Process for removing carbon dioxide from gases

Abstract: This invention relates to the process for removing CO 2 from CO 2 -containing gas such as combustion gas. For example, it is the process for removing CO 2 from combustion gas through the contact of the gas at the atmospheric pressure with an aqueous solution of an amine represented by the general formula R 1 NHC(CH 3 ) 2 CH 2 OH in which R 1 is a lower alkyl group having 1-4 carbon atoms, or an aqueous solution containing both an amine represented by the general formula R 2 CHR 3 NHCH 2 CH 2 OH in which R 2 is a hydrogen atom or a lower alkyl group having 1-4 carbon atoms and R 3 is a hydrogen atom or methyl group and a piperazine compound selected from the group consisting of piperazine, 2-methylpiperazine, 2,3-dimethylpiperazine, and 2,5-dimethylpiperazine, or an mixed aqueous amine solution containing a secondary amine and a tertiary amine at concentrations of 10-45% by weight each, or an aqueous solution of a piperazine derivative.

Description: 1. Field of the invention The present invention relates to a process for removing carbon dioxide (CO 2 ) from gases such as combustion gases. More particularly, it relates to a process for efficiently removing CO 2 from combustion gases or the like at the atmospheric pressure using an aqueous solution containing a specific amine compound. 2. Description of the related art Heretofore varied approaches have been studied and proposed for the recovery and removal of acid gases, especially CO 2 , from various gases (to be treated), such as industrial gases and combustion gases generated in chemical plants handling natural and synthetic gases. With combustion gases, for example, intensive studies are being made for the removal and recovery of CO 2 from the gases through contact with an aqueous alkanolamine solution or for the storage of the recovered CO 2 instead of releasing it to the atmosphere. In recent years the greenhouse effect of CO 2 has been found partly responsible for the global warming, and counteracting that effect is urgently needed across the world to protect the environment on the earth. The source of CO 2 is omnipresent in the whole areas of human activities that involve the combustion of fossil fuels, and the tendency is toward more and more stringent emission control. In view of these, energetic studies are under way on the removal and recovery of CO 2 from boiler combustion gases, especially from the gases produced by power-generating installations such as steam power plants that burn enormous quantities of fossil fuels, through contact with an aqueous alkanolamine solution or the like or on the storage of the recovered CO 2 without discharge to the atmosphere. Examples of the alkanolamine are monoethanolamine, diethanolamine, triethanolamine, N-methyldiethanolamine (MDEA), diisopropanolamine, and diglycolamine. Usually, monoethanolamine (MEA) is used by preference. Aside from these, the use of secondary and tertiary hindered amines in the form of aqueous solutions is under investigation. Aqueous solutions of these alkanolamines, typified by MEA, have been used as liquid absorbents for the absorption and removal of CO 2 from combustion gases. However, they have not always proved satisfactory in view of the CO 2 absorption quantity per given quantity of each aqueous amine solution at a given concentration, the CO 2 absorption quantity per unit amine molar amount of the aqueous amine solution at a given concentration, the rate of CO 2 absorption at a given concentration, and the thermal energy required for the regeneration of the spent aqueous alkanolamine solution after the absorption. As for the separation of acid gases from various mixed gases through the medium of amine compounds, many techniques are known in the art. Japanese Patent Provisional Publication No. 100180/1978 discloses a process for the removal of acid gas which comprises contacting a normally gaseous mixture with an amine-solvent liquid absorbent consisting of (1) an amine mixture composed of at least 50 mol% of a sterically hindered amine which contains at least one secondary amino group bound to either a secondary carbon or tertiary carbon or a primary amino group bound to a tertiary carbon, forming a part of the ring, and at least about 10 mol% of a tertiary amino-alcohol and (2) a solvent for the amine mixture which serves as a physical absorbent for the acid gas. Examples cited of the sterically hindered amine are 2-piperidineethanol[2-(2-hydroxyethyl)-piperidine] and 3-amino-3-methyl-1-butanol and examples of the solvent are sulfoxide compounds which may contain up to 25 wt% water. As regards the gas to be treated, the reference publication, p.11, upper left col., mentions "a normally gaseous mixture containing carbon dioxide and hydrogen sulfide at high concentrations, e.g., 35% CO 2 and 10-12% H 2 S" and uses CO 2 itself in its working example. Japanese Patent Provisional Publication No. 71819/1986 describes a composition for acid gas scrubbing which contains a hindered amine and a nonaqueous solvent such as sulfolane. The publication explains the advantage of the hindered amine in the absorption of CO 2 , with the aid of a reaction formula. Chemical Engineering Science, Vol.41, No.4, pp.997-1003, reveals the carbonic acid gas absorption behavior of an aqueous solution of 2-amino-2-methyl-1-propanol (AMP), a hindered amine. As the gases to be absorbed, CO 2 at the atmospheric pressure and a mixture of CO 2 and nitrogen were used. Chemical Engineering Science, Vol. 41, No. 2, pp. 405408, reports the rates of CO 2 and H 2 S absorption by the aqueous solutions of hindered amines such as AMP and of straight-chain amines such as MEA at around ordinary temperatures. U.S. Patent No. 3,622,267 teaches a technique of purifying a synthetic gas such as partially oxidized gas obtained from crude oil, that contains CO 2 at a high partial pressure, e.g., 30% CO 2 at 40 atm., using an aqueous mixture containing methyldiethanolamine and monoethylmonoethanolamine. German Patent Provisional Publication 1,542,415 unveils in its published specification a technique of adding a monoalkylalkanolamine or the like to a physical or chemical absorbent so as to enhance the rates of absorption of CO 2 , H 2 S, and COS. Similarly, German Patent Provisional Publication 1,904,428 makes public a technique of adding monomethylethanolamine to methyldiethanolamine to increase the latter's absorption rate. U.S. Patent Specification 4,336,233 discloses a technique using an aqueous solution of 0.81-1.3 mole piperazine per liter as a scrubbing solution for the purification of natural, synthetic, or gasified coal gas. Alternatively, piperazine in the form of an aqueous solution with a solvent such as methyldiethanolamine, triethanolamine, diethanolamine, or monomethylethanolamine, is used as well for the scrubbing purpose. Japanese Patent Provisional Publication No. 63171/1977 introduces a CO 2 absorbent prepared by adding piperazine or a piperazine derivative such as hydroxyethylpiperazine as a promoter to a tertiary alkanolamine, monoalkylalkanolamine or the like. In reality, the combination of piperazine and monomethylaminoethanolamine as a monoalkylalkanolamine is not tested. The disclosure is directed to the treatment of synthetic gas; it is utterly silent on the removal of CO 2 from combustion gases at atmospheric pressures. U.S. Patent Specification 4,100,257 and its divisional application U.S. Patent Specifications 4,240,922 both disclose a process for the removal of acidic gases from a gaseous mixture by contacting the mixture with a solution containing a sterically hindered amine, a tertiary amino alcohol and a solvent for the amines. The co-action of the sterically hindered amine and the other components in the mixture increases the absorbtion of CO 2 and lowers the heat of reaction. In view of the state of the art described above, there is a demand for a process whereby CO 2 can be efficiently removed from various gases. For, especially when a gas is to be treated with an aqueous solution containing a given concentration of a CO 2 absorbent (amine compound), great significance is attached today to the choice of an absorbent which excels in both the CO 2 absorption quantity per unit mole of the absorbent and the CO 2 absorption quantity and absorption rate per unit volume of the aqueous solution. Also, the advent of an absorbent which consumes less thermal energy than heretofore in separating absorbed CO 2 and regenerating the liquid absorbent, is being awaited. In some cases where a single amine compound can hardly meet all such desired conditions, it is likely that the discovery of a compound which can satisfy some of the needs can lead to an approach to greater satisfaction of the requirements, for example, through mixing with some other amine compound. Thus, only if the CO 2 absorption quantity per unit mole of the absorbent is high, there will be a possibility of achieving better result through an improvement of the absorption rate in a separate way. SUMMARY OF THE INVENTION The present invention is based on the discovery that among the absorbents for use in removing CO 2 from gases, the aqueous solution of a specific amine compound shows a high degree of CO 2 absorption. The use of an aqueous solution of an alkanolamine typified by MEA or of a mixture of a hindered amine and an amine as a liquid absorbent for the removal of CO 2 from combustion gases has not always proved satisfactory. There is room for improvement in many respects, including the CO 2 absorption quantity per unit molar amount of amine in the aqueous amine solution, the rate of CO 2 absorption by the solution at a given concentration, and the thermal energy requirement for the regeneration of the aqueous alkanolamine solution after the CO 2 absorption. Generally, secondary and tertiary hindered amines are superior to MEA in CO 2 absorption capacity and in regeneration of thermal energy but are yet to be improved in respect of the rate of absorption. An increase in the CO 2 absorption quantity per molar amount of the liquid absorbent and an increase in the CO 2 absorption per volume of the aqueous solution of an amine at a higher concentration are among the major problems that remain to be solved for enhanced absorption efficiency. A new liquid absorbent has been looked forward to which solves these problems and, moreover, consumes less thermal energy than heretofore in separating CO 2 and regenerating the liquid absorbent after the CO 2 absorption. The present invention is based upon the discovery that the use of a mixed aqueous solution of a secondary amine and a tertiary amine at given or higher concentrations is remarkably effective as a liquid absorbent for the removal of CO 2 from combustion gases. According to the present invention there is provided a process for removing CO 2 from a combustion gas through the contact of the gas at the atmospheric pressure with an aqueous amine solution is provided wherein a mixed aqueous amine solution containing a secondary amine and a tertiary amine at concentrations of 10-45% by weight each is used as the aqueous amine solution, characterized in that the concentration of the tertiary amine in the mixed aqueous amine solution is within the range of plus and minus 10% by weight of the concentration of the tertiary amine which, when used alone in an aqueous solution, achieves the maximum CO 2 absorption per unit volume of the singular solution, the absorption conditions being the same. Also, in conformity with the invention, a CO 2 removal process is provided wherein the combined concentration of the amines in the mixed aqueous solution is not more than 70% by weight. The present invention provides a CO 2 removal process wherein the aqueous amine solution to be used is a mixed aqueous solution of a secondary amine selected from the group consisting of 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol, piperazine, 2-methylpiperazine, 2,5-dimethylpiperazine, and 2-piperidinoethanol and a tertiary amine selected from the group consisting of 2-dimethylaminoethanol, 2-diethylaminoethanol, 3-dimethylamino-1-propanol, 4-dimethylamino-1-butanol, 2-dimethylamino-2-methyl-1-propanol, and N-ethyl-N-methylethanolamine. The present invention also provides a CO 2 removal process wherein the secondary and tertiary amines have one alcoholic hydroxyl group each. According to the present invention, a CO 2 removal process is provided wherein the aqueous amine solution to be used is a mixed aqueous solution of a secondary amine selected from the group consisting of 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol, piperazine, 2-methylpiperazine, 2,5-dimethylpiperazine, and 2-piperidinoethanol and a tertiary amine selected from the group consisting of N-methyldiethanolamine, N-ethyldiethanolamine, N-t-butyldiethanolamine, and N-methyldiisopropanolamine. Further, according to the present invention, a CO 2 removal process is provided which uses a secondary amine selected from the group consisting of 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, and 2-n-butylaminoethanol. In the present invention, an aqueous solution of a mixture of 10-45% by weight each of a secondary amine and a tertiary amine is used as a liquid absorbent. A tertiary amine attains a large CO 2 absorption quantity per unit molar amount but the rate of absorption is low. When it is used together with a secondary amine, the absorption rate is increased, and the combined use is markedly advantageous over individual use in respect of the absorption rate. The absorption of CO 2 from a combustion gas is usually effected through a countercurrent contact between the liquid and the gas in an absorption tower. In a regeneration tower, the separation of CO 2 and regeneration of the liquid absorbent are carried out by steam stripping. For the process the relation between the CO 2 saturation absorption quantity per unit molar amount of the amine in the liquid absorbent at a given temperature (X-axis) and the CO 2 partial pressure in the gas (Y-axis), i.e., the equilibrium curve, is obtained with each amine under the individual temperature and CO 2 partial pressure conditions in the absorption tower and the regeneration tower. The possibility of setting operating lines that represent the actual operating conditions apart from, and in parallel with, the equilibrium curves is beneficial since it facilitates fixing of the number of theoretical plates. The equilibrium curve of a tertiary amine is less inclined than that of a secondary amine. This means that the tertiary amine has a greater absorption capacity but is less favorable in its relation to the operating line than the secondary amine is. Mixing the two amines allows the equilibrium curve of the mixed aqueous amine solution to shift in between the secondary and tertiary amines. This makes it easy to set the conditions for absorption operation to an advantage. It has now been found that if the concentration of a tertiary amine in its aqueous solution is continuously increased in absorbing CO 2 from a gas such as combustion gas wherein the partial pressure of CO 2 is low, there is a concentration level where the CO 2 absorption reaches a maximum (the maximum CO 2 absorption concentration), beyond which the absorption quantity begins to dwindle. The amine concentration at that point is approximately 30% by weight, although it varies more or less with amines. With a secondary amine, by contrast, the higher the concentration and larger the CO 2 absorption quantity. Meanwhile, the increase in viscosity, gas-liquid contact condition, fluidity, and other factors naturally place an upper limit on the concentration of the liquid absorbent. In view of the foregoing, it is advisable to set the concentration of a tertiary amine to the neighbourhood of the maximum CO 2 absorption concentration, and add a secondary amine at a concentration in the range up to the above upper limit. In this way an increase in the concentration is attained by the mixing of the two amines and the absorption capacities of the two are displayed to the fullest extent. In the present invention, the secondary and tertiary amines to be used combinedly as a liquid absorbent may or may not have an alcoholic hydroxyl group each in the molecule. Either may be acyclic or cyclic, but the tertiary amine is preferably acyclic. Desirable secondary amines for the invention are acyclic amines, such as 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, and 2-n-butylaminoethanol, and cyclic amines, such as piperazine, 2-methylpiperazine (MP), 2,5-dimethylpiperazine, and 2-piperidinoethanol. The secondary amines may be used singly or as a mixture of two or more. Desirable tertiary amines include those having one alcoholic hydroxyl group in the molecule, such as 2-dimethylaminoethanol, 2-diethylaminoethanol, 3-dimethylamino-1-propanol, 4-dimethylamino-1-butanol, 2-dimethylamino-2-methyl-1-propanol, and N-ethyl-N-methylethanolamine. Those having two alcoholic hydroxyl groups are, e.g., N-methyldiethanolamine, N-ethyldiethanolamine, N-t-butyldiethanolamine, and N-methyldiisopropanolamine. When a tertiary amine having two alcoholic hydroxyl groups is to be employed, it is desirable to combine it with a secondary amine at a higher concentration, e.g., at least 15% by weight. Even a higher concentration of 30% by weight or above is more desirable. The tertiary amines too may be used singly or as a mixture of two or more. In the present invention, the mixed aqueous solution of secondary and tertiary amines (hereinafter also called "the liquid absorbent") for use in contact with a combustion gas is at a concentration such that each amine amount is in the range of 10-45% by weight. The concentration of the tertiary amine is in the range plus and minus 10% by weight, preferably plus and minus 5% by weight, relative to the maximum CO 2 absorption concentration of the particular tertiary amine. Thus, the desirable concentration range of the tertiary amine is about 20-40% by weight. On the other hand, as noted above, a secondary amine usually shows a gradual increase in the saturation absorption quantity as its concentration rises. For this reason a high concentration is desirable, but the combined concentration including the concentration of a tertiary amine should be kept not greater than 70% by weight from the viewpoint of gas-liquid contact property and fluidity. A particularly desirable concentration range for a secondary amine is about 15-20% by weight. In the present invention, the temperature of the liquid absorbent during contact with a combustion gas is usually in the range of 30-70°C. The liquid absorbent for use in the present invention may contain a corrosion preventive, antioxidant, or/and other additives, when necessary. The expression "at the atmospheric pressure" as used here implies the pressure range around the atmospheric in which the blower and the like for feeding a combustion gas can be operated. The treatment of a combustion gas at the atmospheric pressure in accordance with the invention generally achieves a greater CO 2 removal capacity than when a conventional amine liquid absorbent is employed. BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a flow chart of a process for the removal of CO 2 from combustion gases as an embodiment of the present invention; and FIG. 2 is a schematic view of a small-scale testing equipment used in connection with the embodiment of the invention. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS The present invention will now be explained as applied to the treatment of combustion gases. The flow chart of the process equipment that may be employed for the removal of CO 2 from combustion gases in accordance with the invention is not specially limited. One example will be explained below with reference to FIG. 1. Major components of the equipment are shown but auxiliary facilities are not shown. Referring to FIG. 1, numeral 1 designates a CO 2 -removal tower; 2, a lower packing section; 3, an upper packing section or tray; 4, a combustion-gas inlet of the CO 2 -removal tower; 5, a CO 2 -free combustion-gas outlet; 6, a liquid absorbent inlet; 7, nozzles; 8, a combustion-gas cooler provided when necessary; 9, nozzles; 10, a packing section; 11, a circulating pump for moistening-cooling water; 12, a makeup feed line; 13, a pump for draining the liquid absorbent that has absorbed CO 2 ; 14, a heat exchanger; 15, a liquid absorbent regeneration tower (hereinafter also called a "regeneration tower" for brevity); 16, nozzles; 17, a lower packing section; 18, regeneration heater (reboiler); 19, an upper packing section; 20, a reflux water pump; 21, a CO 2 separator; 22, a recovered CO 2 discharge line; 23, a reflux cooler for the regeneration tower; 24, nozzles; 25, a reflux water feed line to the regeneration tower; 26, a combustion-gas feed blower; 27, a cooler; arid 28, a feed port for reflux water from the regeneration tower. As indicated in FIG. 1, a combustion gas is forced by combustion-gas feed blower 26 into combustion-gas cooler 8, where, in packing section 10, it comes in contact with moistening-cooling water from nozzles 9. Moistened and cooled, the gas is then led through combustion-gas inlet 4 to CO 2 -removal tower 1. Meanwhile, the moistening-cooling water after the contact with the combustion gas collects at the bottom of combustion-gas cooler 8, from which it is recycled by pump 11 to nozzles 9. Since it is gradually lost by moistening and cooling the combustion gas, the moistening-cooling water is replenished by makeup feed line 12. When the combustion gas in the moistened and cooled state is to be further cooled, it is possible to install a heat exchanger between moistening-cooling water circulating pump 11 and nozzles 9 and cool the moistening-cooling water to a lower temperature before supply to combustion-gas cooler 8. The combustion gas forced into CO 2 -removal tower 1 enters lower packing section 2, where it is brought into countercurrent contact with the liquid absorbent being supplied at a given concentration from nozzles 7. CO 2 is taken up by the liquid absorbent from the combustion gas, and the CO 2 -free combustion gas flows upward to upper packing section 3. The liquid absorbent supplied to CO 2 -removal tower 1 absorbs CO 2 , and the heat of reaction due to absorption makes it usually hotter than at liquid absorbent inlet 6. The liquid absorbent after the CO 2 absorption is then sent by discharge pump 13 to heat exchanger 14, where it is additionally heated, and is conducted to liquid absorbent regeneration tower 15. The temperature control of the regenerated liquid absorbent can be done by heat exchanger 14 or by cooler 27 that is provided between heat exchanger 14 and liquid absorbent inlet 6. In regeneration tower 15, the liquid absorbent is regenerated in lower packing section 17 with heat from regeneration heater 18. It is then cooled by heat exchanger 14 and, where necessary, by cooler 27 that is installed between heat exchanger 14 and liquid absorbent inlet 6, and returned to CO 2 -removal tower 1. In the upper space of liquid absorbent regeneration tower 15, the CO 2 separated from the liquid absorbent comes in contact with the reflux water supplied by nozzles 24. Following this, it is cooled by regeneration tower reflux cooler 23, and enters CO 2 separator 21, where it is separated to reflux water that has resulted from the condensation of water vapour that had accompanied CO 2 . Finally it is conducted by recovered CO 2 discharge line 22 to a CO 2 recovery step. Part of the reflux water is returned by reflux water pump 20 to regeneration tower 15 through nozzles 24, while the remainder is supplied through regeneration-tank reflux water feed line 25 to the regeneration-tower reflux water inlet 28 of CO 2 -removal tower 1. The reflux water from the regeneration tower contains a slight amount of the liquid absorbent, which contributes to the removal of the slight CO 2 content in the combustion gas with which the reflux water comes in contact in the upper packing section 3 of CO 2 -removal tower 1. The present invention will now be concretely explained in connection with its examples which are in no way limiting and also with comparative and reference examples. Reference Examples 1-3 Reference Examples 1-3 are test examples performed with the view to finding the optimum amine concentrations under ordinary conditions. Aqueous solutions of tertiary amines were varied in concentration as listed in Table 1, and 50 ml of each solution as a liquid absorbent was placed in a glass reaction vessel held inside a thermostatic chamber. A test gas was passed through the liquid absorbent at a flow rate of one liter per minute at the atmospheric pressure, with stirring at 40°C, via a filter to facilitate bubbling. The test gas used was a model combustion gas at 40°C having a composition of 10 mol% CO 2 , 3 mol% O 2 , and 87 mol% N 2 . Each test gas was continuously passed and at the point where the CO 2 concentrations at the inlet and outlet became equal, the CO 2 content in the liquid absorbent was measured using a CO 2 analyzer (total organic carbon meter), and the quantity of saturation absorption of CO 2 (Nm 3 CO 2 / m 3 liquid absorbent, CO 2 / absorbent both in terms of the numbers of moles) was determined. The test results are shown in Table 1. Liquid absorbent (wt%) Qty. of saturation absorption of CO 2 CO 2 mol/amine mol) Nm 3 CO 2 / m 3 liquid absorbent Ref. Ex. 1 DMAE 0 - - 30 0.55 41.7 40 0.35 35.3 50 0.23 29.0 60 0.13 19.2 Ref. Ex. 2 DEAE 0 - - 30 0.75 42.2 40 0.52 40.0 50 0.29 27.3 60 0.17 19.0 Ref. Ex. 3 MDEA 0 - - 30 0.29 16.5 60 0.09 10.1 As Table 1 indicates, the tertiary amines used in the present invention have their own CO 2 absorption capacities such that their maximum CO 2 absorption concentrations in the liquid absorbents are always around 30% by weight. Reference Examples 4-18 Reference Examples 4-18 are test examples intended to determine the quantities of the CO 2 absorption of various secondary and tertiary amines at a concentration of 30% by weight each, under ordinary conditions. The procedure of Reference Example 1 was repeated to perform a CO 2 absorption test of the secondary and tertiary amines listed in Table 2, at a concentration of 30% by weight each. Table 2 gives the results. Liquid absorbent Qty. of CO 2 saturation absorption CO 2 mol / amine mol Nm 3 CO 2 / m 3 liquid absorbent Ref. Ex. 4 MAE 0.63 56.2 Ref. Ex. 5 EAE 0.68 51.3 Ref. Ex. 6 IPAE 0.73 47.3 Ref. Ex. 7 BEA 0.63 35.8 Ref. Ex. 8 Piperazine (conc.15wt%) 0.84 32.8 Ref. Ex. 9 MP 0.81 54.3 Ref. Ex. 10 DMP 0.74 21.9 Ref. Ex. 11 PE 0.84 43.9 Ref. Ex. 12 DMAP 0.60 39.4 Ref. Ex. 13 DMAB 0.73 42.1 Ref. Ex. 14 DMAMP 0.80 46.1 Ref. Ex. 15 EMEA 0.61 39.6 Ref. Ex. 17 BDA 0.44 18.1 Ref. Ex. 18 MDPA 0.32 14.7 Examples 1-5 & Comparative Examples 1-4 In order to confirm the effects of the process for removing CO 2 from combustion gases in accordance with the present invention, the small-scale testing equipment schematically illustrated in FIG. 2 was used. Absorption and regeneration tests were carried out with the above small-scale testing equipment and under the afore-said absorption and regeneration conditions, using the liquid absorbents listed in Table 3. The CO 2 concentrations in the inlet gas (test gas) and the outlet gas (absorption-treated gas) of the absorption tower in Table 3, heat input to the reboiler (in kW), CO 2 concentrations in rich and lean liquid absorbents (measured with the "total organic carbon meter" Model TOC-5000 mfd, by Shimadzu Corp.), and quantities of regenerated heat were determined. The results are given in Table 3. Example Liquid absorbent (wt%) Absorption tower CO 2 conc. Re-Boiler heat input (kW) Absorption tower CO 2 conc. Qty. of regen heat (kcal /k g CO 2 ) Inlet (%) Outlet (%) Rich (Nm 3 CO 2 /m 3 ) Lean (Nm 3 CO 2 /m 3 ) 1 DMAE 30 9.67 2.60 0.28 32.0 8.2 1727 MP 15 Comp. 1 DMAE 30 9.66 7.51 0.28 11.5 2.4 5376 Comp. 2 DMAE 30 9.68 3.93 0.28 35.4 4.0 2471 piperazine 3 2 MDEA 30 9.69 4.32 0.28 24.8 5.0 2238 MP 15 3 MDEA 30 9.65 2.89 0.28 43.6 16.0 1796 MAE 30 4 MDEA 30 9.65 2.53 0.28 33.0 6.1 1713 EAE 30 Comp. 3 MDEA 30 9.65 6.13 0.28 15.2 1.8 3336 MP 3 5 DEAE 30 9.65 1.38 0.28 37.0 6.8 1491 MP 15 Comp. 4 MEA 30 9.65 3.60 . 0.28 48.5 25.6 1993 As will be appreciated from Table 3, the use of a mixed liquid absorbent of secondary and tertiary amines according to the present invention is very advantageous in that it brings marked improvements in absorption capacity and regeneration of energy.

Claims: A process for removing CO 2 from a combustion gas through the contact of the combustion gas at the atmospheric pressure with an aqueous amine solution wherein a mixed aqueous amine solution containing a secondary amine with a tertiary amine at concentrations of 10-45% by weight each is used as the aqueous amine solution, characterised in that the concentration of the tertiary amine in the mixed aqueous amine solution is within the range of plus and minus 10% by weight of the concentration of the tertiary amine which, when used alone in an aqueous solution, achieves the maximum CO 2 absorption per unit volume of the singular solution, the absorption conditions being the same. The process as claimed in claim 1 wherein the combined concentration of the amines in the mixed aqueous solution is not more than 70% by weight. The process as claimed in either of claims 1 or 2 wherein the aqueous amine solution to be used is a mixed aqueous solution of a secondary amine selected from the group consisting of 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol, piperazine, 2-methylpiperazine, 2,5-dimethylpiperazine, and 2-piperidinoethanol and a tertiary amine selected from the group consisting of 2-dimethylaminoethanol, 2-diethylaminoethanol, 3-dimethylamino-1-propanol, 4-dimethylamino-1-butanol, 2-dimethylamino-2-methyl-1-propanol, and N-ethyl-N-methylethanolamine. The process as claimed in claim 1 wherein the secondary and tertiary amines have one alcoholic hydroxyl group each. The process as claimed in either of claims 1 or 2 wherein the aqueous amine solution to be used is a mixed aqueous solution of a secondary amine selected from the group consisting of 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol, piperazine, 2-methylpiperazine, 2,5-dimethylpiperazine, and 2-piperidinoethanol and a tertiary amine selected from the group consisting of N-methyldiethanolamine, N-ethyldiethanolamine, N-t-butyldiethanolamine, and N-methyldiisopropanolamine. The process as claimed in either of claims 1 or 2 wherein the secondary amine to be used is selected from the group consisting of 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, and 2-n-butylaminoethanol.

Inventors: HAYAKAWA ATSUSHI, IIJIMA MASAKI, IWAKI TORU, MIMURA TOMIO, MITSUOKA SHIGEAKI, SHIMAYOSHI HIDENOBU, SHIMOJO SHIGERU, SUZUKI HITOMI, HAYAKAWA, ATSUSHI, IIJIMA, MASAKI, IWAKI, TORU, MIMURA, TOMIO, MITSUOKA, SHIGEAKI, SHIMAYOSHI, HIDENOBU, SHIMOJO, SHIGERU, SUZUKI, HITOMI, IIJIMA, MASAKI, C/O MITSUBISHI JUKOGYO K.K., Iwaki, Toru, Mitsubishi Jukogyo K.K., Mimura, Tomio, The Kansai Electric Power Co., Inc., Mitsuoka, Shigeaki, Mitsubishi Jukogyo K.K., Shimayoshi, Hidenobu, Kansai Elec.Power Co.,In, Shimojo, Shigeru, The Kansai Elec. Power Co., Inc.
Applicants: KANSAI ELECTRIC POWER CO, MITSUBISHI HEAVY IND LTD, MITSUBISHI JUKOGYO KABUSHIKI KAISHA, THE KANSAI ELECTRIC POWER CO., INC.
Application year: 1995
Main classification: B01D53
IPC codes: B01D53