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. 405-408, 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 menoalkylalkanolamine 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. Both European patent applications EP0558019 and EP0647462 disclose a mixture comprising a first amine compound and a relatively small amount of second amine compound which is effective at improving the absorption rate of the first amine compound in a process for removing CO 2 from combustion gases. 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 invention is based upon the discovery that the use of an aqueous solution containing both a specific amine compound and a piperazine compound as a liquid absorbent is markedly effective for the removal of CO 2 from combustion gases. In accordance with the present invention, a process for removing CO 2 from combustion gases is provided by contacting a combustion gas at the atmospheric pressure with an aqueous solution containing both an amine and a piperazine, characterised in that the amine is a compound [2] 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 a methyl group and that the piperazine is a compound [3] selected from the group consisting of 2-methylpiperazine, 2,3-dimethylpiperazine, and 2,5-dimethylpiperazine. According to an embodiment of the present invention there is provided a process for CO 2 removal wherein the piperazine compound [3] is 2-methylpiperazine and the amine compound [2] is 2-(n-butylamino)ethanol. Further, the invention preferably provides a process for CO 2 removal is provided which is characterized in that the concentration of the amine compound [2] in the aqueous solution is in the range of 15-65% by weight and the concentration of the piperazine compound [3] is in the range of 1.5-65% by weight where that piperazine compound is soluble in the aqueous solution of the amine compound [2] at 30°C, the combined concentration of [2] and [3] being not more than 70% by weight. The invention resides in a process for removing CO 2 from combustion gases with an aqueous solution containing both a specific amine compound [2] and a piperazine compound [3]. As a liquid absorbent the aqueous solution containing the both compounds achieves by far the greater absorption performance than a liquid absorbent using either compound alone. In an amine compound [2] of the above general formula for use in the invention, the lower alkyl group having 1-4 carbon atoms represented by R 2 is, e.g., methyl, ethyl, propyl, isopropyl, n-butyl, isobutyl, sec-butyl, or tert-butyl group. It is preferably methyl, ethyl, n-propyl, or n-butyl group, more preferably n-propyl group. R 3 is a hydrogen atom or methyl group, preferably hydrogen. Examples of the amine compound [2] represented by the above general formula are 2-(methylamino)ethanol, 2-(ethylamino)ethanol [EAE], 2-(n-propylamino)ethanol, 2-(n-butylamino)ethanol [n-BAE], 2-(n-pentylamino)ethanol, 2-(isopropylamino)ethanol, 2-(sec-butylamino)ethanol, and 2-(isobutylamino)ethanol, Particularly desirable is 2-(n-butylamino)ethanol [n-BAE]. Not only one but also two or more such amine compounds [2] may be used as a mixture. The aqueous solution of an amine compound [2] and a piperazine compound [3] (hereinafter also called "the liquid absorbent") for contact with a combustion gas usually has an amine compound [2] concentration of 15-65% by weight, preferably 30-50% by weight. The concentration of the piperazine compound [3] is usually in the range of 1.5-65% by weight. The concentration of the piperazine compound [3] in the liquid absorbent is desirably as high as possible. However, some piperazine compounds, have such low degrees of solubility that they cannot be used at high concentrations. Thus, in consideration of the lowest possible temperature that a given liquid absorbent can be used in the whole process of absorption, the compound [3] is used within the above concentration range and also in the range where it is soluble in the aqueous solution of the amine compound [2] at 30°C. In view of this, it is advisable that piperazine compounds be used in the range of 10-40% by weight, preferably 20-35% by weight. If the combined concentration of the amine compound [2] and the piperazine compound [3] is high, the viscosity increases accordingly. Because of this limiting factor, it is desirable that the two compounds be used at a combined concentration of not exceeding 70% 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. Also, in the present invention, the liquid absorbent may contain a corrosion preventive, antioxidant, or/and other additives as needed. The term "atmospheric pressure" as used herein covers the pressure range around the atmospheric pressure in which the blower and the like to feed the gas can be operated. The treatment of a combustion gas at the atmospheric pressure in conformity with the invention realizes a generally improved CO 2 removal capacity over the use of a conventional amine liquid absorbent. 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; and 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 nozzics 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 vapor 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. Examples 1-3 and Comparative Examples 1-4 In order to confirm the effects of the process for CO 2 removal from combustion gases in accordance with the present invention, a small-scale testing equipment schematically illustrated in FIG. 2 was used. As shown in FIG. 2, a test gas 201 is introduced, at a flow rate of 0.98 Nm 3 /h, to the lower part of a stainless steel absorption tower 202, which measures 1500 mm high and 50 mm in inside diameter and accommodates a packing section 1000 mm high. The test gas composition is adjusted to 10% CO 2 , 87% N 2 , and 3% O 2 . Absorption tower 202 has nozzles 203 in the upper part from which a regenerated and recycled liquid absorbent is sprayed out. A packing section 204 held in the middle part of the absorption tower is packed with Dickson packings 6 mm long. That section is surrounded by a hot water jacket 205 and is equipped with a hot water circulating pump 206 and a hot water tank 207 to maintain an absorption temperature of 60°C. In the upper part of absorption tower 202 is installed an absorption tower condenser 208, where absorption-treated gas is cooled and then analyzed by an absorption-treated gas analyzer 209 and finally discharged from the system. Below the absorption tower is located a liquid absorbent drain pump 210. The liquid absorbent is heated by a preheating heater 211 and kept at 110°C and then introduced into the upper space of a regeneration tower 212. Regeneration tower 212 is built of stainless steel and is 1500 mm high and 25 mm in inside diameter. A packing section in the middle part of the tower is 160 mm high and is packed with the same packings as used in the absorption tower. The packing section is provided with a hot water jacket 213 to keep its temperature same and constant as in the absorption tower. A CO 2 -rich liquid absorbent that flow down from the top of the packing section in regeneration tower 212 is heated by a reboilet heater (electrically heated) 214 in the lower part (the reboiler temperature being controlled at 110°C) and is stripped with the resulting steam to be a CO 2 -lean liquid absorbent. This lean liquid absorbent is led through a regenerated liquid absorbent cooler 215, a regenerated liquid absorbent drain pump 216, a regenerated liquid absorbent tank 217. a regenerated liquid absorbent circulating pump 218, and a regenerated liquid absorbent preheater 219 and then is recycled to the upper part of the absorption tower at a flow rate of 2.8 l/h. Part of the lean liquid absorbent is returned to the inlet of the regeneration tower by a regenerated liquid absorbent pump 220. A regeneration tower condenser 221 is provided in the upper part of the regeneration tower. Condenser 221 condenses water vapor away from the CO 2 gas that has been separated from the liquid absorbent. The CO 2 gas is then analyzed by an infrared CO 2 gas meter (Model "VIA-510" mfd. by Horiba Seisakusho) not shown and is discharged by way of a regeneration tower gas scrubber 222. Absorption and regeneration tests were conducted with the afore-described small-scale testing equipment and absorption-regeneration conditions, using liquid absorbents containing the compounds mentioned in Table 1. The CO 2 concentrations in the inlet gas (test gas) and in the outlet gas (absorption-treated gas) of the absorption tower, heat input to the reboiler (in kW), CO 2 concentrations in rich and lean liquid absorbents (as measured with the "total organic carbon meter" Model TOC-5000 mfd. by Shimadzu Corp.), and quantities of regenerated heat were determined. The results are summarized in Table 1. Example Liquid absorbent (wt%) Gas feed rate (Nm 3 /h) CO 2 conc. in absorption tower (%) Reboiler heat input (kW) CO 2 conc in liquid absorbent Qty of regen heat (kcal /kg CO 2 ) Inlet Outlet Rich (Nm 3 CO 2 /m 3 ) Lean (Nm 3 CO 2 /m 3 ) 1 n-BAE 30 MP 15 0.98 9.65 0.50 0.28 41.1 10.3 1360 2 EAB 30 MP 3 0.98 9.64 2.97 0.28 47.9 19.2 1817 Comp. 1 MP 30 0.98 9.66 3.43 0.28 41.5 17.2 1940 Further tests were done with changes in the reboiler heat input, and the reboiler heat input values and the quantities of CO 2 recovered per unit time were determined when they became stabilized. The results are shown in Table 2. As compared with the quantities of regenerated heat in Table 1 that included the quantities of heat dissipated by the equipment, the quantities given in Table 2 exclude the dissipated heat. Example Liquid absorbent (wt%) Gas feed rate (Nm 3 /h) CO 2 conc in absorption tower (%) Reboiler heat input (kW) CO 2 conc in liquid absorbent Qty. of regen heat (kcal /kg CO 2 ) Inlet Outlet Rich (Nm 3 CO 2 /m 3 ) Lean (Nm 3 CO 2 /m 3 ) 3 BAE 30 MP 3 0.47 9.63 3.92 0.20 46.7 22.4 750 Comp. 2 MP 30 0.47 9.61 5.12 0.20 35.0 9.0 939 Comp. 3 n-BAE 30 0.47 9.63 4.15 0.20 32.3 9.2 800 Comp. 4 MEA 30 0.47 9.66 5.32 0.20 52.4 38.7 975 As can be seen from Tables 1 and 2, the use of a mixed liquid absorbent of an amine compound [2] and a piperazine compound [3] in conformity with the present invention is quite advantageous in that it achieves substantial improvements in absorption capacity and in regeneration of energy over the liquid absorbent of a conventional aqueous MEA solution or of the amine compound [2] or the piperazine compound [3] alone.

Claims: A process for removing CO 2 from combustion gases by contacting a combustion gas at the atmospheric pressure with an aqueous solution containing both an amine and a piperazine, the amine is a compound [2] 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 a methyl group characterised in that the piperazine is a compound [3] selected from the group consisting of 2-methylpiperazine, 2,3-dimethyl-piperazine, and 2, 5-dimethylpiperazine. The process as claimed in claim 1 wherein the piperazine compound [3] is 2-methylpiperazine and the amine compound [2] is 2-(n-butylamino)ethanol. The process as claimed in claim 1 or 2 wherein the concentration of the amine compound [2] in the aqueous solution is in the range of 15-65% by weight and the concentration of the piperazine compound [3] is in the range of 1.5-65% by weight where that piperazine compound is soluble in the aqueous solution of the amine compound [2] at 30°C, the combined concentration of [2] and [3] being not more than 70% by weight.

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, c/o Hir. Res. &amp; Dev. Center, Mimura, Tomio, c/o The Kansai Elec. Power Co., Inc, Mitsuoka, Shigeaki, c/o Hir. Res. &amp; Dev. Center, Shimayoshi, Hidenobu, c/o Kansai Elec.Pow. Co. Inc, Shimojo, Shigeru, c/o 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