JP3197183B2 - Method for removing carbon dioxide in flue gas - Google Patents

Description

DETAILED DESCRIPTION OF THE INVENTION

[0001]

The present invention relates to a relates to a method of removing CO ₂ (carbon dioxide) contained in combustion exhaust gas, more particularly, by using a mixed aqueous solution of secondary amine and tertiary amine, atmospheric pressure The present invention relates to a method for efficiently removing CO ₂ in the lower combustion exhaust gas.

[0002]

2. Description of the Related Art In recent years, the greenhouse effect of CO ₂ has been pointed out as one of the causes of the global warming phenomenon, and countermeasures have been urgently required internationally to protect the global environment. CO ₂
As a source of the occurrence, all human activity fields burning fossil fuels tend to be increasingly demanded for emission control. To the target power generation facilities such as thermal power plants using large amounts of fossil fuels with this, a method of flue gas of a boiler into contact with an aqueous alkanolamine solution or the like to remove the CO ₂ in the combustion exhaust gas is recovered and, Methods for storing the recovered CO ₂ without releasing it to the atmosphere are being vigorously studied.

Examples of the alkanolamine include monoethanolamine, triethanolamine, N-methyldiethanolamine (MDEA), diisopropanolamine, and diglycolamine.
Usually, monoethanolamine (MEA) is preferably used. The use of other secondary and tertiary hindered amine aqueous solutions is also being studied.

There are many known techniques for separating an acidic gas from various mixed gases using an amine compound. Japanese Patent Application Laid-Open No. 53-100180 discloses that (1) at least one secondary amino group or tertiary carbon atom which is a part of a ring and bonded to either a secondary carbon atom or a tertiary carbon atom; An amine mixture consisting of at least 50 mol% of sterically hindered amines containing bound primary amino groups and at least about 10 mol% of tertiary amino alcohols, and (2) said amines being physical absorbers for acidic gases A method for removing acidic gases comprising contacting a gaseous mixture with an amine-solvent liquid absorbent comprising a solvent for the mixture is described. Sterically hindered amines include 2-piperidineethanol [2- (2-hydroxyethyl) -piperidine] and 3-amino-3-methyl-1-butanol, and the solvent may contain up to 25% by weight of water. Examples of the processing gas include a sulfoxide compound and the like, as described in the upper left column of page 11 of the same publication, as “normal gaseous state having a high concentration of carbon dioxide and hydrogen sulfide, for example, 35% CO ₂ and 10 to 12% H ₂ S. mixture "is illustrated, also in the embodiment CO ₂ itself is used for.

JP-A-61-71819 describes a composition for scraping an acidic gas containing a non-aqueous solvent such as a sterically hindered amine and sulfolane. In addition, this publication describes the advantage of sterically hindered amines with respect to CO ₂ absorption using a reaction formula.

[0006] Chemical Engineering Science (C
chemical Engineering Science
ce), Vol. 41, No. 2, pp. 997-1003 discloses the carbon dioxide absorption behavior of an aqueous solution of a hindered amine, 2-amino-2-methyl-1-propanol (AMP). As the gas to be absorbed, CO _{2 at} atmospheric pressure and a mixture of CO ₂ and N ₂ are used.

[0007] Chemical Engineering Science (C
chemical Engineering science
ce), Vol. 41, No. 4, pp. 997 to 1003 discloses carbon dioxide absorption behavior of an aqueous solution of a hindered amine, 2-amino-2-methyl-1-propanol (AMP). As a gas to be absorbed, atmospheric pressure CO ₂ and a mixture of CO ₂ and nitrogen are used.

[0008] Chemical Engineering Science (C
chemical Engineering science
ce), Vol. 41, No. 2, pp. 405-408, shows that hindered amines such as AMP and MEA
The absorption rates of aqueous solutions of such linear amines for CO ₂ and H ₂ S have been reported.

US Pat. No. 3,622,267 uses an aqueous mixture containing methyldiethanolamine and monoethylmonoethanolamine, and uses a high partial pressure of CO ₂ contained in a synthesis gas such as a partially oxidized gas such as crude oil. For example, a technique for purifying a synthesis gas containing 30% CO _{2 at} 40 atm is disclosed.

[0010] German Offenlegungsschrift 1,542,415 discloses a technique of adding a monoalkylalkanolamine or the like to a physical or chemical absorbent in order to improve the absorption rate of CO ₂ , H ₂ S and COS. . Similarly, German Offenlegungsschrift 1,904,428 discloses a technique in which monomethylethanolamine is added for the purpose of improving the absorption rate of methyldiethanolamine.

US Pat. No. 4,336,233 discloses that a 0.81-1.3 mol / l aqueous solution of piperazine is used as a cleaning liquid for the purification of natural gas, synthesis gas and gasified coal gas, and that piperazine is methyl. A technique is disclosed which is used as a washing solution in an aqueous solution together with a solvent such as diethanolamine, triethanolamine, diethanolamine, and monomethylethanolamine.

Similarly, Japanese Patent Application Laid-Open No. 52-63171 discloses a CO ₂ absorbent obtained by adding a piperazine derivative such as piperazine or hydroxyethylpiperazine as an accelerator to a tertiary alkanolamine, a monoalkylalkanolamine or the like. ing.

[0013]

An aqueous solution of an alkanolamine represented by MEA as described above or an aqueous solution of a hindered amine or a mixture of amines described in the above-mentioned known document is used as a CO ₂ absorbing solution in combustion exhaust gas. However, in view of the amount of CO ₂ absorbed per unit amine mol in the amine aqueous solution, the absorption rate of CO _{2 at} a predetermined concentration, and the heat energy required for regeneration of the alkanolamine aqueous solution after absorption, it is not always satisfactory. Absent. In general, secondary hindered amines and tertiary hindered amines are superior to MEA in terms of CO ₂ absorption and thermal energy for regeneration, but the absorption rate needs to be further improved, and absorption for improving absorption efficiency is required. increase of CO ₂ absorption quantity per dosage unit mole, a major challenge to be like CO ₂ absorption amount increased resolution per unit volume of the aqueous solution by high concentration of the amine solution. Furthermore after absorption of CO _2, separating the CO _2, less absorbent of the heat energy required in regenerating the absorption liquid is desired.

[0014]

Means for Solving the Problems In view of the above problems, the present inventors have conducted intensive studies on an absorbent used for removing CO ₂ in flue gas and found that secondary amine and tertiary amine
The inventors have found that it is particularly effective to use a mixed aqueous solution having a predetermined concentration or more of a secondary amine, and have completed the present invention. That is, according to the present invention, the flue gas at atmospheric pressure is brought into contact with an amine aqueous solution to reduce the CO in the flue gas.
_In the method for removing ₂ , as the amine aqueous solution,
When the concentration of each of the secondary amine and the tertiary amine is 10
Using an aqueous solution of an amine in the range of
Determine the concentration of the tertiary amine in the amine mixed aqueous solution by the absorption conditions.
When the same aqueous solution of a tertiary amine is used
3rd, which has the largest CO ₂ absorption per unit volume of the aqueous solution
Within the range of 10% by weight before and after the concentration of the secondary amine, and
The total concentration of amine in the amine mixed aqueous solution is 70
% Of CO ₂ in the combustion exhaust gas
Is provided. According to the present invention, as the amine aqueous solution, 2-methylaminoethanol;
A secondary amine selected from the group consisting of 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol, piperazine, 2-methylpiperazine, 2,5-dimethylpiperazine and 2-piperidinoethanol; And 2-dimethylaminoethanol, 2-
Diethylaminoethanol , 3-dimethylamino-1-
Propanol, 4-dimethylamino-1-butanol,
2-dimethylamino-2-methyl-1-propanol,
Provided is a method for removing CO ₂ in flue gas using a mixed aqueous solution of a tertiary amine selected from the group of N-ethyl-N-methylethanolamine. Also according to the invention
If the secondary amine and the tertiary amine both have one alcoholic hydroxyl group, CO
A method is provided for removing ₂ . Furthermore, according to the present invention, as the amine aqueous solution, 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol,
Secondary amines selected from the group consisting of piperazine, 2-methylpiperazine, 2,5-dimethylpiperazine and 2-piperidinoethanol, and N-methyldiethanolamine, N-ethyldiethanolamine, Nt-butyldiethanolamine and N- A method is provided for removing CO ₂ in flue gas using a mixed aqueous solution of a tertiary amine selected from the group of methyldiisopropanolamine.
Furthermore, according to the present invention, CO _{2 in} combustion exhaust gas is removed using a secondary amine selected from 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, and 2-n-butylaminoethanol. A method is provided for doing so.

[0015]

In the present invention, an aqueous solution obtained by mixing a secondary amine and a tertiary amine in a range of 10 to 45% by weight is used as the absorbing solution. Although the tertiary amine has a large CO ₂ absorption amount per unit mole but a low absorption rate, the absorption rate is accelerated by using a secondary amine in combination, and the absorption rate is larger than that of using each alone. There is.

The absorption of CO ₂ is usually carried out by gas-liquid countercurrent contact in an absorption tower, and CO ₂ separation / regeneration of the absorption liquid by steam stripping is carried out in a regeneration tower.
At that time, the saturated absorption amount (X-axis) of CO ₂ per unit mole of amine in the absorbing solution at a constant temperature and the CO _{2 in} gas
The relationship with the partial pressure (Y-axis), that is, the equilibrium curve is obtained for each amine under the conditions of both the temperature of the absorption tower and the regeneration tower and the partial pressure of CO _2. If the line can be set apart and parallel to the equilibrium curve,
This is advantageous because the number of theoretical absorption stages can be easily set. The equilibrium curve for tertiary amines is less steep than that for secondary amines and therefore has a higher absorption capacity, but is less favorable than secondary amines in relation to the operating line. However, by mixing both amines, the equilibrium curve of the mixed amine aqueous solution moves between the secondary amine and the tertiary amine, so that there is an advantage that the absorption operation conditions can be easily set.

Further, according to the findings found by the present inventors, C in a gas having a small CO ₂ partial pressure, such as flue gas, is used.
When absorbing O ₂ , in the tertiary amine aqueous solution, as the concentration of the tertiary amine in the aqueous solution is increased, there is a concentration (maximum CO ₂ absorption concentration) at which the absorption amount of CO ₂ becomes maximum,
Above this, the absorption decreases. The amine concentration at that time depends on the type of amine, but is about 30% by weight.
It is about. In contrast, with secondary amines, the absorption of CO ₂ increases with increasing concentration. Since the concentration of the absorbing solution has an upper limit in terms of viscosity increase, gas-liquid contactability, fluidity, etc., the concentration of the tertiary amine is set to the maximum CO2 concentration.
₍₂₎ Set the concentration near the absorption concentration, add a secondary amine within the range up to the above upper limit, and increase the concentration by mixing both amines, thereby maximizing the absorption capacity of both. There is an advantage that can be.

The secondary amine and tertiary amine used as the CO ₂ absorbent in the present invention may or may not have an alcoholic hydroxyl group in the molecule. . Both may be acyclic or cyclic, but the tertiary amine is preferably acyclic.

Preferred secondary amines in the present invention are 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol,
acyclic amines such as n-butylaminoethanol, and piperazine, 2-methylpiperazine (MP), 2,5-
Examples are cyclic amines such as dimethylpiperazine and 2-piperidinoethanol. The secondary amines can be used alone or in combination of two or more.

Preferred tertiary amines include 2-
Dimethylaminoethanol, 2-diethylaminoethacnol, 3-dimethylamino-1-propanol, 4-
Those having one alcoholic hydroxyl group such as dimethylamino-1-butanol, 2-dimethylamino-2-methyl-1-propanol and N-ethyl-N-methylethanolamine are exemplified. Further, those having two alcoholic hydroxyl groups include N-methyldiethanolamine, N-ethyldiethanolamine, Nt-butyldiethanolamine and N-methyldiisopropanolamine. When a compound having two alcoholic hydroxyl groups is used, the concentration of the secondary amine is preferably increased to, for example, 15% by weight or more, and more preferably 30% by weight or more. preferable. The above tertiary amines can be used alone or in combination of two or more.

The concentration of the mixed aqueous solution of secondary amine and tertiary amine (hereinafter also referred to as absorption liquid) used for contacting with the combustion exhaust gas of the present invention is 10 to 45
% By weight. In particular, the concentration of the tertiary amine is preferably in the range of 10% by weight before and after the maximum CO ₂ absorption concentration of the tertiary amine, and more preferably in the range of 5% by weight before and after the maximum CO ₂ absorption concentration. Therefore, the preferred concentration range of the tertiary amine is about 20 to 40% by weight.
On the other hand, as described above, the secondary amine generally has a higher saturated absorption amount as the concentration is higher. Therefore, the higher the concentration, the more preferable. However, the total concentration of the secondary amine with the tertiary amine is 70% by weight.
The following is preferable from the viewpoint of gas-liquid contactability and fluidity. In particular, as a preferable concentration range of the secondary amine,
It is about 15-20% by weight. In the present invention, the temperature of the absorbent at the time of contact with the combustion exhaust gas is usually in the range of 30 to 70 ° C. Further, a corrosion inhibitor, a deterioration inhibitor and the like are added to the absorbing solution used in the present invention as needed.

Further, the term "under atmospheric pressure" in the present invention includes a pressure range near atmospheric pressure at which a blower or the like acts to supply combustion exhaust gas.

The process that can be employed in the method of the present invention for removing CO ₂ from flue gas is not particularly limited, but one example thereof will be described with reference to FIG. In FIG. 1, only the main equipment is shown, and the auxiliary equipment is omitted. In FIG. 1, 1 is a CO ₂ removal tower, 2 is a lower filling section, 3 is an upper filling section or tray, 4 is a CO ₂ removal tower exhaust gas inlet, and 5 is a CO ₂ removal section.
Combustion exhaust gas outlet, 6 is an absorbent supply port, 7 is a nozzle, 8
Is a flue gas cooler provided as required, 9 is a nozzle, 10 is a filling section, 11 is a humidification cooling water circulation pump, 12
Is a make-up water supply line, 13 is an absorption liquid discharge pump that has absorbed CO ₂ , 14 is a heat exchanger, 15 is an absorption liquid regeneration (hereinafter, referred to as
Tower, 16 is a nozzle, 17 is a lower filling section, 18 is a regenerative heater (reboiler), 19 is an upper filling section, 20 is a reflux water pump, 21 is a CO ₂ separator, and 22 is recovered CO. ₂ discharge line, 23 is a regeneration tower reflux condenser, 24
Is a nozzle, 25 is a regeneration tower reflux water supply line, 26 is a combustion exhaust gas supply blower, 27 is a cooler, and 28 is a regeneration tower reflux water supply port.

In FIG. 1, the flue gas is pushed into the flue gas cooler 8 by the flue gas supply blower 26,
Contact with humidifying cooling water and the filling section 10 from the nozzle 9, is fogging, de-C through the de-CO ₂ tower combustion exhaust gas feed port 4
It is led to the O ₂ tower 1. The humidified cooling water in contact with the combustion exhaust gas accumulates in the lower part of the combustion exhaust gas cooler 8 and is circulated to the nozzle 9 by the pump 11. Since the humidified cooling water is gradually lost by humidifying and cooling the combustion exhaust gas, it is replenished through the makeup water supply line 12. When the combustion exhaust gas is further cooled from the humidified cooling state, a heat exchanger is placed between the humidification cooling circulation pump 11 and the nozzle 9 to cool the humidification cooling water and supply it to the combustion exhaust gas cooler 8. It becomes possible.

The flue gas pushed into the CO ₂ removal tower 1 is brought into countercurrent contact with the absorbent at a constant concentration supplied from the nozzle 7 in the lower filling section 2, and CO ₂ in the flue gas is absorbed and removed by the absorbent. Then, the CO ₂ -free flue gas is directed to the upper filling section 3. The absorbing solution supplied to the CO ₂ removal tower 1 is CO
₂ is absorbed, and the temperature of the reaction is normally higher than the temperature at the absorption liquid supply port 6 due to the heat of reaction caused by the absorption. The absorption liquid is sent to the heat exchanger 14 by the absorption liquid discharge pump 13 that has absorbed CO ₂ and is heated. It is led to the regeneration tower 5. The temperature of the regenerated absorbent is controlled by the heat exchanger 14 or, if necessary, the cooler 2 provided between the heat exchanger 14 and the absorbent supply port 6.
7 can be performed.

In the regeneration tower 15, the heating by the regeneration heater 18 is performed.
The absorption liquid is regenerated in the lower filling section 17 by heat, and the heat exchanger
14 and, if necessary, cooled by a cooler 27 to remove C
O_TwoReturned to Tower 1. Above the absorption liquid regeneration tower 15
And the CO separated from the absorbing solution _TwoIs supplied from nozzle 24
And is cooled by the regenerative tower reflux cooler 23.
Rejected, CO_TwoCO in the separator 21_TwoWater vapor associated with
Is separated from the condensed reflux water, and the recovered CO_TwoDischarge line 2
CO from 2_TwoGuided to the recovery process. Part of the reflux water is refluxed
The water is returned to the regeneration tower 15 by the water pump 20, and a part is regenerated.
CO 2 removal through the reflux water supply line 25_TwoRegeneration tower reflux of tower 1
The water is supplied to the water supply port 28. A trace amount of this recycle tower reflux water
Desorbed CO._TwoTop filling of tower 1
Contact with the exhaust gas in the part 3 and trace amount of CO contained in the exhaust gas
_TwoContributes to the removal of.

[0027]

EXAMPLES The present invention will be described below in detail with reference to examples, but the present invention is not limited to these examples. [Reference Examples 1 to 3] 50 ml of a tertiary amine aqueous solution whose concentration was changed as shown in Table 1 as an absorbing solution was placed in a glass reaction vessel installed in a thermostat. While stirring at a temperature of 40 ° C., the test gas is flowed at a flow rate of 1 liter / min under atmospheric pressure,
The solution was passed through a filter to easily generate bubbles. As a test gas, a model combustion exhaust gas of 40 ° C. having a composition of 10 mol% of CO ₂ , 3 mol% of O ₂ , and 87 mol% of N ₂ was used. The test gas is continuously passed, and when the CO ₂ concentration of the incoming and outgoing gas becomes equal, the C contained in the absorbing solution is
O ₂ is measured using a CO ₂ analyzer (total organic carbon meter),
Saturation absorption of ^{_{CO 2 (Nm 3 CO 2 /}} m 3 absorbent solution, mol CO ₂ / amine molar absorbent) was determined. Table 1 shows the results.
Shown in

[0028]

[Table 1]

As it is apparent from the results in Table 1, the CO ₂ absorbing ability of the tertiary amine per se for use in the present invention are all seen that there is a maximum CO ₂ absorption density before and after concentration of 30 wt%.

[Reference Examples 4 to 18] The secondary amine and tertiary amine shown in Table 2 were subjected to a CO ₂ absorption test at a concentration of 30% by weight in the same manner as in Reference Example 1. Table 2 shows the results.

[0031]

[Table 2]

Examples 1 to 5 and Comparative Examples 1 to 4 In order to confirm the effect of the method for removing CO ₂ in flue gas according to the present invention, a small test apparatus schematically shown in FIG. 2 was used. FIG.
The test gas 201 has a height of 1500 mm and an inner diameter of 5 mm.
Stainless steel absorption tower 2 with 0 mm and filling height 1000 mm
02 at a flow rate of 0.98 Nm ³ / h.
The composition of the test gas is 10% CO ₂ , 87% N ₂ , 3% O ₂
It has been adjusted to. A nozzle 203 is provided above the absorption tower 202, and the regenerated and circulated absorption liquid is sprayed. A filling section 204 provided at the center of the absorption tower is filled with Dickson packing having a length of 6 mm, and a warm water jacket 205 is provided therearound.
Hot water circulation pump 206 and hot water tank 207
It has. Further, an absorption tower condenser 208 is provided above the absorption tower 202. After the absorption processing gas is cooled here, it is analyzed by the absorption processing gas analyzer 209 and discharged. An absorption liquid extracting pump 210 is provided at the lower part of the absorption tower, and the absorption liquid is
After the temperature is controlled to 0 ° C., it is led to the upper part of the regeneration tower 212.
The regeneration tower 212 is made of stainless steel and has a height of 1500 mm, an inner diameter of 25 mm, and a filling height of 160 mm at the center, and is filled with the same packing as the absorption tower. Also, a hot water jacket 213 for keeping the temperature constant as in the absorption tower is provided in the filling section.
It has. The CO ₂ rich absorbent flowing down from the upper part of the packed portion of the regeneration tower 212 is reboiler heater (electric heating) at the lower part
Heated at 214 (the reboiler temperature is controlled at 110 ° C.) is stripped by the generated steam to become a lean absorbent, a regenerated absorbent cooler 215, a regenerated absorbent drain pump 216, a regenerated absorbent tank 217, a regenerated absorbent The liquid is circulated and used at a flow rate of 2.8 liter / h above the absorption tower via a liquid circulation pump 218 and a regenerated absorbent preheater 219. A part of the lean absorbent is returned to the inlet of the regeneration tower by the regeneration absorbent circulation pump 220. A regeneration tower condenser 221 is provided on the upper part of the regeneration tower, and CO ₂ released from the absorbing solution is condensed and separated from water vapor by the condenser 221, and then an infrared CO ₂ gas meter (not shown, manufactured by Horiba Seisakusho)
IA 510) and analyzed by the regeneration tower gas scrubber 22
2 to be discharged.

An absorption / regeneration test was performed using the absorption liquid shown in Table 3 under the above-mentioned small test apparatus and absorption / regeneration conditions, and an inlet gas (test gas) and an outlet gas (absorption gas) of the absorption tower shown in Table 3 were used. CO ₂ concentration in the treated gas) in, indicated by the amount of heat input (kW units reboiler), the rich absorption liquid and the CO ₂ concentration in the lean absorbing solution (manufactured by Shimadzu Corporation "total organic carbon meter" TOC-
5000) and the heat of regeneration was determined. Table 3 shows the results.

[0034]

[Table 3]

As can be seen from Table 3, the second embodiment according to the present invention
It can be seen that the use of a mixed absorbing solution of a tertiary amine and a tertiary amine is greatly improved in terms of absorption capacity and regeneration energy, and is extremely advantageous.

[0036]

As described above in detail, the treatment of the combustion exhaust gas under the atmospheric pressure by the method of the present invention makes it possible to comprehensively absorb CO ₂ more than in the case of using the conventional amine absorbing liquid. Improved performance is achieved.

[Brief description of the drawings]

FIG. 1 is a diagram illustrating an example of a process for removing CO _{2 in} combustion exhaust gas that can be employed in the present invention.

FIG. 2 is a schematic explanatory view of a small test apparatus used in an embodiment of the present invention.

──────────────────────────────────────────────────続 き Continued on the front page (72) Inventor Masaki Iijima 2-5-1 Marunouchi, Chiyoda-ku, Tokyo Mitsubishi Heavy Industries, Ltd. Headquarters (72) Inventor Kaoru Mitsuoka 4-6-1 Kanonshinmachi, Nishi-ku, Hiroshima City, Hiroshima Prefecture 22 Hiroshima Research Laboratory, Mitsubishi Heavy Industries, Ltd. (56) References JP-A-53-100171 (JP, A) JP-A-61-271016 (JP, A) JP-A-2-111414 (JP, A) (58) Field surveyed (Int. Cl. ⁷ , DB name) B01D 53/62

Claims (5)

(57) [Claims] 1. A method of removing CO ₂ in flue gas by bringing flue gas under atmospheric pressure into contact with an aqueous amine solution, wherein the aqueous amine solution comprises a secondary amine and a tertiary amine.
Using an aqueous amine mixture solution in which the concentration of each of the secondary amines is in the range of 10 to 45% by weight ;
The concentration of the tertiary amine is adjusted to the tertiary amine under the same absorption conditions.
Unit volume of aqueous solution when using a single aqueous solution of min
Before and after the concentration of tertiary amine that gives the maximum CO ₂ absorption
In the range of 10% by weight, and the amine mixed aqueous solution
A method for removing CO ₂ from combustion exhaust gas, wherein the total concentration of amines in the exhaust gas is 70% by weight or less . 2. The aqueous amine solution includes 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol, piperazine, 2-methylpiperazine, 2,5
-A secondary amine selected from the group of -dimethylpiperazine and 2-piperidinoethanol, and 2-dimethylaminoethanol, 2-diethylaminoethanol, 3-dimethylamino-1-propanol, 4-dimethylamino-
1-butanol, 2-dimethylamino-2-methyl-1
The C in the combustion exhaust gas according to claim 1, wherein a mixed aqueous solution of a tertiary amine selected from the group of -propanol and N-ethyl-N-methylethanolamine is used.
A method for removing O ₂ . Wherein CO in combustion exhaust gas according to claim 1 or 2, wherein the second and tertiary amines are those having both one alcoholic hydroxyl group
How to remove ₂ . 4. The amine aqueous solution includes 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol, 2-n-butylaminoethanol, piperazine, 2-methylpiperazine, 2,5
A secondary amine selected from the group consisting of -dimethylpiperazine and 2-piperidinoethanol, and N-methyldiethanolamine, N-ethyldiethanolamine, Nt-
Method for removing CO ₂ in the combustion exhaust gas according to claim 1 which comprises using a mixed aqueous solution of a tertiary amine selected from the group consisting of butyl diethanolamine and N- methyl diisopropanolamine. 5. A second compound selected from 2-methylaminoethanol, 2-ethylaminoethanol, 2-isopropylaminoethanol and 2-n-butylaminoethanol.
5. A method according to claim 1, wherein a secondary amine is used.
The method for removing CO ₂ from combustion exhaust gas according to any one of claims 1 to 3 .