The study of using novel scrubbing agent Mg(OH)2 solution to capture CO2 from flue
gases generated by coal-fired power plant
L. Chenga, X. Zhoua, T. Lia, T.C. Keenera,*, J.Y. Leeb
a
Environment Engineering Program, School of Energy, Environmental, Biological, and Medical
Engineering, The University of Cincinnati, Cincinnati, OH 45221, USA
b
Chemical Engineering Program, School of Energy, Environmental, Biological, and Medical
Engineering, The University of Cincinnati, Cincinnati, OH 45221, USA
*
Corresponding author. Tel.: +1 513-556-3676; Fax: +1 513-556-4162. E-mail address:
[email protected] (Tim. C. Keener).
1. Introduction
Coal-fired power plants are the largest sources for the carbon dioxide (CO2) emissions, which
classified as one of the greenhouse gases leading to global warming and climate change.
According to the reports of Environmental Protection Agency (EPA) and Intergovernmental
Panel on Climate Change (IPCC), from 1880 to 2010, the average global temperature have
increased about 0.8 ℃, and it is forecasted that the average global temperature could have
increased by 2 ℃ in the coming century. In U.S., the power generation sector responsible for
almost 40% of total CO2 release and it is projected an increase of 10% for fossil fuels usage,
leading to a CO2 emission increase of 9% over the next 20 years. Therefore, CO2 capture and
control from coal-fired power plants become an important environmental research area. Oxy-fuel
combustion capture, post-combustion capture and pre-combustion capture are three major CO2
capture methods (Damen, Troost et al. 2006; Bouillon, Hennes et al. 2009). Oxy-fuel combustion
and pre-combustion capture require nearly pure O2 in the boiler, resulting a high concentration of
CO2 which benefits the CO2 capture process. However, both concepts have only been applied in
few power plants due to the modification of current boiler configuration and high cost of
operation and maintenance. Existing coal-fired power plants typically generate a flue gas which
consists of 10% to 14% of CO2 gas at atmospheric pressure. Therefore, the challenge for postcombustion capture is how reliable and effectively capture CO2 at such low driving force
conditions. Chemical absorption in the proven gas-liquid contacting device appears to be a
solution. Our focus here is to test and evaluate the technical feasibility of using magnesium
hydroxide solution, which can be reclaimed from FGD process, to scrub CO2 from the flue gases.
2. Description of magnesium solution based flue gas decarbonization system
2.1 process overview
The proposed magnesium based flue gas decarbonation system mainly consists of a scrubber and
a stripper. The bubble column reactor is selected as mass transfer device for this study due to the
simple internal design, good mass transfer performance and great ability of handing solid
containing solution or slurry for the magnesium slurry test. The lean magnesium hydroxide
slurry with high pH is injected at the top of the absorber to meet the flue gas bubbles which are
introduced from the bottom of the absorber, as a result, the CO2 in the gas phase has been
captured by the scrubbing agent and the rich slurry will be send into the stripper for CO2
recovery and solvent regeneration. Regeneration is accomplished by applying the means of
thermal-pressure swing in the stripper, as a result, the concentrated CO2 in the gas stream is
collected and regenerated magnesium solution is ready for returning back to the absorber. The
detailed process flow chart is showed in Figure 1.
CO2 control
system
Commercial
Mg(OH)2
Magnesium
enhanced lime
SO2 ,CO2
Flue gas
FGD for
SOx control
MgSO3
CO2 compression
for sequestration
CO2 lean Mg solution
CO2
CO2
Absorber
Flue gas
CO2
Stripper
Flue
gas to
stack
Mg(HSO3)2
CO2 rich Mg solution
Dewatering
&Oxidizer
MgSO4
Ca(OH)2
Crystallzer
CaSO4
CaSO4 for
residual sulfur
removal via
ThioClear
process
Solid waste (i.e.,
magnesium
compounds formed
through reactions with
acid gases)
Mg(OH)2
Separation
Reclaimed
Mg(OH)2
Landfill
Figure 1. Block Flow Diagram (BFD) of Mg(OH)2-based CO2 separation process.
2.2 summary of the technical challenges
Because our scrubbing agent is slurry, therefore, the first challenge is to select and design a good
mass transfer enhanced absorber which can offer 90% plus CO2 removal efficiency without
plugging issues.
pH and time can highly affect the dissolution of the Mg(OH)2 and the precipitation of the
MgCO3 as well. Longer solution residence time will help the fresh Mg(OH)2 particles to dissolve,
but also lead to a undesired precipitation of MgCO3 solid. Low pH range will help to dissolve the
Mg(OH)2 and prevent the formation of carbonate ion, but this will also decrease the CO2
absorption rate. Therefore, the second challenge is to operate at a pH high enough and residence
time long enough to allow for effective and sufficient CO2 absorption, but also pH low enough
and residence time short enough to minimize the formation of MgCO3 solid.
Regardless of the feedstock cost, safe operational and handling of using Mg(OH)2 as scrubbing
agent. Another major economical and technical consideration is to test whether the reclaimed
Mg(OH)2 itself from FGD by-products can capture more than 90% of CO2 in the flue gas at a
energy less intensive condition than MEA process. As a typically 500MW plant, 3000ppm SO2
and 10-12% CO2 in the flue gases which are 18000 kg/hr and 500000 kg/hr go into the FGD
scrubber, requiring 280000 moles/hr calcium to achieve 99% SO2 removal, hence CO2 removal
capacity of magnesium must be MMg:MCO2=1:10 (dolomitic limestone), 1:20 (magnesian
limestone), 1:82 (high calcium limestone) in order to achieve 90% CO2 removal. Therefore, the
last but not the least challenge is to maximize the utilization of Mg in order to make the process
self-sustained by applying the reasonable desorption conditions.
3. Experimental
3.1 experimental setup
The absorption experimental setup consists of seven major sections: (1) simulated flue gas
generation; (2) flow control; (3) bubble column absorber; (4) stripper; (5) gas sampling and
analysis; (6) pH, temperature measurement; (7) data acquisition. The experimental setup is
shown schematically in Figure 2.
Data acquisition
system
CO2
analyzer
Flue gas
conditioning unit
Stirrer
Qg, T, CO2 conc.
Treated gas
QL, T
pH
Lean slurry tank
pH, T
CO2
N2
Rich slurry
Slipstream to
waste
Magnetic
stirrer
Magnetic
stirrer
Absorber
Stripper
Figure 2. Experimental setup.
Liquid pump
A 130 cm tall, diameter of 10 cm column made of plastic glass with a heating jacket and thermo
insulation was used as the main body of the bubble column reactor. 3 sampling ports are
respectively located near the top, middle and bottom of the reactor to obtain complete
temperature and pH profile of the reactor. Fritted glass size C (porosity 25-50 micron, ACE glass
Inc.) was installed at the bottom of the reactor as the gas bubbler. A 5 L glass column with a
heating jacket and thermo insulation was used as the stripper. Both absorber and stripper were sat
on the magnetic stirrer plate which allows magnetic mixing to be applied to the fluid inside the
columns.
The simulated flue gas is produced by mixing pure CO2 gas with pure N2 gas (high purity >99%,
Wright Brothers Inc.). Both gas streams are controlled by mass flow controllers (Thermal gas
mass flow controller, Cole Parmer Inc.) in order to have desirable CO2 concentration. The mixed
gas stream is heated and maintained at 52 ℃ which is close to the typical temperature at FGD
outlet.
The gas sampling system consists of an in-line flue gas conditioning unit (IMR 400 flue-gas
conditioning system, Environmental Equipment Inc.) where the particles in the sample are
removed by the filter, and water vapor is removed by passing through the nafion dryer. The
pretreated gas sample is then analyzed for CO2 concentration by an infrared CO2 gas analyzer
(Model ZRH infrared analyzer, California Analytical Instruments Inc.) The CO2 gas analyzer is
periodically calibrated by using pure N2 (high purity >99%, Wright Brothers Inc), 5% CO2 and
16% CO2 (certified grade, CO2 in N2, Purity Plus Gas Inc) standard gases.
The pH of the fluid is measured by the pH meter (Model 25, Fisher Scientific Inc.) Temperatures
are measured at gas inlet stream and 3 locations along the bubble column for monitoring and
maintaining the desirable test conditions. A computer with data acquisition system (Model USB1208FS, NI Instruments Inc.) is used to record the CO2 concentrations, temperatures and pH
values throughout the experiments.
Magnesium hydroxide solution is prepared by dissolving magnesium hydroxide powder
(industry grade, 81% purity, Garrison Minerals LLC.) into deionized water.
Experiment conditions are summarized in Table 1.
Table 1. Experiment conditions.
Parameter
Value
Inlet gas temperature
~52 ℃
Absorber temperature
~52 ℃
Stripper temperature
Gas flow rate
Inlet CO2 concentration
Mg(OH)2 concentration
60-85 ℃
0.5 L/min
5-16 % vol.
0.01-0.1 M
Mixing rate
Porosity of gas bubbler
1200 RPM
25-50 micron
4. Results and discussion
Absorption results
90
0.01M
0.025M
0.05M
0.1M
CO2 removal efficiency, %
80
70
60
50
40
30
20
10
0
0
10
20
30
40
50
Time, min
Figure 3. CO2 removal under a steady-state condition in bubble column configuration. Operating
conditions: distributor filter C (ACE glass, 25~50µm); gas flow rate = 1.8 acfm; residence time =
9 s, L/G ratio = 110 gal/1000acf; inlet CO2 concentration = ~8.6%(v).
10.5
10
0.01M
9.5
0.025M
0.05M
pH
9
0.1M
8.5
8
7.5
7
6.5
6
0
10
20
Time, min
30
40
50
Figure 4. pH profile of CO2 removal under a steady-state condition in bubble column
configuration. Operating conditions: distributor filter C (ACE glass, 25~50µm); gas flow rate =
1.8 acfm; residence time = 9 s, L/G ratio = 110 gal/1000acf; inlet CO2 concentration = ~8.6%(v).
Figure 3 and 4 demonstrate the batch experiment results of CO2 capture rate and pH profile of
the absorption, respectively. It is found that 1). At the very beginning of the absorption process,
we observed a quick decrease in the pH and an initial high rate of absorption which is
independent of Mg(OH)2 concentrations. This is due to the consumption of the readily available
dissolved alkalinity. 0.01 to 0.1 mol/L Mg(OH)2 solutions are all saturated, resulting the same
amount of OH- ions available in the solution. The extent of dropping depends on how quick the
dissolution rate can catch up the CO2 uptake rate. 2). Afterwards, the efficiency goes back up
again and reach a relatively constant rate period where the absorption of CO2 is matched by the
dissolution of magnesium ions into the liquid and the pH reaches a relatively constant level. The
rate during this period is dependent on the availability of surface area for dissolution and the pH
of the solution as well, and is therefore dependent on the concentration of Mg(OH)2. It is reveals
that 0.1 and 0.05 mol/L solutions have much faster dissolution rates than 0.025 and 0.01 mol/L
solutions. However, 0.1 mol/L solution only has slightly faster dissolution rate than 0.05 mol/L
solution. 3). A decreasing rate period where the magnesium carbonate formed is being deposited
onto the surfaces of the existing magnesium hydroxide solids, thereby, decreasing the dissolution
rate. In the meantime, the pH values continuous decrease due to reduction of available Mg(OH)2,
and eventually reach the equilibrium points. The equilibrium pH values are 7.2, 7.4, 7.7, and 8.0
for 0.01, 0.025, 0.05 and 0.1 mol/L solutions, respectively.
Figure 5. Effects of L/G ratios on CO2 removal. Operating conditions: distributor filter C (ACE
glass, 25~50µm); gas flow rate = 1.9 acfm; residence time = 9 s; inlet CO2 concentration =
~7.9%(v).
Figure 5 shows the CO2 removal performance at different Liquid-to-Gas ratio. It suggested that
110 gal/1000 acf L/G warrants a high level of CO2 removal. The CO2 removal efficiency
increased from 90% to 98% when the L/G ratio increased from 100 to 450 gal/1000 acf. In
comparison, the wet FGD scrubber typically use 60 to 180 gal/1000acf L/G ratio to achieve >90%
SO2 removal.
Figure 6. Effects of inlet CO2 gas concentrations on CO2 removal. Operating conditions:
distributor filter C; gas flow rate = 1.9 acfm; gas residence time = 8.5 s; L/G ratio = 110
gal/1000acf.
CO2 removal efficiency, %
Figure 6 shows the effects of CO2 partial pressure in the flue gas on the CO2 removal
performance. It is revealed that the Mg(OH)2 solution has almost the same CO2 removal
performance when CO2 partial pressure is less than 20 kPa.
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
0
2
4
6
8
10
Time, seconds
Figure 7. Effects of gas residence time on CO2 removal. Operating conditions: 0.1mol/L
Mg(OH)2; distributor filter C; gas flow rate = 1.9 acfm; L/G ratio = 106 gal/1000acf; inlet CO2
concentration = ~7.9%(v).
The removal efficiency heavily depends on gas residence time, and >8.5 seconds residence time
warrants >90% CO2 removal.
Continuous test results
Figure 8 shows the CO2 removal performance and pH under continuous operation mode. It is
revealed that the CO2 removal can be kept ~90% with the regeneration and a small stream of
make-up fresh Mg(OH)2 slurry. The pH in the absorber can be kept at ~8.6 which the
regenerable bicarbonate ion is dominated. The makeup fresh Mg(OH)2 slurry flow rate has been
determined to be 0.008 L/second to make the system maintain 90% of CO2 capture under 75 ℃
11
100
90
80
70
60
50
40
30
20
10
0
10
9
8
PH
CO2 removal %
desorption temperature.
7
CO2 removal %
pH
6
5
0
20
40
60
80
100
120
140
160
Time,min
Figure 8. CO2 removal and pH under continuous operation mode.
Acknowledgements
The authors would like to acknowledge the financial support for this study under project number:
DE-FE0001834 from the U.S. Department of Energy.
References
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Damen, K., M. v. Troost, et al. (2006). "A comparison of electricity and hydrogen production systems
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technologies." Prog. Energy Combust. Sci. 32(2): 215-246.