Ionic liquids for removal of carbon dioxide

This application claims the benefit of U.S. Provisional Application Nos. 61/381,281 filed Sep. 9, 2010, 61/381,294 filed Sep. 9, 2010, 61/381,351 filed Sep. 9, 2010, 61/420,960 filed Dec. 8, 2010, 61/420,978 filed Dec. 8, 2010, and 61/421,048 filed Dec. 8, 2010, the entire contents of each of which are hereby incorporated by reference herein.

This invention relates to the removal of carbon dioxide and other acid gases from a gaseous stream containing one or more of these gases. In particular, the invention relates to a method for separating an acid gas, e.g., carbon dioxide, from a gas mixture using ionic liquids as the sorbent.

The removal of carbon dioxide from mixed gas streams is of great industrial importance and commercial value. Carbon dioxide is a ubiquitous and inescapable by-product of the combustion of hydrocarbons, and there is growing concern over its accumulation in the atmosphere and its potential role in a perceived global climate change. Laws and regulations driven by environmental factors may therefore soon be expected to require its capture and sequestration. While existing methods of CO 2 capture have been adequately satisfactory for the scale in which they have so far been used, future uses on the far larger scale required for significant reductions in atmospheric CO 2 emissions from major stationary combustion sources such as power stations fired by fossil fuels makes it necessary to improve the processes used for the removal of CO 2 from gas mixtures. According to data developed by the Intergovernmental Panel on Climate Change, power generation produces approximately 78% of world emissions of CO 2 with other industries such as cement production (7%), refineries (6%), iron and steel manufacture (5%), petrochemicals (3%), oil and gas processing (0.4%) and the biomass industry (bioethanol and bioenergy) (1%) making up the bulk of the total, illustrating the very large differences in scale between power generation on the one hand and all other uses on the other. To this must be added the individual problem of the sheer volumes of gas which will need to be treated: flue gases consist mainly of nitrogen from combustion air, with the CO 2 , nitrogen oxides and other emissions such as sulfur oxides making up relatively smaller proportions of the gases which require treatment: typically, the flue gases from fossil fuel power stations typically contain from about 7 to 15 volume percent of CO 2 , depending on the fuel, with natural gas giving the lowest amounts and hard coals the greatest.

Cyclic CO 2 absorption technologies such as Pressure Swing Absorption (PSA) and Temperature Swing Absorption (TSA) using liquid absorbents are well-established. The absorbents mostly used include liquid solvents, as in amine scrubbing processes, although solid sorbents are also used in PSA and TSA processes. Liquid amine absorbents, including alkanolamines, dissolved in water are probably the most common absorbents. Amine scrubbing is based on the chemical reaction of CO 2 with amines to generate carbonate/bicarbonate and carbamate salts: the aqueous amine solutions chemically trap the CO 2 via formation of one or more ammonium salts (carbamate/bicarbonate/carbonate) which are thermally unstable, enabling the regeneration of the free amine at moderately elevated temperatures. Commercially, amine scrubbing typically involves contacting the CO 2 and/or H 2 S containing gas stream with an aqueous solution of one or more simple amines (e.g., monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA) or triethanolamine (TEA)). The low molecular weight of MEA makes it economically attractive because sorption takes place on a molecular basis while the amine is sold on a weight basis. The cyclic sorption process requires high rates of gas-liquid exchange, the transfer of large liquid inventories between the absorption and regeneration steps, and high energy requirements for the regeneration of amine solutions. It is challenged by the corrosive nature of the amine solutions containing the sorbed CO 2 . Without further improvement, these difficulties would limit the economic viability of the aqueous amine scrubbing processes in very large scale applications.

The cyclic absorption processes using aqueous sorbents require a large temperature differential in the gas stream between the absorption and desorption (regeneration) parts of the cycle. In conventional aqueous amine scrubbing methods relatively low temperatures, e.g., less than 50° C., are required for CO 2 uptake with an increase to a temperature to above about 100° C., e.g., 120° C., required for the desorption. The heat required to maintain the thermal differential is a major factor in the cost of the process, and with the need to regenerate the solution at temperatures above 100° C., the high latent heat of vaporization of the water (2260 kJ/Kg at 100° C.) obviously makes a significant contribution to the total energy consumption. If CO 2 capture is to be conducted on the larger scale appropriate to use in power stations, more effective and economical separation techniques need to be developed.

Another area where more efficient CO 2 separation processes are used is in enhanced oil recovery (EOR) where CO 2 is re-injected into the gas or liquid hydrocarbon deposits to maintain reservoir pressure. With the advanced age of many producing reservoirs worldwide and the ever-increasing challenge of meeting demand, the expanding use of EOR methods is becoming more widespread. Typically the source of carbon dioxide for EOR is the producing hydrocarbon stream itself, which may contain anywhere from less than 5% to more than 80% of CO 2 . Other options are to capture CO 2 from the flue gases of various combustion sources and pre-combustion capture of CO 2 from shifted syngas produced in fuel gasification processes.

Various commercial CO 2 capture processes have been brought to market. The Fluor Daniel Econamine™ Process (originally developed by Dow Chemical and Union Carbide), which uses MEA for recovery of CO 2 from flue gases, primarily for EOR applications, has a number of operational plants. The Benfield™ Process using hot potassium carbonate is used in many ammonia, hydrogen, ethylene oxide and natural gas plants with over 675 units worldwide licensed by UOP and has been proposed for treating flue gas, notwithstanding its minimum CO 2 partial pressure requirement of 210−345 kPag (30-50 psig). One significant disadvantage of the Benfield Process is its use of a high temperature stripping step (175° C.) approximately 75-100° C. above the temperature of the absorption step. The Catacarb™ process, also using hot potassium carbonate, also uses high temperature stripping resulting in high energy consumption.

Processes using sterically hindered amines as alternatives to MEA, DEA, and TEA have also achieved success, including the ExxonMobil Flexsorb™ Process and the KS™ Process from Mitsubishi Heavy Industries and Kansai Electric Power Co.

Processes using solid absorbents are also known and while they may avoid many of the limitations of amine scrubbing, they suffer from a lack of absorbents having sufficiently selective CO 2 absorption under the conditions present in most commercial combustion flue gas processes.

We have now found that certain ionic liquids can be capable of acting as chemisorbents for CO 2 in cyclic CO 2 separation processes in which the CO 2 is desorbed from the ionic liquid and then recycled to the sorption step. Specific ionic liquids have been found to be effective at low pressures by a process of chemisorption in the liquid thus facilitating exceptionally high overall system CO 2 uptake efficiency. These processes are particularly useful and efficient in the presence of a non-nucleophilic nitrogenous base promoter. The carboxylation reaction between the ionic liquid and the CO 2 can be effective at relatively low pressures and so enables the present chemisorptive process to be effective at relatively lower pressures than the convention physisorptive process using ionic liquid sorbents.

According to the present invention, a cyclic process for separating CO 2 from a gas stream is provided, which process comprises contacting the gas stream with an absorbent comprising an ionic liquid containing a cation with a potentially nucleophilic carbon atom bearing a relatively acidic hydrogen atom and treating the absorbent containing the sorbed CO 2 under conditions sufficient to cause desorption of at least a portion of the CO 2 to regenerate the ionic liquid. The chemisorptive effect of the ionic liquid may be promoted by the addition of a non-nucleophilic nitrogenous base promoter to the absorbent.

The cyclic sorption-desorption process can normally be operated in a continuous cycle which comprises: a) contacting the gas stream in a gas/liquid sorption zone with a circulating stream of a non-aqueous liquid sorbent medium comprising an ionic liquid containing a cation with a potentially nucleophilic carbon atom bearing a relatively acidic hydrogen atom, under conditions to form a rich solution of CO 2 sorbed in the liquid sorbent medium, optionally in the presence of a non-nucleophilic nitrogenous base promoter; b) passing the rich solution of CO 2 sorbed in the liquid sorbent medium to a regeneration zone in which CO 2 is desorbed from the rich solution in the liquid sorbent medium under conditions required for desorption of the CO 2 ; and c) cycling the resulting regenerated lean solution with reduced CO 2 content to the sorption zone.

The sorption may be carried out at low temperatures, e.g., ambient to about 45° C., but, if the entering gas stream is at a higher temperature, as with flue gas, the sorption may be carried out at temperatures up to about 90 or 100° C. while desorption can typically be carried out at temperatures no higher than 120° C. and desirably lower, e.g., no higher than 90° C. with low temperature sorption. High temperature sorption is not precluded since, with gas streams such as natural gas with a high CO 2 partial pressure, absorption at high temperature can be quite feasible. The use of high temperatures such as those required in the potassium carbonate absorption processes of the prior art is not, however, required by the present process, and no use of solid sorbents mixed with the liquids is contemplated (i.e., the sorption/desorption cycles of the present invention are carried out in the absence of solid sorbents).

FIG. 1 is a simplified schematic of an embodiment of a cyclic separation unit suitable for separating CO 2 from a flue gas stream in accordance with a process of the present invention.

FIG. 2 shows 13 C NMR spectra of the ionic liquid of Example 1 before and after chemical reaction with CO 2 .

FIGS. 3 a and 3 b are graphs showing the TGA results of neat CO 2 sorption and desorption of the ionic liquid in Example 1.

FIG. 4 shows 13 C and 1 H NMR spectra of the ionic liquid—non-nucleophilic nitrogenous base solution of Example 1.1 before and after chemical reaction with CO 2 .

FIG. 5 shows the 1 H and 13 C NMR spectra of 1,3-bis(2,4,6-TMP) imidazolidinium chloride in DMSO-d 6 solution after treatment with CO 2 (top) and after adding TMG (bottom) (Examples 5 and 5.1).

FIG. 6 shows a vapor-liquid equilibrium graph for 1-butyl-3-methylimidazolium acetate/CO 2 for Example 2.1.

FIG. 7 shows a vapor-liquid equilibrium graph for 1-butyl-3-methylimidazolium acetate/TMG/CO 2 for Example 2.2.

The methods of this disclosure involve removing CO 2 and/or other acid gases, such as H 2 S, from a gas stream containing one or more of these gases using an ionic liquid, optionally in the presence of a non-nucleophilic nitrogenous base promoter, as a sorbent. The gas stream, typically a flue gas from the combustion of a carbonaceous fossil fuel such as natural gas, oil, and/or coal, can be brought into contact with an absorbent solution of an ionic liquid, optionally combined with a non-nucleophilic nitrogenous base promoter, under conditions in the sorption zone or tower to effect the removal of the absorbed component (CO 2 ) and thus to produce an effluent gas stream having a reduced concentration relative to the entering gas mixture. Other acid gases which may be present in the gas stream may also be absorbed under the same conditions and thus effectively removed from the gas stream. Subsequently, the absorbed component can be desorbed by adjustment of the conditions, for example, by increase in temperature, decrease in pressure, and/or by reduction of partial pressure of the desorbed component by stripping, typically with an inert (non-reactive) gas and/or a natural gas stream in a regeneration tower. Under the selected desorption conditions, the sorbed component can be purged from the selective absorbent and can then be sent for further processing, utilization, and/or sequestration.

Cyclic Sorption Unit

FIG. 1 shows a representative simplified schematic of a continuous cyclic gas separation unit which may be used for separating CO 2 from flue gas streams, natural gas streams, and other streams using the present ionic liquid absorption medium. The hot flue gas stream can enter the unit by way of line 10 , entering near the bottom of absorber tower 11 and preferably passing through a cooling section 12 , in which its temperature can be reduced by direct or indirect cooling to bring it to a suitable temperature for the sorption step which follows. In an alternative embodiment, the cooling of the hot flue gas stream can be achieved prior to the stream entering the absorber tower 11 .

From here, the gas stream can pass into sorption section 13 in countercurrent contact with a descending stream of the ionic liquid sorbent. At least part of the CO 2 , along with other gases which are amenable to absorption in the solution, can be absorbed into the ionic liquid resulting in a “rich” solution 14 containing the sorbed CO 2 which can be removed with a separation tray (not shown) near the lower end of the sorption section. The rich solution can then pass through heat exchanger 15 to desorption/regeneration tower 20 in which the CO 2 and other gases can be desorbed, in this case, by an increase in temperature, decrease in pressure, and/or the use of a purge (stripping gas), with agitation optionally but advantageously being provided by the stream of desorbed CO 2 and/or a purge gas. The rich solution can enter the tower at a level appropriate to its composition and can pass downwards as dissolved gases are removed. Heat for the regeneration tower can be supplied by reboiler 21 which can circulate a slipstream of solution taken from near the bottom of the regeneration tower by way of line 22 . A stream of regenerated lean solution with a lower content of CO 2 can be taken from the reboiler in line 23 to pass through the other side of heat exchanger 15 before re-entering absorber tower 11 for passage through the gas stream. A gas stream of decreased CO 2 content can pass out of absorber tower 11 through line 16 , and the desorbed CO 2 and other acid gases removed from the original gas stream can be removed in concentrated form through line 24 and taken to final sequestration or utilization (e.g., in industrial gas and/or in enhanced oil recovery processes).

Conventional equipment can be used to perform the various functions of the cyclic scrubbing process, such as monitoring and automatically regulating the flow of gases so that it can be fully automated to run continuously in an efficient manner.

Gas Stream

The gas streams particularly amenable to treatment by the present sorption process can include flue gas from the combustion of carbonaceous fuels and/or natural gas from subterranean and other sources. Flue gas may originate from the combustion of carbon-containing fossil fuels such as natural gas, oils, and/or lignite, as well as sub-bituminous, bituminous, and/or anthracite coals. Its CO 2 content may typically vary from about 6 to about 15 wt %, depending on the fuel, with the highest levels coming from hard coal combustion and the lowest from natural gas. Natural gas streams containing carbon dioxide may contain, in addition to methane and carbon dioxide, one or more other gases such as ethane, n-butane, i-butane, hydrogen, carbon monoxide, ethene, ethyne, propene, nitrogen, oxygen, helium, neon, argon, krypton, hydrogen sulfide, and carbonyl sulfide, as well as, in some cases, mercury and/or other metal contaminants, if they have not been removed by other pre-treatment. Other streams that can be treated by the present separation process can include syngas and shifted syngas produced in fuel gasification processes and gas streams from petrochemical plants whose composition can naturally depend on the process from which they are derived.

The amount of carbon dioxide in the gas mixture can typically vary from about at least 1 percent upwards; in many streams, it can be at least 10 percent and may even be higher, as with some gas streams from natural gas fields such as the LaBarge (Wyoming) field, where the gas is about 66.5 percent carbon dioxide, about 20.5 percent methane, about 7.4 percent nitrogen, about 5.0 percent hydrogen sulfide, and about 0.6 percent helium.

The gas stream may optionally also be subjected to dehumidification prior to contacting with the absorbent materials and processes described herein. The dehumidification can be carried out by conventional methods by the use of a drying agent/absorber guard bed upstream of the acid gas scrubbing unit, and/or by carrying out the CO 2 absorption at temperatures above 100° C. using an absorbent capable of being regenerated above the absorption temperature. For example, the dehumidification can be carried out by absorption over solid sorbents such as salt dryers, molecular sieves, silica gels, and/or aluminas.

Ionic Liquid Sorbents

Ionic liquids are liquids that contain essentially only ions rather than uncharged molecular species. Many ionic liquids remain liquid over a wide temperature range, often more than 300° C. They may have low melting points (as low as −96° C. has been reported), which can be attributed to large asymmetric cations that affect low lattice energies. The term is commonly used for salts whose melting point is relatively low (typically below 100° C.) which typically exhibit no measurable vapor pressure below their thermal decomposition temperature. The properties of ionic liquids result from the composite properties of the wide variety of cations and anions which may be present in these liquids. As a class of materials, ionic liquids are highly solvating for both organic and inorganic materials. Many of them are nonflammable, non-explosive and have high thermal stability. They are also recyclable, which can be helpful in reducing environmental concerns over their use.

Certain ionic liquids have previously been reported as physical sorbents for acid gases, operating under conditions of high pressure ( Fuel Cells Bulletin 2005, Issue 9, 3-10), but have not been previously described as being capable of reaction with CO 2 under low pressures as described below.

A class of ionic liquids which has been found to be highly effective in the present CO 2 chemisorption process and which can therefore be preferred as sorbents include those compounds in which the cation contains a relatively acidic hydrogen atom bonded to a potentially nucleophilic carbon atom, as in cations having a C—H bond present as part of a conjugated —NC(H)N— structure and/or of an —NC(H)S— structure, more specifically designated as a —N═C(H)—N— structure and/or as an —N═C(H)—S— structure, for example, as in imidazolium, benzimidazolium, imidazolidinium (4,5-dihydro-1H-imidazolium), diazolium, and thiazolium salts with a hydrogen at the 2-position. The carbon referred to as nucleophilic can be qualified as potentially nucleophilic, since the carbon itself typically does not become a nucleophile until deprotonation of the acidic hydrogen. Thus, cations that can be effective to achieve chemisorption of CO 2 can advantageously be those in which the potentially nucleophilic carbon can bear a sufficiently acidic hydrogen (on a relative basis) to be susceptible to deprotonation by reaction of the cation and subsequent reaction with CO 2 . Organic cations with pK a (acid dissociation equilibrium constant) values, as measured or predicted at ˜25° C. in DMSO (dimethyl sulfoxide) solution and/or as measured in other solvent and converted to a DMSO value (referred to as DMSO equivalent scale), can be below about 26, for example from about 26 to about 15, from about 25 to about 16, or from about 24 to about 18 (based on the values in the Bordwell online pK a database, http://www.chem.wisc.edu/areas/reich/pkatable/index.htm); the lattermost range effectively covering the imidazolium compounds likely to provide enhanced/optimal CO 2 sorption by the ionic liquid. The salts derived from the imidazolium cation can be preferred, without being bound by theory, in some embodiments because their almost planar structure makes them have the character of amidines, particularly those derived from the 1,3-di(lower alkyl) imidazolium cations, where lower alkyl is C 1 -C 6 (preferably C 1 -C 4 ) alkyl. However, the 1,3-substituents of the imidazolium, benzimidazolium, and/or imidazolidinium cations and/or the N-substituents of the thiazolium cations may include or be other groups, such as aryl (including mesityl (2,4,6-trimethylphenyl)), higher alkyl (e.g., C 7 -C 24 ), cycloalkyl, alkenyl (e.g., C 1 -C 6 ), hydroxyalkyl (e.g., hydroxy-functionalized C 1 -C 6 ), glycol ether, and substituted (C 1 -C 16 , e.g., C 1 -C 6 ) alkyl, wherein a substituent of the alkyl group is a heteroatomic group, aryl, alkenyl, and/or other functionality. The imidazolium, benzimidazolium, thiazolium, and/or imidazolidinium cations may additionally or alternately bear substituents of similar nature at the ring carbon atom positions which do not react with CO 2 via the acidic hydrogen atom.

In the absence of a non-nucleophilic nitrogenous base promoter as described below, it appears that the pK a of the anion of the ionic liquid may be effective to vary the liquid's capability to react with CO 2 . In this case, preferred anions for forming salts with the cations of the ionic liquid can include those in which the conjugate acid of the counterion has a pK a as measured and/or predicted at ˜25° C. in aqueous solution (or as measured in other solvent and converted to an aqueous value, referred to as aqueous equivalent scale) of at least 0, for example of at least 2.0 or of at least 4.0. The anion of the ionic liquid salt can affect its ability to act as an agent for CO 2 capture, with more basic anions (such as acetate and/or thiocyanate) enhancing chemisorption and less basic anions (such as chloride) being ineffective and/or less effective in enhancing chemisorption. A useful means of making an adequate prediction of the pK a value of the counterion can include use of the ACD/PhysChem Suite™ (a suite of software tools for the prediction of basic physicochemical properties including pK a ), available from Advanced Chemistry Development, Inc., 110 Yonge Street, Toronto, Ontario, Canada M5C 1T4.

A preferred class of imidazolium salts includes the 1,3-dialkyl substituted imidazolium salts, with preference for the acetate salts as exemplified by 1-ethyl-3-methyl imidazolium acetate and 1-butyl-3-methyl imidazolium acetate, but other salts may be considered, such as those with halide, thiocyanate, and/or lower alkyl chain carboxylate anions (including acetate, propionate, hexanoate, octanoate, decanoate, and the like, as well as combinations thereof) as well as methanesulfonate, thiocyanate, salicylate, tetracholoroaluminate-aluminum chloride, dioctylsulfosuccinate, alkylbenzenesulfonate (alkyl=e.g., dodecyl), trifluoromethyl sulfonate, sulfate, bromide, methanesulfonate, alkylsulfate, tetrachloroaluminate, dicyanamide, hexafluoroantimonate, bis(trifluoromethylsulfonyl)imide, iodide, trifluorosulfonate, nitrate, tosylate, bis(2,4,4-trimethylpentyl)phosphinate, dibutylphosphate, lactate, and the like, as well as combinations thereof.

The ionic liquid can advantageously be selected to be substantially liquid over the temperature range at which the process is to be operated. Normally, the melting point of the liquid can therefore be at least ˜10° C. (e.g., at least ˜20° C.). Similarly, the boiling point can be sufficiently high to preclude significant evaporation at process operating temperatures, although this is unlikely to be a significant problem with most ionic liquids, which are generally characterized by high boiling points. The viscosity of the liquid, especially when containing the chemisorbed CO 2 , can be a factor to be controlled in order to maintain pumpability. This may be determined empirically, considering also the potential use of solvent and/or the concentration of the chemisorbed species in the liquid sorbent under process conditions.

Taking imidazolium salts as an example, the sorption reaction with CO 2 can proceed by a reaction involving carboxylation at the C-2 carbon of the imidazole ring, as follows:

This reaction between the CO 2 and the ionic liquid can proceeds easily (and qualitatively or quantitatively reversibly) upon heating to provide a convenient liquid-phase CO 2 capture-regeneration process. A limited temperature differential between the sorption and desorption steps can make for an energy efficient cyclic separation process with the potential for a substantially isothermal sorption-desorption cycle.

The C-carboxylation reaction between CO 2 and the ionic liquid can be promoted by the presence of a strong non-nucleophilic nitrogenous base having a pKa as measured and/or predicted at ˜25° C. in aqueous solution (or as measured in other solvent and converted to an aqueous value, referred to as aqueous equivalent scale) of at least 10.0, for example at least 12.0 or at least 13.0. The ACD/PhysChem Suite™ may be used for making a prediction of the pKa value of the base in many cases. While bases such as tertiary amines with pKa's as low as about 10.0 can tend not to increase reaction yield with acetate-anion ionic liquids, they appear to have the potential to promote the reaction with thiocyanate-anion ionic liquids and other salts with counterions that may not favor optimal CO 2 sorption.

The base can advantageously be strong enough to influence the C-carboxylation product equilibrium effectively, but, on the other hand, advantageously not so strong as to sufficiently stabilize the carboxylated reaction product to the point of irreversibility, making desorption of the CO 2 from the carboxylated reaction product difficult or infeasible, e.g., by an inconveniently high temperature requirement. Additionally, the protonated form of the base should preferably remain quantitatively available to the ionic liquid for deprotonation/regeneration during the CO 2 desorption step of the cycle. Unacceptable bases can include those that give overly volatile protonated species, species that precipitate from the sorbent phase, species that may influence the reaction chemistry of CO 2 (e.g., hydroxide bases that form water upon protonation), and/or the like. The base should also preferably lack the propensity to act as a competing nucleophile towards CO 2 under the conditions of the sorption process. The non-nucleophilic nitrogenous bases selected according to the above criteria can function as excellent promoters for ionic liquid C-carboxylation with CO 2 in the chemisorption reaction.

When the non-nucleophilic nitrogenous base is used as a promoter for the ionic liquid chemisorption reaction, the base can appear to function as a Bronsted base, sequestering the proton of the C-carboxylation product (or at least influencing the C-carboxylation equilibrium) in such a way that larger yields can be obtained. The reaction, using an imidazolium salt as an exemplary ionic liquid, may be represented as:

Non-nucleophilic nitrogenous bases useful for promoting the carboxylation reaction with the ionic liquid sorbents can include cyclic, multicyclic, and acyclic structures, such as imines, heterocyclic imines and amines, amidines (carboxamidines), including the N,N-di(lower alkyl) carboxamidines (e.g., lower alkyl preferably being C 1 -C 6 alkyl), N-methyltetrahydropyrimidine, 1,8-diazabicyclo[5.4.0]-undece-7-ene (DBU), 1,5,7-triazabicyclo[4.4.0]dec-5-ene (TBD), 7-methyl-1,5,7-triazabicyclo[4.4.0]dec-5-ene (MTBD), 1,5-diazabicyclo[4.3.0]non-5-ene (DBN), guanidines, including substituted guanidines of the formula (R 1 R 2 N)(R 3 R 4 N)C═N—R 5 where R 1 , R 2 , R 3 , and R 4 are preferably lower alkyl (e.g., C 1 -C 6 ) and R 5 is preferably H, such as 1,1,3,3-tetramethylguanidine, and combinations thereof. Additionally or alternately, other substituents, such as higher alkyl, cycloalkyl, aryl, alkenyl, and substituted alkyl as defined previously, and other structures may be used. These strong nitrogenous bases can typically be used on a 1:1 molar basis with the ionic liquid, although they may be present or used in molar excess with a higher reaction yield expected with a higher concentration of base in the solution. Because such bases they can be non-nucleophilic under the conditions of the sorption process, they may advantageously not engage in an N-carboxylation reaction with CO 2 .

The selected ionic liquid can function to trap the CO 2 by chemisorption. The ionic liquids have not shown themselves to be effective for non-reactive physisorption at low pressures, typically below 1 to 2 bara (100−200 kPaa); although both chemisorption and physisorption may take place under such conditions, one or the other may be the predominant mode of CO 2 uptake, depending upon the sorbent medium and operating conditions. Such low pressures can be typical of those encountered in treating flue gases from hydrocarbon combustion processes; the present process lends itself well to post combustion flue gas CO 2 capture when CO 2 partial pressures are in the range of about 0.03 to 2 bara (about 0.5 to 30 psia, or about 3 to 200 kPaa).

The ionic liquid and the optional non-nucleophilic nitrogenous base may be used alone or taken up in an aprotic, preferably polar non-aqueous solvent of the type described in U.S. Application Ser. No. 61/381,351, filed Sep. 9, 2010, to which reference is made for a description of such solvents and their use in a CO 2 sorption process. In some embodiments, the use of the additional solvent can be less desirable, unless required to achieve a liquid of appropriate viscosity and pumpability, since it may diminish the sorption capacity of the system. If used, the solvent may typically be used in a ratio of up to about 1:1 molar (solvent:ionic liquid). Solvents such as toluene, dimethylsulfoxide, dimethylformamide, sulfolane, N-methyl-2-pyrrolidone, propylene carbonate, dimethyl ethers of ethylene and propylene glycols, tetrahydrofuran, and the like may accordingly be used.

The ionic liquids can additionally be capable of suppressing formation of the carbamate/bicarbonate product when water is present in the system. This can be significant, since, in the processing of flue gas as well as natural gas streams, water may be introduced into the system. However, as discussed prior, if significant amounts of water are present in the CO 2 -containing feedstreams, it is recommended that such stream be dewatered/dehumidified prior to contacting with the absorbent materials and processes described herein.

Absorption/Desorption Conditions

The ionic liquid sorbent is not necessarily limited to removal of CO 2 but, in view of the system chemistry, can be capable of removing H 2 S and/or other acid gases such as those typically found in flue gas and/or wellhead natural gas.

The gas mixture containing carbon dioxide can originate from natural and/or artificial sources. The gas mixture can contain, in addition to carbon dioxide, one or more other gases, such as methane, ethane, n-butane, i-butane, hydrogen, carbon monoxide, ethene, ethyne, propene, nitrogen, oxygen, helium, neon, argon, krypton, hydrogen sulfide, and the like.

The constituents of the gas mixture may have different proportions. The amount of carbon dioxide in the gas mixture can typically be at least 1 percent by volume, for example at least 10 percent by volume or 50 percent by volume or greater. The gas mixture can include or be any of a variety of gases, for example, natural gas, flue gas, fuel gas, waste gas, air, or the like, or combinations thereof.

The absorption conditions (i.e., temperature, pressure, and/or the like) can advantageously be favorable for selectively absorbing the CO 2 component of the gas mixture to produce an absorption effluent gas stream having a reduced concentration of the absorbed component. The CO 2 loadings on the sorbent liquid in normal operation may typically be less than the equilibrium concentration observed in batch operation, since complete sorption may not occur, e.g., as a result of the kinetics of the process when in operation on a full scale and/or as a result of other factors such as contact efficiency between the gas phase and the sorbent liquid, corrosion concerns, and the like. The loadings actually achieved can depend on the ionic liquid and/or the optional non-nucleophilic nitrogenous base, the efficiency of the contacting in the absorber, the average residence time in the absorber, and/or other factors, but can be up to about 90% of the theoretical 1:1 molar loading may be achieved. The initial nucleophilic reaction between the amine and the CO 2 tends to be relatively fast, and the second rearrangement of the zwitterion can supposedly take place instantaneously, implying that the sorption should typically not be dependent on average residence time in the absorber; the effectiveness and efficiency of the sparging and contacting may, however, create practical barriers to achieving maximal CO 2 sorption.

For absorption processes herein, the temperature can typically be in the range from about 20° C. to about 90° C., for example from about 25° C. to about 75° C., from about 45° C. to about 75° C., or from about 45° C. to about 90° C., with greater sorption typically achieved at lower temperatures within these ranges. In most cases, therefore, a maximum temperature for the sorption can be about 80° C. (or alternately about 70° C.). The sorption temperature can typically correlate in an inverse manner with the partial pressure of the CO 2 in the entering gas stream; higher CO 2 partial pressures can enable higher sorption temperatures to be used. For example, the lowest possible sorption temperature can be beneficial in treating feedstreams (e.g., flue gas) with ˜100 mbar (˜10 kPa) partial pressure of CO 2 . Conversely, absorption can be achieved at much higher temperatures, possibly over 100° C., with feedstreams (e.g., natural gas streams) with much higher CO 2 pressure. For flue gas streams, for instance, it can be desirable to operate towards the higher end of the temperature range, since the flue gas can tend to be hot, unless initially cooled to make sorption more favorable. In each case, however, the absorption temperature can be tailored for the sorbent system in use and with regard to the desorption temperature required for that system. The possibility opened up by the use of low sorption temperatures from about 20° C. to about 50° C. or from about 20° C. to about 30° C., however, can offer the possibility of using desorption temperatures below 100° C., e.g., about 75° C. to about 90° C. or about 50° C. to about 90° C., respectively, with consequent savings in process energy requirements.

The absorption pressure can be in the range from about 0.1 barg (about 10 kPag) to about 20 barg (about 2 MPag), for example from about 0.1 barg (about 10 kPag) to about 10 barg (about 1 MPag). The partial pressure of carbon dioxide in the gas mixture can vary according to the gas composition and/or the pressure of operation, but can typically be from about 0.1 barg (about 10 kPag) to about 20 barg (about 2 MPag), for example from about 0.1 barg (about 10 kPag) to about 10 bar (about 1 MPag). The gas mixture can be contacted countercurrently or co-currently with the absorbent material at a gas hourly space velocity (GHSV) from about 50 (S.T.P.)/hour to about 50,000 (S.T.P.)/hour.

The low pressure of flue gas can, in general, represent a significant limitation for CO 2 recovery, since the CO 2 can be absorbed much more easily into solvents at higher pressures, but the cost of compression can be relatively high and can tend not to be favored with the present sorption systems with their high sorption capacities. The pressure when treating flue gas which enters from the combustion source at a low pressure is unlikely to exceed about 1 atmosphere gauge (˜100 kPag) unless a separate means is utilized to increase pressure. Natural gas recovery and processing is commonly at a much higher pressure and may enter the treatment process at a pressure typically in the range from about 1 atm (˜100 kPag) to about 90 atm (˜9.1 MPag), with the actual value selected being dependent on pipelining specifications and/or the extent to which it is desired to eliminate recompression following treatment, for example.

The carbon dioxide can be desorbed from the absorbent material by one or more of several methods. One possibility can be to desorb the carbon dioxide by means of stripping with an inert (generally non-reactive) gas stream such as nitrogen in the regeneration tower. The reduction in the CO 2 partial pressure that can occur on stripping can promote desorption of the CO 2 , and, when this expedient is used, a significant pressure reduction may not be required, although the pressure may be reduced for optimal/better stripping, suitably to the levels used in pressure swing operation. Additionally or alternately, a pressure swing process may be used to reduce the pressure on the liquid absorbent to a relatively lower value than that prevailing in the sorption phase.

When carrying out desorption by inert gas sparging and/or pressure swing operation, the temperature may be maintained at a value at or close to that used in the adsorption step. Desorption can, however, be favored by an increase in temperature, with or without stripping and/or a decrease in pressure.

When the absorbent is loaded with CO 2 to a satisfactory level, the sorbent system can be regenerated by desorption of the CO 2 . Regeneration can be conveniently effected in a regeneration tower, e.g., by reducing the partial pressure of the CO 2 by stripping with a non-reactive gas such as nitrogen, by increasing the temperature of the amine rich stream from the absorber, and/or by reducing the pressure, or a combination of any of these expedients. During this step, the CO 2 may be removed and can be taken to utilization and/or sequestration and the sorbent medium freed for recycle to the absorber. An additional or alternative option can be to decompose the carbamate/carbamic acid with substantially pure CO 2 (previously isolated) at ˜1 atm (˜100 kPa partial pressure) or higher at relatively high temperatures, typically at least 120° C., at which the carbamic acid/carbamate reaction product can be decomposed. Stripping with a CO 2 stream at a desorption temperature of at least 120° C. and at a pressure greater than ˜1 atm (˜100 kPa partial pressure) may give a significant advantage in order to remove any water that may have entered the system since under these conditions; water can thus be removed from the amine/ionic liquid solution and can be separated from the CO 2 in a further downstream separation step, e.g., a pressure swing operation, for instance at an elevated temperature above ambient.

In principle, the ionic liquid sorbent medium containing the base can manage trace amounts of water entering with the gas stream by using a molar excess of base, which can form a bicarbonate product with CO 2 and H 2 O, while the ionic liquid can react with CO 2 and the majority of base. The bicarbonate formed by reaction of the water with the excess base can be decomposed at temperatures above ˜100° C. (typically at ˜100-140° C., depending on the basicity of the base).

In any event, the desorption temperature can typically be about 120° C. or less, and successful desorption may be achievable at temperatures not exceeding about 100° C. (e.g., from about 70° C. to about 90° C., from about 70° C. to about 95° C., from about 75° C. to about 90° C., or from about 75° C. to about 95° C.), with lower values (e.g., from about 30° C. to about 70° C., from about 30° C. to about 50° C., or from about 50° C. to about 70° C.) if sorption is carried out at low temperature. In the non-aqueous environment using the ionic liquid solvent, stripping can be feasible with or without purge gas at relatively lower temperatures. The possibility of desorption at lower temperatures can offer the potential for isothermal (or near isothermal) stripping using a purge gas at a temperature the same as, or not much higher than, the sorption temperature (for example, at a temperature not more than 30° C. higher than the sorption temperature); in favorable cases, it may be possible to attain a sorption/desorption temperature differential of no more than 20° C.

As noted above, the flue gases which may be treated by the present process include water from the combustion process; untreated natural gas may be similar. With desorption/regeneration temperatures above 100° C., any water entering the system will be kept at a low level and for this reason competing reactions will not be significant. Water entering the low temperature processes with desorption/regeneration operating at temperatures under 100° C. may be driven off by the stripping which takes place during the regeneration. The entering gas stream can, however, be dehumidified prior to contacting with the sorbent solution. The dehumidification can be carried out by conventional methods. For example, the dehumidification can be carried out by absorption over solid sorbents such as molecular sieves, silica gels or aluminas or by cooling to condense the water content of the stream.

It should be appreciated that conventional equipment can be used, in whole or in part, to perform the various functions of the non-aqueous amine scrubbing processes/steps described herein, such as monitoring and/or automatically regulating the flow of gases, e.g., to enable fully automated and/or continuous process control in an efficient manner.