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and processes for energy: communicating current research and technological developments (A. Méndez-Vilas, Ed.)
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Carbon Dioxide Post-Combustion Capture: Solvent Technologies
Overview, Status and Future Directions
Mohammad R. M. Abu-Zahra1,* , Zeina Abbas1, Prachi Singh2, Paul Feron3
1
Masdar Institute of Science and Technology, P.O. Box 54224, Abu Dhabi, United Arab Emirates
IEA Greenhouse Gas R&D Programme, Orchard Business Centre, Stoke Orchard, Cheltenham GL52 7RZ, UK
3
CSIRO Energy Technology, P. O. Box 330, Newcastle, NSW 2300, Australia
*Corresponding author: [email protected], +9712 810 9181
2
Keywords: CO2 post-combustion capture; chemical absorption; amines; pilot plants
1. Introduction
One of the most promising approaches to tackle the high emission rate of carbon dioxide is the use of Carbon Capture
and Storage (CCS) technology. This technology aims at capturing carbon dioxide from power stations and other
industrial facilities, compressing, and then transporting it to underground storage locations.
Three technological routes for carbon capture from power plants exist: pre-combustion, post-combustion and oxycombustion. Pre-combustion is the removal of the carbon element from fuel gas prior to combustion [1]. This process
takes place in Integrated Gasification Combined Cycle (IGCC) plants and operates at high pressures for high
concentrations of CO2. IGCC plants still face several obstacles to commercialization. For instance, only two IGCC
demonstration plants are in operation in the power sector in the United States. The second option is oxy-fuel
combustion, which involves the use of high purity oxygen (instead of air) for fuel combustion and produces a CO2/H2O
stream from which water is easily condensed [2]. However, the air (or nitrogen-oxygen) separation step is considered a
bottle-neck for this process due to its energy intensiveness and high capital and operational costs. Finally, postcombustion capture involves a highly energy intensive nitrogen-carbon dioxide separation step [3]. As an end-of-pipe
technology, this process is easier to implement compared to the other capture routes. In this chapter, the focus will be
placed on post-combustion capture technology due to its high maturity, ability to be retrofitted to existing power plants
and operational flexibility in switching between capture and no-capture modes [4].
2. Post-Combustion Capture
Post-combustion capture (PCC) is the separation of low concentration CO2 (typically 3-15 %) from flue gas and the
production of a relatively pure CO2 stream, which is then compressed to a pressure of approximately 110 bar and
transported via pipelines to be stored in geological formations or used for other applications, such as Enhanced Oil
Recovery (EOR). Although PCC incurs high costs making commercialization difficult, it is viewed as the best available
technology for CO2 capture, specifically for coal-fired power plants, mainly due to its maturity level, high CO2
selectivity and retrofit-ability to the power plants [5].
Several separation technologies can be employed within the PCC category, including: adsorption, cryogenics,
membranes and absorption [6]. Comparative assessment studies [[8]-[10]] have shown that the absorption process,
specifically based on chemical solvents, is currently the preferred option for post-combustion CO2 capture. Chemical
absorption offers high capture efficiency, high selectivity at low partial pressures, and the lowest energy use and costs
when compared with the other separation techniques. For this reason, details on the chemical absorption for postcombustion capture technology only are shown in this chapter.
Due to the acidity of CO2 and the basicity of chemical solvents, a reversible acid–base neutralization reaction takes
place upon their interaction in a packed absorber column at a temperature ranging between 40 and 65°C, forming a CO2
rich solvent while the rest of the flue gas is vented. The rich solvent solution is then pumped to the stripper to
regenerate the solvent and separate the CO2 by increasing the temperature to approximately 90-120 °C using low
pressure reboiler steam. Water vapor in the CO2 product is then condensed, resulting in a highly concentrated (>99%)
CO2 product stream. This stream is liquefied or compressed for transportation to be utilized commercially or stored
underground. The regenerated solvent is cooled to absorption temperature (at 40–65 °C) and is recycled back into the
absorption column [11].
Chemical absorption based PCC, using monoethanolamine (MEA) solvent, was first commercially employed in the
1970s for use in EOR operations and commercial applications, such as carbonation of brine and production of dry ice,
urea and beverages [[12]-[13]]. However, the largest capacity of CO2 recovered in these applications was approximately
ten times less than that of a typical 500 MW coal-fired power plant [14].
Although development of solvents was made more than 80 years ago for CO2 separation in natural gas processing
applications, several studies have shown that amine-based absorption systems are the most suitable option for CO2
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separation from flue gas emitted from power plants [15]. However, the commercialization of this technology faces
major obstacles: intensive solvent regeneration energy, huge absorption towers and high solvent losses and degradation.
These obstacles call for the need of developing more economical and efficient solvent systems. Typically, a good
solvent candidate should have high CO2 loading with fast kinetics to reduce plant sizes. It should also require low heat
of regeneration for the process to be energy efficient. Moreover, it should have high selectivity and high solubility for
CO2, so as to avoid reactions with the other impurities in the flue gas stream. Furthermore, it must have low byproduct
formation and low decomposition rates to maintain solvent performance and to limit the amount of solvent makeup and
waste materials produced. Significant research efforts are being directed at developing improved solvents to be able to
commercialize chemical absorption technology for carbon capture from flue gas [[16]-[19]].
3. Amine Solvents Used for Chemical Absorption
3.1 Types, structures and reaction mechanisms
Common amine solvents used in industry for CO2 separation include simple alkanolamines and sterically hindered
amines. Simple alkanolamines can be divided into three groups: primary, secondary and tertiary amines. Each of these
groups has a different reaction rate with respect to CO2 absorption. In addition, they vary in their equilibrium absorption
characteristics and have different sensitivities with respect to solvent stability and corrosion factors [20]. In general,
primary and secondary amines react rapidly with CO2 to form carbamates through several principal reactions [21]:
2H2O ↔ H3O+ + OHCO2 + 2H2O ↔ HCO3- + H3O+
RNH2 + H3O+ ↔ RNH3+
RNH2 + CO2 ↔ RNHCOO- + H3O+
However, due to the additional heat of absorption associated with the formation of carbamate ions, the regeneration
energy requirement for primary and secondary amines is higher compared to tertiary or other amines which do not form
carbamates [20]. Primary and secondary amines also have the disadvantage of requiring two moles of amine to react
with one mole of CO2; thus, their loadings are limited to 0.5 mol of CO2/mol of amine [22]. The most commonly used
primary amine in chemical absorption is MEA and that of secondary amines is diethanolamine (DEA).
On the other hand, tertiary amines lack the N−H bond required to form the carbamate ion and therefore do not react
directly with CO2. However, in aqueous solutions, tertiary amines promote the hydrolysis of CO2 to form bicarbonate
and a protonated amine, but with much slower kinetics than those of primary and secondary amines [23]. Another
advantage of using tertiary amines is that one mole of amine is needed to react with one mole of CO2, which indicates
higher equilibrium CO2 loading than primary and secondary amines [22]. The most frequently used tertiary amine in
industry is methyldiethanolamine (MDEA).
Cyclic diamines have been suggested as a possible improvement to MEA for capturing CO2, such as concentrated
piperazine (PZ). This amine has faster kinetics, higher capacity and higher resistance to oxidative and thermal
degradation than MEA [[24]-[25]]. Its loading is approximately 1 mol CO2/mol PZ [26]. The chemical reactions that
take place between PZ and CO2 are the following [27]:
2PZ + CO2 → PZH+ + PZCOO2PZCOO- + CO2 → PZ(COO-)2 + H+PZCOOPZCOO- + CO2 + H2O → HCO3- + H+PZCOOSterically hindered amines are primary or secondary amines with bulky alkyl groups attached to the amino group that
provide steric hindrance to the amine group from the reacting CO2 [28]. Steric hindrance leads to lowering the initial
reaction rate and producing less stable carbamates, which then undergo hydrolysis and form bicarbonates while
releasing the free amine. This free amine then reacts with CO2 leading to an overall higher loading [[29]-[30]]. These
amines are considered as a breakthrough in the solvent development field due to the combined advantages of primary,
secondary and tertiary amines that they offer, including: high CO2 absorption capacity and low heat regeneration
requirements [[22], [31]]. Moreover, when compared to other amine solvents, they have lower degradation rate, lower
solvent circulation rate, low corrosivity, less solvent losses and thus, lower costs [32]. A disadvantage of sterically
hindered amines is the lower reaction kinetics as compared to primary and secondary amines. A common example of
sterically hindered amines is 2-amino-2-methyl-1-propanol (AMP).
3.2 Solvents physical and thermodynamic properties
The most extensively used amine in industry for CO2 removal is MEA [15]. It is considered as the least expensive of the
other commercial alkanolamines, and has several advantages over them, such as high reactivity, low solvent cost, low
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molecular weight, reasonable thermal stability and thermal degradation rate [5]. In a commercial process, up to 30 wt%
MEA has been employed successfully to remove 80% - 95% of the carbon dioxide from the feed gas [3]. Although the
MEA-based chemical absorption process is considered to be a well-established technology for CO2 capture, the solvent
has its own drawbacks [34]. MEA has a high enthalpy of reaction with CO2. Substantial energy is required to break the
bonds, leading to high energy requirement in the stripper, making the process uneconomical [5]. Moreover, MEA has
relatively low CO2 loading capacity which results in large MEA recirculation rates and ultimately, large equipment
sizes and high capital cost. Other problems associated with MEA are solvent losses and degradation [[35], [36]]. MEA
has a relatively high vapor pressure, causing high solvent carryover during the absorption and regeneration step [23].
MEA degradation is usually caused by the reaction between MEA and flue gas constituents, such as oxygen, sulfur
oxides and nitrogen oxides, or by the effect of the thermal degradation, resulting in the formation of heat stable salts.
Moreover lighter degradation components are formed such as N-nitrosamines which are considered to be harmful for
human health and the environment [123]. These MEA losses reduce the CO2 absorption capacity and induce higher
solvent makeup rates. Furthermore, MEA is highly corrosive in nature and it also might react with materials used in
reactor vessels, piping, and other process compartments. This means that high concentrations of MEA cannot be used
unless a corrosion inhibitor is added [37]. Appropriate materials of construction and mild operating conditions are also
required to reduce corrosive effects of MEA [38]. In spite of all the problems associated with MEA, it is considered to
be the baseline solvent for CO2 capture from flue gases. Process improvements are currently being made for the MEA
system to be a competitive option for CO2 capture.
The second most widely used alkanolamine in the gas processing industry is DEA. It has a lower regeneration energy
requirement than MEA, but a much lower absorption rate and capacity [39]. Similar to MEA, DEA is also prone to
losses and degradation, but to a relatively lower extent.
Table 1 Physical and thermodynamic properties of amine solvents.
Solvent
Vapor pressure
(kPa)
Absolute viscosity
(cP)
Rich Loading
(mol CO2/mol amine)
Reaction enthalpy
(kJ/mol CO2)
70.5 (30 wt% MEA) [46]
82 (7 m MEA with PCO2=
1.5 kPa) [47]
84 [48]
83 (5M MEA at 25°C) [50]
66.7 (30 wt% MEA at
40°C) [51]
66.5 [48]
MEA
0.0085 (at 20°C) [43]
24.1 (at 20°C)
[44]
0.50 (PCO2= 5 kPa) [45]
0.48 (PCO2= 1.5 kPa) [45]
0.56 (30 wt% at 40°C) [46]
0.45-0.55 [47]
0.30-0.35 (for 15-20 wt% MEA) [48]
0.46 (30 wt% MEA) [49]
DEA
0.077 (at 25°C) [53]
380 (at 30°C) [44]
0.35-0.40 (for 25-30 wt% DEA) [48]
MDEA
0.0013 (at 20°C) [43]
101 (at 20°C) [44]
0.45-0.55 (for 35-55 wt% MDEA) [48]
AMP
0.1347 (at 20°C) [43]
2.26 (26.73 wt%
at 30°C) [54]
0.84 (30 wt% AMP) [49]
0.1066 (at 20°C) [43]
11.5 (8 m PZ) and
21.1 (10 m PZ)
[55]
0.41 (8 m PZ) [56]
0.42 (PCO2= 8.4 kPa) [45]
0.40 (PCO2= 5 kPa) [45]
0.31-0.39 [47][48]
PZ
59 [48]
44.6 (20 wt% MDEA at
40°C) [51]
58.2 (20 wt% AMP at
40°C) [51]
70 [[47], [57]]
The tertiary amine MDEA, on the other hand, has found increased usage in carbon capture, due to its relatively low
regeneration energy requirement for CO2 liberation, low tendency to form degradation products, and low corrosion rates
[23]. MDEA is being used for natural gas processing on large industrial scale. Furthermore, it is less basic than MEA
and DEA and can be used in significantly higher concentrations. However, MDEA is well known for its relatively slow
kinetics compared with those of MEA or DEA [24].
As for sterically hindered amines, AMP is the most common for CO2 absorption. AMP is two orders of magnitude
slower in oxidative degradation and more resistant to thermal degradation than MEA [40]. The CO2 loading of AMP
can reach a ratio of one to one. Piperazine, on the other hand, is considered a promising solvent as compared to MDEA
or AMP. This is due to its high acid gas loading capacity (two moles of CO2 per one mole of PZ), high reaction rate
with CO2 (greater than that of MEA, DEA, MDEA and AMP), and high resistance to thermal and oxidative degradation
[41]. The apparent second order rate constant of PZ has been found to be an order of magnitude higher than that of
MEA [42]. The main physical and thermodynamic characteristics of the five common solvents (MEA, DEA, MDEA,
AMP and PZ) are shown in Table 1.
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4. Amine-Based Commercial Processes
In the period between year 1978 and year 2000, at least a dozen commercial CO2 capture plants were commissioned
worldwide, ranging in size from 90 to 1200 ton/day CO2 [58]. In 1978, Kerr-McGee and ABB Lummus installed a
20 wt% MEA system to capture 800 ton/day CO2 from boilers firing a mix of coal and petroleum coke at Kerr-McGee’s
soda ash plant in Trona, California USA, for delivering CO2 for soda ash and liquid CO2 preparations [38]. Typically,
about 75% to 90% of the CO2 is captured using this technology, producing a nearly pure (>99%) CO2 product stream.
Two other commercial plants were operated, with capacities of 200 and 300 tons/day of CO2 from coal boilers in 1991
using this technology [59]. Dow Chemical and Union Carbide developed 30 wt% MEA processes for recovering CO2
from a gas boiler primarily for EOR applications [[60], [61]]. Using this technology, a large CO2 capture plant, which
recovered 1200 ton/day CO2 sourcing from natural gas processing, was built in Lubbuck, Texas USA. It only operated
for two years (1982-84) before being shut down as low crude oil prices rendered EOR uneconomical. Other smaller
scale commercial plants were then built and operated using this technology in China, India and Australia between years
1985 and 1988. This process was then acquired by Fluor Daniel Inc. from Dow Chemical Company in 1989 and
renamed to Econamine FG. This process is capable of capturing 85-95% of CO2 and producing 99.95+% pure CO2
product (dry basis), and has been employed by many plants worldwide recovering up to 320 ton CO2 per day for use in
beverage and urea production predominantly from flue gases from gas firing. Fluor Daniels’ second generation
Econamine FG Plus technology, introduced in 2003, claimed significant reductions in energy consumption (2.95 GJ/ton
CO2), but at the expense of increased complexity and capital cost [[62], [63]].
Since 1990, the Kansai Electric Power Co. (KEPCO) and Mitsubishi Heavy Industries, Ltd. (MHI) have jointly
conducted research and development of a new CO2 capture technology for CO2 recovery from power plant boiler flue
gas and gas turbine exhaust, using patented proprietary sterically hindered amines designated as KS-1, KS-2 and KS-3
[[7], [19], [64]]. They claim that their process is the most energy efficient of the commercial offerings, and experiences
low amine losses and low solvent degradation without the use of inhibitors or additives. In addition, it was claimed to
require 20% less regeneration heat with less corrosion and amine degradation [14]. The first commercial MHI KMCDR (Kansai Mitsubishi Carbon Dioxide Recovery) process plant was commissioned in Malaysia in 1999 with a
capacity of 200 ton CO2 per day, where flue gas containing 8 vol % CO2 is being treated with 90% recovery. Another
nine commercial plants have been commissioned and are operating for gas-fired plants using the KM-CDR technology
during the period of 2005-2012, with capacities ranging from 240 to 450 tons/day of CO2 recovered. Tests are currently
being conducted at the pilot scale on coal-fired flue gas [[65], [66]]. Solvent compositions of KS-1, KS-2, and KS-3
have been described by Mimura et al. [19]. KS-1 is claimed to have 40% less solvent circulation rate, 20% less
regeneration energy, 90% less solvent degradation, 90% less solvent losses and 65% less corrosion than that of MEA
[67]. 1.22 tons of low-pressure steam per ton CO2 recovered was consumed using KS-1 solvent [68]. With further
process improvements, this figure is expected to be lowered to 0.85-1.0 ton of steam per ton of CO2. It is also claimed
that KS-3 is better than KS-1 and KS-2 in terms of energy consumption for solvent regeneration [64].
Another important carbon capture facility is the CO2 Technology Centre Mongstad (TCM), which is a joint venture
between the Norwegian state, Statoil, Shell and South African company Sasol [69]. It is the world’s largest CO2 capture
test facility and was launched in mid-2012. It is also the only centre to test two different types of technology applicable
to emissions from both coal-fired and natural gas power plants. Flue gas from a Residual Catalyst Cracker (RCC) and
Combined Heat and Power Plant (CHP) is being provided to the capture facility. Two technology suppliers were also
selected to initially run the capture process, being Aker Clean Carbon amine technology and Alstom’s chilled ammonia
technology. This facility has a capacity of capturing 100,000 tons of CO2 per year [70].
Cansolv Technologies Inc. CO2 capture process is based on a recently developed amine system using a proprietary
solvent named DC101 [71]. This solvent is based on tertiary amine formulations, likely promoted with piperazine
and/or its derivatives, to yield sufficient absorption rates and can be used for low pressure flue gas streams [72]. With
the use of oxidation inhibitors, this process can be applied to oxidizing environments and where limited concentrations
of oxidized sulfur exist. It is claimed that this process can also simultaneously remove other acidic contaminants and
particulate material, such as SOx, and NOx. In order to optimize the balance between capital cost and operating cost for
a given facility, Cansolv now offers two variants of its second generation CO2 capture solvent, DC-103 and DC-103B.
DC-103 is kinetically slower, thus requires a larger absorber, but less regeneration heat. DC-103 is claimed to reduce
operating cost, while DC-103B reduces capital cost. For these solvents absorption rates comparable to MEA are
claimed, with a 40% reduction in regeneration energy. In addition to very low degradation rates compared to MEA,
degradation products retain scrubbing capacity. Two demonstration plants of the Cansolv CO2 capture system have
already been built; one in Montreal, Canada, for capture of CO2 from flue gas of a natural gas fired boiler, and one in
Virginia, for CO2 capture from flue gas of a coal fired boiler [66]. Cansolv is also partnering with Saskpower, Fluor,
Hitachi, Babcock&Wilcox Canada, Neill and Gunter Ltd. and Air Liquide to commission a demonstration carbon
capture plant at Boundary Dam power station in Saskatchewan, Canada with a capacity of one million tons CO2 per
year using amine solvent [73]. This plant is planned to start operation in 2014.
HTC Purenergy have also developed a series of proprietary designer solvents designated as PSR solvents, through
research performed at the International Test Centre (ITC) at the University of Regina, Saskatchewan, Canada [74].
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These solvents are claimed to have higher CO2 working capacities than MEA, ranging from 20-80%, and can be used at
higher amine concentration. The key features claimed for the PSR solvents are lower regeneration temperature, lower
solvent circulation rate, lower solvent degradation rate and lower corrosion rate. Relative energy requirements are
reportedly 55-85% of conventional amines. The ability to regenerate PSR solvents at temperatures 5-10°C (9-18°F)
lower than that of MEA not only reduces amine degradation, but potentially facilitates process integration by permitting
the use of lower pressure steam [74]. The PSR process is being tested on a 4 ton/day CO2 capture facility at the Sask
Power 875 MW lignite fired Boundary Dam Power Station under the auspices of the ITC, a consortium of 13 industrial
and governmental organizations including two Canadian Universities.
Although post combustion carbon capture has been demonstrated commercially in large scale, the CO2 containing
feed stream to the capture process is mainly emitted from industrial processes. There is a need for commercial scale
plants that treat flue gas from power plants. However, achieving this goal faces obstacles such as high cost and high
solvent losses. For this reason, research efforts have been going on in order to develop suitable amine solvents (both
single solvent systems and blended amines) which can make the commercialization of post combustion carbon capture
feasible.
5. Ongoing Research Efforts
5.1 Single Solvent Systems
Dugas and Rochelle [75] studied the CO2 absorption/desorption of MEA and PZ in a wetted wall column, and the
results showed that 8 m PZ had a 75% greater CO2 capacity than 7 m MEA. Also, using PZ showed double to triple the
absorption rate of that of MEA. In a similar work, Freeman and Rochelle [55] found the CO2 absorption rate of aqueous
PZ to be more than double of that of 7 m MEA, with negligible thermal degradation up to a temperature of 150 ºC. The
Rochelle group at Texas University has established that concentrated PZ is a superior solvent with twice the capacity
and CO2 absorption rate of 30 wt % MEA and excellent thermal and oxidative stability [76].
Aroonwilas and Veawab [77] studied AMP and it was more efficient in terms of CO2 removal than DEA by 9% at
0.40 mol/mol CO2 loading, and placed next to MEA based on absorption performance. Yeh et al. [52] found that
20 wt% MEA has a higher rate of absorption (around 1.5 times more) than 29.2 wt% AMP for the same type of
packing, but a lower regeneration rate (around 1.8 times less) than AMP.
Chowdhury et al. [78] have studied several new hindered amine solvents; seven secondary and two tertiary amine
based CO2 solvents were synthesized with systematic modification of their chemical structures by an appropriate
placement of substituent functional groups, especially the alkyl functions, relative to the position of the amino group. At
least three solvents were found to have faster absorption rates and lower heats of reaction compared to AMP and
MDEA. In their previous work, Chowdhury et al. [79] found several high performance tertiary amines with high
absorption rates and low heats of reaction compared to MDEA. Traditionally, amines with higher absorption rates are
found to exhibit higher heats of reaction, but in Chowdhury and RITE’s studies [84], the tertiary amines showed inverse
trends. On the other hand, Singh et al. [80] investigated the structural effects of alkanolamines on CO2 absorption rate
and cyclic capacity. The CO2 absorption capacity (for most absorbents) increased while the absorption rate decreased as
the chain length between the functional group and the amine group increased. However, six carbon chain length amines,
such as hexadimethylenediamine and hexylamine, showed exceptionally high absorption rate and capacity. Moreover,
substitution of alkyl and amine groups increased the absorption rate and capacity while hydroxyl group substitution
results in a reduced absorption rate. Dibenedetto and Aresta [81] found that the absorption capacity of diamines was
double that of monoamines, and showed better regeneration performances. Jang et al. [82] found that the CO2 loading
capacity of aqueous AEPD (2-Amino-2-ethyl-1,3-propanediol) is much higher than that of aqueous MEA. Furthermore,
IFP has claimed new amine based solvents “DMX1 and DMX2”, which are demixing solvents, meaning that they
characterize a phase separation of the solvent into a CO2 lean phase and a CO2 rich phase. Studies of these solvents
have shown that they have comparable CO2 absorption performances compared to standard MEA but lower
regeneration energies [83]. Reaction enthalpies of DMX1 and DMX2 solvents were found to be 60 and 63 kJ/mol
respectively, whereas that of MEA is approximately 80 kJ/mol.
Due to the limitations provided by single solvents and the need for further improvement, blended systems have been
approached as they combine the advantages of the amines that are mixed. Studies have been made comparing blends to
single solvents and show how improvement is possible in certain characteristics when blending is applied.
5.2 Blended Amine Solvents
Blended amines have been developed and reported to have the ability to combine the relatively high rate of reaction
with CO2 of the primary or secondary alkanolamine, with the low heat of reaction with CO2 of the tertiary one, leading
to higher rates of absorption and lower heats of regeneration [[7], [85]]. Blended amine solutions also offer the
advantage of setting the selectivity of the solvent toward CO2 by thoroughly mixing the amines in varying proportions,
which results in an additional degree of freedom for achieving the desired separation for a given gas mixture, and
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hence, a reduction in capital and operating costs. Investigation of the CO2 absorption and desorption characteristics of
different amine blends have been approached by several researchers. For example, Veawab et al. [[74], [86], [87]]
studied the absorption characteristics of MEA, DEA, MDEA and their blends and found that the absorption
performance and stripping energy requirements are greatest in MEA, followed by DEA and then MDEA, while those of
the blended alkanolamines lay between their parent alkanolamines. Additionally, Idem and Veawab [88] reported
substantial reduction in energy requirements and modest reduction in circulation rates for MEA/MDEA blends in their
studies at two CO2 capture pilot plants, one based on natural gas and the other on coal-fired. An aqueous 4:1 molar ratio
MEA/MDEA showed a significant reduction in heat duty compared to an equivalent concentration of aqueous MEA.
These results were also confirmed by Huttenhuis et al. [89].
The use of PZ activated aqueous MDEA solutions was first patented by BASF as it proved to be successful when
applied to the bulk removal of CO2 in ammonia plants [90]. BASF has also been developing a wide range of advanced
amine-based solvents for efficiently recovering CO2 emitted from flue gas [91]. Closmann et al. [92] studied the
MDEA/PZ blend in a molality ratio of 7.7 : 1.2. Outcomes of the study showed that the heat of CO2 absorption of the
blended solvent is about 75 kJ/mol while that of 7 m MEA is around 84 kJ/mol. MDEA/PZ blend also showed better
performance than MEA and MDEA alone for resistance to thermal and oxidative degradation at typical
absorption/stripping conditions. The resistance to oxidative degradation was found to be highest in the blend, followed
by MDEA and then PZ. Furthermore, Bishnoi and Rochelle [42] reported that 6 M PZ/4 M MDEA blend absorbed
CO2 faster than MEA or DEA blends with MDEA at similar concentrations. Park et al. [93] studied the absorption rates
of CO2 into aqueous mixtures of MDEA and hexamethylenediamine (HMDA). As the concentration of HMDA
increased from 0.7 wt% to 14.4 wt%, the absorption rate constant was increased from 25% to 292% compared with
20.5 wt% MDEA. Han et al. [94] also confirmed a similar effect of HMDA in MEA blends but results showed higher
absorption rate and capacity using HMDA/AMP blends. Singh et al. [122] tested HMDEA/AMP blend in a pilot plant
for 10 vol% CO2 and found that regeneration energy requirement is lower (3.41 MJ/kgCO2) than that of MEA
(4.33 MJ/kg CO2). Furthermore, Mangalapally and Hasse [[95], [96]] have presented high performance new solvents
named as CESAR1 and CESAR2. CESAR1 is a mixture of AMP and PZ whereas CESAR2 is a primary amine with
two amine groups (1,2- Ethanediamine (EDA)). Their pilot plant results showed that the new solvents require lower
flow rates and regeneration energy as compared to standard MEA. For example, CESAR1 requires 20% less
regeneration energy and 45% less solvent flow rate than MEA. Currently there is also research and development in the
area of amine based solvents in combination with enzymes, which acts as a catalyst to transform carbon dioxide to
bicarbonate such as Carbonic Anhydrase. Carbonic Anhydrase is an enzyme found in the blood of humans and other
mammals. This enzyme facilitates the transfer of CO2 during respiration. Genetic modification of this enzyme makes it
possible to use it in combination with aqueous alkanolamine solutions within an industrial environment, like flue gas
treatment [121].
6. Pilot Activities
As a primary step to achieving commercialization for amine based post combustion carbon capture, pilot plants using
chemical absorption have been commissioned at several power plants worldwide. Currently, there are numerous pilot
scale post-combustion capture plants running worldwide and deploying various forms of amines. Both Research and
Development (R&D) institutions and industrial companies have contributed to the establishment of these pilot plants.
Major R&D groups include CSIRO, the University of Texas, the University of Regina, NTNU and University of
Melbourne. Industrial companies which supply the amine technologies include: Fluor (Econamine FG PlusTM
technology), MHI (KM-CDR process), Aker Clean Carbon, BASF (aMDEA technology), Cansolv (Cansolv absorbent
DC), Alstom (Chilled Ammonia process), Siemens (PostCap amino acid salt technology), Babcock&Wilcox
(Regenerable Solvent Absorption Technology), HTC Purenergy, Toshiba, Powerspan (ECO2®) and Hitachi [63]. The
capacity of operating pilot plants ranges between 0.5 to 50 tons/day. The most commonly used solvents in these pilot
plants are MEA, KS-1, chilled ammonia, and Cansolv solvents. A list of the pilot activities taking place worldwide is
shown in Table 2.
928
©FORMATEX 2013
©FORMATEX 2013
Hitachi/EERC pilot plant (University of North Dakota)
MEA
Amine based solvents
Aqueous ammonia
Alternative solvents
Amine based solvents, including MEA
Different solvents, including MEA (20 wt% to
40 wt%)
Amine solvent
New CO2 capture solvents
Amine based Toshiba solvent
MEA and proprietary solvents, including H3
(Hitachi’s proprietary solvent)
MEA and H3-1 solvents
1,000 t/yr
3,000 t/yr
3,000 t/yr
600 t/yr
1,000 t/yr
4.5 t/day
Amino Acid Salt formulations
Amino Acid Salt
N.A.
N.A.
Hitachi/TEPCO Yokosuka power plant
Amine solvent
100 t/day
0.3 t/hr
0.05 t/hr
10 t/day
Proprietary advance-amine technology
Chilled ammonia
Chilled ammonia
Chilled ammonia
MEA
1800 t/yr
15,000 t/yr
10 t/h
10 t/h
1.2 t/day
2.25 ton/hr
KM-CDR process with KS-1 solvent
10 t/day
2010
-ongoing
-ongoing
2009-ongoing
2010-ongoing
2008-ongoing
2008-ongoing
2009-ongoing
2010-ongoing
2009-ongoing
2013-ongoing
2011-ongoing
2009-ongoing
2008-ongoing
2009-ongoing
2012-ongoing
2012-ongoing
2006-ongoing
1991-ongoing
2004-ongoing
1991-ongoing
KS-1TM
KS-1TM and other solvents
1 t/day
2 t/day
KS-1
2009-ongoing
[112]
[111]
[108]
[109]
[110]
[107]
[[105],[106]]
[[105],[106]]
[105]
[[105],[106]]
[[104],[105]]
[103]
[103]
[102]
[100]
[63]
[63]
[63]
[101]
[[97], [98]]
[63]
[[97], [98]]
[[98], [99]]
[97]
[97]
[97]
2000- ongoing
2006-2012
Reference
[97]
[97]
Operational Status
2002-ongoing
1999-2000
BASF PuraTreatTM and other new solvents
Technology/Solvent used
MEA and 2 variants of PZ- promoted K2CO3
MEA and MEA/MDEA
Fluor’s
Econamine FGSM Technology
30 wt% MEA, CASTOR-1 and CASTOR-2,
CESAR1 and CESAR2
50 t/day
24 t/day
4 t/day
Capacity
3 t/day
1 t/day
MHI/KEPCO/J-Power Matsushima Thermal Power Station of Electric
Power Development Co. (Nagasaki)
Alstom and DOW Chemical
Alstom/EPRI/ We Energies (Wisconsin)
Alstom/AEP/US DOE Mountaineer plant (New Haven)
Alstom/Statoil (Mongstadt)
Imperial College London
Doosan Power Systems, SSE and Vattenfall CCPilot100+ (Ferrybridge
power station, Yorkshire, UK)
Siemens and E.ON (Staudinger power station, Germany)
Tampa Electric/Siemens Big Bend Station project (Florida)
Tarong Energy/CSIRO/Stanwell corporation Tarong power station
(QLD)
CSIRO/China Huaneng Group Gaobeidian power station (Beijing)
CSIRO/Delta electricity Munmorah power station (New South Wales)
CSIRO transportable pilot plant (China)
CSIRO Loy Yang power station (Victoria)
IFP Energies nouvelles/ENEL Brindisi power plant (Italy) (HiCapt+TM
process)
EnBW CHP Plant Heilbronn
SINTEF/NTNU pilot plant (Norway)
Sigma Power Ariake Co. Ltd/Toshiba Mikawa power plant (Japan)
MHI/KEPCO Kansai power station
CO2CRC/International Power (Hazelwood coal-fired power plant,
Australia)
MHI-KEPCO (MHI Hiroshima R&D Centre)
MHI/KEPCO Nanko Pilot Plant
CESAR/CASTOR (Dong Energy in Denmark)
Project
C2P3 University of Texas’ Separations Research Program (SRP)
ITC (University of Regina)
ITC/consortium Saskpower power station Boundary Dam
(Saskatchewan)
Table 2 Post Combustion Capture Pilot Plants.
Materials
and processes for energy: communicating current research and technological developments (A. Méndez-Vilas, Ed.)
____________________________________________________________________________________________________
929
930
CANSOLV solvents
MEA solvent using Econamine FG+
CANSOLV solvents
CANSOLV solvents
KS-1
Chilled ammonia
ECO2
50 t/h
3 t/h
4 t/h
25 kg/h
4 t/h
1 t/h
1 Mt/yr
©FORMATEX 2013
1.8 Mt/yr
200 kg/h
500 kg/h
100,000
t/yr
PG Elektrownia Belchatow (Poland)
Aker Clean Carbon Scottish power (Longannet)
China Huaneng Group Beijing Cogeneration plant
South Energy/MHI/SCS/SECARB/EPR Plant Barry power station
(Alabama)
First Energy/Powerspan/Ohio Coal development office (Ohio)
Doosan/Emissions Reduction Test Facility (ERTF)
20 t/d
1 t/d
500 t/d
250 kg/h
Korean Institute of Energy Research
China Huaneng Group (Shanghai)
25 t/d
Chilled ammonia and KS-1 solvents (MHI
technology)
N.A.
MEA solvent & RS-2 solvent
Amine solvents
Alstom amine technology
Amine solvents
Amine solvents
20 wt% MEA using ABB Lumus technology
UCARSOLTM FGC 3000 (DOW solvent) using
Alstom’s Advanced Amine Process technology
Various solvents
CANSOLV solvents
1 t/h
180 kg/h
H3-1 solvent
Amine solvents developed by Hitachi
Amino Acid Salt solutions
Amine solvents
1 t/h
250 kg/h
0.5 t/h
EdF (Le Havre, France)
Aker Kvaerner Karsto gas terminal facilities (Stavanger)
Babcock-Hitachi Kure Research Laboratory (Japan)
Hitachi/Electrabel/GDF Suez/E.ON mobile pilot plant
TNO/E.ON Maasvlakte pilot plant
RWE/BASF/Linde RWE Coal Innovation Centre (Niederaussem)
RWE/Cansolv Technologies/BOC/IM Skaugen/The Shaw group
Inc./Tullow Oil Plc. (South Wales)
RWE Aberthaw pilot plant
Fluor/E.ON power station (Wilhelmshaven, Germany)
E.ON/Cansolv Technologies (Heyden)
Cansolv transportable pilot plant
E.ON/MHI
E.ON/Alstom power (Sweden)
Powerspan/Basin Electric Antelope’s Valley power station (North
Dakota)
[63]
1998-currently not
operational
2008-2010
2010
2011-ongoing
2009-ongoing
2004-currently not
operational
2017
2009-ongoing
2008-ongoing
[119]
[120]
[118]
[63]
[117]
[63]
[63]
[66]
[116]
[63]
2012-ongoing
2012-ongoing
[114]
[63]
[63]
[63]
[63]
[[63], [115]
[63]
[113]
[[63], [113]]
[63]
[63]
2012-ongoing
2010-ongoing
2009-ongoing
Variable
2010-ongoing
2009-ongoing
2010-ongoing
N.A.
2008- ongoing
2009- ongoing
Materials
and processes for energy: communicating current research and technological developments (A. Méndez-Vilas, Ed.)
____________________________________________________________________________________________________
Materials
and processes for energy: communicating current research and technological developments (A. Méndez-Vilas, Ed.)
____________________________________________________________________________________________________
7. Conclusions
Amine scrubbing is a proven technology and is ready to be tested and used on large coal-fired power plants. As a tailend technology, it offers flexibility through implementation in scale-up, on/off operation during peak demand, and can
be retrofit to existing utility plants. Other advanced technologies will not provide solutions as energy-efficient or as
timely to decrease CO2 emissions. Amongst the different amine solvents used for CO2 separation, 30 wt% MEA has
served as the standard for the evaluation of processes for post-combustion capture. However, this solvent needs to be
improved due to its drawbacks and other more economically efficient amines need to be developed. Pilot plants have
already been built at several power stations to demonstrate the amine based post-combustion chemical absorption
process. However, large scale commercialization of this process is yet to be performed. There is a need for full
integration of the carbon capture process to power plants. In the direction for large scale CO2 post-combustion capture
plants; novel solvents focusing on amine blends together with improved capture process configurations are required. In
addition, the capture process integration with the power plant, plant flexibility, process control and the ability to
incorporate future process/solvent improvements are essential to have successfully operational capture plant in
commercial scale.
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