2.1. Background
There are two significant points that should be considered before capture CO2, which are
- (a)
How to deal with the huge amount of carbon dioxide from fossil fuels formed during combustion;
- (b)
How to grip impurities of the stream in flue gas.
The impurities in flue gas may contain sulfur and nitrogen oxides, particulate matter, and water vapor. The combustion of the fuel source will produce various amounts of impurities and changes, depending upon the fuel source. It is crucial to know the fundamental mechanisms behind CO
2 and to prevent impurities and the formation of impurities during the combustion of fossil fuel [
9]. The common reactions taking place during combustion can be applied to any fuel for CO
2 formation, as follows in Equations (1) and (2) [
9]:
This is uncompleted combustion,
This is a complete combustion.
It should be noted that, when using natural gas instead of coal, the emissions of carbon dioxide will be significantly reduced and the coal will emit more nitrogen and sulfur dioxide because it will contain more impurities, rather than natural gas. Acid rain is caused by nitrogen and sulfur oxides, which are the main contributors to its formation. There is an advantage of employing some technologies for capturing CO
2, such as oxy-combustion, chemical looping combustion, and pre-combustion, which is the creation of an environment for combustion without impurity precursors, such as H
2, S, N, and N
2. However, there are certain amounts of inherent nitrogen and sulfur in fuel, so complete impurity removal is not possible, and it cannot be considered as a perfect fuel. In addition, this impurity of combustion depends on the process that is used to treat the fuel before use in burning. In common cases of CO
2 capture, the impurities are removed from flue gas before capture is applied. Finding ways to handle the large quantity of CO
2 produced by burning fuel in power stations, whatever the source of fuel, is a big challenge [
9]. In the different power plants in Hebei Province, China, as shown in
Table 2, the raw coal had a high emission value of about 900 to 1000 g per KW/h, which is double the amount of oil and gas that was emitted. Moreover, it needs excess oxygen more than other fuels to complete combustion, which is considered a challenge when using chemical solvents to capture CO
2, increasing the degradation when amine solution is used [
10,
11]. However, the consumption of fuel per KW/h for oil and natural gas represents less than one third of the consumption of raw coal required to generate power. Currently, commercial CO
2 capture systems have a maximum capacity of about 800 t/d CO
2, which means that the capture process emits approximately ten times less than that in a power plant. Therefore, it is appropriate to begin discussing the various CO
2 capture approaches and their associated technologies, such as post-combustion, pre-combustion, oxy combustion, and chemical looping combustion [
7,
9,
10,
12,
13].
On the other hand, rather than the amount of CO
2 emitted into the atmosphere by many industries, the chemical and the physical properties of the CO
2 should be studied to learn about it and how it behaves. Therefore,
Table 3 illustrates the physical and chemical properties of CO
2 [
14], and
Table A1 shows the properties of CO
2 that used in amine absorption come out from ProMax in
Appendix A.
2.2. Process Technology Description of Different Amines
Amine processing includes two major processes of absorption and separation. When the CO
2 is absorbed by a lean amine aqueous solution solvent through an absorption process, the equipment used is called an absorber. In addition, the process in which the CO
2 is separated from aqueous solution by applying heat is called a separation or regeneration process, and the equipment employed is called a regenerator or stripper [
15]. Moreover, the treatment occurs at an absorber at high pressure and at a low temperature, while at the stripper, there is a low pressure and high temperature between 100 and 120 °C [
13,
16]. There are some arguments about the stripping temperature, which varies between 120 and 150 °C [
8,
17], 95 and 135 °C [
18], and 120 and 140 °C [
15]. Therefore, the system includes heat, a cooling source, and a compressor to raise the pressure of flue gas before it enters the absorber. Furthermore, the system includes a pump to circulate the lean solution and rich amine [
13,
15,
16]. In absorption, the following steps occur [
19]:
- (a)
CO2 dissolves into the absorbent;
- (b)
A low temperature is required to ensure a high rapport for the absorption of CO2;
- (c)
The distribution of CO2 will occur between the gas–liquid interface and the bulk gas;
- (d)
The CO2 will react with the amine in the solution.
The flue gas results from burning fossil fuel in power stations and represents approximately 3–20% of gas emitted. It is fed into an absorption column, needed to cool the temperature of flue gas to below 50 °C or about 47–50 °C, due to the high temperatures of the exhaust gas of power generations [
17]. After the flue gas has been cooled by an exchanger, such as cooling water and a fan cooler, it will enter the absorption tower or so-called absorber column and pass through it from bottom to top, in which approximately 86–90 vol.% of the CO
2 is absorbed by solvent [
5,
13,
15,
20] and amine absorbs the carbon dioxide at 40–75 °C [
18]. In addition, the absorbent or solvent enters the column from the top side of the tower and moves down to the bottom. In the meantime, the flue gas which contains acid gas will react with the solvent and usually has a temperature of nearly 40 °C. Through this process, lean amine is converted into rich amine, which means that CO
2 is absorbed by aqueous amine solution. Secondly, heat is released as a result of the absorbed CO
2 and the temperature of the solvent is increased due to the exothermic reaction, which is a kind of reversible reaction. At the bottom of the absorber, the CO
2-rich stream will be collected at a required level, to prevent untreated gas from escaping from the desorber tower and, for safety reasons, to prevent the stripper tower caps and trays from being damaged due to the high differential pressure between the regenerator and absorber.
The purified gas emitted out into the atmosphere is washed by water at the top of the absorber to cool the top of the tower, prevent evaporation of the amine solution, and mitigate the loss of solvent [
9,
13,
15,
17]. Furthermore, the loading is varied from 0.1 to 0.45 mol CO
2/mol amine, depending on the lean and rich solvent (generally, lean and rich solvent CO
2 loading of 0.1-0.2 mol CO
2/mol MEA and 0.4–0.5 mol CO
2/mol MEA, respectively) and on several other factors, which are
The increasing or decreasing amine flow rate;
The increasing/decreasing concentration of amine, considering the factors of corrosion that are caused by amine and the amount of CO2 that will be absorbed;
The loading is defined as the total amount of CO
2 absorbed by amine and can be described as in Equations (3) and (4) [
16,
21]:
The absorber column or tower includes trays and is different, depending on the solvent used for the capturing process [
15].
Figure 1 illustrates the different types of amine aqueous solutions with the number of trays used in each solvent [
15].
The rich amine solution leaves via the bottom of the absorber, which is then heated to about 100 °C across the amine–amine exchanger (lean/rich amine heat exchanger). It is fed to the top side of a stripping column or regenerator, in order to minimize the heating energy cost of the rich solution, which is required before it enters the stripper to avoid widely different temperatures between the solvent and regenerator. The flow that happens between the absorber and stripper occurs due to the different pressures between them, which is quite high, being about 15–20 times greater than the regenerator pressure [
21]. In the desorption column, the following occur [
19]:
- (a)
To ensure a lower relationship for the absorption of CO2, the temperature be should be high;
- (b)
To ensure that CO2 will be released, chemical equilibria should occur;
- (c)
The desorption process is endothermic; therefore, to maintain the high temperature, heat must be applied to the absorbent.
Where further heated, a supply at the bottom of the stripper is required to increase the temperature to 120–140 °C by using a steam reboiler which is generated for this purpose or the power plant will become exhausted. The operating pressure for a stripper is nearly 1.5–2 bar and it is formed of a packed column which has a kettle reboiler [
5,
15,
21]. The rich solution or stable product that formed in the absorber and the CO
2, which was absorbed by the solvent, will be recovered at the regenerator column; then, CO
2 will be released from the absorbent inside the stripper at a high temperature of 100–120 °C, due to the equilibrium isotherm and loading (mole of CO
2/mole of amine) transfer from higher (rich amine) to lower loading (lean amine means amine that had taken off the CO
2); that is why the solvent-recovering energy cost is high. The lean solution at the bottom of the regenerator is circulated back to the absorption tower after passing through the heat exchanger and cooler [
13,
15,
16]. The gas consisting of a mixture of water vapor and CO
2 with some evaporated amine travels out of the top of the stripper and enters a cooler to cool it. Then, it is fed into a flash drum and the acid gas, which is CO
2 from condensate water, and amine are physically separated, no matter the kind of amine. Finally, CO
2 is compressed and transported for sequestration.
Figure 2 shows a schematic diagram of the amine-based chemical absorption process [
8,
17].
2.3. Amine-Based Chemical Solvent Using Monoethanolamine (MEA)
Amines are officially derivatives of ammonia, and where one or more hydrogen atoms have been displaced by an organic substituent, such as an alkyl group, these amines called alkylamines [
22]. MEA is one of the most important absorption liquids and is the least expensive. It can be produced in large quantities from ethylene oxide and ammonia reactions. The Acid Dissociation Constant (pKa) is close to a primary amine. Therefore, it has a very good viscosity and an excellent average rate of absorption of CO
2, with an over-average normalized ability [
19]. An amino group is the perfect group for absorbing CO
2 and provides enough alkalinity. It is commonly dissolved so that CO
2 chemically reacts with alkanolamines. One of the most crucial advantages of alkanolamines is that, structurally, at least one hydroxyl group is contained in them. Due to this, it can help to raise the solubility in aqueous solutions and mitigate the vapor pressure [
10]. Monoethanolamine (MEA) is considered one of the most general alkanolamine groups and is widely used. It has been used for over 75 years to remove CO
2 and H
2S from natural gas and flue gas [
23]. Due to MEA having a high-water solubility, high cyclic capacity, and considerable kinetic rates of absorption-stripping at a low CO
2 concentration, it is considered to be a standard sorbent [
8].
The capacities of chemical and physical MEA absorption are affected by the pressure, temperature, concentration of aqueous MEA, and presence of additional gases, which means impurities [
22]. The weight % concentration of monoethanolamine varies from 15 to 35%, depending on the process and 0.45 CO
2 moles/mole amine (324 g CO
2/kg MEA), so the lean and rich amine solvent loading can vary from 0.242 to 0.484 CO
2 moles/mole amine, respectively [
2,
9,
22]. However, others have reported that monoethanolamine can remove around 90% and 30 wt.% MEA solution with optimum lean amine solvent loading of nearly 0.32–0.33 mol CO
2/mol MEA and a requirement of thermal energy of 3.45 GJ/ton CO
2 [
2].
Figure 3 [
24] shows the chemical structure of primary amine and
Table 4 illustrates the typical characteristics of amine solvents for MEA and other amines used for CO
2 absorption [
8,
15,
16,
24,
25].
There are two major amine technologies used to treat flue gas. Kerr-McGee/ABB Lummus Crest was the first commercial technology, developed by Mitsubishi Heavy Industries with the Kansai Electric Power Company in the 1990s. This technology is operated with cogeneration systems and boilers that have a range of fire fuels. The concentration of aqueous amine solution MEA is about 15–20%. However, in this process, the flue gas should contain limited sulfur dioxide, as well as tolerate a reasonable amount of oxygen. Furthermore, in 1978, the first Kerr-McGee/ABB Lummus Crest technology in Trona (California) recovered CO
2 from flue gas, with a production value of 800 t/day of CO
2. The most crucial advantages are the low amine losses, low heat required for regeneration, and low amine degradation due to the additives and inhibitors used in this technology [
15].
The second technology is the Fluor process, which was developed by Fluor Daniel from Dow Chemical in 1989. Using a 30 wt.% of MEA solvent, the Kerr-McGee/ABB Lummus Crest process uses additives and inhibitors to prevent equipment corrosion and degradation. The Fluor Daniel process has mainly been used to remove exhaust gases and has been employed in more than 20 plants worldwide. For example, in Lubbock, Texas, the plant has a capacity rate of about 1200 t/day of CO
2. This technology can recover between 85 and 95% of CO
2 from flue gas, with the purity reaching 99.95% [
15,
19,
21]. The two most fundamental reactions of amines are shown in Equations (5) and (6) [
22,
26,
27]:
Finally, the temperature which causes the MEA to become exposed to thermal degradation is 120 °C and is considered one of the main drawbacks in comparison to oxidation, so inhibitors should be used to avoid it [
20].
2.4. Degradation of MEA and Other Solvents
The MEA degradation rate is nearly 1.5 kg/ton CO
2 whatever the type of degradation [
2,
20]; therefore, degradation has several types, and two major types will now be discussed.
- A.
Oxidative degradation
Oxidation degradation occurs because of flue gas containing oxygen in the absorber tower. Neither a high temperature nor CO
2 is required for oxidative degradation. This is a major issue for capturing CO
2 in the flue gas, and the concentration of oxygen varies between 3 and 5% in the gas stream. It mainly occurs in the absorber, at 40–70 °C [
8]. In addition, according to a study conducted at the University of Texas, the degradation can be controlled by the mass transfer of oxygen under industry conditions, where the degradation rate is nearly 0.29–0.73 kg of MEA/ton of CO
2. Furthermore, loss of the solvent and the formation of heat-stable salts are also caused by oxidative degradation, and to prevent this, inhibitors are added to the system [
21,
23]. The products, such as aldehydes, organic acids, and ammonia, are formed by an oxidative degradation chain of amine solvent starting with MEA. In the second step, the acids are formed (heat-stable salts), leading to mitigation of the capacity rate of the absorption of CO
2 by the solvent. These acids react with the absorbent MEA, leading to the production of amide compounds [
8,
23].
Table 5 shows the oxidative degradation compounds formed from MEA [
8,
23].
Diethanolamine is formed by oxidizing primary and tertiary amines; however, a large amount of diethanolamine is also produced by oxidizing MDEA, as shown in
Figure 3 [
19].
Polderman was the first person to propose the mechanism of the polymerization of carbamate of MEA in 1955 [
28]. The polymerization of carbamate occurs in the stripper column at a high temperature and over a long period of time [
21]. The thermal degradation increases when the temperature is increased in the stripper column, where the degradation rate of MEA or any solvent will be 2.5–6% per week at a temperature of about 135 °C [
16]. The polymerization of carbamate causes an increased amine solution viscosity, loss of carbon dioxide’s absorption capacity, increased corrosion, and foaming [
28]. The mechanism of degradation is as follows.
First, the reaction occurs at the absorber with CO
2, and CO
2 associates with MEA to form carbamate of MEA, as shown in Equation (7) [
28]:
Then, at the stripper, the reaction is generally reversed; however, for some statuses, 2-oxazolidone will form due to the cyclizing of MEA carbamate, and this reaction type is also reversible, as shown in Equation (8) below [
8]:
Furthermore, the 2-oxazolidone will react with one mole of monoethanolamine to form 1-(2-hydroxyethyl)-2-imidazolidone and is referred to as HEIA. Equation (9) shows the reaction [
29]:
After that, the HEIA will react with water (hydrolyze) to form HEEDA, which is N-(2-hydroxyethyl)-ethylenediamine, as illustrated in Equation (10) [
28]:
These four types (HEEDA, dihydroxy ethyl urea, 2-oxazolidone, and HEIA) of formation are the major products of thermal degradation [
29].
2.5. Diethanolamine DEA Solvent
DEA is often used an abbreviation for diethanolamine, and it is an organic component that has both a Dialcohol and a secondary amine. In addition, a Dialcohol contains two hydroxyl groups in its molecule [
19,
30]. Diethanolamine, like other alkanol amines, rules as a weak base [
24].
DEA is an inexpensive solvent due to its wide use in many industries, and it is especially used for removing CO
2 and H
2S in natural gas that has rapidly reacted, where the selectively is high (between other and acid gases), and for the reversible reaction process at the absorber column. Furthermore, the operation conditions can be a low heat reaction (around 70 kJ/mol CO
2) and low pressure [
30]. One of the most common disadvantages is the presence of SO
2 and O
2 in flue gas, causing solvent degradation (which should be less than 10 ppm). The presence of O
2 in flue gas causes the oxidation of DEA and leads to increased degradation [
10]. The concentration of diethanolamine varies, depending on the amount of CO
2 to absorb. In approved industries, the concentration has been shown to be between 25 and 35% and lean amine (DEA) loading is set at 0.1 mol CO
2/mol DEA [
30], whereas the rich amine of diethanolamine loading is 0.4 mol CO
2/mol DEA, as illustrated in
Figure 4 [
5].
However, the mechanism of degradation of DEA is a similar to that of MEA [
28]. Consequently, the products produced after degradation are Tris-hydroxyethyl ethylenediamine called THEED, Bis-hydroxyethyl piperazine (bis-HEP), MEA, Bis-(hydroxyethyl) glycine (Bicine), and polymers. Polymers are products produced when the DEA molecule reacts with THEED (ethylenediamines). Furthermore, the MEA product is obtained when the DEA molecule degrades in the presence of oxygen [
31].
2.6. Methyldiethanolamine MDEA
MEDA is an abbreviation of N-methyldiethanol-amine and the chemical formula of it is C
5H
13NO
2 [
15]. MDEA is considered a chemical solvent, so the chemical solvents have a characteristic during the absorption process, which is that the acid gas component in the solvent is bonded chemically [
32]. The density of MDEA can range from 1 to 1.149 at a temperature roughly between 298 and 363.15 K with a concentration percentage between 23.8 and 60 wt.% [
3]. MDEA can degrade at 119–129 °C [
8]. Some of the advantages of MDEA are the need for only a low energy for regeneration due to the acidic gas reaction having a low enthalpy and the high capacity for the absorption of CO
2 [
10]. In addition, the solution has a lower vapor pressure and corrosiveness, with a good chemical and thermal stability. On the other hand, there are some drawbacks, including the slow reaction with carbon dioxide and low absorption capacity when the concentration of carbon dioxide is low [
4].
MDEA has several advantages which make it a very popular solvent, including the fact that it is less aggressive, requires a low heat for the reaction with CO
2, is less corrosive, can be used in higher concentrations, has lower circulation rates, and is easier to regenerate [
24].
The major determinate for the operating cost and capital cost is the circulation rate of the solvent, which is roughly proportional to the amount of acid gas to be removed. The process of gasification and flue gas treatment shown in
Figure 5 is common and, as in the MEA process, the lean MDEA enters the absorber and reacts with acid gas to absorb some of the CO
2 and H
2S, whereas bonding MDEA with H
2S takes place quicker than carbon dioxide. At the bottom of the absorber, the rich stream is pre-heated and enters the stripper/regenerator to regenerate the solvent by using the reboiler to break the bond of chemically reacted substances. The component of acid gas will be cooled through the cooler when exiting the top of the stripper column to condensate out the water for recycling purposes [
32].
The degradation of MDEA will produce several products, which include dimers (degradation of DIPA-OX to diamines (“dimers”)), polymers (dimer reacts with a DIPA molecule), Monoisopropanolamine (MIPA) (occurs when oxygen reacts with a DIPA molecule), Triisopropanolamine (TIPA) (produced when amine degrades in the presence of oxygen in the flue gases to produce simpler amines, whilst these simpler amines will react with other base amines to produce complex amines), and others, such as DIPA and 1,1-Dioxidetetrahydrothiophene (Sulfolane) [
31].
In 2008, Bedel assumed that there were several degradation pathways for MDEA, including hydrolysis, elimination reactions, disproportionation, and hemolytic splitting. Amino acid hydrolysis occurs in extrapolated conditions of a stripper and at a high temperature, which is a reasonable reason for degradation [
28]. Under normal conditions of the regenerator, the common pathway for the degradation of MDEA involves the reaction of disproportionation, sometimes referred to as alkanolamine “scrambling”. Therefore, one molecule of dimethylethanolamine and triethanolamine is formed by replacing the methyl group in the MDEA molecule with another molecule of the ethanol group [
8,
28]. In this process, a methyl group can be replaced with a hydrogen to form DEA, and this reaction can continue for amine degradation by the polymerization of carbamate [
8,
15,
19].