Water control in non-aqueous acid gas recovery systems

Abstract

This invention is directed to methods and systems for controlling water in acid gas removal processes comprising the steps of a) treating the gas stream in an absorption zone with the NAS absorption liquid; b) direction the acid gas-loaded NAS absorption liquid to a regeneration zone; c) directing the regenerated NAS absorption liquid to step a); and d) controlling the first and second set of conditions.

Claims

1. A process for regulating water content and removing acid gases from a water-containing gas stream using a non-aqueous solvent (NAS) absorption liquid, wherein the NAS absorption liquid has a solubility of less than about 10 g of water per 100 g of NAS which comprises: (a) treating the gas stream in an absorption zone with the NAS absorption liquid under a first set of controlled conditions of temperature, pressure and flow rate to obtain an acid gas-depleted treated gas stream and an acid gas-loaded NAS absorption liquid; (b) directing the acid gas-loaded NAS absorption liquid to a regeneration zone under a second set of controlled conditions of temperature, pressure and flow rate and regenerating the loaded NAS absorption liquid to expel a portion of the acid gases and obtain a regenerated NAS absorption liquid; (c) directing the regenerated NAS absorption liquid to step a); and (d) controlling the first and second set of conditions such that the temperature for the first set of controlled conditions is greater than 30 C. and less than 57 C. so as to avoid the necessity of a separation device to separate a water-rich phase from the NAS absorption liquid, to regulate the water content, and remove acid gases from the water-rich gas stream and wherein the water content is regulated such that the quantity of water entering the process in the water-rich gas stream balances the water content leaving the process in the acid gas-depleted treated gas stream or off gases from the regeneration zone.

2. The process of claim 1, wherein the acid gas is carbon dioxide.

3. The process of claim 1, wherein the water-containing gas stream is from a desulfurization pre-treatment process.

4. The process of claim 1, wherein the gas stream is a flue gas from the combustion of a fossil fuel.

5. The process of claim 1, wherein the gas stream is an exhaust gas from a combustion process.

6. The process of claim 1, wherein the gas stream is an exhaust gas from a cement plant.

7. The process of claim 1, wherein regenerating the loaded NAS absorption liquid occurs by pressure release, heating, stripping or a combination thereof.

8. The process of claim 1, wherein the loaded NAS absorption liquid is preheated by indirect heat exchange with the regenerated absorption liquid.

9. The process of claim 1, wherein the NAS absorption liquid comprises a nitrogenous base; a weak acid having pKa between 8-15; and a hydrophobic, aliphatic diluent or a polyether diluent; or combination thereof.

10. The process of claim 1, wherein the NAS absorption liquid comprises a nitrogenous base having a nitrogen with a hydrogen atom leaving group, a weak acid, and a hydrophobic diluent.

11. The solvent system of claim 1, wherein the solvent system is immiscible with water.

12. The process of claim 9, wherein the nitrogenous base is an amine, an amidine, a guanidine, or a combination thereof.

13. The process of claim 9, wherein the weak acid is a fluorinated alcohol, a phenol, a substituted phenol, or a combination thereof.

14. The process of claim 9, wherein the nitrogenous base is 2-fluorophenylethylamine or N-methylbenzylamine; the weak acid is aniline, octafluoropentanol, phenol, substituted phenol; and the polyether diluent is a substituted ether of polyethylene glycol, a substituted ether of polypropylene glycol, or a mixture thereof.

15. The process of claim 1, wherein the temperature for the first set of controlled conditions are greater than 30 C. and less than 42.5 C.

16. The process of claim 1 wherein the temperature for the first set of controlled conditions are greater than 35 C. and less than 42.5 C.

17. A process for regulating water content and removing acid gases from a water-containing gas stream using a non-aqueous solvent (NAS) absorption liquid, wherein the NAS absorption liquid has a solubility of less than about 10 g of water per 100 g of NAS which comprises: (a) treating the gas stream in an absorption zone with the NAS absorption liquid under a first set of controlled conditions of temperature, pressure and flow rate to obtain an acid gas-depleted treated gas stream and an acid gas-loaded NAS absorption liquid; (b) directing the acid gas-loaded NAS absorption liquid to a regeneration zone under a second set of controlled conditions of temperature, pressure and flow rate and regenerating the loaded NAS absorption liquid to expel a portion of the acid gases and obtain a regenerated NAS absorption liquid; (c) directing the regenerated NAS absorption liquid to step a); and (d) controlling the first and second set of conditions such that the temperature for the first set of controlled conditions is greater than 30 C. and less than 57 C. so as to (i) balance the water content entering the process in the water-rich gas stream with the water content leaving the process and (e) remove acid gases from the water-rich gas stream.

Description

3. BRIEF DESCRIPTION OF THE FIGURES

(1) FIG. 1: Shows a simplified schematic of the lab-scale, continuous flow gas absorption system having a standard absorber-desorber configuration.

(2) FIG. 2: Shows time-on-stream (TOS) data for experiment demonstrating control of the water balance in a NAS CO.sub.2 Removal Process.

(3) FIG. 3: Shows a simplified schematic of LsGAS after 90 h TOS showing presence of a water-rich phase in the CO.sub.2-lean feed stream and no water phase in the absorber or desorber sumps.

(4) FIG. 4: Shows TOS data for experiment demonstrating that the water balance in a NAS CO.sub.2 Removal Process can be controlled and operated without the formation of a separate, water-rich phase.

(5) FIG. 5: Shows a schematic of the key components of one non-limiting embodiment of an acid gas scrubbing process arrangement with a water balancing system.

4. DETAILED DESCRIPTION OF THE INVENTION

(6) The invention describes a method for achieving water balancing in a non-aqueous solvent (NAS) AG removal process and more specifically a CO.sub.2 removal process, avoiding the formation of a water-rich phase that must be mechanically separated from the NAS. In some embodiments, it is preferable to operate the absorber such that the mass of water entering the column in the feed gas stream leaves in the treated gas stream. One approach is to control the feed gas temperature and thus the water content of the feed gas stream while simultaneously controlling the temperature of the treated gas exiting the top of column. Several factors contribute to the temperature of the treated gas exiting the column including the lean solvent feed temperature but more importantly the temperature profile in the absorber. The specific shape of the temperature profile in the absorber is dependent upon the heat of absorption, the gas and liquid heat and mass transfer characteristics, and gas and liquid flow rates.

(7) Due to the exothermic nature of the AG absorption reaction and the counter-current flow of gas and liquid, the temperature profile of the absorber exhibits a maximum or bulge at some intermediary point in the column and as such, the liquid typically leaves the bottom of the column at a temperature greater than the flue gas enters and the treated flue gas typically leaves the top of the column at a temperature greater than the feed solvent. As such, controlling the temperature of the treated gas stream can be used to balance the water in the process, however, since there are many contributing factors to the temperature of the outlet gas stream and there is no single control variable to adjust. One approach to controlling the treated gas temperature exiting the top of the column is to control the temperature of the solvent feed to the absorber. Although not a direct control variable, in most cases it can be used as a good surrogate variable. For the treated gas to carry the same mass of water it must leave the absorber slightly warmer than the flue gas enters the column since both gases are nearly saturated with water and the flow rate of the treated gas exiting the absorber is lower than the feed gas due to the absorption of some fraction of the CO.sub.2 portion of the feed gas stream. For coal-derived flue gas applications, the flow rate of the treated gas is approximately 88% of the feed gas assuming a CO.sub.2 concentration of 13.3% and a capture efficiency of 90%. As such the treated gas must be slightly warmer than the feed gas.

(8) Based on several sets of experiments including three phase (CO.sub.2H.sub.2O-NAS) equilibrium measurements and continuous testing in a lab-scale absorption-regeneration system representing the process, it has been shown that a neutral water balance can be achieved in a NAS CO.sub.2 removal process by: (i) avoiding the formation of a second water phase through adjusting the operating conditions of the absorber and therefore eliminating the need for separation devices and (ii) eliminating the separation device and feeding a biphasic solvent directly to the CO.sub.2 absorber.

(9) Both of these water balancing methods are not described in the prior art and are considered improvements. The proposed water balancing methods: (i) simplify the process design and operation by eliminating separation equipment; (ii) reduce the capital cost of the AG removal process; (iii) create a neutral water balance via ensuring that the treated gas stream contains the same mass of water as the feed gas entering the absorber; (iv) beneficially integrates the water balancing and AG absorption in the same process vessel; and (v) effectively provides the heat required for evaporating water into the gas stream by utilizing the exothermic heat of absorption while simultaneously providing in-situ cooling to the NAS during the absorption process.

(10) In addition, this approach to water balancing is applicable to process operating strategies that lead to the NAS being described as water containing yet forms a single phase and the case where the water content is higher such that there are two phases, a water-rich phase and an NAS-rich phase. In the case that two phases are formed, the water-rich stream can be separated from the NAS and introduced to the absorber top and additionally, in the cases where the solvent is either water containing or a two-phase mixture, the solvent will be returned directly to the top of the absorber without using a water separation device.

(11) 4.1. Definitions

(12) As used herein the term non-aqueous solvent (NAS) means an organic solvent system that is miscible (NAS) means an organic solvent system that is miscible with 0-20% (weight/weight percent water), 0-10% (weight/weight percent) water, and preferably less than 10 (weight/weight percent) water. NAS includes both polar aprotic and protic solvent systems and mixtures thereof. The NAS may be weak acids or nitrogenous bases. The NAS may be a 3-way combination of a weak acid, a nitrogenous base, and a polyether diluent.

(13) 4.2. NAS Systems

(14) In some specific embodiments, the weak acid may be selected from the group consisting of: 2,2,3,3,4,4,5,5-octafluoropentanol (OFP); 2,2,3,3 tetrafluoropropanol (TFP); 2,2,3,3,3-pentafluoropropanol (PFP); 2,2,3,3,4,4-hexafluorobutanol (HFB); 2,2,2-trifluoroethanol (TFE); nonafluoro-1-hexanol; 4,4,5,5,6,6,7,7,7 nonafluoroheptanol; 1,1,3,3-hexafluoro-2-phenyl-2-propanol 4-methoxyphenol (4-MeOPh); 4-ethoxyphenol (4-EtOPh); 2-ethoxyphenol; 4-propoxyphenol; imidazole; benzimidazole; N-methylimidazole; 1-trifluoroacetylimidazole; 1,2,3-triazole; 1,2,4-triazole; 2-trifluoromethylpyrazole; 3,5-bistrifluoromethylpyrazole; 3-trifluoromethylpyrazole; or mixtures thereof. In some embodiments, the weak acid has a pKa of 8-15.

(15) In some embodiments, the nitrogenous base may be a primary or secondary amine, an amidine, or a guanidine. In certain embodiments, the primary or secondary amine may be selected from amines functionalized with fluorine-containing-alkyl-aromatic groups. In specific embodiments, the amine may be selected from the group consisting of 2-fluorophenethylamine; 3-fluorophenethylamine; 4-fluorophenethylamine; 2-fluoro-N-methylbenzylamine; 3-fluoro-N-methylbenzylamine; 4-fluoro-N-methylbenzylamine; 3,5-difluorobenzylamine; D-4-fluoro-alpha-methylbenzylamine; L-4-fluoro-alpha-methylbenzylamine; or mixtures thereof.

(16) In certain embodiments, the nitrogenous base may be selected from the group consisting of 1,4-diazabicyclo-undec-7-ene (DBU); 1,4-diazabicyclo-2,2,2-octane; piperazine (PZ); triethylamine (TEA); 1,1,3,3-tetramethylguanidine (TMG); 1,8-diazabicycloundec-7-ene; monoethanolamine (MBA); diethyl amine (DEA); ethylenediamine (FDA); 1,3-diamino propane; 1,4-diaminobutane; hexamethylenediamine; 1,7-diaminoheptane; diethanolamine; diisopropylamine (DIPA); 4-aminopyridine; pentylamine; hexylamine; heptylamine; octylamine; nonylamine; decylamine; tert-octylamine; dioctylamine; dihexylamine; 2-ethyl-1-hexylamine; 2-fluorophenethylamine; 3-fluorophenethyl amine; 3,5-difluorobenzylamine; 3-fluoro-N-methylbenzylamine; 4-fluoro-N-methylbenzylamine; imidazole; benzimidazole; N-methyl benzylamine; N-methyl imidazole; 1-trifluoroacetylimidazole; 1,2,3-triazole; 1,2,4-triazole; or mixtures thereof. In other embodiments, the nitrogenous base may be a guanidine or an amidine.

(17) Examples of NAS systems may be found in Wang et al. 2010 Angew Chem Int Ed 49 5978-5981; U.S. Pat. Pub. Nos. US 2009/0136402, or US 2009/0220397; and PCT Intl. Pub. Nos. WO 2009/097317, WO 2012/031274, or WO 2012/031281, the contents of which are hereby incorporated by reference in their entireties.

(18) Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. The article a and an are used herein to refer to one or more than one (i.e., to at least one) of the grammatical object(s) of the article. By way of example, an element means one or more elements.

(19) Throughout the specification the word comprising, or variations such as comprises or comprising, will be understood to imply the inclusion of a stated element, integer or step, or group of elements, integers or steps, but not the exclusion of any other element, integer or step, or group of elements, integers or steps. The present invention may suitably comprise, consist of, or consist essentially of, the steps, elements, and/or reagents described in the claims.

(20) It is further noted that the claims may be drafted to exclude any optional element. As such, this statement is intended to serve as antecedent basis for use of such exclusive terminology as solely, only and the like in connection with the recitation of claim elements, or the use of a negative limitation.

(21) Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limits of that range is also specifically disclosed. Each smaller range between any stated value or intervening value in a stated range and any other stated or intervening value in that stated range is encompassed within the invention. The upper and lower limits of these smaller ranges may independently be included or excluded in the range, and each range where either, neither or both limits are included in the smaller ranges is also encompassed within the invention, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the invention.

(22) The following Examples further illustrate the invention and are not intended to limit the scope of the invention. In particular, it is to be understood that this invention is not limited to particular embodiments described, as such may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting, since the scope of the present invention will be limited only by the appended claims.

5. EXAMPLES

5.1. Example 1

Three Phase Equilibrium Measurements to Observe Water Separation in a NAS CO2 Removal System

(23) A 5 mL sample of an exemplary NAS consisting of equimolar portions of 2-fluorophenethylamine (2FPEA) and octafluoropentanol (OFP) and a 5 mL aliquot of DI water were placed in a stirred glass, round bottom flask equipped with an overhead condenser. Excess water was maintained in the vessel at all times to ensure that equilibrium H.sub.2O loading in the NAS was achieved. The pressure of the stirred vessel was maintained at atmospheric pressure. The two phase sample was heated to the desired temperature, i.e., 40, 80, or 90 C., using a electric heater jacket and 100 mL/min of a CO.sub.2N.sub.2 blend gas with various compositions was bubbled through the two phase liquid sample. The CO.sub.2N.sub.2 feed was stopped once the CO.sub.2 concentration in the outlet stream was >99% of the inlet concentration. A 0.9 mL sample from the NAS phase was extracted from the batch vessel using a syringe through a septum and placed in a sealed 2.5 mL autosample vial. 0.1 mL of methanol was added to the sealed vial and analyzed for CO.sub.2, H.sub.2O, and NAS mass composition using an in-house developed gas chromatographic method. Each reported measurement is an average of three replicate injections. A short description (rationale) for the experimental conditions (i.e., temperature, CO.sub.2 concentration in feed) used to prepared each sample is provided in Table 1. Each sample was prepared in a manner that approximates the process conditions at the top and bottom of the absorber and desorber in a conventional AG scrubbing/removal process arrangement.

(24) TABLE-US-00001 TABLE 1 Sam- ple Temp. CO.sub.2 Conc. ID [ C.] [% vol] Rationale 1 40 13 Absorber Inlet; CO.sub.2-rich solvent 2 30 (40) 13 Absorber Inlet; CO.sub.2-rich solvent; Cooled to 30 C. to determine if cooling shifts the H.sub.2O equilibrium 3 40 1.0 Absorber Inlet; Approx. conditions that the CO.sub.2-lean solvent will see upon entering the Absorber; Attempt #1 for matching CO.sub.2 comp. of sample regen. at 80 C. 4 40 0.5 Absorber Inlet; Approx. conditions that the CO.sub.2-lean solvent will see upon entering the Absorber; Attempt #2 for matching CO.sub.2 comp. of sample regen. at 80 C. 5 40 0.1 Absorber Inlet; Approx. conditions that the CO.sub.2-lean solvent will see upon entering the Absorber; Attempt #3 for matching CO.sub.2 comp. of sample regen. at 80 C. 6 80 100 Desorber Inlet; Approx. conditions for the CO.sub.2-rich solvent at 80 C. entering Regenerator 7 80 13 Desorber Outlet; Approx. conditions for the CO.sub.2-rich solvent at 80 C. entering Regenerator 8 40 (80) 13 Absorber Inlet; CO.sub.2-lean solvent regenerated at 80 C.; Cooled to 40 C. to determine if cooling shifts the H.sub.2O equilibrium 9 90 100 Desorber Inlet; Approx. conditions for the CO.sub.2-rich solvent at 90 C. entering Regenerator; 10 40 (90) 100 Absorber Inlet; CO.sub.2-lean solvent regenerated at 90 C.; Cooled to 40 C. to determine if cooling shifts the H.sub.2O equilibrium

(25) The Table 2 reports the equilibrium composition for the samples prepared at the conditions reported in Table 1. A total of 10 samples were prepared.

(26) TABLE-US-00002 TABLE 2 Compositional CO.sub.2 Analysis Sample Temp. Conc. CO.sub.2 H.sub.2O ID [ C.] [% vol] [% wt] [% wt] 1 40 13 2.66 8.70 2 30 (40) 13 2.69 8.82 3 40 1.0 1.63 7.02 4 40 0.5 1.08 5.50 5 40 0.1 0.43 4.67 6 80 100 1.79 10.15 7 80 13 0.56 6.06 8 40 (80) 13 0.57 4.45 9 90 100 0.81 7.47 10 40 (90) 100 0.85 5.22

(27) Samples approximating the CO.sub.2-lean NAS entering the top of the CO.sub.2 absorber (Sample 3-5), were found to have a CO.sub.2 content ranging from 0.43 to 1.63% wt CO.sub.2 and water contents of 4.67 to 7.02% wt H.sub.2O indicating that water content is a strong function of CO.sub.2 content at 40 C., especially at low CO.sub.2 contents in the NAS. These results indicate that the leaner the NAS returns from the desorber, the less likely a separate aqueous phase will form in the CO.sub.2 absorber. A sample approximating the CO.sub.2-rich NAS exiting the bottom of the absorber (Sample 1) was found to have a CO.sub.2 content of 2.66% wt CO.sub.2 and a water content of 8.70% wt H.sub.2O. Comparing the water content of the CO.sub.2-rich sample (1) to that of the CO.sub.2-lean samples (3-5), it is seen that the water content does not increase linearly with CO.sub.2 content and, in fact, that water content increases most significantly at lower CO.sub.2 contents. As stated above, the CO.sub.2 content of the CO.sub.2-lean NAS returning from the desorber can significantly affect the appearance of a second water phase in the absorber. Considering that the flue gas from a typical 500 MWe power plant carries with it 500,000 lbs/hr of water, the CO.sub.2-rich NAS at the bottom of the absorber would not be saturated with water for NASs returning to the absorber with a water content <6.5 to 7.0 wt % H.sub.2O.

(28) A 4 mL aliquot of the NAS phase form the CO.sub.2-rich sample (Sample 1) was extracted from the batch vessel and placed in a 5 mL sealed vial and cooled from 40 C. to 30 C. in a temperature controlled oven to determine if cooling the CO.sub.2 and H.sub.2O-rich solvent could shift the H.sub.2O equilibrium thus creating a second water-rich phase (Sample 2). Although the compositional analysis indicates a small increase in the CO.sub.2 and H.sub.2O content with decreasing temperature, comparing sample 1 and 2, this is not physically possible because no additional CO.sub.2 or water were added to the 5 mL vial. The small difference in the CO2 and H2O contents is within the tolerance of the analytical method. A second liquid phase, a water-rich phase, was visually observed as a small globule floating on top of the NAS phase indicating that cooling the CO.sub.2-rich NAS from 40 C. to 30 C. reduced the water content of the NAS phase but only by a very small amount.

(29) A sample approximating the hot NAS entering the desorber (Sample 6) was prepared at 80 C. and 100% CO.sub.2 (1 atm CO.sub.2). These conditions represent the condition of the NAS exiting the desorber. At 80 C. and 1 atm CO.sub.2, the CO.sub.2 content of the NAS was found to be 1.79 wt % CO.sub.2 which closely matches the CO.sub.2 content of the sample prepared at 40 C. and 1% CO.sub.2 (0.01 atm) (Sample 3). This suggests that under these absorber and desorber conditions, the process could operate continuously and in a balanced manner, at least with respect to CO.sub.2, and achieve 90% CO.sub.2 capture and generate a 1 atm CO.sub.2 product stream. The water content of the 80 C. sample (Sample 6) was found to be 10.15 wt % H.sub.2O. Comparing the water content of Sample 6 (80 C.) and 3 (40 C.), which have comparable CO.sub.2 content, suggests that water content of the NAS is strongly dependent upon temperature. In fact, the regenerated solvent has a higher water content at 80 C. than the CO.sub.2-rich NAS exiting the absorber (Sample 1). Therefore, under this desorber condition (80 C. & 1 atm), it is highly unlikely that water will separate from the NAS in the desorber.

(30) A sample was prepared at 80 C. and 0.13 atm CO.sub.2 (Sample 7) to achieve a CO.sub.2 content in the CO.sub.2 lean NAS. The CO.sub.2 content decreased from 1.79 to 0.56% wt CO.sub.2, a three-fold decrease, while the water content decreased from 10.15 to 6.06% wt H.sub.2O indicating a strong dependence of the water content in the NAS phase upon the CO.sub.2 content of the NAS phase. Under these desorber conditions, water would form a separate and distinct phase in the desorber given adequate settling time. Although the CO.sub.2 partial pressure appears to be low at first glance, it is a possible condition, although not preferred in this process arrangement, in the desorber if water in the NAS is evaporated effectively becoming a stripping agent and lowering the CO.sub.2 partial pressure. Although there may be benefit from this in terms of broadening the CO.sub.2 working capacity of the NAS, it comes at the cost of an increase energy penalty due to the energy required to vaporize the water and as such this is not a desired operating condition.

(31) A 4 mL aliquot of the NAS phase from Sample 7 was extracted, using a similar method as described above, and cooled in a temperature controlled oven to 40 C. in a closed, sealed vial (Sample 8). Upon cooling, a second liquid phase, a water-rich phase, was formed which was clearly visible. The water content of the NAS phase decreased from 6.06 (Sample 7) to 4.45% wt (Sample 8) and the CO.sub.2 and water content of the cooled sample closely matched that of Sample 5 indicating that the cooled sample achieved an expected equilibrium value although it was prepared in a different manner.

(32) A sample approximating the hot NAS entering the desorber (Sample 9) was prepared at 90 C. under 100% CO.sub.2 (1 atm CO.sub.2). At 90 C. and 1 atm CO.sub.2, the CO.sub.2 content of the NAS was found to be 0.81 wt % CO.sub.2 which closely matches the CO.sub.2 content of the sample (Sample 4) prepared at 40 C. and 0.05% CO.sub.2 (0.005 atm). This suggests that under these absorber and desorber conditions, the process could operate continuously and in a balanced manner, at least with respect to CO.sub.2, and achieve 90% CO.sub.2 capture and generate a 1 atm CO.sub.2 product stream. The water content of the 90 C. sample (Sample 9) was found to be 7.47 wt %. Comparing the water content of Sample 9 (90 C.) and 4 (40 C.), which have comparable CO.sub.2 content, once again suggests that the water content of the NAS phase is strongly dependent upon temperature. In fact, the regenerated NAS has nearly the same water content at 90 C. as the CO.sub.2-rich NAS exiting the absorber (Sample 1).

(33) A 4 mL aliquot of the NAS phase from Sample 9 was extracted, using a similar method as described above, and cooled in a temperature controlled oven to 40 C. in a closed, sealed vial (Sample 10). Upon cooling, a second liquid phase, a water-rich phase, was formed that was clearly visible. Compositional analysis of NAS phase revealed that the water content decrease from 7.47 (Sample 9) to 5.22% wt (Sample 10) and that the CO.sub.2 and water content of the cooled sample closely matched that of Sample 4 indicating that the cooled sample achieved an expected equilibrium value although it was prepared in a different manner.

(34) Example 1 clear shows that forming a separate water-rich phase in the absorber is highly unlikely and is only possible if the CO.sub.2-lean NAS returning from the desorber is very rich in CO.sub.2 and thus contains a high water content. As long as the CO.sub.2-lean NAS returns to the absorber having a water content <6.5-7.0 wt %, the NAS will not become saturated with water from the feed flue gas and only one phase will be present in the Absorber. In addition, the process can be operated in a manner such that water does not separate from the NAS in the desorber or desorber sump, which is undesirable from an energetics perspective in that water vaporization is energy intensive. And finally, based on this set of experiments, the most likely location in the NAS CO.sub.2 removal process for water to separate from the NAS and form a separate water-rich phase is upon cooling of the regenerated solvent prior to returning the CO.sub.2-lean NAS to the CO.sub.2 absorber feed.

(35) Further, Example 1 teaches the following: the water content of the NAS is affected by temperature, CO.sub.2 partial pressure, the CO.sub.2 content of the NAS, and the NAS formulation the water content of the NAS can be manipulated/controlled by controlling process parameters including the temperature of the NAS, CO.sub.2 partial pressure, the CO.sub.2 content of the NAS, and the NAS formulation the formation of a separate, water-rich phase in the presence of a NAS can be controlled by process parameters including temperature, CO.sub.2 partial pressure, the CO.sub.2 content of the NAS, and the NAS formulation through proper operation of the process, it is unlikely that the CO.sub.2-rich NAS exiting the absorber will be saturated with water or that a water-rich phase will be formed in the CO.sub.2 absorber for this specific NAS formulation, there is insufficient water in a typical flue gas stream to saturate the CO.sub.2-rich solvent exiting the absorber or to form a second, water-rich phase in the absorber the formation of a separate water-rich phase in the desorber is controllable and most importantly can be avoided through proper control of the process conditions a NAS process can be operated in a manner that a separate water-rich phase can be avoided in the main process vessels including absorber and desorber

5.2. Example 2

Water Balance in a NAS CO2 Removal Process

(36) An experiment was performed in a lab-scale, continuous flow gas absorption system having a standard absorber-desorber configuration to experimentally demonstrate control of the water balance in a NAS CO.sub.2 removal process. A simplified schematic of the LsGAS is provided in FIG. 1 and the operating conditions are provided in Table 3. An exemplary NAS consisting of equimolar portions of 2-fluorophenethylamine (2FPEA) and octafluoropentanol (OFP) was used in this study. Selected process measurements from this experiment are presented in FIG. 2. Under these conditions the system was found to be very stable over the entire 100 h experiment exhibiting a CO.sub.2 capture efficiency of 85% and a CO.sub.2 balance of 102%2%.

(37) TABLE-US-00003 TABLE 3 Feed Gas Flow Rate 3 SLPM Composition 13.3% CO.sub.2, 5.65% H.sub.2O (sat @ 35 C.), Bal. N.sub.2 Temperature 40 C. Absorber Flow Rate 23 g/min Inlet Temp. 40 C. Pressure 1 atm Desorber Temp. 90 C. Pressure 1 atm

(38) Results presented in FIG. 2 show that the NAS CO.sub.2 removal process operated in a stable manner over the entire 100 h experiment. After approximately 60 h time on stream (TOS), a second, water-rich, phase was observed in the CO.sub.2-lean NAS feed to the absorber downstream of the solvent cooler as can be seen in FIG. 3. Operating the system under these specific process conditions resulted in the system having a neutral water balance over a period of 100 h with the majority of the water being introduced to the system leaving via the treated flue gas (absorber outlet). In addition, under these conditions, the system was found to operate in a manner consistent with that described in EXAMPLE 1, in which a water-NAS mixture is fed to the top of the absorber as a means of water balancing the process by humidifying (ideally saturating) the treated gas.

(39) This experiment demonstrated that the formation of a water-rich phase can be avoided in the absorber and desorber sumps through control of the process operating conditions thus eliminating the necessity for a water-NAS separation device and the formation a water-rich stream containing trace quantities of NAS that must be mechanically separated.

(40) Further, Example 2 teaches: that the teachings from Example 1, which were based on equilibrium measurements, are correct and have been validated in a continuous flow process arrangement consistent with a commercial AG scrubbing/removal process that a NAS AG scrubbing process and particularly a CO.sub.2 removal process can be operated such that water, which is introduced to the process in the feed gas to the absorber, can be balanced by leaving in the process in the treated gas exiting the absorber that a NAS acid-gas scrubbing process can be operated in a manner that avoids the formation of a separate, water-rich phase in the desorber that a NAS acid-gas scrubbing process can be operated such that the treated gas exiting the Absorber carries a majority of the water that enters in the feed gas to the absorber from the process that a NAS acid-gas scrubbing process can be operated such that the most likely position in the process for water separated from the NAS is downstream of the solvent cooler

5.3 Example 3

Controlling the Water Balance in a NAS CO2 Removal Process (Study #1)

(41) An experiment was performed to demonstrate that the formation of a water-rich phase can be avoided in the process through control of the operating conditions of the CO.sub.2 absorber thus eliminating the necessity for a water-NAS separation device and creating a single phase NAS process. Specifically, operating the process such that water-rich stream containing trace quantities of NAS is eliminated.

(42) A simplified schematic of the LsGAS is provided in FIG. 1 and the operating conditions are provided in Table 3. An exemplary NAS consisting of equimolar portions of 2-fluorophenethylamine (2FPEA) and octafluoropentanol (OFP) was used in this study. For the treated gas to carry the same mass of water it must leave the absorber slightly warmer than the flue gas enters the column since both gases are approximately saturated with water and the flow rate of the treated gas is lower than the feed gas due to the removal of the CO.sub.2. In this case, the feed gas entered the absorber saturated at 38 C. which corresponds to a mass flow rate of water of 9.49 g.sub.H2O/h. In the case that the treated flue gas leaves the column at the same temperature as feed solvent, 40 C., assuming that the gas is saturated with water it will carry with it 9.27 g.sub.H2O/h. The expected accumulation rate of 0.22 g.sub.H2O/h is small considering the scale of the system the amount of heat loss to the environment and the fact that the treated gas will be warmer than the solvent. Therefore, it was expected that these operating conditions will lead to a neutral water balance.

(43) Selected process measurements from this experiment are presented in

(44) FIG. 3: Shows a simplified schematic of LsGAS after 90 h TOS showing presence of a water-rich phase in the CO.sub.2-lean feed stream and no water phase in the absorber or desorber sumps.

(45) FIG. 4. From these results it is seen that the system was stable and operable over a 225 h period. For the first 175 h (7.5 days) the operating conditions were maintained at those described in Table 3. Under these conditions, the system was found to operate in a stable manner without the appearance of a water-rich phase in the process, however, the CO.sub.2 capture efficiency was found to be dependent upon the NAS composition as exhibited by the saw-tooth shape of the CO.sub.2 capture efficiency. The water content of the NAS under these conditions was found to be quite stable at 2 wt %, which is much lower than the saturation level of 8 wt % (based on equilibrium measurements). As such, the water content of the solvent is below its saturation level.

(46) After 175 h TOS, the temperature of the CO.sub.2-lean NAS feed was reduced to 38 C. as a means of reducing the temperature of the treated flue gas to determine if the water content of the NAS could be increased while still avoiding the formation of a water-rich phase. Reducing the feed temperature by 2 C. increased the water content in the solvent from 2 wt % to 6-7 wt % in less than 24 hours and over the next 70 h no water-rich phase was observed. Reducing the temperature of the solvent feed immediately improved the CO.sub.2 capture efficiency from 70% to 88% and dramatically improved the stability of the performance.

(47) These results indicate that the water balance, water content in the NAS, and the appearance of a water-rich phase in the process can be controlled by manipulation of process conditions including the temperature profile of the absorber.

(48) Further, Example 3 teaches: that the water content of the NAS in a NAS AG removal process and particularly a NAS CO.sub.2 removal process can be varied by control of process parameters that the formation of a separate water-rich phase can be avoided in a NAS AG removal process and particularly a NAS CO.sub.2 removal process the water balance in a NAS AG removal process and particularly a NAS CO.sub.2 removal process can be maintained by control of the process such that a majority of the water entering the process in the feed gas leaves the process in the treated gas stream

5.4 Example 4

Controlling the Water Balance in a NAS CO2 Removal Process (Study #2)

(49) This experiment was performed to demonstrate that the water balance in the NAS process can be controlled by manipulating process parameters. The goal of this work was to show that the water balance could be controlled, that the water content in the process could be controlled, and that multiple water balance conditions exist. This experiment consisted of operating the process at four different conditions described in Table 4 with all other process conditions remaining the same. An exemplary NAS consisting of equimolar portions of 2-fluorophenethylamine (2FPEA) and octafluoropentanol (OFP) was used in this study.

(50) TABLE-US-00004 TABLE 4 Water Balanced Water Water Balanced -Condition 1- Accumulating Water Stripping -Condition 2- Gas Feed Temperature 37.2 40.0 35.0 40.0 [ C.] Absorber Gas Outlet 40.0 40.0 40.0 42.5 Temperature [ C.] Expected Rate of 0 1.25 1.25 0 Water Accum. [g h.sup.1]

(51) Results from this experiment are presented in Table 5. Under Water BalancedCondition #1 conditions, the process was found to maintain a water balance over a 24 hour period with a rate of water accumulation of approximately 0.01 g/h. Under these conditions, no separate, water-rich phase observed in the process and in fact the water content in the NAS was approximately 1.32% wt H.sub.2O which is below the saturation level. This experiment verified that the process could be operated and controlled in a water balanced manner.

(52) The process operating conditions were then adjusted such that a water balance was not maintained and water would accumulate Water Accumulating. Within 24 hours of operation under these conditions, the water content of the NAS increased to the saturation level, approximately 7.6% wt H.sub.2O, and in fact exceeded the saturation level of the solvent resulting in the formation of water-rich phase in the process. This water-rich phase was visually observed in the desorber sump. The measured rate of water accumulation was found to be +0.29 g/h verifying that the water balance is positive and therefore more water is entering and accumulating within the process then exiting. This experiment verified that the process could be operated and controlled such that the water balanced could be shifted to water accumulating conditions.

(53) The process operating conditions were then adjusted such that the water balance shifted to Water Stripping conditions. Under these conditions, more water leaves the process than is being introduced. Within 24 hours of operation under these conditions, the water-rich phase in the desorber sump was eliminated and the water content of the NAS decreased to below the saturation level. The measured rate of water accumulation was found to be 0.42 g/h verifying that the water balance is negative and therefore more water is leaving the process then entering. This experiment verified that the process could be operated and controlled such that the water balanced could be shifted to water stripping conditions.

(54) The process operating conditions were then adjusted such that the water balance shifted to Water BalancedCondition #2 conditions. Under these conditions, the process is predicted to operate in a water balanced condition. The objective of this experiment was to demonstrate that there are numerous water balanced conditions that is that the net rate of water accumulation is zero. In this experiment, two conditions are demonstrated but more can be envisioned. Under these conditions, the measured rate of water accumulation was found to be 0.00 g/h verifying that the process is water balanced and therefore the rate of water entering the process is equal to the rate of water leaving.

(55) Example 4 demonstrated that a NAS CO.sub.2 removal process could maintain a water balance, be shifted into a water accumulation state, stripped of water, and returned to a different water balance state by adjusting the absorber gas feed (i.e., water content) and solvent feed temperatures. These results indicate that the water content in the NAS process can be effectively controlled and shifted as desired between water accumulating, water balanced, and water stripping conditions. In addition, these experiments show that there are numerous steady states with respect to balancing water and that the process can be operated in a manner to purposefully accumulate or strip water on an as-needed basis. It may be beneficial to accumulate water during specific operational timeframes and similarly to strip water at others.

(56) TABLE-US-00005 TABLE 5 Water Balanced Water Water Balanced -Condition 1- Accumulating Water Stripping -Condition 2- Gas Feed Temperature 35.2 40.1 35.2 40.1 [ C.] Absorber Gas Outlet 37.8 40.0 40.0 42.0 Temperature [ C.] Absorber Solvent 39.6 35.0 35.5 36.2 Feed [ C.] Measured Rate of 0.01 0.29 0.42 0.00 Water Accum. [g h.sup.1] H.sub.2O Content in 1.32 7.60 5.51 5.72 Solvent [wt %] Separate Aqueous No Yes - No No Phase Regen. Sump CO.sub.2 Capture 85.22 87.36 86.03 86.75 Efficiency [%]

(57) Further, Example teaches: that the water content of a NAS AG scrubbing process and particularly a NAS CO.sub.2 capture process can be controlled by manipulating process variables such that the process the rate of water accumulation is net zero (balanced), positive (accumulating), or negative (stripping) that more than one set of process conditions exists to maintain a water balance in a NAS CO.sub.2 removal process

(58) FIG. 5 shows one non-limiting embodiment of an acid gas recovery system. One of ordinary skill would recognize alternative configurations are possible. In particular raw flue gas (1) enters a wet flue gas desulfurization (FGD) unit (2) and the De-SOx'd flue gas (3) leaves. The FGD unit has a deep desulfurization/direct contact cooling section (4) and a deep desulfurization/direct contact cooling unit (5). The De-SOx'd flue gas (3) enters the CO2 absorber section (6) which as has a CO.sub.2-lean solvent (or NAS) feed to absorber section (7) and absorber overhead wash section (8). The treated flue gas sent to stack/exhaust (9) exits from the CO.sub.2 absorber section (6). Also coupled to the CO.sub.2 absorber section (6) is a wash unit (10) and a flow for recovered solvent (or NAS) return to process (11).

(59) The CO2-rich solvent (or NAS) (12) leaves from the CO2 absorber section (6) and flows to an absorber sump pump (13) and a crossover heat exchanger (14). The CO.sub.2-rich solvent (or NAS) feed to solvent regenerator (15) flows into the solvent regenerator (16). coupled to the solvent regenerator (16) may be a reboiler (17) generating low-pressure steam (18) and/or condensate (19). The CO2-lean solvent (or NAS) (20) is returned to the CO.sub.2 absorber section (6). The solvent regenerator (16) has an off-gas cooler and wash section (21) generating CO.sub.2 product gas to a compression train (22) or other CO.sub.2 product gas use and a wash unit (10) and a flow for recovered solvent (or NAS) return to process (11). The reboiler (17) is connected to a regenerator pump (23) and trim cooler (24) in fluid connection with the CO.sub.2 absorber section (6).

(60) It is to be understood that, while the invention has been described in conjunction with the detailed description, thereof, the foregoing description is intended to illustrate and not limit the scope of the invention. Other aspects, advantages, and modifications of the invention are within the scope of the claims set forth below. All publications, patents, and patent applications cited in this specification are herein incorporated by reference as if each individual publication or patent application were specifically and individually indicated to be incorporated by reference.