Process for removing carbon dioxide and nitrogen oxides from combustion gases

Abstract: A process for removing both CO₂ and NO x from combustion gases consists, first, in cooling a combustion gas to 50 to 100°C and adding ozone to oxidize NO in the combustion gas to NO₂. Then, in a CO₂ removal step, the gas is brought into contact with an aqueous solution of an alcoholic hydroxyl-containing secondary- or tertiary-amine to remove NO₂ together with CO₂ from the gas.

Description: BACKGROUND OF THE INVENTION 1. Field of the Invention The present invention relates to a process for removing carbon dioxide (CO 2 ) and nitrogen oxides (NO x ) from combustion gases. More particularly, it relates to a process for converting nitrogen monoxide (NO), the main constituent of NO x in combustion gases, into nitrogen dioxide (NO 2 ) by oxidation with ozone and removing the NO 2 together with CO 2 by absorption from the combustion gases. 2. Description of the Related Art It is common knowledge these days that the greenhouse effect of CO 2 resulting from the burning of fossil fuels is responsible for the global warming and that other combustion products NO x cause photochemical smog and acid rain. Above all, acid rain has perniciously influenced natural ecosystems, directly attacking forests and farm products, indirectly affecting the plants through changes of soils, and acidifying lakes and rivers and thereby reducing the fish population. Since the air pollutants CO 2 and NO x do extensive harm to the environment across international borders, reducing them is a problem of great urgency. One approach already taken is recovery and removal of CO 2 from combustion gases, e.g., coming out of boilers of thermal power plants that burn much fossil fuels, through contact with an aqueous solution of monoethanolamine (MEA), hindered amine, or the like. On the other hand, the technology of wet denitration of combustion gases is difficult to develop, because the NO x concentration is low and more than 90% of NO x is accounted for by poorly reactive NO. As for dry denitration, a process is already in use which reduces NO x in combustion gas with the aid of a catalyst and with injection of ammonia. A typical wet process is oxidative absorption, which consists in scrubbing NOx-laden gas with water or a chemical solution, oxidizing NO to NO 2 with an oxidizing agent or the like for effective removal of NO, and then scrubbing or directly washing with an oxidizing chemical solution. The afore-described wet denitration process has drawbacks including high cost of the oxidizing agent to be used for favorable NO x absorption and the necessity of disposal of the used liquid absorbent. Combustion gases generally contain about 10% CO 2 , but their NO x contents are at most hundreds of parts per million, and the addition of an exclusive step for denitration would call for a large-scale equipment. As regards the simultaneous removal of CO 2 and NO x , no satisfactory liquid absorbent has been available yet that is capable of removing both of them. In German Offenlegungsschrift DE-A-2 311 098, a method of removing sulfur dioxide and mixtures of sulfur dioxide and sulfur trioxide from a combustion gas containing mainly carbon dioxide in which the absorption of carbon dioxide gas is kept to a minimum. The combustion gas is counterdirected mixture at a temperature of less than 100°C in an absorption apparatus to a solvent composition containing alkanolamine solutions. The main object is not to oxidize NO in the combustion gas to NO 2 . Furthermore, U.S. patent specification US-A-4,247,321 describes method and apparatus for obtaining fertilizing solutions from fossil fueled stationary engines, particularly gas fired compressors, by adding carbon dioxide and nitrogenous compounds, derived from exhaust gases, and ozone gas derived from a generator, to water so as to produce a fertilizing solution which promotes crop growth. NO 2 is formed by direct oxidization of NO with ozone or hydrogen peroxide formed from ozone. The conversion into fertilizers (NO 2 and N 2 O 5 ) is obtained by reaction with inorganic compounds such as slaked lime, limestone calcium phosphate or the like. The water solution containing the ozone gas and the agent is contacted in a scrubber. The enriched water from the scrubber is cooled. The cooled enriched water is recycled through the scrubber until a desired concentration of carbon dioxide and nitrogen compounds is achieved. The enriched water is then collected in a storage facility. German Offenlegungsschrift DE-A-2,248,586 teaches the use of an aqueous solution of aminoalcohol as an absorption liquid for acidic gas by adding a corrosion inhibiting composition containing at least one aminoacid or a derivative thereof, at least one trivalent inorganic acid ester, at least one water-soluble chelate forming agent and at least one water-soluble compound of divalent metal ions. This composition is only added for the prevention of corrosion and not for removing CO 2 and NO x from combustion gases. The alcanolamines cause significant corrosion in apparatuses and, therefore, it is necessary, to add the aforementioned corrosion inhibitors. Thus, because of the influence of combustion gases over the environment, there is a strong desire for early development of a process that solves the problems of the prior art, is simple in operation, recovers both CO 2 and NO x with high efficiency, and can be incorporated in existing facilities for the treatment of combustion gases. SUMMARY OF THE INVENTION As a result of our research for the solution of the foregoing problems, it has now been found that both CO 2 and NO x can be removed from combustion gases by oxidizing NO x in advance with ozone to NO 2 and allowing a certain liquid absorbent for CO 2 removal to remove the thus formed NO 2 together with CO 2 . This discovery has led to the present invention. The invention thus provides a process for removing both CO 2 and NO x from combustion gases characterized by the steps of cooling a combustion gas to 50 to 100°C, oxidizing NO in the gas to NO 2 by the addition of ozone, and bringing the gas into contact with an aqueous solution of an alcoholic hydroxyl-group- and N-C 1 -C 4 -alkyl group-containing secondary- or tertiary-amine and removing NO 2 together with CO 2 from the gas. First, under the invention, the inert NO, the main constituent of NO x in the combustion gas, is oxidized with ozone to NO 2 in a combustion-gas treating step or the like. Then, the gas is contacted with an alcoholic hydroxyl group- and N-C 1 -C 4 -alkyl group-containing secondary- or tertiary-amine aqueous solution as a liquid absorbent for CO 2 , whereby both CO 2 and NO 2 are removed for recovery. Of 100 ppm of NO x present in a combustion gas, about 90% is NO, and if about 90% of the combined amount of the NO 2 that results from the oxidation with ozone and the original NO 2 content in the gas could be removed, the NO x content in the treated gas would reduce to mere 10 ppm or less. The process of the invention for removal of CO 2 and NO x from combustion gases will now be described in more detail. In the process of removing CO 2 and NO x in accordance with the invention, the combustion gas desirably is cooled and dedusted at the same time. Cooling is preferably done by direct contact with cooling water to a temperature optimum for the oxidation of NO x contained in the combustion gas. For the reactivity of ozone toward NO x , the adequate cooling temperature ranges from 50 to 100°C, preferably from 60 to 80°C. As regards dedusting, it is desirable that the combustion gas be dedusted to about the same degree as with a conventional wet flue-gas denitration apparatus. The NO in the NO x contained in the cooled combustion gas is easily oxidized to NO 2 in the step of oxidation with air that contains ozone supplied by an ozone generator. In the practice of the oxidation step, ozone may be introduced into a duct through which the combustion gas passes. Ordinarily, the NO x concentration in the combustion gas is low and poorly reactive NO accounts for over 90% of it, and therefore NO x are mostly oxidized with ozone to NO 2 . The amount of ozone to be added is usually about one-fold molar amount to the number of moles of the NO content. Adding this much ozone leaves no excess ozone in the ozone-containing combustion gas after the reaction. Where ozone and the combustion gas are very poorly mixed, the reaction between ozone and NO x can form a slight amount of N 2 O 5 . To avoid this, it is advisable that nozzles for ozone injection into a combustion gas duct be so arranged as to ensure uniform dispersion of ozone in the gas. CO 2 and the NO 2 that has resulted from oxidation with ozone are brought into contact with a liquid absorbent, an alcoholic hydroxyl-containing secondary- or tertiary-amine aqueous solution, in the absorption step, where they are both removed by absorption. The alcoholic hydroxyl-containing secondary-amine aqueous solution as a liquid absorbent for CO 2 and NO 2 is, for example, an amine that contains one hydroxyl group, such as 2-(methylamino)ethanol (MAE), 2-(ethylamino)ethanol [EAE], 2-(isopropylamino)ethanol (IPAE), N-(n-butyl)ethanolamine, or N-(tert-butyl)ethanolamine, or that contains two hydroxyl groups, such as diethanolamine. Examples of the alcoholic hydroxyl-containing tertiary-amine aqueous solution are those containing one or two hydroxyl groups, such as 2-(dimethylamino)ethanol, 2-(diethylamino)ethanol (DEAE), (N-methyl)diethanolamine (MDEA), (tert-butyl)diethanolamine, triisopropanolamine, 3-(N,N-dimethylamino)-1-propanol, 4-(N,N-dimethylamino)-1-butanol, 2-(N,N-dimethylamino)-2-methyl-1-propanol, and 3-(N,N-dimethylamino)-2,2-dimethyl-1-propanol. These may be used in a combination of two or more, or as a mixture of a compound that promotes the absorption of CO 2 and NO 2 , e.g., piperazine. BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a flow chart of the process embodying the present invention; FIG. 2 is a schematic layout for the step for removal of CO 2 and NO 2 in the flow chart of FIG. 1 according to the invention; and FIG. 3 is a graph showing results of wet wall tests conducted in Example 9. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS FIG. 1 shows a flow chart of the process for treating a combustion gas embodying the present invention. The symbol A designates a boiler, B a cooling tower, C an ozone generator, D an oxidation step, E a desulfurization step, F a CO 2 and NO 2 removal step, and G a stack. Now, with reference to FIG. 2, the step F for removal of CO 2 and NO 2 in the flow chart of FIG. 1 according to the invention will be described. Essential equipment components are illustrated but minor ancillary ones are omitted. Unless otherwise specified, the term "CO 2 " as used herein means that it contains part of NO 2 . Referring to FIG. 2, there are shown a CO 2 -removal tower 201, a lower-packing section 202, an upper-packing section or tray 203, a combustion gas inlet 204 of the CO 2 -removal tower, a combustion gas outlet 205 of the tower, an inlet 206 of an alcoholic hydroxyl-containing secondary- or tertiary-amine aqueous solution (hereinafter called the "liquid absorbent"), arrays of nozzles 207, a combustion gas cooler 208 (which may be omitted when the temperature of the combustion gas being fed is low enough), nozzles 209, a packing section 210, a moistening-cooling water circulating pump 211, a makeup-water feed line 212, a liquid absorbent drain pump 213, a heat exchanger 214, a liquid absorbent regeneration tower 215 (which may also be called the "regeneration tower" for brevity), nozzles 216, a lower-packing section 217, a regeneration heater (reboiler) 218, an upper-packing section 219, a reflux water pump 220, a CO 2 separator 221, a recovered CO 2 discharge line 222, a reflux condenser 223 for the regeneration tower, nozzles 224, a reflux water feed line 225 for the regeneration tower, a combustion gas blower 226, and a cooler 227. In the arrangement of FIG. 2, combustion gas is forced by combustion gas blower 226 into combustion gas cooler 208. It then comes in contact with moistening-cooling water from nozzles 209 in packing section 210 and is moistened and cooled. Next, the gas is led through combustion gas inlet 204 into CO 2 -removal tower 201. The moistening-cooling water that has contacted the combustion gas is collected in the lower part of combustion gas cooler 208, and is recycled by moistening-cooling water circulating pump 211 to nozzles 209. The moistening-cooling water is gradually lost as it moistens and cools the combustion gas, and is replenished by a fresh supply through makeup-water feed line 212. The combustion gas that has been forced into CO 2 -removal tower 201 ascends through lower-packing section 202 in countercurrent contact with the liquid absorbent being sprayed at a given concentration by nozzles 207. During this, the CO 2 in the combustion gas is removed as it is absorbed by the alcoholic hydroxyl-containing secondary- or tertiary-amine aqueous solution, and the combustion gas freed from CO 2 continues to ascend into upper-packing section 203. The liquid absorbent supplied to CO 2 -removal tower 201 thus absorbs CO 2 and becomes hotter owing to the heat of reaction on absorption than at liquid absorbent inlet 206. The liquid absorbent is then transferred by absorbent drain pump 213 to heat exchanger 214, where it is reheated and led to regeneration tower 215. In regeneration tower 215, the liquid absorbent is regenerated by heating with reboiler (regeneration heater) 218, cooled by heat exchanger 214, and, via cooler 227 provided when necessary, returned to the upper part of CO 2 -removal tower 201. The CO 2 that has been separated from the liquid absorbent comes in contact with reflux water from nozzles 224 in the upper part of regeneration tower 215 and is cooled by regeneration tower reflux condenser 223. Then, CO 2 is separated in CO 2 separator 221 from the reflux water that is water vapor entrained by CO 2 and condensed to water, and is taken out through recovered CO 2 discharge line 222 to a CO 2 removal station. Part of the reflux water is returned by reflux water pump 220 to regeneration tower 215, while the remainder is recycled through regeneration tower reflux water feed line 225 to the upper part of CO 2 -removal tower 201. In the practice of the invention, the CO 2 removal step may be preceded by a desulfurization step when the combustion gas to be handled has a large enough SO x content. In that case, the desulfurized combustion gas is further treated in the CO 2 removal step, whereby SO x together with CO 2 and NO 2 are almost completely removed. This is because the alcoholic hydroxyl-containing secondary- or tertiary-amine aqueous solution used in the CO 2 removal step reacts also with SO x . When the combustion gas has too low a SO x content to justify the desulfurization step, the SO x are nearly completely removed, as well as CO 2 and NO 2 , in the CO 2 -removal tower. Examples of the present invention will be discussed below in conjunction with Table 1 and FIG. 3. Examples 1-8 and Comparative Examples 1-4 First, Examples 1-8 will be explained. Into each glass reaction vessel held in a thermostatic chamber was placed 50 mℓ of each liquid absorbent, or alcoholic hydroxyl-containing secondary- or tertiary-amine aqueous solution, listed in Table 1. With stirring at 40°C, test gas was passed through the liquid absorbent at the atmospheric pressure at a flow rate of one liter per minute, through a filter so that bubbles can easily form. The test gas was a simulated combustion gas with a composition of 10 mol% CO 2 , about 10 ppm NO 2 , and 90% N 2 at 40°C. The test gas was continuously passed through the absorbent until the CO 2 concentrations in the incoming and outgoing gas streams became equal, when the CO 2 content in the liquid absorbent was measured using a CO 2 analyzer (total organic carbon meter), and the saturation absorption was found. Also, the initial outlet NO 2 concentration, or the NO 2 concentration in the gas at the outlet of the reaction vessel in the initial stage of the absorption test, was found. It may safely be said that the lower the initial outlet NO 2 concentration the higher the NO 2 absorption rate of the liquid absorbent. By way of comparative examples, absorption tests were conducted also with aqueous solutions of primary amines listed in Table 1. The NO 2 saturation absorption and initial outlet NO 2 concentration values thus obtained too are given in Table 1. It will be appreciated from Table 1 that the use of an alcoholic hydroxyl-containing secondary- or tertiary-amine aqueous solution in accordance with the present invention reduces the initial outlet NO 2 concentration, as in Examples 1 through 8, compared with the liquid absorbents of comparative examples. All the liquid absorbents used could be regenerated, without difficulty, upon heating. Liquid absorbent NO 2 absorption data Amine compound Concentration, wt% Inlet NO 2 conc., ppm Outlet NO 2 conc., ppm Initial absorption rate, % Comp. Ex. 1 30 10 10 0 2 40 11 10 9.1 3 30 11 8 27.3 4 30 11 7 36.4 + 3 Example 1 EAE 30 10 5 50.0 2 EAE 40 10 6 40.0 3 MAE 30 10 5 54.5 4 IPAE 30 11 5 50.0 Example 5 MDEA 30 11 4 63.6 6 MDEA 30 10 4 60.0 + 3 7 DEAE 30 10 3 70.0 8 DEAE 30 11 4 63.6 + 3 Example 9 As Example 9, a contact absorption test was performed with a wetted-wall absorption apparatus as a pilot equipment for the CO 2 removal process illustrated in FIG. 2, using a test gas adjusted to given CO 2 and NO 2 concentrations and aqueous EAE as a liquid absorbent. In order to compare, a contact absorption test was also done with aqueous MEA as a liquid absorbent. The results are shown in FIG. 3. The testing conditions used in common with those tests were as follows. The CO 2 and O 2 concentrations in the feed gas were set to the average values of boiler combustion gases. [Common conditions] Type of CO 2 absorption tower : wetted-wall absorption tower Inside diameter and height of the tower : 5 mm dia. x 7500 mm CO 2 concentration in the gas : 10 vol% O 2 concentration in the gas : 2 vol% Feed gas temperature : 60°C Feed gas quantity : 2 m 3 N/h Liquid absorbent concentration : 30 wt% Liquid absorbent quantity : 4 liter/h As has been described in detail, the process of the present invention in its CO 2 removal step removes both CO 2 and NO x from combustion gases by oxidizing the gases in advance with ozone and thereby converting NO x in the gases into NO 2 .

Claims: A process for removing both CO 2 and NO x from combustion gases, comprising the steps of cooling a combustion gas to 50 to 100°C, adding ozone to the combustion gas so as to oxidize NO in the combustion gas to NO 2 , and thereafter, bringing the gas into contact with an aqueous solution of an alcoholic hydroxyl group- and N-C 1 -C 4 -alkyl group-containing secondary or tertiary amine so as to remove NO 2 and CO 2 from the combustion gas. The process as claimed in claim 1, wherein the combustion gas is a waste gas that results from burning of a fossil fuel. The process as claimed in claim 1, wherein the ozone is air that contains ozone supplied by an ozone generator. The process for removing both CO 2 and NO x , from combustion gases as claimed in claim 1, wherein the alcoholic hydroxyl group- and N-C 1 -C 4 -alkyl group containing secondary amine is 2-(methylamino)ethanol (MAE), 2-(ethylamino)ethanol (EAE), 2-(isopropylamino)ethanol (IPAE), N-(n-butyl)ethanolamine, N-(tert-butyl)ethanolamine or a mixture thereof. The process for removing both CO 2 and NO from combustion gases as claimed in claim 1, wherein the alcoholic hydroxyl group and N-C 1 -C 4 -alkyl group- containing tertiary amine is 2-(dimethylamino)ethanol, 2-(diethylamino)ethanol (DEAE), (N-methyl)diethanolamine (MDEA), (tert-butyl)diethanolamine, 3-(N,N-dimethylamino)-1-propanol, 4-(N,N-dimethylamino)-1-butanol, 2-(N,N-dimethylamino)-2-methyl-1-propanol, 3-(N,N-dimethylamino)-2,2-dimethyl-1-propanol or a mixture thereof. The process for removing both CO 2 and NO, from combustion gases as claimed in any one of the claims 1, 4, 5, wherein the aqueous solution of the alcoholic hydroxyl-containing secondary or tertiary amine further contains piperazine.

Inventors: IIJIMA MASAKI, MIMURA TOMIO, MITSUOKA SHIGEAKI, SHIMOJO SHIGERU, IIJIMA, MASAKI, MIMURA, TOMIO, MITSUOKA, SHIGEAKI, SHIMOJO, SHIGERU, IIJIMA, MASAKI, C/O MITSUBISHI JUKOGYO K.K., Mimura, Tomio, c/o The Kansai Elec. Power Co. Inc., Mitsuoka, Shigeaki, c/o Hiroshima R&amp;DC Mitsubishi, Shimojo, Shigeru, c/o 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