Article pubs.acs.org/IECR
Characteristics of Absorbent Loss and CO2‑Selective Absorption of CO2/SO2 Gas into Aqueous 2‑Amino-2-methyl-1-propanol/Ammonia Solution Soo-Bin Jeon,† Sang-sup Lee,‡ Min-Kyoung Kang,† Dae-Jong Kang,§ and Kwang-Joong Oh*,† †
Department of Environmental Engineering, Pusan National University, San 30 Jangjeon-Dong, Geumjeong-Gu, Busan 609735, Republic of Korea ‡ Department of Environmental Engineering, Chungbuk National University, Cheongju 361-763, Republic of Korea § Department of Environmental R&D group, Wels Korea, Ulsan 689863, Republic of Korea ABSTRACT: The effect of SO2 on the loss of 2-amino-2-methyl-1-propanol (AMP)/ammonia (NH3) solution and simultaneous removal of CO2 and SO2 into aqueous AMP/NH3 solution was investigated. Solvent loss and selectivity of CO2 were studied using a reactor constructed of stainless steel and a wetted wall column. The losses of NH3 from solution containing 1 wt % NH3, 30 wt % AMP + 1 wt % NH3, and 30 wt % AMP + 1 wt % NH3 loaded with 0.5 mol of CO2/mol at 313 K were 0.0179, 0.013, and 0.010, respectively. The initial degradation rate constants for the CO2/SO2-loaded AMP solution were 0.000 21−0.003 186 h−1, higher than those for the CO2-loaded solution of 0.000 9−0.000 95 h−1. Selective absorption of CO2 into aqueous AMP/NH3 solution decreased from 0.99 to 1.48 as a function of SO2 partial pressure (1, 3, 5, 10, and 15 kPa).
1. INTRODUCTION The increasing concentration of the greenhouse gas CO2 has become an important global issue because of the increasing demand for energy throughout the world.1 Fossil-fuel-fired power plants are the most significant source of CO2 emissions. Therefore, innovative separation processes for the removal and recovery of CO2 are greatly needed.2,3 A number of techniques have been used for separating CO2 from the flue gases of fossil-fuel-fired power plants, including chemical absorption, physical absorption, cryogenic methods, membrane separation, and biological fixation. Of these, one commercially available chemical absorption process uses aqueous alkanolamine solution to capture CO2 from lowpressure flue gas streams.4 The flue gas of fuel-fired power plants contains not only CO2 but also fly ash, O2, N2, SO2, and NO.5 The concentrations of sulfur compounds are very low: SO2 is about 0.245 vol % and SO3 is 0.005−1.005 vol%. However, the overall amount of discharged sulfur compounds is substantial because of the large volume of the flue gas stream.6 In removing and regenerating acid gas using aqueous alkanolamine solutions, undesirable compounds can be produced through complex reactions involving the irreversible transformation of alkanolamines, called degradation.7 Likewise, SO2 causes the loss of alkanolamines and may contribute to operational problems such as equipment fouling, impairment of process efficiency and throughput, and formation of degradation products that cause corrosion. Aqueous monoethanolamine (MEA) solution is the one most frequently used for CO2 capture, because of its high reactivity with CO2 and low cost.8 However, its CO2 absorption capacity is limited by stoichiometry to 0.5 mol of CO2/mol of amine and it has a high energy requirement for CO 2 regeneration. © 2013 American Chemical Society
A different class of alkanolaminessterically hindered amines such as 2-amino-2-methyl-1-propanol (AMP)has recently been proposed as commercially attractive CO2 absorbents because of high absorption capacity, degradation resistance, and ease of regeneration.9 Because AMP solution has a lower absorption rate for CO2 than MEA, many studies have been conducted to improve this disadvantage. Recently, the use of alkanolamine blends of two or more amines in varying concentrations has been shown to produce absorbents with excellent absorption and energy characteristics. Several studies of the absorption of CO2 into aqueous AMP solutions and blended amine solutions containing AMP have been conducted.10−13 In our previous studies, NH3 solution has been used as an additive in AMP solutions to improve CO2 absorption efficiency as well as absorption of complex gases (CO2/NO2/SO2).14−17 The NH3 solution improved absorption efficiency, but resulted in loss of the absorbent at high vapor pressure. Increasing the NH3 concentration increased the concentrations of free ammonia (NH3) and NH4+ balanced with bicarbonate, carbonate, or carbamate associated with CO2. Increasing the free ammonia concentration resulted in higher vapor pressure and vaporization of the solution. This problem can be solved by adding a hydroxyl group such as an alkanolamine. Unlike previous studies of characteristic of CO2/SO2 absorption into aqueous AMP/NH3 solution using stirred cells, the present study investigated the effect of SO2 on the loss of AMP/NH3 solution and the simultaneous removal of CO2 in flue gas. The loss of NH3 solution is investigated at a constant Received: Revised: Accepted: Published: 4881
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temperature and humidity. To analyze the influence of acid gas on AMP degradation, CO2/SO2 gas was fed into the AMP solution and evaluated as a function of temperature. To investigate the effect of SO2 on the CO2 absorption rate, a test of absorption of CO2 and SO2 into aqueous AMP/NH3 solution was conducted and the selectivity factor (Sp) for CO2 was determined using a wetted wall column (WWC). The effects of SO2 concentration, reaction temperature, and NH3 concentration on the rate of absorption of CO2 and the selectivity factor were investigated.
log[amine]t = log[amine]0 −
kamine = A exp[−E /RT ] log kamine = log A −
(1)
(2)
The chemical reactions between CO2 and NH3 can be expressed by the following reactions:18,19 2NH3(l) + CO2 (g) + H 2O(l) ⇔ (NH4)2 CO3(s)
(3)
NH3(l) + CO2 (g) + H 2O(l) ⇔ NH4HCO3(s)
(4)
ηCO = 1 − 2
(5)
H 2SO3 + 2RNH 2 → (RNH3)2 SO3
(6)
Sp
Ammonium sulfite ((NH4)2SO3) and ammonium bisulfite (NH4HSO3) are formed by reacting NH3 with SO2 at 25 °C and 1 atm:18 (8)
NH3(g) + SO2 (g) + H 2O(l) ⇔ NH4HSO3(s)
(9)
2.2. Degradation Kinetics. Degradation is a complex phenomenon affected by temperature, pressure, raw gas composition, amine concentration, solution pH, and possibly the presence of metal ions.24 Generally, degradation initially occurs through a first-order reaction represented by the following equation: kamine
amine ⎯⎯⎯⎯→ degradation product
(10)
This reaction can be represented by the following reaction rate equations: d[amine] = −kamine[amine]t dt
(15)
( = (
) )
molar concn of CO2 molar concn of SO2
liquid phase
gas phase
(16)
3. EXPERIMENTAL SECTION 3.1. Materials. Analytical grade AMP and NH3 solutions with purities of 99 and 28% were supplied by Acros Organics (Fair Lawn, NJ, USA) and Junsei Chemical Co. (Tokyo, Japan), respectively. Aqueous solutions were prepared with distilled water. CO2 and N2 gases were of commercial grade with purities of 99.99%. High-purity SO2 (99.9%) gas was also used. 3.2. Solvent Loss Reactor. The reactor was constructed of stainless steel with a volume of ∼30 cm3 (10 cm height, 3 cm diameter). The silicon oil bath and heating oil bath were equipped with temperature controllers to maintain the reaction temperature, confirmed with a thermometer. The ammonia solution prepared with distilled water was held at a constant temperature. The AMP solution was prepared with distilled water, and then 6 wt % CO2 or SO2 was absorbed into solution using an absorption instrument. After 30 mL of the solution was fed into the reactor, the oil bath was heated to 353, 383, 413, or 443 K. The reactor was maintained at a constant humidity using a thermo-humidity chamber. Degraded solutions were acquired on scheduled days, and the total solvent concentration was analyzed using an automatic titrator (702 SM Titrino; Metrohm, Riverview, FL, USA). In addition, the AMP concentration was analyzed by gas chromatography (GC; 7890A network gas chromatograph; Agilent Technolo-
(7)
2NH3(g) + SO2 (g) + H 2O(g) ⇔ (NH4)2 SO3(s)
yCO ,2 ⎛ 1 − yCO ,1 − ySO ,1 ⎞ 2 ⎜ 2 2 ⎟ yCO ,1 ⎜⎝ 1 − yCO ,2 − ySO ,2 ⎟⎠ 2 2 2
molar concn of CO2 molar concn of SO2
The overall reaction of amine with SO2 is as follows: SO2 + 2RNH 2 + H 2O ⇔ 2RNH3+ + SO32 −
(14)
For a simultaneous absorption process involving absorption of both CO2 and SO2, the selectivity factor Sp is used as a yardstick for selectivity and is expressed as
The wet method of ammonia scrubbing of the flue gas to capture CO2 produces ammonium carbonate ((NH4)2CO3) and ammonium bicarbonate (NH4HCO3).20,21 The chemical reactions between SO2 and AMP can be described assuming that SO2 reacts with water22 and aqueous alkali solution,23 as follows: SO2 (g) + H 2O ⇔ 2H+ + SO32 −
E 1 2.303R T
(13)
The degradation of amine is governed by a pseudo-first-order reaction, and log kamine is represented in linear form as a function of temperature, [1/T]. 2.3. Selectivity. The effects of H2S loading, the temperature of the lean solution, the gas flow rate, and the mole ratio of CO2/H2S of the feed gas on removal efficiency and selectivity were studied. The selectivity of amine solvents for H2S has been described in previous reports.25,26 In this study, a similar theory was applied to confirm the selectivity for CO2 in the CO2/SO2 complex gas. The removal efficiency of CO2 is ηCO2, which is calculated using the following material balance equation:
bicarbonate formation: RNH 2+COO− + H 2O ⇔ RNH 2+ + HCO3−
(12)
where [amine]0 is the initial concentration, [amine]t is the concentration at time t, t is the degradation time, and kamine is the reaction rate constant for amine. These equations can be represented by the following Arrhenius equations:
2. THEORETICAL BASIS 2.1. Absorption Mechanism. The reaction of CO2 with the amino group of AMP can result in three possible products: formation of carbamate, formation of bicarbonate, and reversion of carbamate to bicarbonate or formation of the carbonate ion.13 carbamate formation: CO2 + RNH 2 ⇔ RNH 2+COO−
kaminet 2.303
(11) 4882
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Figure 1. Schematic diagram of the wetted wall column apparatus. Legend: 1, CO2 gas; 2, SO2 gas; 3, N2 gas; 4, MFC; 5, mixing chamber; 6, saturator; 7, wetted wall column; 8, water bath; 9, absorbent inflow; 10, absorbent outflow; 11, paraffin oil inflow; 12, paraffin oil outflow; 13, gas inflow; 14, gas outflow; 15, condenser; 16, GC/TCD; 17, thermocouple; 18, pressure transducer.
%, and the gas flow rates were controlled using mass flow controllers (5850E; Brooks Instrument, Hatfield, PA, USA). Concentrations of CO2 and SO2 were analyzed using a gas chromatograph (7890A; Agilent Technologies). A packed column (30 m × 0.32 mm, GS-Gaspro; Agilent Technologies) was used as the GC column with a thermal conductivity detector (TCD).
gies, Santa Clara, CA, USA). A packed column (Tenax-TA, 1/8 in. × 9 ft, GS-Gaspro; Agilent Technologies) was used as the GC column with a flame ionization detector (FID). The operating conditions of the GC were as follows: the flow rate of the helium carrier gas was 20 mL/min, and the oven temperature was increased from 150 to 300 °C at a rate of 6 °C/min, maintained at 150 °C for 0.5 min, and then maintained at 300 °C for 3 min. The temperatures of the injector and detector were 300 °C, and 1 μL of the degraded solution was instilled using a syringe. 3.3. Wetted Wall Column. In this study, a WWC was used to investigate the absorption rate and selectivity, unlike in the previous study. The experimental apparatus for measuring the absorption rate is shown in Figure 1. The WWC used in this study was similar to that used by Nam et al.27 As shown in Figure 1, the gas−liquid contactor in the center was constructed from a stainless-steel tube 91 mm in length and with a 12.6-mm outside diameter. The column was enclosed in cylindrical thick-walled glass. The entire chamber was surrounded by a second glass wall with a liquid such as paraffin oil flowing between the walls as a heat transfer medium. The absorbent was pumped upward inside the column and flowed out the top, supplying liquid to the bottom of the chamber. The gases contacted the liquid against the current and then exited from the top. During the experiment, the water bath maintained the absorbent and paraffin oil at a constant temperature. The pressure inside the reactor was measured with pressure transducers (MGI/MGAMP series, accuracy ±0.1 kPa) installed in the reactor and feeder. The concentration of CO2/SO2 in the feed gas stream was 15 vol
4. RESULTS AND DISCUSSION 4.1. Ammonia Loss with Increased Vapor Pressure. Ammonia loss was studied to determine how the vapor pressure was affected by CO2 loading and addition of AMP solution. The experiment was conducted with 10 replicate samples to assess experimental error. Figure 2 shows loss of NH3 from solutions containing 1 wt % NH3, 30 wt % AMP + 1 wt % NH3, and 30 wt % AMP + 1 wt % NH3 loaded with 0.5 mol of CO2/mol as a function of time at 313 K, 1 atm, and 65% relative humidity. Loss of NH3 was decreased by adding AMP as well as through reactions with CO2. The vaporization rate of solution containing only NH3 was 0.0179 mol/h, and that of the blended solution with 30 wt % AMP was 0.013 mol/h. This reduction was due to hydrogen bonding between NH3 and the hydroxyl groups of AMP: alkanolamines such as AMP with hydroxyl groups are strongly polar and rapidly form hydrogen bonds with NH3. The CO2 loading solution containing AMP and NH3 had a 0.010 mol/h vaporization rate, indicating that CO2-loaded NH3 solutions have lower vapor pressure than non-CO2-loaded solutions. Ammonium carbamate and ammonium bicarbonate produced by reactions 3 and 4 may result in 4883
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concentration of AMP solution decreased to 2.66 and 2.01 mol/L. As a result of degradation, the loss of AMP was 4.7, 9.9, 20.9, and 40.1% at 353, 383, 413, and 443 K, respectively. Thus, the AMP degradation rate increased as the temperature of the solution increased, because of increased thermal degradation of AMP with increasing reaction temperature. The initial degradation rate of aqueous AMP in the solution loaded with 5 wt % CO2 and 5 wt % SO2 was higher than that loaded with 5 wt % CO2 alone; rapid degradation with increasing reaction temperature and time was observed. Loss of AMP at 9 days was 10.7, 25.6, 43.9, and 82.1% at 353, 383, 413, and 443 K, respectively. Thus, the degradation rate of AMP in the solution loaded with CO2 and SO2 was more than twice that in solution loaded with CO2 alone. Although AMP solutions have generally been found to be more stable than those of other alkanolamines, most alkanolamines are degraded by acid gases (e.g., SO2, CO2, O2). Degradation of AMP in the presence of CO2 and SO2 proceeds through complex reactions; many degradation mechanisms exist and the degradation products cause serious operating problems.28−32 Using these results, degradation reaction rate constants as a function of temperature of the aqueous AMP solutions loaded with CO2 and CO2/SO2 were determined based on eq 12. The degradation rate constants (kAMP, h−1) for aqueous AMP solution loaded with 5 wt % CO2 were 0.000 09, 0.000 19, 0.000 43, and 0.000 95 h−1 at 353, 383, 413, and 443 K, respectively. Also, those for AMP solution loaded with 5 wt % CO2 and 5 wt % SO2 were 0.000 21, 0.000 55, 0.001 07, and 0.003 19 h−1 at 353, 383, 413, and 443 K, respectively. The degradation rate constants for the CO2/SO2-loaded AMP solution were higher than those for the CO2-loaded solution. These results demonstrate that SO2 causes loss of AMP by irreversible transformation through complex reactions, and may contribute to loss of absorbent and operational difficulties. 4.3. Effect of SO2 Partial Pressure on CO2 Selectivity. Measurements of the absorption rate and selectivity of CO2 into aqueous AMP/NH3 were conducted under various conditions, including several SO2 concentrations. Figures 6 and 7 show the absorption rates of CO2 and SO2 with respect to AMP/NH3 solution concentrations. Conditions used during these experiments were as follows: CO2, 15 kPa; SO2, 1, 3, 5, 10, and 15 kPa; AMP, 30 wt %; NH3, 1, 3, and 5 wt %. Figure 4 shows the absorption rates of CO2 and SO2 gases into solution as a function of the SO2 partial pressure (1, 3, 5, 10, and 15 kPa) and NH3 concentration (0, 1, 3, and 5 wt %) at 313 K. The absorption rates of SO2 into 30 wt % AMP containing 1, 3, and 5 wt % NH3 were (0.48−0.68) × 10−6 kmol m−2 s−1 at 1 kPa and increased to (10.89−15.85) × 10−6 kmol m−2 s−1 with increasing SO2 partial pressure up to 15 kPa. In contrast, the absorption rate of CO2 decreased with increasing SO2 partial pressure. The absorption rates of CO2 were (7.16−12.36) × 10−6 kmol m−2 s−1 at 1 kPa SO2 and decreased to (4.75−9.21) × 10−6 kmol m−2 s−1 at 15 kPa. However, because of the strong influence of the hydration reaction, the increase in the SO2 absorption rate with the concentration of the aqueous AMP/NH3 solution was smaller than that of CO2. SO2 has a higher reaction rate constant than CO2; thus, SO2 was effectively absorbed first because of the very fast hydration reaction between SO2 and water, as shown in eq 5.23 Addition of NH3 (1, 3, and 5 wt %) to the 30 wt % AMP solution increased the CO2/SO2 absorption rate to that of the AMP solution without NH3, as mass transfer increased
Figure 2. Reduction in ammonia concentration through increased AMP and CO2 loading as a function of time at 313 K, 1 atm, and 65% relative humidity.
decreases in the free NH3 concentration and in the vapor pressure of the blended solution. 4.2. AMP Loss by CO2/SO2 Degradation. The effects of CO2 and SO2 on absorbent degradation were evaluated using 3.36 mol of AMP in aqueous solution loaded with 5 wt % CO2 and 5 wt % CO2 + 5 wt % SO2 under the same conditions. The solutions were injected into the reactor, and the temperature was maintained at several different temperatures (353−443 K) using the oil bath. Figure 3 shows the effects of 5 wt % CO2 and 5 wt % CO2 + 5 wt % SO2 on AMP concentration as a function of reaction
Figure 3. Effect of reaction temperature and time on AMP degradation in the presence of CO2 and CO2/SO2.
time (1, 3, 5, 7, and 9 days) and temperature (353, 383, 413, and 443 K). As shown Figure 3, the concentration of AMP solution loaded with 5 wt % CO2 decreased with increasing reaction time and temperature. As the temperature and time increased, the concentration of AMP decreased. At 353−383 K, AMP concentrations decreased linearly over time from 3.36 to 3.0 mol/L. However, at higher temperatures (413−443 K), the initial degradation rate and loss of AMP solution were higher than at lower temperature for the first 3 days. After the third day, the degradation rate decreased steadily and the 4884
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Figure 6. Absorption rates of CO2 and SO2 into aqueous AMP/NH3 solutions as a function of temperature at different NH3 concentrations and pA2 = 1 kPa. pA = partial pressure of species A, where A1 = CO2 and A2 = SO2.
Figure 4. Absorption rates of CO2 and SO2 into aqueous AMP/NH3 solutions as a function of SO2 partial pressure (pA2) at different NH3 concentrations and 313 K. A1 = CO2; A2 = SO2.
with the increasing concentration gradient. However, absorption of CO2 into high-concentration aqueous NH3 solution can interfere with operations through formation of (NH4)2CO3 and NH4HCO3, as shown in eqs 3 and 4. Therefore, to increase the removal efficiency, the proper amount of NH3 must be added. In our previous study, NH3 addition was fixed at 3 wt % in noncrystallized salt form.15 Figure 5 shows the effects of SO2 partial pressure (1, 3, 5, 10, and 15 kPa) and NH3 concentration (0, 1, 3, and 5 wt %) on
temperature (293, 303, 313, and 323 K) with the addition of 1, 3, and 5 wt % NH3 at 15 kPa CO2 and 1 kPa SO2. The SO2 absorption rates at 293 K were (0.41−0.56) × 10−6 kmol m−2 s−1 with increasing amounts of NH3 added to the 30 wt % AMP solution. As the reaction temperature increased, the absorption rates for SO2 increased to (0.55−0.79) × 10−6 kmol m−2 s−1 at 323 K. In contrast, CO2 absorption rates decreased with an increase in reaction temperature. The absorption rates for CO2 were (4.32−8.07) × 10−6 kmol m−2 s−1 at 293 K and increased to (8.46−14.51) × 10−6 kmol m−2 s−1 at 323 K. This increase may have been caused by increased mass transfer with increasing reaction temperature at the gas−liquid interface. However, the absorption of SO2 is more influenced by hydration than by reactions with the AMP molecule; thus the increase in the SO2 absorption rate with temperature was lower than that of CO2. Figure 7 shows the effects of reaction temperature (293, 303, 313, and 323 K) and NH3 concentration (0, 1, 3, and 5 wt %) on the selectivity factor (Sp) for CO2. The Sp for addition of NH3 to the aqueous 30 wt % AMP solution increased linearly with temperature, because the absorption rate of SO2 increased
Figure 5. Effect of SO2 partial pressure (pA2) on the selectivity factor (Sp) at different NH3 concentrations and 313 K.
selectivity for CO2. The Sp values for addition of NH3 to the aqueous 30 wt % AMP solution were 0.99−1.48. However, the selectivity factor decreased and converged on 0.29 with increasing the SO2 partial pressure to 15 kPa. This was due to the instantaneous hydration reaction of SO2 and interruption of CO2 absorption into the aqueous solution. The difference in the CO2 selectivity factor was minor at a concentration of 15 kPa as a result of the predominance of the SO2 reaction. However, these results show a gradual difference with decreasing SO2 partial pressure. 4.4. Effect of Reaction Temperature on CO2 Selectivity. Figure 6 shows the absorption rates of CO2 and SO2 into 30 wt % aqueous AMP solution as a function of reaction
Figure 7. Effect of temperature on the selectivity factor (Sp) at different NH3 concentrations and pA2 = 1 kPa. pA = partial pressure of species A, where A1 = CO2 and A2 = SO2). 4885
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Solvents at the University of Regina CO2 Capture Technology Development Plant and the Boundary Dam CO2 Capture Demonstration Plant. Ind. Eng. Chem. Res. 2006, 45, 2414. (6) Astarita, G.; Savage, D. W.; Bisio, A. Gas Treating with Chemical Solvents; Wiley: New York. 1983. (7) Idem, R.; Bello, A. Pathways for the Formation of Products of the Oxidative Degradation of CO2-Loaded Concentrated Aqueous Monoethanolamine Solutions during CO2 Absorption from Flue Gases. Ind. Eng. Chem. Res. 2005, 44, 945. (8) Mandal, B. P.; Biswas, A. K.; Bandyopadhyay, S. S. Absorption of carbon dioxide into aqueous blends of 2-amino-2-methyl-1-propanol and diethanolamine. Chem. Eng. Sci. 2003, 58, 4137. (9) Mandal, B. P.; Bandyopadhyay, S. S. Absorption of carbon dioxide into aqueous blends of 2-amino-2-methyl-1-propanol and monoethanolamine. Chem. Eng. Sci. 2006, 61, 5440. (10) Aroonwilas, A.; Veawab, A. Characterization and comparison of the CO2 absorption performance into single and blended alkanolamines in a packed column. Ind. Eng. Chem. Res. 2004, 43, 2228. (11) Erdogan, A. Reaction mechanism and kinetics of aqueous solutions of 2-amino-2methyl-1-propanol and carbon dioxide. Ind. Eng. Chem. Res. 1990, 29, 1728. (12) Mandal, B. P.; Bandyopadhyay, S. S. Absorption of carbon dioxide into aqueous blends of 2-amino-2-methyl-1-propanol and monoethanolamine. Chem. Eng. Sci. 2006, 61, 5440. (13) Yih, S. M.; Shen, K. P. Kinetics of carbon dioxide reaction with sterically hindered 2-amino-2-methyl-1-propanol aqueous solutions. Ind. Eng. Chem. Res. 1988, 27, 2237. (14) Lee, D. H.; Choi, W. J.; Moon, S. J.; Ha, S. H.; Kim, I. G.; Oh, K. J. Characteristics of absorption and regeneration of carbon dioxide in aqueous 2-amino-2-methyl-1-propanol/ammonia solutions. Korean J. Chem. Eng. 2008, 25, 279. (15) Choi, W. J.; Min, B. M.; Seo, J. B.; Park, S. W.; Oh, K. J. Effect of Ammonia on the Absorption Kinetics of Carbon Dioxide into Aqueous 2-Amino-2-methyl-1-propanol Solutions. Ind. Eng. Chem. Res. 2009, 48, 4022. (16) Choi, W. J.; Min, B. M.; Shon, B. H.; Seo, J. B.; Oh, K. J. Characteristics of absorption/regeneration of CO2/SO2 binary systems into aqueous AMP + ammonia solutions. J. Ind. Eng. Chem. 2009, 15, 635. (17) Seo, J. B.; Jeon, S. B.; Choi, W. J.; Kim, J. W.; Lee, G. H.; Oh, K. J. The absorption rate of CO2/SO2/NO2 into a blended aqueous AMP/ammonia solution. Korean J. Chem. Eng. 2011, 28, 170−177. (18) Diao, Y. F.; Zheng, X. Y.; He, B. S.; Chen, C. H.; Xu, X. C. Experimental study on capturing CO2 greenhouse gas by ammonia scrubbing. Energy Convers. Manage. 2004, 45, 2283. (19) Bai, H.; Yeh, A. C. Removal of CO2 Greenhouse Gas by Ammonia Scrubbing. Ind. Eng. Chem. Res. 1997, 36, 2490. (20) Bai, H.; Yeh, A. C. Comparison of ammonia and monoethanolamine solvents to reduce CO2 greenhouse gas emissions. Sci. Total Environ. 1999, 228, 121. (21) Yeh, J. T.; Renik, K. P.; Rygle, K.; Pennline, H. W. Semi-batch absorption and regeneration studies for CO2 capture by aqueous ammonia. Fuel Process. Technol. 2005, 86, 1533. (22) Hikita, H.; Asai, S.; Tsufi, T. Absorption of sulfur dioxide into aqueous solution sodium hydroxide and sodium sulfite solution. AIChE J. 1977, 23, 538. (23) Hikita, H.; Asai, S.; Nose, H. Absorption of sulfur dioxide into water. AIChE J. 1978, 24, 147. (24) Kennard, M. L.; Meisen, A. Mechanisms and kinetics of DEA degradation. Ind. Eng. Chem. Fundam. 1985, 24, 129−140. (25) Savage, D. W.; Funk, E. W.; Yu, W. C.; Astarita, G. Selective Absorption of H2S and CO2 into Aqueous Solutions of Methyldiethanolamine. Ind. Eng. Chem. Fundam. 1986, 25, 326. (26) Mandal, B. P.; Biswas, A. K.; Bandyopadhyay, S. S. Selective absorption of H2S from gas streams containing H2S and CO2 into aqueous solutions of N-methyldiethanolamine and 2-amino-2-methyl1-propanol. Sep. Purif. Technol. 2004, 35, 191.
more than that of CO2 as a function of temperature. In addition, Sp increased with increasing NH3 added to the AMP solution. Therefore, addition of NH3 to an aqueous AMP solution may be an effective way of enhancing the absorption rate of CO2/SO2.
5. CONCLUSIONS In this study, we observed decreased vaporization of NH3 solution with loading of CO2 gas and addition of aqueous AMP solution. In addition, CO2 and SO2 were absorbed into aqueous AMP/NH3 solution to investigate the effects of SO2 on CO2 absorption and absorbent degradation. The vaporization rate of NH3 decreased to 27.4% after blending with AMP because of hydrogen bonding between the hydroxyl groups of AMP and NH3. The vaporization rate decreased to 44.1% after blending with aqueous AMP solution loaded with CO2 as a result of reactions forming ammonium carbamate and ammonium bicarbonate. The degradation rates in aqueous AMP solutions loaded with 5 wt % CO2 and 5 wt % CO2 + 5 wt % SO2 were 0.000 21−0.003 186 h−1 and 0.000 9−0.000 95 h−1, respectively. Degradation was caused by thermal degradation and irreversible transformation through complex reactions between CO2/SO2 and AMP. Sp for addition of NH3 to the aqueous 30 wt % AMP solution decreased from 1.48 to 0.99 as a function of SO2 partial pressure (pA2 = 1, 3, 5, 10, and 15 kPa). However, Sp for the AMP/NH3 blended solution increased with increasing NH3 and reaction temperature. Based on these results, SO2 absorption into AMP/NH3 solution likely causes AMP degradation and reduced CO2 absorption efficiency. A certain amount of NH3 solution may be an appropriate additive for increasing selective CO2 absorption in treating CO2/SO2 complex gases. This study confirmed several challenges related to the presence of SO2 gas; therefore, pretreatment of SO2 is necessary to prevent a decrease in CO2 absorption efficiency.
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS This research was supported by the Brain Korea 21 Project in 2012. REFERENCES
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dx.doi.org/10.1021/ie302667z | Ind. Eng. Chem. Res. 2013, 52, 4881−4887
