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Pilot-scale experiments for post-combustion CO2 capture from gas fired power plants with a novel solvent
International Journal of Greenhouse Gas Control 30 (2014) 212–215
Contents lists available at ScienceDirect
International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
Pilot-scale experiments for post-combustion CO2 capture from gas fired power plants with a novel solvent Hamid Esmaeili ∗ , Behrooz Roozbehani School of Chemical Engineering, Petroleum University of Technology, Abadan Branch, Iran
a r t i c l e
i n f o
Article history: Received 29 December 2013 Received in revised form 13 August 2014 Accepted 15 September 2014 Keywords: CO2 capture Amine-based solvent Gas fired power plants Regeneration energy demand Solvent flow rate Post combustion capture
a b s t r a c t Aqueous MEA is the most common solvent used to absorb CO2 . Its problem is that the energy required for solvent regeneration and solvent flow rate is high. This work focuses on introducing and developing a novel solvent to reduce both the regeneration energy demand and solvent flow rate. The novel solvent based on the mixture of MEA, TETA, AMPD and PZEA from Abadan Center of Research (ACOR100) was studied and compared to mono-ethanolamine (MEA). For both solvent, the regeneration energy is determined for different solvent flow rates at a constant CO2 removal rate of 90% and a low partial pressure (54 mL bar). The optimum numbers for both the regeneration energy and solvent flow rate are found and compared to each other, for each of solvents. The resulting numbers of the ACOR100 indicate a considerable improvement compared to MEA with a reduction of about 25% in the regeneration energy and 27% in the solvent flow rate. © 2014 Elsevier Ltd. All rights reserved.
1. Introduction Carbon dioxide capture has been practiced industrially for several decades. There exist some processes which need the removal of CO2 . In natural gas processing CO2 is removed to reduce the costs of compression and transportation. Carbon dioxide must be removed from the hydrogen system in ammonia manufacture, since it has a very harmful and unpleasant effect on catalysts for the reaction between H2 and N2 . Power plant flue gases are a new practical use of CO2 capture processes, compared to the first two. In this case the main object of CO2 removal is reducing the greenhouse emissions. This subject has attracted so much of interest, because global warming is an important environmental and political problem (Freguia, 2002). Fundamentally, there exist three systems for carbon dioxide removal and they are called as post-combustion capture (PCC), oxyfuel combustion, and pre-combustion capture (Kothandaraman, 2010). Post-combustion capture (PCC) is a developed process that could be engaged faster than competing technologies. High operating cost and high capital cost are the main drawbacks of the implementation of aqueous absorption/desorption process on a industrially level of post-combustion capture an important choice
∗ Corresponding author at: School of Chemical Engineering, Petroleum University of Technology, Abadan Branch, Iran. Tel.: +98 937 669 1944; fax: +98 21 339 67 288. E-mail address: [email protected] (H. Esmaeili). http://dx.doi.org/10.1016/j.ijggc.2014.09.013 1750-5836/© 2014 Elsevier Ltd. All rights reserved.
in order to reduce both the capital and operating cost include the advancement of improved solvent (Mangalapally and Hasse, 2011). Also, it has been investigated that the solvent circulation rate to be the most effective variable to adjust in order to reduce the capital and operation cost (Freguia, 2002). Until now, the EU project CASTOR (2004–2008) developed two new amine-based solvents called CASTOR1 and CASTOR2. The test with the novel solvent CASTOR2 illustrates that it is possible to develop amine solvents with lower regeneration energies and increasing stability toward degradation. For CASTOR2 solvent, the minimum requiring energy is reported to be below 3.6 GJ/tCO2 which is slightly lower than that of MEA. Furthermore, the minimum steam demand is achieved at a lower L/G ratio in comparison to that of MEA. This demonstrates that the cyclic CO2 carrying capacity of CASTOR2 is much better than MEA (Knudsena et al., 2009). Another progress achieved by Mitsubishi Heavy Industries together with Kansai Electric, commercially engage other solvents instead of MEA. Furthermore, these companies employ different types of proprietary equipment in their process. The “KS-1TM ” is said to reduce the regeneration heat of process to ∼ 3 GJ/tCO2 , i.e. 20% lower than that of MEA ∼ 3.7 GJ/tCO2 (Mangalapally et al., 2009; Mimura et al., 1997). It has been investigated that “KS-1TM ” also has advantages in comparison to MEA regarding degradation and corrosion by the supplier. Furthermore, Siemens together with E.on, implement another solvent instead of MEA. Their solvent “Siemens AAS” is known to be an aqueous solution of an amino acid salt. The
H. Esmaeili, B. Roozbehani / International Journal of Greenhouse Gas Control 30 (2014) 212–215 Table 1 Comparison of optimal operation points for the different solvents for two sets of experiments at low and high CO2 partial pressure.
pCO2 (mbar) MEA CESAR1 CESAR2
Regeneration energy (GJ/tCO2 )
L/G ratio (kg/kg)
54 3.8 (100%) 3.0 (79%) 3.45 (91%)
54 1.2 (100%) 0.65 (54%) 0.95 (79%)
102 4.1 (100%) 3.3 (80%) 3.8 (93%)
102 2.5 (100%) 1.4 (56%) 1.9 (76%)
Adapted from Mangalapally and Hasse (2011).
requiring energy for their improved process with Siemens AAS solvent for a full-scale removal plant is published to be 2.7 GJ/tCO2 (Jockenhoevel et al., 2010). The CO2 solubility in an aqueous tertiary amine solution was measured by Zheng et al. (2011). The results show that the mixed amine solution of the tertiary amine with MEA could save regeneration energy about 20% compared with 30% MEA aqueous solution. Recently, two new PCC solvents, CESAR 1 and CESAR 2 were studied in the pilot plant using a systematic approach. In that study the optimum operation points for the two new solvents for two sets of experiments at low and high CO2 partial pressure have been investigated. The results have been compared to the optimal operation points of the MEA in the table (Mangalapally and Hasse, 2011) (Table 1). There has been performed much research to find better solvents than MEA for CO2 removal from flue gas. Usually primary and secondary amine solutions have fast reaction rates with CO2 , but they always suffer from smaller solubility for CO2 because of carbamate formation. Tertiary amines and sterically hindered amines usually have large solubility for CO2 , but unfortunately they suffer from slow reaction rates (Zheng et al., 2011). Yoon et al. (2003) has studied CO2 absorption into AMPD (2-amino-2-methyl-1,3propanediol). One idea is to combine the reactivity of one amine (e.g. MEA) with the low desorption energy of another amine (e.g. MDEA) (Lars Erik, 2010). The shuttle mechanism was proposed by Astarita et al. (1981). The concept was that absorbed CO2 reacts with the most reactive reactant near the interface and is transported into the bulk liquid. Then CO2 is transferred to the less reactive component, and the most reactive reactant is shuttled back to the interface. Most of the studied mixtures contain one primary amine (e.g. MEA) and more tertiary amine or a sterically hindered amine. Glasscock et al. (1991), Rangwala et al. (1992), Hagewiesche et al. (1995) and Liao and Li (2002) have studied the absorption and
213
desorption in mixtures of MDEA with MEA or DEA. The system MEA/AMP has been studied by Xiao et al. (2000), Mandal et al. (2001) and Mandal and Bandyopadhyay (2006). Piperazine (PZ) is a cyclic nitrogen containing component that can catalyze CO2 absorption. The mechanisms involved in CO2 absorption into an MDEA/PZ mixture have been studied by Zhang et al. (2001). Bishnoi and Rochelle (2000) and Derks et al. (2006) have described absorption into pure aqueous piperazine. So, the different types of amines can also be mixed in order to combine the specific advantages of each type of amines. This work focuses on the development of a new solvent based on a mixture of different types of amines solution primary: mono-ethanolamine (MEA), tertiary: tri-ethylene tetramine (TETA), sterically hindered: 2-amino-2-methyl-1,3-propanediol (AMPD), and absorption activators: (piperazinyl1-1)-2-ethylamine (PZEA). It must be noticed that the composition of these mixtures has a strong effects on energy consumption and solvent flow rate for CO2 absorption. Because of existence the kinetic and thermodynamic data of 30% MEA, it was selected as the reference solvent. The present paper reports on testing the solvent in a gas-fired PCC absorption/desorption pilot plant. The results are compared to MEA, to study the potential of improvement in regeneration energy for the new solvent. From comparing the results of works in literatures and experimental results that conducted in Abadan Center of Research, it could be concluded that this paper presents the most effective solvent for removal of CO2 . 2. Experiments 2.1. Pilot plant experiments with new solvent (ACOR100) CO2 has been removed from industrial streams at least since 1930 (Kohl and Nielsen, 1997). A removal process consisting of absorption, desorption, heat exchangers and auxiliary equipment is shown in Fig. 1. Absorption is traditionally performed in a column with plates, random packing or structured packing. The experiments were conducted in an absorption/desorption process. The absorber equipped with the Structured Grid Packing. The total height is 1.5 m; the diameter is 0.15 m. For steady state operation the liquid level in absorber bottom is controlled by a pump. The rich solvent (ACOR100) is pumped into the desorber through the rich lean heat exchanger. The flow rate of the solvent
Fig. 1. Principle for CO2 removal process based on absorption in amine solution.
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H. Esmaeili, B. Roozbehani / International Journal of Greenhouse Gas Control 30 (2014) 212–215
Table 2 Tested post combustion capture (PCC) solvents.
Table 3 CO2 absorption plant design specifications at low CO2 partial pressure.
Name
Composition
Process variables
Experiment set
MEA ACOR 100
0.3 g/g Mono-ethanolamine + 0.7 g/g Water MEA + TETA + AMPD + PZEA
Flue gas volume flow (L/min) Flue gas temperature at absorber inlet (◦ C) Variation range of solvent volume flow (L/min) Solvent temperature at absorber inlet (◦ C) Solvent to flue gas volume flow ratio (L/G) (L/L) CO2 partial pressure in flue gas (mbar) CO2 volume flow in flue gas (L/min) CO2 volume flow captured (L/min) CO2 removal rate (%)
12 with 8% CO2 of flow gas 40 0.4–0.8 45 0.033–0.066 54 0.96 0.864 90
can be set between 0.4 and 0.8 L/min. The desorber is equipped with Structured Grid Packing similar to the absorber. The total packing height in the desorber is 1.5 m; the diameter is 0.05 m. The bottom of the desorber contains electrical heating elements for partial evaporation of the solvent. The vapor at the desorber top is led into a condenser where most of the water is removed so that almost pure CO2 is obtained. The flow rate of the flue gas can be set between 2 and 18 L/min. But due to fluid dynamic restrictions, maximum operational gas flow rate through the absorber tower is limited to about 12 L/min. The search of new solvent for CO2 removal in Abadan Center of Research (ACOR) was focused on a mixture of different types of amines. Table 2 elaborates the details of the novel solvent (ACOR100) and MEA.
2.1.1. Comparison of equilibrium data The equilibrium data of carbon dioxide at 40 ◦ C (contributed to the absorber temperature) and 120 ◦ C (related to the typical value of desorber temperature) using the Electrolyte-NRTL model is showed in Fig. 2 (Asprion, 2006) in comparison to experimental data for ACOR100. The loading of CO2 is presented in mol CO2 per kg solvent. This unit was selected, so that the effect of the solvent mass flow pumped around in the absorption/desorption process can be observed easily (Mangalapally and Hasse, 2011). The regeneration energy needed in the desorber can be segregated into the following items (Mangalapally et al., 2009): the energy needed for desorption of CO2 (desorption enthalpy), the energy to heat up the solvent and the reflux, and the energy needed for supplying the stripping stream. According to Fig. 2, it can be concluded that the distance between the equilibrium curves at 120 ◦ C and 40 ◦ C is closely connected to the solvent flow rate in addition to the stripping stream. Consequently, a large distance in the case of ACOR100 resulting in a larger number for the enthalpy of desorption. It is a desire result, because it will often result to a lower regeneration energy and lower solvent flow rate (Notz, 2010a,b; Notz et al., 2010). Fig. 2 illustrates that the distance between the equilibrium curves for the ACOR100 is larger than the equilibrium curves of MEA. For this reason, lower optimum solvent flow rate and lower regeneration energy for the ACOR100 compared to MEA could be predicted.
2.1.2. Method for solvent comparison in the pilot plant and experimental results For testing solvents in the pilot plant, a consistent method was defined and applied to all solvents, here to MEA and ACOR100. For each set of experiments the CO2 partial pressure in the flue gas is fixed. One level is studied, 54 mbar, corresponding to gas fired power plants (Rolker and Arlt, 2006). Furthermore, the CO2 removal rate (CO2 ) is specified. For post combustion capture of CO2 from power plants, the target is often a CO2 removal rate of 90%. Therefore, the experiments were carried out at that rate. As a direct setting of the CO2 removal rate is not possible it has to be adjusted by suitably choosing the re-boiler duty in an iterative process during each experiment. The re-boiler duty at the desired removal rate is the most important result of the experiment. As there is no perfect insulation, there are always losses. So, the experimental number needs to be corrected for heat losses which can be accurately assessed (Notz, 2010a,b). All numbers reported here are corrected numbers after the subtraction of heat losses. They are given in terms of regeneration energy per ton of captured CO2 (Mangalapally, 2010). The operating conditions of the experiments of the present work are summarized in Table 3. The results from these experiments are analyzed in plots of the regeneration energy versus the ratio of the liquid to the gas mass flow. These plots allow finding an optimum solvent flow rate and the corresponding minimum regeneration energy. The optima for the different solvents are then compared. Fig. 3 shows the regeneration energy as a function of the solvent flow rate (L/G ratio) for the experiment at low CO2 partial pressure. Two solvents are compared: MEA, ACOR100. 3. Results and discussion Experiments were carried out at the low partial pressure to optimize both the absorber L/G ratio and the regeneration energy demand at 90% CO2 removal for two solvents. The tests were 5
pCO2 / (mbar)
400 ACOR100 at 120C
300
ACOR100 at 40C MEA at 120C
200
MEA at 40C
Specific Steam Consumpon (GJ/ton CO2)
4.5
500
ACOR100
4
MEA 3.5
3
100 0
2.5 0
1
2
3
4
5
XCO2 / (molCO2/kgSolvent) Fig. 2. Calculated equilibrium data of CO2 solubility at 40 ◦ C and 120 ◦ C for MEA in comparison to experimental data for ACOR100.
0.02
0.03
0.04
0.05
0.06
0.07
0.08
Absorber L/G rao (lit/lit)
Fig. 3. Comparison of pilot plant results for experiments carried out with MEA and ACOR100 at low CO2 partial pressure at ∼90% CO2 removal.
H. Esmaeili, B. Roozbehani / International Journal of Greenhouse Gas Control 30 (2014) 212–215 Table 4 Comparison of optimal operation points at 54 mbar P.P of CO2 .
MEA ACOR100
Regeneration energy (GJ/tCO2 )
L/G ratio (lit/lit)
3.6 (100%) 2.7 (75%)
0.055 (100%) 0.04 (73%)
conducted by operating the absorber at a fixed flue gas (∼12 L/min) and changing the solvent flow rate. In the following figure, the specific steam demand has been plotted as a function of the absorber L/G ratio (in L Solvent/L Flue Gas) for each of the tested solvents. Fig. 3 shows that with MEA the lowest specific steam demand (∼3.6) was obtained at an optimum L/G ratio of about 0.055 L/L. It is easy to notice that at the higher L/G ratio (∼0.06), the regeneration energy demand obviously increases. It worth to mention that according to Fig. 3 it was not possible to attain the 90% CO2 removal at L/G ratios below approximately 0.04 L/L. On the other hand, for the ACOR100 solvent, Fig. 3 indicates that the optimum energy demand is about 2.7, which is clearly lower than that of MEA. Moreover, that optimum energy demand is obtained at a significantly lower L/G ratio in comparison to that of MEA. Also, the temperature of stripper tower was about 110 ◦ C. In order to have a better comparison between two solvents the corresponding numbers to each solvent are summarized in Table 4. This Table allows an exact comparison between the results of MEA and ACOR100. The considerable improvement can be seen for ACOR100 at low CO2 partial pressure (54 mbar), for both the regeneration energy and the solvent flow rate. 4. Conclusion The tests with the novel solvent ACOR100 and MEA as a reference were conducted in order to achieve development in both regeneration energy demand and absorber L/G ratio at a constant CO2 removal rate of 90%. The steam requirement for solvent regeneration using 30% MEA was found to be 3.6 GJ/ton CO2 at an approximately L/G = 0.055. However, the optimum number for regeneration energy using ACOR100 is found to be 2.7 at L/G = 0.04. The experiments with the novel solvent ACOR100 have shown that it is possible to achieve considerable progress in optimizing both the regeneration energy and absorber L/G ratio. Acknowledgments This work was supported by the Abadan Research Center at the Petroleum University of Technology at Abadan. References Asprion, N., 2006. Nonequilibrium rate-based simulation of reactive systems: simulation model, heat transfer, and influence of film discretization. Ind. Eng. Chem. Res. 45, 2054–2069. Astarita, G., Savage, D.W., Longo, J.M., 1981. Promotion of CO2 mass transfer in carbonate solutions. Chem. Eng. Sci. 36, 581–588.
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Bishnoi, S., Rochelle, G.T., 2000. Absorption of carbon dioxide into aqueous piperazine: reaction kinetics, mass transfer and solubility. Chem. Eng. Sci. 55, 5531–5543. Derks, P.W.J., Kleingeld, T., van Aken, C., Hogendoorn, J.A., Versteeg, G.F., 2006. Kinetics of absorption of carbon dioxide in aqueous piperazine solutions. Chem. Eng. Sci. 61, 6837–6854. Freguia, S., 2002. Modeling of CO2 Removal from Flue Gases with Monoethanolamine, in Chemical Engineering. University of Texas, Austin. Glasscock, D.A., Critchfield, J.E., Rochelle, G.T., 1991. CO2 absorption/desorption in mixtures of methyldiethanolamine with monoethanolamine or diethanolamine. Chem. Eng. Sci. 46, 2829–2845. Hagewiesche, D.P., Ashour, H.A., Al-Ghawas, H.A., Sandall, O.C., 1995. Absorption of carbon dioxide into aqueous blends of monoethanolamine and N-methyldiethanolamine. Chem. Eng. Sci. 50, 1071–1079. Jockenhoevel, T., Schneider, R., Rode, H., 2010. Validation of a second-generation post-combustion capture technology – results from POSTCAP pilot plant operation. In: PowerGen Europe, June 08–10. Knudsena, J.N., Jensena, J.N., Vilhelmsenb, P.-J., Biedec, O., 2009. Experience with CO2 capture from coal flue gas in pilot-scale: testing of different amine solvents. Energy Procedia 1, 783–790. Kohl, A., Nielsen, R., 1997. Gas Purification, 5th ed. Gulf Publications, Houston. Kothandaraman, A., (PhD Thesis) 2010. Carbon Dioxide Capture by Chemical Absorption: A Solvent Comparison Study. Massachusetts Institute of Technology, USA. Lars Erik, 2010. Removal of CO2 from Exhaust Gas. Telemark University College, Faculty of Technology. Liao, C., Li, M., 2002. Kinetics of absorption of carbon dioxide into aqueous solutions of monoethanolamine + N-methyldiethanolamine. Chem. Eng. Sci. 57, 4569–4582. Mandal, B.P., Bandyopadhyay, S.S., 2006. Absorption of carbon dioxide into aqueous blends of 2-amino-2 methyl-1-propanol and monoethanolamine. Chem. Eng. Sci. 61, 5440–5447. Mandal, B.P., Guha, M., Biswas, A.K., Bandyopadhyay, S.S., 2001. Removal of carbon dioxide by absorption in mixed amines: modelling of absorption in aqueous MDEA/MEA and AMP/MEA solutions. Chem. Eng. Sci. 56, 6217–6224. Mangalapally, H.P., Hasse, H., 2011. Pilot plant experiments for post combustion carbon dioxide capture by reactive absorption with novel solvents. Energy Procedia 4, 1–8, http://dx.doi.org/10.1016/j.egypro.2011.01.015. Mangalapally, H.P., Notz, R., Hoch, S., Asprion, N., Sieder, G., Garcia, H., Hasse, H., 2009. Pilot plant experimental studies of post combustion CO2 capture by reactive absorption with MEA and new solvents. Energy Procedia 1, 963–970. Mimura, T., Simayoshi, H., Suda, T., Iijima, M., Mitsuoka, S., 1997. Developments of energy saving technology for flue gas carbon dioxide recovery in power plant by chemical absorption method and steam system. Energy Convers. Manag. 38, S57–S62. Mangalapally, H.P., 2010. Post Combustion Capture of CO2 by Reactive Absorption. TU Kaiserslautern, Germany (PhD Dissertation), (in preparation). Notz, R., (PhD Dissertation) 2010a. CO2 -Abtrennung aus Kraftwerksabgasen mittels Reaktivabsorption. Universitaet Stuttgart, Germany. Logos Verlag Berlin GmbH, ISBN 978-3-8325-2386-2. Notz, R., 2010b. CO2-Abtrennung aus Kraftwerksabgasen mittels Reaktivabsorption. Universitaet Stuttgart, Germany, Logos Verlag Berlin GmbH, ISBN 978-3-83252386-2 (PhD Dissertation)2010a. Notz, R., Tönnies, I., Mangalapally, H.P., Hoch, S., Hasse, H., 2010. A Short-cut Method for Assessing Absorbents for Post Combustion Carbon Dioxide Capture. Int. J. Greenhouse Gas Control (in press). Rangwala, H.A., Morrell, B.R., Mather, A.E., Otto, F.D., 1992. Absorption of CO2 into aqueous tertiary amine/MEA solutions. Can. J. Chem. Eng. 70 (June), 482–490. Rolker, J., Arlt, W., 2006. Abtrennung von Kohlendioxid aus Rauchgasen mittels Absorption. Chem. Ing. Tech. 78, 416–424. Xiao, J., Chie-Wei, L., Meng-Hui, L., 2000. Kinetics of absorption of carbon dioxide into aqueous solutions of 2-amino-2-methyl-1-propanol + monoethanolamine. Chem. Eng. Sci. 55, 161–175. Yoon, J., Baek, J., Yamamoto, Y., Komai, T., Kawamura, T., 2003. Kinetics of removal of carbon dioxide by aqueous 2-amino-2-methyl-1,3-propanediol. Chem. Eng. Sci. 58, 5229–5237. Zheng, Y., Guo, D., Dong, L., Chen, J., 2011. Simulation and pilot plant measurement for CO2 absorption with mixed amines. Energy Procedia 4 (2011), 299–306. Zhang, X., Zhang, C., Qin, S., Zheng, Z., 2001. A kinetics study on the absorption of carbon dioxide into a mixed aqueous solution of methyldiethanolamine and piperazine. Ind. Eng. Chem. Res. 40, 3785–3791.
Contents lists available at ScienceDirect
International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
Pilot-scale experiments for post-combustion CO2 capture from gas fired power plants with a novel solvent Hamid Esmaeili ∗ , Behrooz Roozbehani School of Chemical Engineering, Petroleum University of Technology, Abadan Branch, Iran
a r t i c l e
i n f o
Article history: Received 29 December 2013 Received in revised form 13 August 2014 Accepted 15 September 2014 Keywords: CO2 capture Amine-based solvent Gas fired power plants Regeneration energy demand Solvent flow rate Post combustion capture
a b s t r a c t Aqueous MEA is the most common solvent used to absorb CO2 . Its problem is that the energy required for solvent regeneration and solvent flow rate is high. This work focuses on introducing and developing a novel solvent to reduce both the regeneration energy demand and solvent flow rate. The novel solvent based on the mixture of MEA, TETA, AMPD and PZEA from Abadan Center of Research (ACOR100) was studied and compared to mono-ethanolamine (MEA). For both solvent, the regeneration energy is determined for different solvent flow rates at a constant CO2 removal rate of 90% and a low partial pressure (54 mL bar). The optimum numbers for both the regeneration energy and solvent flow rate are found and compared to each other, for each of solvents. The resulting numbers of the ACOR100 indicate a considerable improvement compared to MEA with a reduction of about 25% in the regeneration energy and 27% in the solvent flow rate. © 2014 Elsevier Ltd. All rights reserved.
1. Introduction Carbon dioxide capture has been practiced industrially for several decades. There exist some processes which need the removal of CO2 . In natural gas processing CO2 is removed to reduce the costs of compression and transportation. Carbon dioxide must be removed from the hydrogen system in ammonia manufacture, since it has a very harmful and unpleasant effect on catalysts for the reaction between H2 and N2 . Power plant flue gases are a new practical use of CO2 capture processes, compared to the first two. In this case the main object of CO2 removal is reducing the greenhouse emissions. This subject has attracted so much of interest, because global warming is an important environmental and political problem (Freguia, 2002). Fundamentally, there exist three systems for carbon dioxide removal and they are called as post-combustion capture (PCC), oxyfuel combustion, and pre-combustion capture (Kothandaraman, 2010). Post-combustion capture (PCC) is a developed process that could be engaged faster than competing technologies. High operating cost and high capital cost are the main drawbacks of the implementation of aqueous absorption/desorption process on a industrially level of post-combustion capture an important choice
∗ Corresponding author at: School of Chemical Engineering, Petroleum University of Technology, Abadan Branch, Iran. Tel.: +98 937 669 1944; fax: +98 21 339 67 288. E-mail address: [email protected] (H. Esmaeili). http://dx.doi.org/10.1016/j.ijggc.2014.09.013 1750-5836/© 2014 Elsevier Ltd. All rights reserved.
in order to reduce both the capital and operating cost include the advancement of improved solvent (Mangalapally and Hasse, 2011). Also, it has been investigated that the solvent circulation rate to be the most effective variable to adjust in order to reduce the capital and operation cost (Freguia, 2002). Until now, the EU project CASTOR (2004–2008) developed two new amine-based solvents called CASTOR1 and CASTOR2. The test with the novel solvent CASTOR2 illustrates that it is possible to develop amine solvents with lower regeneration energies and increasing stability toward degradation. For CASTOR2 solvent, the minimum requiring energy is reported to be below 3.6 GJ/tCO2 which is slightly lower than that of MEA. Furthermore, the minimum steam demand is achieved at a lower L/G ratio in comparison to that of MEA. This demonstrates that the cyclic CO2 carrying capacity of CASTOR2 is much better than MEA (Knudsena et al., 2009). Another progress achieved by Mitsubishi Heavy Industries together with Kansai Electric, commercially engage other solvents instead of MEA. Furthermore, these companies employ different types of proprietary equipment in their process. The “KS-1TM ” is said to reduce the regeneration heat of process to ∼ 3 GJ/tCO2 , i.e. 20% lower than that of MEA ∼ 3.7 GJ/tCO2 (Mangalapally et al., 2009; Mimura et al., 1997). It has been investigated that “KS-1TM ” also has advantages in comparison to MEA regarding degradation and corrosion by the supplier. Furthermore, Siemens together with E.on, implement another solvent instead of MEA. Their solvent “Siemens AAS” is known to be an aqueous solution of an amino acid salt. The
H. Esmaeili, B. Roozbehani / International Journal of Greenhouse Gas Control 30 (2014) 212–215 Table 1 Comparison of optimal operation points for the different solvents for two sets of experiments at low and high CO2 partial pressure.
pCO2 (mbar) MEA CESAR1 CESAR2
Regeneration energy (GJ/tCO2 )
L/G ratio (kg/kg)
54 3.8 (100%) 3.0 (79%) 3.45 (91%)
54 1.2 (100%) 0.65 (54%) 0.95 (79%)
102 4.1 (100%) 3.3 (80%) 3.8 (93%)
102 2.5 (100%) 1.4 (56%) 1.9 (76%)
Adapted from Mangalapally and Hasse (2011).
requiring energy for their improved process with Siemens AAS solvent for a full-scale removal plant is published to be 2.7 GJ/tCO2 (Jockenhoevel et al., 2010). The CO2 solubility in an aqueous tertiary amine solution was measured by Zheng et al. (2011). The results show that the mixed amine solution of the tertiary amine with MEA could save regeneration energy about 20% compared with 30% MEA aqueous solution. Recently, two new PCC solvents, CESAR 1 and CESAR 2 were studied in the pilot plant using a systematic approach. In that study the optimum operation points for the two new solvents for two sets of experiments at low and high CO2 partial pressure have been investigated. The results have been compared to the optimal operation points of the MEA in the table (Mangalapally and Hasse, 2011) (Table 1). There has been performed much research to find better solvents than MEA for CO2 removal from flue gas. Usually primary and secondary amine solutions have fast reaction rates with CO2 , but they always suffer from smaller solubility for CO2 because of carbamate formation. Tertiary amines and sterically hindered amines usually have large solubility for CO2 , but unfortunately they suffer from slow reaction rates (Zheng et al., 2011). Yoon et al. (2003) has studied CO2 absorption into AMPD (2-amino-2-methyl-1,3propanediol). One idea is to combine the reactivity of one amine (e.g. MEA) with the low desorption energy of another amine (e.g. MDEA) (Lars Erik, 2010). The shuttle mechanism was proposed by Astarita et al. (1981). The concept was that absorbed CO2 reacts with the most reactive reactant near the interface and is transported into the bulk liquid. Then CO2 is transferred to the less reactive component, and the most reactive reactant is shuttled back to the interface. Most of the studied mixtures contain one primary amine (e.g. MEA) and more tertiary amine or a sterically hindered amine. Glasscock et al. (1991), Rangwala et al. (1992), Hagewiesche et al. (1995) and Liao and Li (2002) have studied the absorption and
213
desorption in mixtures of MDEA with MEA or DEA. The system MEA/AMP has been studied by Xiao et al. (2000), Mandal et al. (2001) and Mandal and Bandyopadhyay (2006). Piperazine (PZ) is a cyclic nitrogen containing component that can catalyze CO2 absorption. The mechanisms involved in CO2 absorption into an MDEA/PZ mixture have been studied by Zhang et al. (2001). Bishnoi and Rochelle (2000) and Derks et al. (2006) have described absorption into pure aqueous piperazine. So, the different types of amines can also be mixed in order to combine the specific advantages of each type of amines. This work focuses on the development of a new solvent based on a mixture of different types of amines solution primary: mono-ethanolamine (MEA), tertiary: tri-ethylene tetramine (TETA), sterically hindered: 2-amino-2-methyl-1,3-propanediol (AMPD), and absorption activators: (piperazinyl1-1)-2-ethylamine (PZEA). It must be noticed that the composition of these mixtures has a strong effects on energy consumption and solvent flow rate for CO2 absorption. Because of existence the kinetic and thermodynamic data of 30% MEA, it was selected as the reference solvent. The present paper reports on testing the solvent in a gas-fired PCC absorption/desorption pilot plant. The results are compared to MEA, to study the potential of improvement in regeneration energy for the new solvent. From comparing the results of works in literatures and experimental results that conducted in Abadan Center of Research, it could be concluded that this paper presents the most effective solvent for removal of CO2 . 2. Experiments 2.1. Pilot plant experiments with new solvent (ACOR100) CO2 has been removed from industrial streams at least since 1930 (Kohl and Nielsen, 1997). A removal process consisting of absorption, desorption, heat exchangers and auxiliary equipment is shown in Fig. 1. Absorption is traditionally performed in a column with plates, random packing or structured packing. The experiments were conducted in an absorption/desorption process. The absorber equipped with the Structured Grid Packing. The total height is 1.5 m; the diameter is 0.15 m. For steady state operation the liquid level in absorber bottom is controlled by a pump. The rich solvent (ACOR100) is pumped into the desorber through the rich lean heat exchanger. The flow rate of the solvent
Fig. 1. Principle for CO2 removal process based on absorption in amine solution.
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Table 2 Tested post combustion capture (PCC) solvents.
Table 3 CO2 absorption plant design specifications at low CO2 partial pressure.
Name
Composition
Process variables
Experiment set
MEA ACOR 100
0.3 g/g Mono-ethanolamine + 0.7 g/g Water MEA + TETA + AMPD + PZEA
Flue gas volume flow (L/min) Flue gas temperature at absorber inlet (◦ C) Variation range of solvent volume flow (L/min) Solvent temperature at absorber inlet (◦ C) Solvent to flue gas volume flow ratio (L/G) (L/L) CO2 partial pressure in flue gas (mbar) CO2 volume flow in flue gas (L/min) CO2 volume flow captured (L/min) CO2 removal rate (%)
12 with 8% CO2 of flow gas 40 0.4–0.8 45 0.033–0.066 54 0.96 0.864 90
can be set between 0.4 and 0.8 L/min. The desorber is equipped with Structured Grid Packing similar to the absorber. The total packing height in the desorber is 1.5 m; the diameter is 0.05 m. The bottom of the desorber contains electrical heating elements for partial evaporation of the solvent. The vapor at the desorber top is led into a condenser where most of the water is removed so that almost pure CO2 is obtained. The flow rate of the flue gas can be set between 2 and 18 L/min. But due to fluid dynamic restrictions, maximum operational gas flow rate through the absorber tower is limited to about 12 L/min. The search of new solvent for CO2 removal in Abadan Center of Research (ACOR) was focused on a mixture of different types of amines. Table 2 elaborates the details of the novel solvent (ACOR100) and MEA.
2.1.1. Comparison of equilibrium data The equilibrium data of carbon dioxide at 40 ◦ C (contributed to the absorber temperature) and 120 ◦ C (related to the typical value of desorber temperature) using the Electrolyte-NRTL model is showed in Fig. 2 (Asprion, 2006) in comparison to experimental data for ACOR100. The loading of CO2 is presented in mol CO2 per kg solvent. This unit was selected, so that the effect of the solvent mass flow pumped around in the absorption/desorption process can be observed easily (Mangalapally and Hasse, 2011). The regeneration energy needed in the desorber can be segregated into the following items (Mangalapally et al., 2009): the energy needed for desorption of CO2 (desorption enthalpy), the energy to heat up the solvent and the reflux, and the energy needed for supplying the stripping stream. According to Fig. 2, it can be concluded that the distance between the equilibrium curves at 120 ◦ C and 40 ◦ C is closely connected to the solvent flow rate in addition to the stripping stream. Consequently, a large distance in the case of ACOR100 resulting in a larger number for the enthalpy of desorption. It is a desire result, because it will often result to a lower regeneration energy and lower solvent flow rate (Notz, 2010a,b; Notz et al., 2010). Fig. 2 illustrates that the distance between the equilibrium curves for the ACOR100 is larger than the equilibrium curves of MEA. For this reason, lower optimum solvent flow rate and lower regeneration energy for the ACOR100 compared to MEA could be predicted.
2.1.2. Method for solvent comparison in the pilot plant and experimental results For testing solvents in the pilot plant, a consistent method was defined and applied to all solvents, here to MEA and ACOR100. For each set of experiments the CO2 partial pressure in the flue gas is fixed. One level is studied, 54 mbar, corresponding to gas fired power plants (Rolker and Arlt, 2006). Furthermore, the CO2 removal rate (CO2 ) is specified. For post combustion capture of CO2 from power plants, the target is often a CO2 removal rate of 90%. Therefore, the experiments were carried out at that rate. As a direct setting of the CO2 removal rate is not possible it has to be adjusted by suitably choosing the re-boiler duty in an iterative process during each experiment. The re-boiler duty at the desired removal rate is the most important result of the experiment. As there is no perfect insulation, there are always losses. So, the experimental number needs to be corrected for heat losses which can be accurately assessed (Notz, 2010a,b). All numbers reported here are corrected numbers after the subtraction of heat losses. They are given in terms of regeneration energy per ton of captured CO2 (Mangalapally, 2010). The operating conditions of the experiments of the present work are summarized in Table 3. The results from these experiments are analyzed in plots of the regeneration energy versus the ratio of the liquid to the gas mass flow. These plots allow finding an optimum solvent flow rate and the corresponding minimum regeneration energy. The optima for the different solvents are then compared. Fig. 3 shows the regeneration energy as a function of the solvent flow rate (L/G ratio) for the experiment at low CO2 partial pressure. Two solvents are compared: MEA, ACOR100. 3. Results and discussion Experiments were carried out at the low partial pressure to optimize both the absorber L/G ratio and the regeneration energy demand at 90% CO2 removal for two solvents. The tests were 5
pCO2 / (mbar)
400 ACOR100 at 120C
300
ACOR100 at 40C MEA at 120C
200
MEA at 40C
Specific Steam Consumpon (GJ/ton CO2)
4.5
500
ACOR100
4
MEA 3.5
3
100 0
2.5 0
1
2
3
4
5
XCO2 / (molCO2/kgSolvent) Fig. 2. Calculated equilibrium data of CO2 solubility at 40 ◦ C and 120 ◦ C for MEA in comparison to experimental data for ACOR100.
0.02
0.03
0.04
0.05
0.06
0.07
0.08
Absorber L/G rao (lit/lit)
Fig. 3. Comparison of pilot plant results for experiments carried out with MEA and ACOR100 at low CO2 partial pressure at ∼90% CO2 removal.
H. Esmaeili, B. Roozbehani / International Journal of Greenhouse Gas Control 30 (2014) 212–215 Table 4 Comparison of optimal operation points at 54 mbar P.P of CO2 .
MEA ACOR100
Regeneration energy (GJ/tCO2 )
L/G ratio (lit/lit)
3.6 (100%) 2.7 (75%)
0.055 (100%) 0.04 (73%)
conducted by operating the absorber at a fixed flue gas (∼12 L/min) and changing the solvent flow rate. In the following figure, the specific steam demand has been plotted as a function of the absorber L/G ratio (in L Solvent/L Flue Gas) for each of the tested solvents. Fig. 3 shows that with MEA the lowest specific steam demand (∼3.6) was obtained at an optimum L/G ratio of about 0.055 L/L. It is easy to notice that at the higher L/G ratio (∼0.06), the regeneration energy demand obviously increases. It worth to mention that according to Fig. 3 it was not possible to attain the 90% CO2 removal at L/G ratios below approximately 0.04 L/L. On the other hand, for the ACOR100 solvent, Fig. 3 indicates that the optimum energy demand is about 2.7, which is clearly lower than that of MEA. Moreover, that optimum energy demand is obtained at a significantly lower L/G ratio in comparison to that of MEA. Also, the temperature of stripper tower was about 110 ◦ C. In order to have a better comparison between two solvents the corresponding numbers to each solvent are summarized in Table 4. This Table allows an exact comparison between the results of MEA and ACOR100. The considerable improvement can be seen for ACOR100 at low CO2 partial pressure (54 mbar), for both the regeneration energy and the solvent flow rate. 4. Conclusion The tests with the novel solvent ACOR100 and MEA as a reference were conducted in order to achieve development in both regeneration energy demand and absorber L/G ratio at a constant CO2 removal rate of 90%. The steam requirement for solvent regeneration using 30% MEA was found to be 3.6 GJ/ton CO2 at an approximately L/G = 0.055. However, the optimum number for regeneration energy using ACOR100 is found to be 2.7 at L/G = 0.04. The experiments with the novel solvent ACOR100 have shown that it is possible to achieve considerable progress in optimizing both the regeneration energy and absorber L/G ratio. Acknowledgments This work was supported by the Abadan Research Center at the Petroleum University of Technology at Abadan. References Asprion, N., 2006. Nonequilibrium rate-based simulation of reactive systems: simulation model, heat transfer, and influence of film discretization. Ind. Eng. Chem. Res. 45, 2054–2069. Astarita, G., Savage, D.W., Longo, J.M., 1981. Promotion of CO2 mass transfer in carbonate solutions. Chem. Eng. Sci. 36, 581–588.
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