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CO2 Capture Using Amine Solution Mixed with Ionic Liquid Jie Yang,† Xinhai Yu,*,†,‡ Jinyue Yan,§,∇ and Shan-Tung Tu† †

Key Laboratory of Pressure Systems and Safety, Ministry of Education, School of Mechanical and Power Engineering, East China University of Science and Technology, Shanghai, People’s Republic of China ‡ State Key Laboratory of Bioreactor Engineering, East China University of Science and Technology, Shanghai, People’s Republic of China § School of Sustainable Development of Society and Technology, Mälardalen University, Västerås, Sweden ∇ School of Chemical Science and Engineering, Royal Institute of Technology, Stockholm, Sweden S Supporting Information *

ABSTRACT: It is a focus to reduce the energy consumption and operating cost of CO2 capture from low-pressure flue gas streams of power plants using an aqueous amine-based absorbent. In this study, CO2 capture experiments were conducted in an absorption−desorption loop system using amine-based absorbents. The gas mixture containing CO2, O2, SO2, and N2 in the composition range of flue gas from coal-fired power plant after flue gas desulfurization was selected as the feed gas. For an aqueous amine solution, the largest contribution to monoethanolamine (MEA) loss was made by evaporation during desorption, followed by the formation of sulfate and heat-stable salts. To reduce MEA loss and meanwhile decrease the energy consumption during CO2 desorption, an aqueous amine solution mixed with ionic liquid (30 wt % MEA + 40 wt % [bmim][BF4] + 30 wt % H2O) was proposed. The energy consumption of the mixed ionic liquid solution for absorbent regeneration was 37.2% lower than that of aqueous MEA solution. The MEA loss per ton of captured CO2 for the mixed solution was 1.16 kg, which is much lower than that of 3.55 kg for the aqueous amine solution. No ionic liquid loss was detected. In addition, the mixed ionic liquid solution showed a low viscosity of 3.54 mPa s at 323 K, indicating that the ionic liquid disadvantage of high viscosity can be overcome for absorbent delivery of CO2 capture.

1. INTRODUCTION Perspectives of anthropogenically forced climate change due to greenhouse gas emission are now well-accepted. The combustion of fossil fuel contributes the most significant fraction of CO2 that is emitted into the atmosphere, with the flue gas of coal-fired power plants being the greatest source.1,2 One of the most effective and widely used techniques to capture CO2 from low-pressure flue gas streams from power plants is chemical absorption using aqueous amine-based absorbents.3,4 However, because of drawbacks of efficiency penalty, tendency for corrosion, and various operational problems in conventional chemical absorption techniquesseveral initiatives have been conducted to overcome the disadvantages of conventional chemical absorption techniques. For CO2 capture from flue gas stream, MEA solution loss is mainly due to degradation and evaporation. It is well-known that monoethanolamine (MEA) might form degradation products such as 2-oxazolidone and N-(2-hydroxyethyl)ethylenediamine (HEED) via intermediates of N,N′-di(hydroxyethyl)urea and 1-(2-hydroxyethyl)-2-imidazolidone.5 Chakma et al.6 identified the following as products of partially degraded aqueous N-MDEA solutions: methanol, ethylene oxide, trimethylamine, ethylene glycol, 2-(dimethylamino)ethanol, 1,4-dimethylpiperazine, N-(hydroxyethyl)methylpiperazine, triethanolamine, and N,N-bis(hydroxyethyl) piperazine. The Dow Chemical Co. documented the products of degraded MEA as aldehydes and organic acids.6 These organic acids dissociate to form heat-stable salts (HSS) with MEA. HSS are the products of reaction between the degraded © 2014 American Chemical Society

organic acids and MEA, containing formates, acetates, glycolates, oxalates, etc. Rochelle and his co-workers7 carried out extensive studies on oxidative degradation of aqueous MEA by measuring the rate of NH3 evolution from the amine solutions, using Fourier transform infrared (FTIR) spectroscopy. They analyzed MEA oxidation caused by ferrous ion and examined the effects of amine concentration, CO2 loading, O2 concentration, and agitation rate under a typical absorber condition of 328 K. Their results showed that dissolved iron (from 0.0001 mmol L−1 to 1 mmol L−1) yielded oxidation rates from 0.37 mmol L−1 h−1 to 2.2 mmol L−1 h−1 in MEA solutions loaded with 0.4 mol CO2 per mol MEA. They also indicated that the degradation rates were controlled by the rate of physical absorption of O2 and NH3 evolution rates ranging from 0.2 mmol L−1 h−1 to 8.0 mmol L−1 h−1 when the aqueous MEA concentrations were above 7 mol L−1. For industrial flue gas, the CO2 capture processes are much more complicated, because of the presence of a mixture of CO2, O2, SO2, NOx, and fly ash. The concentrations of these impurities are regarded as particularly important variables in the degree of degradation. Among them, O2 and SO2 play important roles in the degradation of amine-based absorbents. SO2 is believed to degrade MEA to form organosulfates and thiovanic acid.8 Uyanga et al.9,10 evaluated the contributions of Received: Revised: Accepted: Published: 2790

December 1, 2013 January 28, 2014 January 28, 2014 January 28, 2014 dx.doi.org/10.1021/ie4040658 | Ind. Eng. Chem. Res. 2014, 53, 2790−2799

Industrial & Engineering Chemistry Research

Article

captured in absorption and desorption cycles utilizing an imidazolium-based IL as the absorption solution. The results promised the application of this novel process on an industrial scale. However, the partial pressure of CO2 was as high as 10 bar in their process to ensure an acceptable CO2 capture efficiency. This high pressure of CO2 limits the application of IL in the CO2 capture from the flue gas streams of coal-fired power plants, because the flue gas streams are almost under atmospheric pressure. The cost of flue gas compression is large. Therefore, it seems interesting to combine amines and ILs together to reduce MEA loss and meanwhile decrease energy consumption. However, few reports can be found. In this study, CO2 capture experiments were hence conducted in an absorption−desorption loop system using a polypropylene (PP) hollow fiber membrane contactor as the absorber. A gas mixture containing CO2, O2, SO2, and N2 in the composition range of flue gas of coal-fired power plant after flue gas desulfurization (FGD) was selected as the feed gas. The aqueous MEA solution was used as an absorbent. The MEA loss was investigated and the main contributor was confirmed. Based on the experimental results, an aqueous amine solution mixed with ionic liquid (IL) of [bmim][BF4] was proposed for CO2 capture to decrease the energy consumption and operating cost. The performance and energy consumption of the mixed solution were studied.

SO2 and O2 to the degradation of MEA during CO2 capture from power plant flue gas streams. They formulated a kinetic model to describe the oxidative degradation of MEA as a function of temperature (328−413 K), MEA concentrations (3−7 mol L−1), SO2 concentration (6−196 ppm), and O2 concentrations (6−100%). Supap et al.11 improved this degradation rate model and found that SO2 exhibited a higher propensity to cause MEA degradation than O2. It was reported that both fugitive emission of volatile organic compounds (VOC) and vapor loss resulted in amine-based absorbent loss during the desorption of CO2.12 IEA reported that ∼1.6 kg of MEA per ton of captured CO2 escapes to the atmosphere.13 Therefore, the amine-based absorbent concentration changes with the evolution of CO2 capture. This tendency is crucial to the industrial application and cannot be investigated by a single absorption experiment. Gao et al.14 established an absorption−desorption loop experiment to investigate the CO2 capture performance with the feed gases of 214 and 317 ppm SO2 and 18% O2. They found that the addition of SO2 gave rise to more serious amine degradation and more HSS formation. However, they introduced the desorption gas into the inlet of the absorber. In other words, the flue gas is recycled. Therefore, in their experiments, the amine-absorbent loss by fugitive emission and evaporation is eliminated. This is different from the real industrial application. Little systematic investigation can be found on the amine-based absorbent concentration changes with the evolution of CO2 capture regarding a real industrial case. In our previous work, the effects of SO2 (294 ppm) on CO2 capture system were analyzed without O2 in the feed gas in an absorption−desorption loop system using a polypropylene (PP) hollow fiber membrane contactor as the absorber.15 The experimental results showed that the MEA loss per ton captured CO2 increased with the addition of SO2, resulting in sharp decreases in CO2 removal efficiency and mass-transfer rate of CO2 after initial several days of operation. This tendency is mainly attributed to the promotional effect of SO2 on the degradation of MEA by the formation of sulfate. This SO2 concentration of 294 ppm is above the average of that using conventional wet desulfurization methods (6−300 ppm16). The discharge standards of SO2 in various countries become more and more strict. In China, the SO2 emission limits after desulfurization should be 35 ppm for the newly built plants, in accordance with the SO2 emission standard for coal-fired power plant implemented in 2012.17 The lower SO2 concentration of ca. 35 ppm other than 294 ppm for CO2 capture should be taken. In addition, in our previous work, the feed stream did not contain O2, which is not in agreement with the O2 concentration of 6% in the flue gas streams of coal-fired power plants. This neglect of the O2 in the feed stream probably gives rise to a deviation from the actual tendency of MEA loss because O2 can result in the MEA degradation. Therefore, considering the coexistences of O2, SO2, fugitive emission and vapor loss, it is necessary and interesting to further investigate the performance of the absorption− desorption loop system in the long-term operation of CO2 capture using amine-based chemicals. In addition to aqueous amine solution, ionic liquid (IL) is one of potential candidates for CO2 capture, because of its advantages, such as extremely low volatility, low heat capacity, and high thermal stability.18−21 An interesting technical-scaleplant of CO2 absorption from natural gas streams using ILs was set up by Janiczek et al.22 In their study, high-pressure CO2 was

2. REACTION MECHANISM OF MEA DEGRADATION WITH O2 AND SO2 Despite the recent progress achieved over the last five years, the mechanism for the oxidative degradation of MEA is still unclear. The electron and hydrogen abstractions were proposed as two primary mechanisms with the same degradation products. In general, the stoichiometric equation given below represents the reactions of MEA with O2:16 MEA + ΔO2 ⇔ NH3 + degradation products

(1)

The above degradation products include formaldehyde, acetic acid, hydroxyacetaldehyde, glycolic acid, formic acid, CO, oxalic acid, and CO2.6 SOx is believed to degrade MEA to form organosulfates and thiovanic acid, via the reactions shown below:23 SO2 + 2RNH 2 + H 2O → 2RNH+3 + SO32 −

(2)

2(C2H5ONH 2) + SO3 + H 2O ⇔ (C2H5ONH3)2 SO4 (3)

2(C2H5ONH 2) + SO2 + 0.5O2 + H 2O ⇔ (C2H5ONH3)2 SO4 C2H5ONH 2 + SO2 ⇔ C2H4O2 S + NH3 + 0.5O2

(4) (5)

3. EXPERIMENTAL SECTION 3.1. Materials. Concentrated MEA and [bmim][BF4] (reagent grade, 99% purity) were supplied by Shanghai Bangcheng Chemical Co., Ltd. Four gas cylinders were used to provide the simulated flue gas: analytical-grade CO2, O2, N2, and 2% SO2 balanced with N2 obtained from Shanghai Wetry Standard Gas Co., Ltd. Hydrochloric acid (1 mol L−1) obtained from Shanghai Bangcheng Chemical Co., Ltd. was used to measure the concentration of MEA by titration. Sodium acetate, glycolic acid, formic acid, oxalate acid dihydrate, 2791

dx.doi.org/10.1021/ie4040658 | Ind. Eng. Chem. Res. 2014, 53, 2790−2799

Industrial & Engineering Chemistry Research

Article

The PP fibers were gold-coated in a vacuum for 40 s to prevent charging. The morphology of samples then was observed via scanning electron microscopy (Model JSM7401FFE-SEM, JEOL, Tokyo). Viscosities of the solutions with different contents were measured by a rotational viscometer (NDJ-1, Hengping Co., Ltd.) with a reproducibility of

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