to gas injection regulatory system (X) where it is dehydrated using methods known in the art, e.g., triethylene glycol dehydration or heatless absorption using molecular sieves. The dehydrated gas is then sent to compressor (Y) to be pressurized, under normal pressure and a temperature of less than about 60° C., to about 7.4 MPa or higher, and sent off to pipeline (Z). In one embodiment, the captured CO 2  can be used on-site or can be made available for sale to a co-located facility. Dried CO 2  will be compressed in a series of compressors and intercoolers to a final temperature of about 40° C. to about 60° C. The last compression stage would be close to the supercritical pressure of CO 2  (i.e., about 1100 psig). Once CO 2  is supercritical, it may be pumped as a dense phase fluid to any pressure required for transportation—final dense phase pressure may range from about 100 to about 200 bar. 
     The reboiler (Q) is a shell and tube heat exchanger, ionic absorbent stream (S) coming from the bottom of the regenerator (H) enters into the tubes of the reboiler (Q) where it is heated by steam in the shell-side of the reboiler. Stream (T) is the supply heating medium, such as steam that it is available from the facility generating the fine gas (e.g., refinery, gas/oil-fired boiler, power plant, etc) while stream (U) is the return condensate that is returned back to the utility system of the facility. Therefore, the ionic absorbent stream (S) is heated in the reboiler (Q) and at least a portion of the carbon dioxide and water vapor present therein is released out and leaves from the top of reboiler (Q) into regenerator (H) as stripping gas (I). On the other hand, ionic absorbent solution (J) with significantly decreased content of absorbed carbon dioxide (also referred to as “CO 2 -lean absorbent solution”) is sent back to cross exchanger (K). 
     The following non-limiting examples are illustrative of the present invention. 
     Experiments were conducted to measure the CO 2  absorption of ionic absorbent materials diluted with water and to demonstrate their effectiveness. 
     The equilibrium CO 2  carrying capacity of the aqueous ionic absorbent solutions was measured via a volumetric method. A known quantity of ionic absorbent-water mixture is injected into a sealed pressure vessel containing high purity CO 2  gas at pressure of approximately 15 psia, and the vessel is shaken to provide mixing of the solution. The pressure in the vessel decreases as CO 2  is absorbed into the solution, and the pressure is monitored until the system reaches an equilibrium pressure. The temperature of the system is controlled and monitored, and an equilibrium pressure is measured for multiple temperatures in each experiment. The initial and final pressure of CO 2 , the volume of the pressure vessel, and the quantity and composition of the injected ionic absorbent-water mixture are all known. 
     The measured experimental data are used to calculate the loading of CO 2  in the solution, which is reported as moles of CO 2  bound per mol of ionic absorbent in the solution. An aqueous ionic absorbent solution is contacted in a sealed vessel with a low partial pressure CO 2  gas simulating a flue gas stream. The vessel is maintained at a constant temperature by way of heating tape and is shaken to allow good contact between CO 2  and the absorbent solution until the system reaches equilibrium. When the pressure reaches the steady state, then a pressure is recorded and the vessel temperature is changed to the next set point. Based on the equilibrium CO 2  pressure, the loading per mole of ionic absorbent is calculated. The measured pressure in the vessel is used to determine the moles of gaseous CO 2  present in the vessel before and after CO 2  absorption occurs (before and after the solvent is injected into the vessel) using the ideal gas equation of state: P CO2  V=n R T, where Pro CO2 =partial pressure of CO 2  (psia), V=volume of the gas phase hi the vessel, n=total moles of CO 2  gas, T=measured experimental, temperature in degrees Kelvin, and R is the Ideal Gas Constant, which, has units of energy per mol per degree Kelvin (approximately 8.314 J/mol K). 
     The water vapor pressure in the vessel is determined assuming the solvent is an ideal mixture of water and absorbent using the known vapor pressure of water at the temperature of a given experiment (taken from the NIST steam tables, see http://webbook.nnist.gov/chemistry/fluid): the partial pressure of water in the vessel is calculated as the vapor pressure of water multiplied by the mol fraction of water in the solvent (which is known from the mass of water and absorbent used in preparing the solvent mixture). Because the ionic materials used as absorbents have negligibly low vapor pressure, the gas in the vessel is composed only of water and CO 2 . The partial pressure of CO 2  is calculated as the difference between the measured total pressure and the water vapor pressure. The difference between the gas-phase quantity of CO 2  before and after solvent injection is used to calculate the absorbed quantity of CO 2  for various temperatures in a single experiment. The absorbed quantity of CO 2  is then divided by the quantity of ionic material in the solvent to calculate the loading as moles of CO 2  absorbed per mole of ionic absorbent. 
     EXAMPLE 1 
     The effect of water addition to the ionic absorbents was studied using tetraethylammonium N-isopropyl-N-(3-sulfopropyl)amine (TEA) as the ionic absorbent. Neat TEA is a very viscous material. The addition of water lowered the viscous nature of the TEA significantly. Varying amounts of water was added to the TEA and the time to reach the equilibrium CO 2  uptake was determined. The results are summarized below in Table 1. 
                                 TABLE 1                           Viscosity       Water Diluent,   Time to reach   Viscosity (cSt)   (cSt)       Wt. %   equilibrium CO 2  uptake   at 20° C.   at 80° C.                                                    0   &gt;&gt;2   days   Very viscous   —       25   ~24   hours   Viscous   —       50   &lt;1   hour   10.5   1.7                    
As the data show, a neat ionic absorbent (i.e., TEA) provided a significantly longer time to approach equilibrium as compared to (1) the aqueous ionic absorbent solution containing TEA with 25 wt. % water and (2) the aqueous ionic absorbent solution containing TEA with 50 wt. % water, i.e., 2 days versus 24 hours and 1 hour, respectively. The lower viscosity of the aqueous ionic absorbent, solution case facilitates rapid mass transfer of CO 2  between the gas and liquid phases, and enables CO 2  absorption to occur on a faster timescale as compared to the neat ionic absorbent which is mass-transfer limited due to the high viscosity of the absorbent. These results demonstrate that sufficient diluent content is necessary to achieve CO 2  removal from gas streams on an industrially-relevant timescale.
 
     EXAMPLE 2 
     Two 50 wt. % aqueous ionic absorbent solutions of ionic absorbent were prepared. The ionic absorbents were tetraediylammonium N-isopropyl-N-(3-sulfopropyl)amine (TEA) and tetramethylammonium N-isopropyl-N-(3-sulfopropyl)amine (TMA), respectively. The aqueous ionic absorbent solution was contacted in a sealed vessel with a low partial pressure CO 2  gas simulating a model flue gas stream. The vessel was maintained at a constant temperature and is shaken to allow good contact between CO 2  and the absorbent ionic absorbent solution until the system reached equilibrium. When the pressure reached the steady state, then a pressure was recorded and then the vessel temperature was changed to the next set point. Based on the equilibrium CO 2  pressure, the loading per mole of ionic absorbent was calculated. The CO 2  loading of the two ionic absorbents were plotted as a function of CO 2  partial pressure in  FIG. 6 . The data in this figure demonstrate that these solutions have high molar absorption capacities ranging from 0.5 to about 0.85 CO 2  absorption loading per mole of ionic absorbent. These absorption capacities are significantly higher than the conventional amine-based solvents such as monoethanolamine (MEA). The CO 2  loading for 30 wt. % MEA was also measured and the data are presented in  FIG. 7  which shows 0.4 to 0.5 mol CO 2  absorbed per mole of MEA (comparative example). 
     EXAMPLE 3 
     From the data in  FIG. 6  the expected CO 2  removal capacity of the ionic absorbent from flue gas can be estimated. The plot shows that an aqueous ionic absorbent solution of TMA with 50 wt. % water can absorb up to 0.74 mol CO 2  per mol ionic absorbent at 40° C. with a CO 2  partial pressure of 2.8 psia. This condition is reflective of the “rich” solution loading in the absorber. The solution absorption capacity for CO 2  at 95° C. and a CO 2  partial pressure of 5.0 psia decreases to 0.5 mol CO 2  per mol aqueous ionic solution. This second condition may reflect the “lean” solution loading achieved in the regeneration column. Therefore, the absorber-regenerator system described herein could remove 0.24 moles of CO 2  per mol of TMA ionic absorbent circulated through the absorber-regenerator system per pass. 
     Since the ionic absorbent for use in the aqueous ionic absorbent solution can be operated in a wide range of temperatures, the CO 2  capture process conditions can be chosen to increase the loading difference between the “rich” and “lean” CO 2  capacities. As one skilled in the art will readily appreciate, the chemical absorption capacity of solvent decreases with (1) decreasing partial pressure of the absorbed species in the gas phase and (2) increasing temperature. Therefore, by operating the stripper at temperatures in excess of 95° C., the CO 2  removal capacity of the system can be further increased. The removal capacity of the system can also be increased by operating the stripper with lower CO 2  partial pressure. 
     Therefore, our results show that that TMA would have the capacity to remove at least 0.24 moles of CO 2  per mol of ionic absorbent circulated through the absorber-regenerator system per pass. 
     EXAMPLE 4 
     From the data in  FIG. 6 , the expected CO 2  removal capacity of TEA from flue gas can be estimated. The plot shows that an aqueous ionic absorbent solution of TEA with 50 wt. % water absorb up to 0.76 mol CO 2  per mol ionic absorbent at 40° C. with a CO 2  partial pressure of 1.2 psia. This condition is reflective of the “rich” solution loading in the absorber. In this TEA-based solution, the absorption capacity for CO 2  at 95° C. and a CO 2  partial pressure of 6.3 psia decreases to 0.57 mol CO 2  per mol aqueous ionic solution. This second condition may reflect the “lean” solution loading achieved in the regeneration column. Therefore, the absorber-regenerator system described herein could remove 0.19 moles of CO 2  per mol of aqueous ionic absorbent solution circulated through the absorber-regenerator system. As in the previous example, the CO 2  removal capacity of the system will be further increased by operating the stripper at higher temperatures and/or operating the stripper at lower CO 2  partial pressure. 
     Therefore, our results show that TEA would have the capacity to remove at least 0.19 moles of CO 2  per mol of ionic absorbent circulated through the absorber-regenerator system per pass. 
     COMPARATIVE EXAMPLE A 
       FIG. 7  shows measured CO 2  absorption data for an aqueous solution containing 30 wt % MEA with 70 wt. % water. At 20° C., the absorption capacity for CO 2  at a CO 2  partial pressure of 1.5 psia was approximately 0.5 mol CO 2  per mol MEA, which reflects the loading in the absorption column. By heating the solution at 95° C. and a CO 2  partial pressure of 3.0 psia, the measured loading decreases to 0.4 mol CO 2  per mol of MEA. This second condition reflects the “lean” solution loading achieved in the regeneration column. Therefore, the absorber-regenerator system using an aqueous solution of MEA under these conditions could remove 0.10 moles of CO 2  per mol of MEA. When comparing Comparative Example A with Examples 2 and 3, the capacities of aqueous ionic absorbent solution containing TEA and TMA, respectively, for CO 2  are higher than that of aqueous MEA, measured as moles of CO 2  captured per mol of absorbent. 
     It will be understood that various modifications may be made to the embodiments disclosed herein. Therefore the above description should not be construed as limiting, but merely as exemplifications of preferred embodiments. For example, the functions described above and implemented as the best mode for operating the present invention are for illustration purposes only. Other arrangements and methods may be implemented by those skilled in the art without departing from the scope and spirit of this invention. Moreover, those skilled in the art will envision other modifications within the scope and spirit of the claims appended hereto.