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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 2 IEA Greenhouse Gas R&D
Programme, Orchard Business Centre, Stoke Orchard, Cheltenham GL52
7RZ, UK 3CSIRO Energy Technology, P. O. Box 330, Newcastle, NSW
2300, Australia *Corresponding author: [email protected],
+9712 810 9181
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 oxy-combustion. 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,
post-combustion 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 post-combustion capture technology only are shown in
this chapter. Due to the acidity of CO2 and the basicity of
chemical solvents, a reversible acidbase neutralization reaction
takes place upon their interaction in a packed absorber column at a
temperature ranging between 40 and 65C, 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 4065 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+ + OH- CO2 + 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 NH 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+ + PZCOO- 2PZCOO- + CO2 PZ(COO-)2 + H+PZCOO-
PZCOO- + CO2 + H2O HCO3- + H+PZCOO-
Sterically 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)
MEA 0.0085 (at 20C) [43] 24.1 (at 20C) [44]
0.50 (PCO2= 5 kPa) [45] 0.48 (PCO2= 1.5 kPa) [45] 0.56 (30 wt%
at 40C) [46] 0.45-0.55 [47] 0.30-0.35 (for 15-20 wt% MEA) [48] 0.46
(30 wt% MEA) [49]
70.5 (30 wt% MEA) [46] 82 (7 m MEA with PCO2= 1.5 kPa) [47] 84
[48] 83 (5M MEA at 25C) [50] 66.7 (30 wt% MEA at 40C) [51]
DEA 0.077 (at 25C) [53] 380 (at 30C) [44] 0.35-0.40 (for 25-30
wt% DEA) [48] 66.5 [48]
MDEA 0.0013 (at 20C) [43] 101 (at 20C) [44] 0.45-0.55 (for 35-55
wt% MDEA) [48] 59 [48] 44.6 (20 wt% MDEA at 40C) [51]
AMP 0.1347 (at 20C) [43] 2.26 (26.73 wt% at 30C) [54] 0.84 (30
wt% AMP) [49] 58.2 (20 wt% AMP at 40C) [51]
PZ 0.1066 (at 20C) [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]
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-McGees
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 KM-CDR (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 worlds 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 Alstoms 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 5-10C
(9-18F) 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 C. 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 RITEs 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.
Materials and processes for energy: communicating current
research and technological developments (A. Mndez-Vilas,
Ed.)____________________________________________________________________________________________________
FORMATEX 2013928
-
Tab
le 2
Pos
t Com
bust
ion
Cap
ture
Pilo
t Pla
nts.
Proj
ect
Cap
acity
Te
chno
logy
/Sol
vent
use
d O
pera
tiona
l Sta
tus
Ref
eren
ce
C2P
3 U
nive
rsity
of T
exas
Sep
arat
ions
Res
earc
h Pr
ogra
m (S
RP)
3
t/day
M
EA a
nd 2
var
iant
s of P
Z- p
rom
oted
K2C
O3
2002
-ong
oing
[9
7]
ITC
(Uni
vers
ity o
f Reg
ina)
1
t/day
M
EA a
nd M
EA/M
DEA
19
99-2
000
[97]
IT
C/c
onso
rtium
Sas
kpow
er p
ower
stat
ion
Bou
ndar
y D
am
(Sas
katc
hew
an)
4 t/d
ay
Fluo
rs
Econ
amin
e FG
SM T
echn
olog
y 20
00- o
ngoi
ng
[97]
CES
AR
/CA
STO
R (D
ong
Ener
gy in
Den
mar
k)
24 t/
day
30 w
t% M
EA, C
AST
OR
-1 a
nd C
AST
OR
-2,
CES
AR
1 an
d C
ESA
R2
2006
-201
2 [9
7]
CO
2CR
C/In
tern
atio
nal P
ower
(Haz
elw
ood
coal
-fire
d po
wer
pla
nt,
Aus
tralia
) 50
t/da
y B
ASF
Pur
aTre
atTM
and
oth
er n
ew so
lven
ts
2009
-ong
oing
[9
7]
MH
I-K
EPC
O (M
HI H
irosh
ima
R&
D C
entre
) 1
t/day
K
S-1T
M20
04-o
ngoi
ng
[[97
], [9
8]]
MH
I/KEP
CO
Nan
ko P
ilot P
lant
2
t/day
K
S-1T
M a
nd o
ther
solv
ents
19
91-o
ngoi
ng
[[98
], [9
9]]
MH
I/KEP
CO
Kan
sai p
ower
stat
ion
K
S-1
1991
-ong
oing
[6
3]
MH
I/KEP
CO
/J-P
ower
Mat
sush
ima
Ther
mal
Pow
er S
tatio
n of
Ele
ctric
Po
wer
Dev
elop
men
t Co.
(Nag
asak
i) 10
t/da
y K
M-C
DR
pro
cess
with
KS-
1 so
lven
t 20
06-o
ngoi
ng
[[97
], [9
8]]
Als
tom
and
DO
W C
hem
ical
18
00 t/
yr
Prop
rieta
ry a
dvan
ce-a
min
e te
chno
logy
20
09-o
ngoi
ng
[100
] A
lsto
m/E
PRI/
We
Ener
gies
(Wis
cons
in)
15,0
00 t/
yr
Chi
lled
amm
onia
20
08-o
ngoi
ng
[63]
A
lsto
m/A
EP/U
S D
OE
Mou
ntai
neer
pla
nt (N
ew H
aven
) 10
t/h
Chi
lled
amm
onia
20
09-o
ngoi
ng
[63]
A
lsto
m/S
tato
il (M
ongs
tadt
) 10
t/h
Chi
lled
amm
onia
20
12-o
ngoi
ng
[63]
Im
peria
l Col
lege
Lon
don
1.2
t/day
M
EA
2012
-ong
oing
[1
01]
Doo
san
Pow
er S
yste
ms,
SSE
and
Vat
tenf
all C
CPi
lot1
00+
(Fer
rybr
idge
po
wer
stat
ion,
Yor
kshi
re, U
K)
100
t/day
A
min
e so
lven
t 20
11-o
ngoi
ng
[102
]
Siem
ens a
nd E
.ON
(Sta
udin
ger p
ower
stat
ion,
Ger
man
y)
N.A
. A
min
o A
cid
Salt
form
ulat
ions
20
09-o
ngoi
ng
[103
] Ta
mpa
Ele
ctric
/Sie
men
s Big
Ben
d St
atio
n pr
ojec
t (Fl
orid
a)
N.A
. A
min
o A
cid
Salt
2013
-ong
oing
[1
03]
Taro
ng E
nerg
y/C
SIR
O/S
tanw
ell c
orpo
ratio
n Ta
rong
pow
er st
atio
n (Q
LD)
1,00
0 t/y
r M
EA
2010
-ong
oing
[[
104]
,[105
]]
CSI
RO
/Chi
na H
uane
ng G
roup
Gao
beid
ian
pow
er st
atio
n (B
eijin
g)
3,00
0 t/y
r A
min
e ba
sed
solv
ents
20
08-o
ngoi
ng
[[10
5],[1
06]]
C
SIR
O/D
elta
ele
ctric
ity M
unm
orah
pow
er st
atio
n (N
ew S
outh
Wal
es)
3,00
0 t/y
r A
queo
us a
mm
onia
20
09-o
ngoi
ng
[[10
5],[1
06]]
C
SIR
O tr
ansp
orta
ble
pilo
t pla
nt (C
hina
) 60
0 t/y
r A
ltern
ativ
e so
lven
ts
[1
05]
CSI
RO
Loy
Yan
g po
wer
stat
ion
(Vic
toria
) 1,
000
t/yr
Am
ine
base
d so
lven
ts, i
nclu
ding
MEA
20
08-o
ngoi
ng
[[10
5],[1
06]]
IF
P En
ergi
es n
ouve
lles/
ENEL
Brin
disi
pow
er p
lant
(Ita
ly) (
HiC
apt+T
M
proc
ess)
2.
25 to
n/hr
D
iffer
ent s
olve
nts,
incl
udin
g M
EA (2
0 w
t% to
40
wt%
) 20
10-o
ngoi
ng
[107
]
EnB
W C
HP
Plan
t Hei
lbro
nn
0.3
t/hr
Am
ine
solv
ent
-ong
oing
[1
08]
SIN
TEF/
NTN
U p
ilot p
lant
(Nor
way
) 0.
05 t/
hr
New
CO
2 cap
ture
solv
ents
-o
ngoi
ng
[109
] Si
gma
Pow
er A
riake
Co.
Ltd
/Tos
hiba
Mik
awa
pow
er p
lant
(Jap
an)
10 t/
day
Am
ine
base
d To
shib
a so
lven
t 20
09-o
ngoi
ng
[110
]
Hita
chi/T
EPC
O Y
okos
uka
pow
er p
lant
4.
5 t/d
ay
MEA
and
pro
prie
tary
solv
ents
, inc
ludi
ng H
3 (H
itach
is p
ropr
ieta
ry so
lven
t)
[111
]
Hita
chi/E
ERC
pilo
t pla
nt (U
nive
rsity
of N
orth
Dak
ota)
MEA
and
H3-
1 so
lven
ts
2010
[1
12]
Materials and processes for energy: communicating current
research and technological developments (A. Mndez-Vilas,
Ed.)____________________________________________________________________________________________________
FORMATEX 2013 929
-
Bab
cock
-Hita
chi K
ure
Res
earc
h La
bora
tory
(Jap
an)
H
3-1
solv
ent
[1
13]
Hita
chi/E
lect
rabe
l/GD
F Su
ez/E
.ON
mob
ile p
ilot p
lant
1
t/h
Am
ine
solv
ents
dev
elop
ed b
y H
itach
i N
.A.
[[63
], [1
13]]
TN
O/E
.ON
Maa
svla
kte
pilo
t pla
nt
250
kg/h
A
min
o A
cid
Salt
solu
tions
20
08- o
ngoi
ng
[63]
R
WE/
BA
SF/L
inde
RW
E C
oal I
nnov
atio
n C
entre
(Nie
dera
usse
m)
0.5
t/h
Am
ine
solv
ents
20
09- o
ngoi
ng
[63]
R
WE/
Can
solv
Tec
hnol
ogie
s/B
OC
/IM S
kaug
en/T
he S
haw
gro
up
Inc.
/Tul
low
Oil
Plc.
(Sou
th W
ales
) 1
t/h
CA
NSO
LV so
lven
ts
2010
-ong
oing
[6
3]
RW
E A
berth
aw p
ilot p
lant
50
t/h
CA
NSO
LV so
lven
ts
2012
-ong
oing
[1
14]
Fluo
r/E.O
N p
ower
stat
ion
(Wilh
elm
shav
en, G
erm
any)
3
t/h
MEA
solv
ent u
sing
Eco
nam
ine
FG+
2010
-ong
oing
[6
3]
E.O
N/C
anso
lv T
echn
olog
ies (
Hey
den)
4
t/h
CA
NSO
LV so
lven
ts
2009
-ong
oing
[6
3]
Can
solv
tran
spor
tabl
e pi
lot p
lant
25
kg/
h C
AN
SOLV
solv
ents
V
aria
ble
[63]
E.
ON
/MH
I 4
t/h
KS-
1 20
10-o
ngoi
ng
[63]
E.
ON
/Als
tom
pow
er (S
wed
en)
1 t/h
C
hille
d am
mon
ia
2009
-ong
oing
[[
63],
[115
] Po
wer
span
/Bas
in E
lect
ric A
ntel
ope
s Val
ley
pow
er st
atio
n (N
orth
D
akot
a)
1 M
t/yr
ECO
2 20
12-o
ngoi
ng
[63]
Ake
r Kva
erne
r Kar
sto
gas t
erm
inal
faci
litie
s (St
avan
ger)
18
0 kg
/h
Var
ious
solv
ents
19
98-c
urre
ntly
not
op
erat
iona
l [6
3]
EdF
(Le
Hav
re, F
ranc
e)
25 t/
d U
CA
RSO
LTM
FG
C 3
000
(DO
W so
lven
t) us
ing
Als
tom
s A
dvan
ced
Am
ine
Proc
ess t
echn
olog
y 20
12-o
ngoi
ng
[116
]
Kor
ean
Inst
itute
of E
nerg
y R
esea
rch
250
kg/h
20
wt%
MEA
usi
ng A
BB
Lum
us te
chno
logy
20
04-c
urre
ntly
not
op
erat
iona
l [6
6]
PG E
lekt
row
nia
Bel
chat
ow (P
olan
d)
1.8
Mt/y
r A
lsto
m a
min
e te
chno
logy
20
17
[117
] A
ker C
lean
Car
bon
Sco
ttish
pow
er (L
onga
nnet
) 20
0 kg
/h
Am
ine
solv
ents
20
09-o
ngoi
ng
[63]
C
hina
Hua
neng
Gro
up B
eijin
g C
ogen
erat
ion
plan
t 50
0 kg
/h
Am
ine
solv
ents
20
08-o
ngoi
ng
[63]
Chi
na H
uane
ng G
roup
(Sha
ngha
i) 10
0,00
0 t/y
r A
min
e so
lven
ts
2009
-ong
oing
[6
3]
Sout
h En
ergy
/MH
I/SC
S/SE
CA
RB
/EPR
Pla
nt B
arry
pow
er st
atio
n (A
laba
ma)
50
0 t/d
C
hille
d am
mon
ia a
nd K
S-1
solv
ents
(MH
I te
chno
logy
) 20
11-o
ngoi
ng
[118
]
Firs
t Ene
rgy/
Pow
ersp
an/O
hio
Coa
l dev
elop
men
t off
ice
(Ohi
o)
20 t/
d N
.A.
2008
-201
0 [1
19]
Doo
san/
Emis
sion
s Red
uctio
n Te
st F
acili
ty (E
RTF
) 1
t/d
MEA
solv
ent &
RS-
2 so
lven
t 20
10
[120
]
Materials and processes for energy: communicating current
research and technological developments (A. Mndez-Vilas,
Ed.)____________________________________________________________________________________________________
FORMATEX 2013930
-
7. Conclusions Amine scrubbing is a proven technology and is
ready to be tested and used on large coal-fired power plants. As a
tail-end 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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