Dual Alkali Solvent System for CO2 Capture from Flue Gas

Jun 26, 2017 - The reboiler heat duty consists of reaction enthalpy between alkali and CO2, sensible heat for heating the CO2-loaded solution to the t...
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Dual Alkali Solvent System for CO2 Capture from Flue Gas Yang Li, H. Paul Wang,*,† Chang-Yu Liao,† Xinglei Zhao, Tung-Li Hsiung,† Shou-Heng Liu,† and Shih-Ger Chang* Environmental Energy Technology Division, Lawrence Berkeley National Laboratory, University of California, Berkeley, California 94720, United States ABSTRACT: A novel two-aqueous-phase CO2 capture system, namely the dual alkali solvent (DAS) system, has been developed. Unlike traditional solvent-based CO2 capture systems in which the same solvent is used for both CO2 absorption and stripping, the solvent of the DAS system consists of two aqueous phases. The upper phase, which contains an organic alkali 1-(2-hydroxyethyl) piperazine (HEP), is used for CO2 absorption. The lower phase, which consists of a mixture of K2CO3/ KHCO3 aqueous solution and KHCO3 precipitate, is used for CO2 stripping. Only a certain kind of amine (such as HEP) is able to ensure the phase separation, satisfactory absorption efficiency, effective CO2 transfer from the upper phase to the lower phase, and regeneration of the upper phase. In the meantime, due to the presence of K2CO3/KHCO3 in the lower phase, HEP in the upper phase is capable of being regenerated from its sulfite/sulfate heat stable salt, which enables the simultaneous absorption of CO2 and SO2/SO3 from the flue gas. Preliminary experiments and simulations indicate that the implementation of the DAS system can lead to 24.0% stripping energy savings compared to the Econamine process, without significantly lowering the CO2 absorption efficiency (∼90%).

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INTRODUCTION Carbon dioxide (CO2) is a major greenhouse gas which causes climate changes resulting in global warming. Over the last few decades, use of fossil fuels has contributed to significant increases of CO2 concentration in the atmosphere. A direct and effective option for the reduction of CO2 emission is the capture of CO2 from large stationary fossil fuel power generation units, e.g. power plants in the electric as well as in manufacturing or industrial sectors. Aqueous amine absorption is the most well-developed technology for postcombustion CO2 capture from flue gas.1 However, amine absorption has a number of drawbacks. The main drawback is its high stripping energy penalty because 70− 80% water in amine solvents has to undergo a temperature swing process from ∼40 to ∼120 °C. Due to the large heat capacity of water (4.184 kJ/kg·K), even if efficient state-of-theart heat recovering technologies are applied, the sensible heat consumption is still substantial. An alternative candidate for CO2 capture is the alkali metal carbonate solvent.2 It has many advantages over amine-based solvents including lower cost, less toxicity, and less degradation effects.3 One of the most important advantages is that bicarbonate solid precipitates after CO2 absorption.4 This allows the majority of the water in the solvent to be excluded during the stripping process, thereby achieving a much lower stripping energy penalty. However, the biggest challenge associated with using alkali metal carbonate is that it has a low rate of reaction, resulting in poor CO2 mass transfer. The combination of amine and alkali metal carbonate as a solvent for CO2 capture to acquire various benefits has been extensively researched. 5−14 The issue with these © 2017 American Chemical Society

approaches is that the amine and water still have to undergo temperature swing, leading to a huge energy penalty. In our laboratory, an advanced solvent system with a disruptive solvent regeneration method has been developed. The new system, named the dual alkali solvent (DAS) system, uses an organic alkali (amine) in the CO2 absorption step, which takes advantage of its fast kinetics and an inorganic alkali (KHCO3) in the CO2 desorption step, which takes advantage of thermodynamics, lower heat of regeneration, and lesser emissions. Unlike conventional amine solvent systems using thermal methods involving steam for CO2 desorption to regenerate amine,8,16 the DAS system employs a chemical method for the release of the absorbed CO2. This results in absorbent regeneration by the transfer of CO2 to an inorganic alkali. Here an aqueous two-phase system based on the saltingout effect17−20 was adopted to segregate the organic alkali from the inorganic alkali. This new class of solvent system possesses the benefits of both amine and alkali metal carbonate, respectively, in fast CO2 absorption kinetics and low solvent regeneration energy demand. In the process, the absorbed CO2 by amine can be transferred to alkali metal carbonate to enable the formation of alkali metal bicarbonate precipitates. The DAS system allows for the use of novel process features that can be incorporated to reduce the operating and capital costs of the CO2 capture process. Specifically, the DAS system is expected Received: Revised: Accepted: Published: 8824

January 1, 2017 June 20, 2017 June 26, 2017 June 26, 2017 DOI: 10.1021/acs.est.7b00006 Environ. Sci. Technol. 2017, 51, 8824−8831

Article

Environmental Science & Technology

Figure 1. (a) Process configuration of the dual alkali solvent (DAS) system employing a chemical method for the regeneration of amine. (b) Benchscale DAS system including absorber, recirculation tank, stripper, condenser, steamer, reboiler, and calorimeter.

prepared by mixing amines and K2CO3 in aqueous solutions either without or with the condition of salting-out effect, resulting in a single or two aqueous phases, respectively. The salting-out effect enables phase separation with aqueous amine stayed on the top and K2CO3 at the bottom in a recirculation tank. The gas phase was continuous and liquid phase dispersed with the interface visible at the bottom of the packed section. The gas exiting the top of the column passed through a condenser to remove water vapor before entering the CO2 analyzer. The rich solvent exiting the absorber was collected in the recirculation tank. The pressure drop of the packed column was measured by a U-tube manometer. Phase Diagram of the Aqueous Two-Phase System. Following CO2 absorption, the rich HEP aqueous solution entered the recirculation tank where the absorbed CO2 was transferred to K2CO3, resulting in the formation of KHCO3 precipitation. Meanwhile, the salting-out effect with the consequent aqueous phase separation was observed. To determine the species distribution in aqueous phase, experiments were performed to develop phase diagram. A gas mixture of CO2 (15%) and N2 (85%) was bubbled through an aqueous solution of 2.5 M HEP at 40 °C in a gas absorber for various time intervals to obtain solvents with CO2 loadings of 0, 0.247, 0.443, 0.538, and 0.608 mol CO2/mol HEP. The amount of CO2 absorbed was determined by monitoring CO2 concentration exiting the absorber with the IR CO2 analyzer. Each CO2 loaded solution was divided into several equal portions for subsequent addition of various amount of solid K2CO3 at 40 °C, resulting in the formation of a KHCO3 precipitation and separation of aqueous phases. Chemical compositions in each phase were analyzed by means of 1H NMR, 13C NMR, and laser Raman spectroscopy. A species distribution investigation of HEP aqueous solutions under various CO2 loading was also conducted by means of 1H NMR and 13C NMR. Thermal Stripping of CO2. KHCO3 solid produced in the recirculation tank was transferred to a CO2 stripper for thermal regeneration of K2CO3. The stripping system consisted of a stripper, a reboiler, a steamer, and a calorimeter. The stripper and the reboiler were completely surrounded with glass fiber insulation materials to reduce heat loss. A KHCO3 solid

to show enhancement of CO2 absorption efficiency, reducing absorber capital cost; reduction of processing water, resulting in reduced solvent regeneration energy demands; employment of stable and low heat capacity KHCO3, resulting in reduced sensible heat demands; reduction of emissions as K2CO3 can be generated at higher temperature (in comparison with amine) without any emissions of heat degradation harmful products; and reduction of reagent loss and equipment corrosion, resulting in reduced operation costs. Furthermore, DAS could be employed for simultaneous removal of SO2 and CO2 because dissolved SO2 can be removed from the liquid stream by the precipitation of KHSO3 and/or K2SO4 solids due to the low solubility. The experimental results of the DAS CO2 capture system are reported below.

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EXPERIMENTAL MATERIALS AND METHODS General. Laser Raman spectra of reaction samples were taken with an RSI R-3000QE Raman system, and 1H and 13C nuclear magnetic resonance (NMR) spectra were obtained with a Bruker 400 MHz spectrometer. CO2 concentrations in gas stream were monitored by a VacuMed IR CO2 analyzer (Model 17515). Materials. 1-(2-Hydroxyethyl) piperazine (HEP), piperazine (Pz), monoethanolamine (MEA), 2-amino-2-methyl-1propanol (AMP), deuterium oxide (D2O), potassium sulfate (K2SO4), potassium carbonate (K2CO3), and potassium bicarbonate (KHCO3) were obtained from Sigma-Aldrich, and used as received without further purification. Carbon dioxide (CO2) and nitrogen (N2) gases were from corresponding gas cylinders purchased from Airgas. CO2 Absorption. CO2 absorption was performed on a structured packing gas absorption system. The absorber is a glass column (2.5 cm i.d. × 1 m height) filled with Mellapak 900X packing material. The temperature of the packed-bed was controlled with a thermostatic water jacket surrounding the column. A gas mixture containing 15% CO2 and 85% N2 entered the bottom of the absorber through a distributer and flowed upward through the packing material. The solvent entered the top of the absorber through a distributer and flowed downward. The tests were performed with the solvent 8825

DOI: 10.1021/acs.est.7b00006 Environ. Sci. Technol. 2017, 51, 8824−8831

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Figure 2. (a) Comparison of CO2 removal efficiency of chemically regenerated amines and thermally regenerated MEA. The effect of phase separation on CO2 removal efficiency was investigated on HEP. (b) Cyclic runs of CO2 absorption and transformation from rich HEP to K2CO3, resulting in the regeneration of HEP and production of KHCO3 precipitate.

transferred to the regenerator. Another K2CO3 influent stream coming from the lower phase was pumped to the bottom of the stripper. In the regenerator, steam decomposes the KHCO3 to regenerate K2CO3 and liberate CO2. The regenerated K2CO3 is recycled back via a more concentrated K2CO3 effluent stream to the recirculation tank. Under the current circumstance, no heat exchangers were used to transfer heat from the effluent stream to influent stream and solid KHCO3 stream. In the energy consumption calculation, we made assumptions of 82% sensible heat recovery efficiency, identical to that of the MEA system. The conditions for aqueous phase separation can be applied in the recirculation tank, with a majority of K2CO3/KHCO3 remaining on the bottom with the lean HEP in the top aqueous layer. The lean HEP is recycled back to the absorber for CO2 absorption. Because of the reduced KHCO3 concentration in the top aqueous layer (i.e., lean HEP), the phase separation technique provides the benefit of enhanced CO2 absorption efficiency and reduced KHCO3 solid formation in the absorber. The phase separation also provides the benefit of reduced amine degradation due to the confinement of amines to the low temperature absorber/recirculation tank loop, preventing it from entering the high temperature regenerator. Figure 1b shows a photo of a bench-scale experimental setup of the DAS system. CO2 Absorption. For the single aqueous phase operation (i.e., without salting-out effect), the rich amine was regenerated by filtering out the KHCO3 solid precipitate, then replenishing the solution by the addition of K2CO3. For the aqueous twophase operation (i.e., with salting-out effect), rich amine entered the recirculation tank where it transferred the absorbed CO2 to concentrated K2CO3, resulting in the formation of a lean amine aqueous solution expelled to the top layer, and the bottom layer was composed of K2CO3/KHCO3 aqueous phase and a KHCO3 precipitate falling to the bottom. The regenerated lean amine was recycled to the top of the absorber for CO2 absorption (Figure 1b). CO2 absorption efficiencies of various amines regenerated by chemical methods involving the reaction with K2CO3 were examined to determine if chemical regeneration method is feasible. Amines evaluated were HEP, MEA, AMP, and Pz. Chemically regenerated MEA is denoted as MEA-chem-reg, and thermally regenerated 30% MEA was tested to provide a

(between 2 and 2.5 kg) was placed on the top of the Raschig rings packing (height 1.5 ft) in the stripper (i.d. 2 in.; height 6− 8 ft). An aqueous K2CO3 solution (about 4.8 M) was pumped, at a flow rate of 19 mL/min (26 g/min), from the recirculation tank to the bottom of the stripper before entering the reboiler compartment. The primary steam (60 psi at 15 g/min) supplied by the steamer entered a stainless steel coil inside the reboiler to heat the K2CO3 aqueous solutions for generating secondary steam. The temperature inside the reboiler was about 120−130 °C. The stripping pressure was controlled by a check valve with a threshold pressure of 1 psig. The secondary steam rose upward, passed through the packed bed, and then reacted with KHCO3 solid to produce liquid water, K2CO3, and CO2 gas. Subsequently, concentrated aqueous K2CO3 solutions flowed downward, passing through the packed bed before entering the reboiler compartment; while CO2 gas rose upward through a stainless steel gas-guide tube (i.d. 1/4 in. with small holes on the wall along the tube) embedded in the KHCO3 solid bed. After exiting the stripper, CO2 gas amount was determined with the IR CO2 analyzer. The flow rate of makeup water flowing down from a condenser to the solid bed was 3.9 g/min. The feeding rate of KHCO3 solid to the stripper depended on its consumption rate. The top level of KHCO3 solid bed in the stripper was maintained at between 4 and 6 ft above the top of packed bed, which was monitored through a section of the stripper made of glass (height 1.5 ft). When solid level dropped to about 4 ft above the top of the packed bed, the inlet gate was opened and KHCO3 solid was refurbished. A calorimeter was constructed and connected to the stripping system for the measurement of K2CO3 regeneration energy demand.

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RESULTS AND DISCUSSION The DAS system includes three major process components: absorber, recirculation tank, and regenerator as shown in Figure 1a. An aqueous solution comprising HEP15,21 is used for the capture and removal of CO2 from the flue gas in the absorber. The rich HEP is transferred to the recirculation tank where the absorbed CO2 is transferred from the rich solvent to K2CO3, resulting in the regeneration of lean HEP and formation of KHCO3. The separation of KHCO3 precipitation can be accomplished in continuous or batch basis by a rotating auger at the bottom of the recirculation tank. The KHCO3 solid is 8826

DOI: 10.1021/acs.est.7b00006 Environ. Sci. Technol. 2017, 51, 8824−8831

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Figure 3. (a) Ternary phase diagram of the mixture of HEP-K2CO3-H2O in the presence of CO2 at 40 °C. (b) Binodal phase diagrams of HEPK2CO3-H2O mixtures with a CO2 loading of 0.443 mol CO2/mol HEP at 40 °C.

amount of K2CO3 solid was then added to the recirculation tank for replenishment. Subsequently, the investigation focused on the performance of HEP regenerated with phase separation conditions because of the enhanced CO2 absorption. The cyclic CO2 absorption in the absorber and HEP regeneration in the recirculation tank were performed. Figure 2b shows that CO2 removal efficiencies of 90% or greater at L/G of 117 gal/1000 ft3 were maintained for 14 repetitive cycles, indicative of the sustainability in high CO2 absorption efficiency. Also shown is the CO2 absorption rate in each cyclic run. Amine Regeneration in the Recirculation Tank. The CO2-lean HEP aqueous solutions were chemically regenerated in the recirculation tank. The key characteristic of the DAS system is the immiscibility of the HEP aqueous solutions and the K2CO3/KHCO3 aqueous solutions due to the salting-out effect, leading to an aqueous two-phase system. Based on the analytical results, a ternary phase diagram at 40 °C was constructed as shown in Figure 3a. Two groups of points were observed. The left group denotes the weight fractions of species in the upper phase, and the right group denotes the weight fractions of species in the lower phase. When an aqueous mixture with a composition lies above these data at the corresponding CO2 loading, the mixture is expected to stay in one phase. On the other hand, phase separation will occur and two immiscible aqueous phases are formed if the composition of the mixture lies below these data. Alternatively, binodal phase diagrams were drawn for a CO2 loading of 0.443 mol CO2/mol HEP at 40 °C, to directly indicate species concentrations in both aqueous phases, as illustrated in Figure 3b. The bar chart on the left-hand and right-hand sides of the phase diagram indicates species concentrations in the upper and lower phases, respectively. It is apparent, that almost all HEP species (HEPH, HEPH2+, and HEPCO2−) exist in the upper phase and very little in the lower phase. On the other hand, a majority of CO32− and HCO3− present in the lower phase. The liquid/liquid phase separation allows the DAS process to confine the HEP species in the low temperature circulation loop of the absorber and recirculation tank, which reduces the reagent loss due to exposure to high temperature in the regenerator. Also, the CO2 absorption efficiency is significantly enhanced due to the deduction of HCO3− in the lean amine aqueous solution. Not all amines work well in the DAS system as demonstrated in Figure 2a. The appropriate amine must be able to react with

benchmark, denoted as MEA-therm-reg. All amine tests were performed with single aqueous phase, except HEP which was also tested with the two aqueous phase conditions. HEP without and with a phase separation is denoted as HEP-onephase and HEP-two-phase, respectively. Aqueous mixture of HEP and K2CO3 exhibited phase separation after increasing the concentration of K2CO3 to 3.5 M with 2.5 M HEP at 40 °C, with the upper phase primarily comprising a mixture of HEP containing species and the lower phase being mainly K2CO3 and KHCO3. The phase diagrams showing species distribution in both phases were determined by means of NMR and laser Raman spectroscopy and will be presented later. Amine concentration and CO2 loading in one phase operation, after mixing rich amine with 2.5 M K2CO3, were HEP-one-phase 2 M, loading 0.23; AMP 1 M, loading 0.32; Pz 1 M, loading 0.38; and MEA-chem-reg 3.3 M, loading 0.36. The concentrations of AMP, Pz, and MEA were limited by the solubility in an aqueous solution containing 2.5 M K2CO3. Judging from the high CO2 loading after chemical regeneration, it is clear that chemical method is not suitable for the regeneration of AMP, Pz, and MEA. Figure 2a shows that the effectiveness of CO2 removal efficiency follows the order of HEP-one-phase, Pz, and AMP/MEA-chem-reg at L/G ranging between 125 and 275 gal/1000 ft3. For comparison, an aqueous solution of 2.5 M K2CO3 (loading 0.4, without amines) was also tested. The results indicate that aqueous K2CO3 solutions without a promoter was the worst and that none of chemically regenerated amines with single aqueous phase condition exhibited a CO2 absorption efficiency even close to that of MEA-therm-reg.22 However, chemically regenerated HEP with the phase separation techniques exhibited CO2 removal efficiencies comparable to those of thermally regenerated 30% MEA with L/G ranging between 125 and 250 gal/1000 ft3 (Figure 2a). In this new approach, an aqueous mixture of 2.5 M HEP and 3.5 M K2CO3 was added in the recirculation tank. The phase separation occurs soon after mixing to form two immiscible aqueous phases. The upper aqueous phase was used for CO2 absorption in the packed absorber. The CO2-rich upper phase solution then transferred the absorbed CO2 to the CO32− in the lower phase in the recirculation tank while the two phases were well mixed, resulting in the formation of KHCO3 precipitate when reaching its solubility product. The KHCO3 solid was separated, dried, and weighed. Equivalent 8827

DOI: 10.1021/acs.est.7b00006 Environ. Sci. Technol. 2017, 51, 8824−8831

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Figure 4. Species distributions as a function of CO2 loading in MEA-H2O-CO2 (Reprinted with permission from the work of Böttinger et al.23 Copyright 2008 Elsevier.) and HEP-H2O-CO2.

CO2 in a rapid manner, produce a sufficient amount of HCO3− after CO2 absorption, possess an appropriate polarity to facilitate phase separation, and not produce amine precipitation. For example, MEA produces a negligible amount of HCO3− (Figure 4a) between 0.15 and 0.4 CO2 loading, which is the normal operating range of MEA. On the contrary, HEP produces a significant amount of HCO3− according to a species distribution study (Figure 4b). As a result, in the presence of K + , the absorbed CO 2 can continue to form KHCO 3 precipitates with HEP but not MEA. In the case of piperazine, carbamate potassium salts form precipitate due to its smaller solubility compared to KHCO3. The problems with 2-amino-2methyl-1-propanol are the formation of precipitates and inferior CO2 absorption kinetics compared to piperazine and HEP. The kinetics and mechanisms of CO2 absorption and transformation were investigated by analyzing samples taken periodically with 1 H NMR during the course of CO 2 absorption. Figure 5 shows that with a newly prepared HEP solution (i.e., without K2CO3), HEP carbamate (HEPCO2−)

increased with increasing CO2 absorption, presumably through the formation of a zwitterion intermediate (HEPH+CO2−) similar to the MEA mechanism (reactions 1 and 2). HEPH + CO2 = HEPH+CO2−

(1)

HEPH+CO2− + HEPH = HEPCO2− + HEPH 2+

(2)

−

HCO3−

In addition to HEPCO2 , was also formed during CO2 absorption, which was attributed to concurrent reactions involving base catalyzed hydrolysis of zwitterion intermediate (reaction 3). However, the contribution from acid catalyzed hydrolysis of HEPCO2− (reaction 4) cannot be ruled out, although the acid (H3O+) concentration was very small (10−12 M) at pH 12. Besides, carbamate decomposition efficiency is expected to increase with absorption time, should acid catalyzed hydrolysis of HEPCO2− dominate. HEPH+CO2− + H 2O = HEPH 2+ + HCO3−

(3)

HEPCO2− + H3O+ = HEPH 2+ + HCO3−

(4)

Subsequently, rich HEP was mixed with K2CO3 aqueous solutions for solvent regeneration by chemical methods. However, HEPCO2− concentration increased to a new level in lean HEP (Figure 5) in spite of its subsequent high CO2 absorption efficiency. Apparently, the removal of CO2 from HEPCO2− did not occur like what would be the case in steam stripping. On the contrary, the transformation of CO2 from K2CO3 solution to HEP took place to form additional HEPCO2−. The reactions were attributed to a consecutive reaction mechanism by the neutralization of protonated HEP (HEPH2+) (reactions 2, 3, and 5) with CO32− to regenerate HEP, and followed by the extraction of CO2 from HCO3− by HEP to form additional HEPCO2−. HEPH 2+ + CO32 − = HEPH + HCO3−

(5)

HEPH + HCO3− = HEPCO2− + H 2O

(6)

When chemically regenerated HEP solution was used for CO2 absorption, HEPCO2− concentration exhibited an initial slow increase and then decrease with prolong CO2 absorption

Figure 5. Comparison of HEP carbamate concentration changes between new and regenerated HEP during the course of CO2 absorption. 8828

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Environmental Science & Technology (Figure 5). The initial increase of HEPCO2− was attributed to the perturbation of the equilibrium concentrations of species established in the recirculation tank with the intake of additional CO2 by regenerated HEP (reaction 5). As a result, an increase of HEPCO2− concentration was observed until a new equilibrium was established according to equilibriums 1−6. As discussed above, concurrent reactions involving the hydrolysis of HEPH+CO2− (reaction 3) could take place to produce HCO3−, which would result in the formation of KHCO3 precipitate in the presence of K+ (reaction 7), this served as a driving force (reaction 3) to reverse reaction 2, resulting in the decrease of HEPCO2−. HCO3− + K+ = KHCO3↓

(7)

K2CO3 Regeneration Energy Demands. KHCO3 solid produced in the recirculation tank will thermally decompose to regenerate K2CO3. The decomposition has various potential methods, one approach of which is to heat KHCO3 solids directly under high temperatures. This method will produce K2CO3 solid and water vapor and requires a high reaction enthalpy under standard state, ΔH° (eq 8). The energy penalty with this approach is very high even before including sensible and latent heats. Figure 6. Schematic of a stripping system equipped with a calorimeter for the measurement of K2CO3 regeneration energy demands.

2KHCO3(s) → K 2CO3(s) + H 2O(g) + CO2 (g) 3180 kJ/kg CO2

(8)

stream (at the bottom of the stripper). Sakwattanapong et al.16 found that, at a given lean-CO2 loading, a reduction in rich-CO2 loading causes the reboiler heat duty to increase substantially. This effect is mainly attributed to the differences in magnitude of equilibrium CO2 partial pressure at different rich-CO2 loadings. In the present stripping system, the existence of K2CO3 is equivalent to a reduction in rich-CO2 loading, which reduces the equilibrium CO2 partial pressure. In the main stripping reaction zone (above the Raschig ring packing in the stripper, as shown in Figure 6), if the contamination of K2CO3 in KHCO3 solid is negligible, the stripping reagents would be KHCO3 solid and secondary water vapor. It means that the maximum rich-CO2 loading (1 mol CO2/mol K2CO3) and the maximum CO2 partial pressure could be achieved (due to the lack of K2CO3), which would lead to a reduced reboiler heat duty and an improved CO2 stripping rate. After the stripping experiments, K2CO3 regeneration energy demand was calculated from the rate of CO2 production, the amount of steam energy supplied, and the heat loss measurement, which was measured using the energy consumption determined with an identical stripping column but without any feed stream. The time dependent CO2 production rates from the decomposition of KHCO3 solid is shown in Figure 7a. The results indicate that K2CO3 regeneration energy demand was 2079 kJ/kg CO2 in average at steady state conditions (Figure 7b). The assumption that 82% sensible heat recovery efficiency, identical to that of the MEA system, was made in the calculation. Considering a net plant heat rate of 9165 kJ/kWh with a steam temperature of 125 °C (in the case of a 550 MW supercritical pulverized coal power plant with CO2 capture24), the reboiler equivalent work of DAS technology would be 226.8 kWh/tonne CO2. Compared with the Fluor Econamine FG Plus (Econamine) process (298.4 kWh/tonne CO2 power loss due to the reboiler heat duty24), the DAS process could possess 24.0% stripping energy saving. The reboiler heat duty consists of reaction enthalpy between alkali and CO2, sensible heat for

Even if water vapor is condensed to liquid water and all the condensation energy is recovered, the reaction enthalpy is still very high (eq 9). 2KHCO3(s) → K 2CO3(s) + H 2O(l) + CO2 (g) 2180 kJ/kg CO2

(9)

The approach we have been investigating involved the reaction of KHCO3 solid in the regenerator with secondary steam, which was produced by boiling aqueous K2CO3 solutions in the reboiler compartment with low pressure primary steam. K2CO3 solution in the reboiler can be sourced from the recirculation tank (Figure 6). The enriched K2CO3 solution is then recycled back to the recirculation tank. A water stream was injected from the top of the stripper to make up the water loss in the absorber and other parts of the system. Raschig ring packing was used in the stripper to increase the contact time and improve contact distribution between potassium bicarbonate and the secondary steam. In this approach, K2CO3 and water produced were in liquid state, and the reaction enthalpy is reduced to 1479 kJ/kg CO2 (eq 10). 2KHCO3(s) → K 2CO3(aq) + H 2O(l) + CO2 (g) 1479 kJ/kg CO2

(10)

The heat of formation of chemicals at standard state was used to calculate the enthalpies of reactions mentioned above. Nevertheless, the scale-up demonstration and modeling should better determine the lowest heat of steam that can be used to minimize the cost of the energy for the disassociation reaction. Using the stripping system described in Figure 6, stripping of KHCO3 solid was conducted. The main characteristic of the stripping process was the separation of KHCO3 solid feed stream (at the top of the stripper) and K2CO3 solvent feed 8829

DOI: 10.1021/acs.est.7b00006 Environ. Sci. Technol. 2017, 51, 8824−8831

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Figure 7. Time dependent CO2 production rate (a) and K2CO3 regeneration energy demand (b) from the decomposition of KHCO3 solid.

nonideal solutions, such as that in this case with the presence of mixed ions at high concentrations, the ionic strength effect must be considered and the activity rather than concentration should be used to predict species behavior according to Debye−Huckel theory and Pitzer equation,25 but these are not in the scope of this study. For those power plants already equipped with FGD, the residual SO2 can be removed by polishing with a prescrubber ahead of the CO2 capture absorber. Future work needed in the development of DAS includes focus on the improvement optimization of operation conditions to improve the absorption capacity and to avoid the formation of KHCO3 solid in the absorber. The production of KHCO3 precipitation in the absorber could occur in the DAS system, even with reduced soluble KHCO3 concentration in the absorption liquors. Scale-up demonstration needs to determine the operating conditions by controlling CO2 loading to prevent the precipitation from taking place in each stage of a vertical multistage absorption column. The flue gas flows upward through all the stages from bottom to top in a sequential manner, and the lean amine solution only flows from the top to the bottom of each stage to shorten the contact time and avoid the formation of solid. The transport of KHCO3 solid from the recirculation tank to high pressure stripper can be demonstrated using an antechamber setup with the aid of pressurized steam. Here, an antechamber with two gates will be used between the recirculation tank and high-pressure stripper. When the pressure in the upper chamber of the antechamber is reduced to that of the recirculation tank, the upper gate is open, and solid KHCO3 is transferred to the top chamber in a batch fashion. Then both gates are closed, and the pressurized steam is introduced to the top chamber until its pressure is equal to that of the stripper. Subsequently, the bottom gate is open to allow the transfer of solid KHCO3 to the stripper. Additional work is necessary to address the challenges of this newly developed CO2 capture technology. In summary, the advanced dual alkali solvent CO2 capture system with the disruptive solvent regeneration method is described. The DAS system employs an organic alkali (1-(2hydroxyethyl) piperazine aqueous solution) in CO2 absorption and an inorganic alkali (K2CO3 aqueous solution) in CO2 desorption steps. Unlike conventional amine solvent systems using thermal methods involving steam for CO2 desorption

heating the CO2-loaded solution to the temperature of the reboiler, and latent heat of evaporation to generate the stripping vapor. Compared with traditional amine solvent processes, in the DAS technology, the reaction enthalpy of the stripping process lies close to 1479 kJ/kg CO2, which is lower than that of MEA (1636 kJ/kg CO2). The exclusion of majority of water by KHCO3 precipitation before stripping is responsible for a significant sensible heat reduction. The dissolution of flue gas SO2 in aqueous solutions produces sulfite (SO32− or HSO3−) and sulfate (SO42−) ions, which form heat stable salts with amine in the conventional amine solvent systems, rendering the amine unable to bind CO2 and resulting in the reagent loss. In the DAS system, sulfite and sulfate ions will be removed from the solutions by precipitation as potassium salts in the recirculation tank due to their low solubility (Figure 8). This application is primarily for new and old coal-fired plants without an existing flue gas desulfurization (FGD) scrubber. Figure 3b reveals that the concentration of K+ in the recirculation tank can reach as high as 13 M. With the solubility of K2SO4 of 1 M (Figure 8), the sulfate ion concentration in the liquor will be less than 0.006 M at standard state if at an ideal solution condition. However, in

Figure 8. Relative solubility of K2CO3, KHCO3, K2SO4, and CaSO4. 8830

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Article

Environmental Science & Technology

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while regeneration of amine, the DAS system employs a chemical method for the release of the absorbed CO2, resulting in absorbent regeneration and the transfer of CO2 to the inorganic alkali. As a result, a new class of solvent system is created, with which novel process features can be incorporated to acquire benefits including a significant reduction of the amount of processing water, reagent loss, and waste products. Preliminary experimental results and estimates of the DAS technology have exhibited significantly reduced energy penalty compared with that of the well-developed Econamine system. The concept of the DAS technology, which is the use of two substantially different solvents in one system, has brought a new perspective to address the challenges of solvent-based CO2 capture technologies, and made it possible to largely reduce the CO2 capture cost.

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AUTHOR INFORMATION

Corresponding Authors

*Tel.: +1 510 6852127. E-mail address: [email protected] (S.G.C.). *Tel.: +886 62763608. E-mail address: [email protected]. tw (H.P.W.). ORCID

Yang Li: 0000-0002-7400-7403 Present Address †

H.P.W., C.-Y.L., T.-L.H., S.-H.L.: On leave from the Department of Environmental Engineering, National ChengKung University, Tainan 70101, Taiwan. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This work was supported by the U.S. Department of Energy (DOE), under Contract No. DE-AC02-05CH11231 through the National Energy Technology Laboratory (NETL) under Field Work Proposal FWP ED33EE. We appreciate Elaine Everett, NETL project manager, for her research guidance throughout the entire development of this technology. The National Science Council (NSC) of Taiwan also provided financial support for this work.

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REFERENCES

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DOI: 10.1021/acs.est.7b00006 Environ. Sci. Technol. 2017, 51, 8824−8831