Process for removing carbon dioxide from gases

Abstract: This invention relates to the process for removing CO₂ from CO₂-containing gas such as combustion gas. For example, it is the process for removing CO₂ 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 R¹NHC(CH₃)₂CH₂OH in which R¹ is a lower alkyl group having 1-4 carbon atoms, or an aqueous solution containing both an amine represented by the general formula R²CHR³NHCH₂CH₂OH in which R² is a hydrogen atom or a lower alkyl group having 1-4 carbon atoms and R³ 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: BACKGROUND OF THE INVENTION 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 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. 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. Thus, the invention provides a process for removing CO 2 from gases which is characterized by the contact of an untreated gas with an aqueous solution of an amine compound represented by the general formula [1] R 1 NHC(CH 3 ) 2 CH 2 OH in which R 1 is a lower alkyl group having 1-4 carbon atoms. Preferably, the amine compound is one in which R 1 of the formula is an isopropyl group. Preferably an aqueous solution of an amine compound of the general formula [1] is used at a concentration in the range of 15-65% by weight. Preferably, the CO 2 -containing gas is one which is a combustion gas at the atmospheric pressure. The lower alkyl group having 1-4 carbon atoms is, e.g., methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, or tert-butyl. Above all, an alkyl group having 1-3 carbon atoms is desirable because of the ease with which the compound is prepared and also in view of the CO 2 absorption capacity and water solubility. Examples of the amine compounds represented by the general formula [1] are 2-methylamino-2-methyl-1-propanol, 2-ethylamino-2-methyl-1-propanol, 2-propylamino-2-methyl-1-propanol, 2-isopropylamino-2-methyl-1-propanol, 2-n-butylamino-2-methyl-1-propanol, 2-isobutylamino-2-methyl-1-propanol, 2-sec-butylamino-2-methyl-1-propanol, and 2-tert-butylamino-2-methyl-1-propanol. Of these, 2-isopropylamino-2-methyl-1-propanol is preferred. The amine compounds of the general formula [1] may be used either singly or as a mixture of two or more. The aqueous solution of the amine compound (hereinafter to be also called "the liquid absorbent") for use in contact with the gas usually has a concentration of 15-65% by weight, preferably 30-50% by weight. The temperature of the liquid absorbent during the contact with the gas is usually in the range of 30-70°C. The liquid absorbent may contain a corrosion preventive, antioxidant, or/and other additives, according to the necessity. It is also possible to mix an amine compound of the general formula [1] with another amine compound or compounds so as to enhance the absorption performance, including the CO 2 absorption quantity and absorption rate, of the liquid absorbent. Among such other amine compounds are 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol, piperazine, 2-methylpiperazine, 2,5-dimethylpiperazine, piperidine, and 2-piperidineethanol. When such an amine compound or compounds are used, its or their concentration is usually in the range of 1.5-50% by weight, preferably in the range of 5-40% by weight, so long as such other compounds are soluble in water together with the amine compound of the general formula [1]. The gases to be treated include natural gas, synthetic gas and various other industrial gases produced by chemical plants and also the gases as combustion products. The invention is desirably applicable to gases at the atmospheric pressure, most desirably to combustion gases at the atmospheric pressure. For the purposes of the invention the term "atmospheric pressure" is used to cover the pressure range around the atmospheric pressure in which blower and the like to feed the gas can be operated. Contacting an untreated gas with an aqueous solution of an amine compound of the general formula [1] as a liquid absorbent allows more CO 2 to be absorbed per unit molar amount of the absorbent compound than with an aqueous MEA solution or the like that is commonly used as the liquid absorbent. An amine compound of the general formula [1], as judged from its molecular structure, has greater amino group hindrance than MEA and AMP and is presumed to call for less regenerative thermal energy for heating the liquid absorbent after the CO 2 absorption. It thus promises a process that generally economizes on the energy needed for the CO 2 recovery. BRIEF DESCRIPTION OF THE DRAWING The accompanying drawing is a flow chart of a process for the removal of CO 2 from combustion gases as an embodiment of the present invention. DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT 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 the accompanying drawing, 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 the accompanying drawing 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 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 an example which is in no way limitative and also with comparative examples. Example 1 and Comparative Examples 1-2 The present invention will be illustrated by examples in which the CO 2 absorption capacity of an amine compound of the general formula [1] was evaluated in small-scale absorption tests. Into a glass reaction vessel held in a thermostatic chamber was placed 50 ml of an aqueous solution containing 30% by weight of 2-isopropylamino-2-methyl-1-propanol (IPAMP), a compound of the general formula [1] in which R 1 is an isopropyl group. With stirring at 40°C, CO 2 gas was passed through the liquid absorbent at the atmospheric pressure at a rate of one liter per minute, through a filter so that bubbles can easily form. One hour later, the CO 2 content in the liquid absorbent was measured using a CO 2 analyzer (total organic carbon meter), and the absorption quantity (mol.CO 2 /mol.absorbent) was found. Similar absorption tests were conducted with aqueous solutions of MEA and AMP, respectively, as Comparative Examples 1 and 2. The results are shown in the Table. Absorbent mol CO 2 / mol absorbent Example 1 IPAMP 1.00 Comp. Ex. 1 MEA 0.58 Comp. Ex. 2 AMP 0.86 As is obvious from the Table the use of the aqueous solution of 2-isopropylamino-2-methyl-1-propanol (IPAMP), an amine compound for use in the invention, as a liquid absorbent shows a greater CO 2 absorption quantity per mole than the aqueous solutions of MEA and AMP.

Claims: A process for removing CO 2 from a CO 2 -containing gas characterized by the contact of the CO 2 -containing untreated gas with an aqueous solution of an amine compound represented by the general formula [1] R 1 NHC(CH 3 ) 2 CH 2 OH in which R 1 is a lower alkyl group having 1-4 carbon atoms. The process as claimed in claim 1 wherein the amine compound is represented by the general formula [1] in which R 1 is an isopropyl group. The process as claimed in claim 1 or claim 2 wherein the aqueous solution of the amine compound of the general formula [1] is used at a concentration in the range of 15-65% by weight. The process as claimed in any of the preceding claims 1 to 3 wherein the CO 2 -containing gas is a combustion gas at the atmospheric pressure.

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 Hiroshima Mitsubishi, Mimura, Tomio, c/o The Kansai Elec. Power Co.,Inc., Mitsuoka, Shigeaki, c/o Hiroshima Mitsubishi, Shimayoshi, Hidenobu The Kansai Elec.Power Co.Inc., 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