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PERSPECTIVE
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Clean coal conversion processes – progress and challenges
Fanxing Li and Liang-Shih Fan*
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Published on 30 July 2008 on http://pubs.rsc.org | doi:10.1039/B809218B
Received 30th May 2008, Accepted 11th July 2008
First published as an Advance Article on the web 30th July 2008
DOI: 10.1039/b809218b
Although the processing of coal is an ancient problem and has been practiced for centuries, the
constraints posed on today’s coal conversion processes are unprecedented, and utmost innovations are
required for finding the solution to the problem.
With a strong demand for an affordable energy supply which is compounded by the urgent need for
a CO2 emission control, the clean and efficient utilization of coal presents both a challenge and an
opportunity to the current global R&D efforts in this area. This paper provides a historical perspective
on the utilization of coal as an energy source as well as describing the progress and challenges and the
future prospect of clean coal conversion processes. It provides background on the historical utilization
of coal as an energy source, along with particular emphasis on the constraints in current coal
conversion technologies. It addresses the energy conversion efficiencies for current coal combustion
and gasification processes and for the membrane and looping based novel processes which are currently
under development at various stages of testing. The control technologies for pollutants including CO2
in flue gas or syngas are also discussed. The coal conversion process efficiencies under a CO2
constrained environment are illustrated based on data and ASPEN Plus simulations. The challenges
for future R&D efforts in novel coal conversion process development are also presented.
Department of Chemical and Biomolecular Engineering, The Ohio State
University, 140 West 19th Avenue, Columbus, Ohio, 43210, USA.
E-mail: [email protected]; Fax: +001-614-292-3769; Tel: +001-614688-3262
renewable energy is not likely to contribute to a significant share
of the total energy demands in the foreseeable future.4,5 Similarly,
concerns over plant safety and radioactive waste disposal will
impede the wide utilization of nuclear power.6 Thus, despite high
crude oil and natural gas prices, fossil fuels will continue to
provide more than 85% of the overall world energy consumption
for the next several decades.7 US DOE studies indicate that the
consumption of coal as an energy resource is more responsive to
crude oil price fluctuations than renewable energy sources in
the near term, and coal could regain its role as a major energy
source by 2030.7 Fig. 1 shows the impact of oil prices on the
consumption of coal and other energy sources. The attractiveness of coal lies in its abundant reserves and stable prices when
compared to both oil and natural gas.
Without the implementation of pollution control, enhanced
coal usage will result in serious environmental impacts since coal
Fanxing Li received his B.S.
degree in 2001 and his M.S.
degree in 2004 in Chemical
Engineering from Tsinghua
University. He is a graduate
research associate in the
Department of Chemical and
Biomolecular Engineering at The
Ohio State University. He is
currently working on a number of
projects with Professor L. S. Fan
including energy and environmental reaction engineering and
clean coal conversion processes.
L. S. Fan is Distinguished
University Professor and C.
John Easton Professor in Engineering in the Department of
Chemical and Biomolecular
Engineering at The Ohio State
University. His expertise is in
fluidization and multiphase flow,
powder technology and energy
and environmental reaction
engineering. He is a member of
the U. S. National Academy of
Engineering, and an Academician of the Academia Sinica.
1. Background
Energy and global warming are two intertwined issues of significant magnitude in the modern era. With oil prices rising above
$120/barrel and atmospheric CO2 levels increasing at a rate greater
than 1.5 ppm each year,1–3 an urgent need exists for development
of clean and cost effective energy conversion processes.
Renewable energy sources such as hydro, wind, solar,
geothermal, and biomass will help reduce anthropogenic CO2
emissions by mitigating fossil fuel consumption. However, with
the high cost, geological constraints, and intermittency issues,
F: Li
248 | Energy Environ. Sci., 2008, 1, 248–267
L: S: Fan
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Fig. 1 (a) Three different (long term) world oil price scenarios predicted by EIA; (b) world energy consumption in 2030 based on energy sources.7
contains various contaminants and is the most carbon-intensive
energy source. Of major global concern is the fact that the
combustion of fossil fuels releases 27 gigatons of CO2 each
year.7,8 With increasing coal consumption, the anthropogenic
CO2 emission rate may reach well over 40 gigatons per year
within the next two decades in the absence of effective CO2
mitigation techniques.7,8 Therefore, modern coal conversion
technologies need to be able to efficiently convert coal into useful
products while controlling the CO2 emission. Unlike crude oil,
which is primarily used as transportation fuels, coal is primarily
used as a stationary source for electricity generation. Thus, CO2
capture from coal can be more readily implemented.
This article addresses clean coal conversion technologies from
the process viewpoint. Coal combustion processes are first
discussed along with the various options for pollutant control
and CO2 capture. It is then followed by an overview of coal
gasification processes. Advanced membrane and chemical looping based systems using gaseous feedstock as well as advanced
direct coal chemical looping systems are illustrated. These
advanced technologies that yield high energy conversion efficiencies are at various stages of development and are potentially
deployable in the near or intermediate term.
2. Coal combustion processes
Archeological evidence indicates that humans have been burning
coal for at least 4000 years.9–11 Throughout history, coal has been
used to generate heat and to smelt metals. However, it was not
until the 18th century that coal started to play an indispensible
role in the economy. As an important fuel that propelled
the industrial revolution,12,13 coal has been widely used since the
1700s to drive steam engines, in the operation of blast furnaces
for metal production, in the production of cement, and in the
generation of town gas for lighting and cooking. Since the late
19th century, coal has been used to power utility boilers for
electricity generation.14 Although its dominance as an energy
source was replaced by crude oil in the 1950s, coal is still the
single most important fuel for electricity generation today,
accounting for 40% of the electricity generated worldwide.7
The dominance of coal in electricity generation is expected
to continue well into the 21st century.
This journal is ª The Royal Society of Chemistry 2008
Fig. 2 Simplified schematic diagram of a Pulverized Coal (PC)
combustion process for power generation.
Presently, pulverized coal (PC) fired power plants account for
more than 90% of the electricity generated from coal.15 The
schematic flow diagram of a PC power plant is illustrated in Fig. 2.
In a PC power plant, coal is first pulverized into fine powder
with over 70% of the particles smaller than 74 mm (200 mesh).
The pulverized coal powder is then combusted in the boiler with
the presence of 20% excess air.14 The heat of combustion is used
to generate high pressure, high temperature steam that drives the
steam turbine system based on a regenerative Rankine cycle for
electricity generation. Although the underlying concept is quite
simple, the following challenges need to be addressed for modern
PC power plants: enhancement of energy conversion efficiency;
effective control of hazardous pollutants emission; and CO2
capture (and sequestration).
2.1 Energy efficiency improvement
An increase in the combustion process efficiency leads to reduced
coal consumption and hence, a potential cost reduction for
electricity generation. The first generation coal fired power plants
constructed in the early 1900s converted only 8% of the chemical
energy in coal into electricity (based on the higher heating value,
HHV).16 Since then, a significant improvement in plant efficiencies has been made. Thermodynamic principles require higher
steam pressures and temperatures for a higher plant efficiency.
The corrosion resistance of the materials for boiler tubes,
however, constrains the maximum pressure and temperature of
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the steam. Most of the PC power plants currently under operation
utilize sub-critical PC (Sub-CPC) boilers which produce steam
with pressures up to 22 MPa and temperatures around 550 C. The
energy conversion efficiencies of traditional Sub-CPC power
plants typically range from 33% to 37% (HHV).17 With an increase
in the steam pressure, supercritical PC (SCPC) power plants were
first introduced in the early 1960s in the US.16 Supercritical power
plants involve steam with a typical pressure of 24.3 MPa and
temperatures up to 565 C, leading to a plant efficiency of 37 to
40%.17 Many supercritical power plants were constructed in the
1960s and 70s in the US. However, due to the low reliability of
the boiler materials, the further application of the SCPC technology was essentially halted in the US in the early 1980s. The
development of high performance super alloys coupled with
increasing environmental concerns and the rising cost of coal
during the last two decades has stimulated the revival of supercritical technology, especially in Europe and Japan, leading to the
reduction of subcritical boilers in newly installed fleets.
Recent advancements in coal combustion technologies are
highlighted by the generation of ‘‘ultra-supercritical’’ (USCPC)
steam conditions that can provide even higher process efficiencies. The ultra-supercritical condition refers to the ‘‘operating
steam cycle conditions above 565 C (>1050 F)’’.17 The pressure
and temperature of the steam generated from existing ultrasupercritical power plants can reach 32 MPa and 610 C,
corresponding to an energy conversion efficiency of over
43%.17,18 The global on-going R&D activities on PC boilers focus
on the development of super alloys that can sustain steam pressures up to 38.5 MPa and temperatures as high as 720 C. It is
expected that a plant efficiency of over 46% can be achieved
under such conditions.17–19 Other efforts in ultra-supercritical
technology include minimizing the usage of super alloys,
improving the welding technique, and optimizing the boiler
structure design to minimize the steam line to steam turbine.18
Besides PC boilers, Fluidized Bed Combustors (FBC) using
either turbulent fluidized beds or circulating fluidized beds are
also being used for steam and power generation world wide. In
these processes, limestone is often injected to capture SOx formed
during coal combustion. Compared to PC boilers, the FBC has
lower SOx and NOx emissions.20,21 Furthermore, it has superior
fuel flexibility.22 Most commercial FBC plants operate under
atmospheric pressures, with energy conversion efficiencies
similar to subcritical PC power plants. Higher efficiencies can be
achieved by operating the FBC at elevated pressures.22–24 The
Pressurized Fluidized Bed Combustor (PFBC) generates a high
temperature, high pressure exhaust gas stream which drives a gas
turbine–steam turbine combined cycle system for power generation. In an advanced PFBC (APFBC) configuration, fuel gas is
generated from coal via particle oxidation and pyrolysis. The fuel
gas is combusted to drive a gas turbine (topping cycle). Such
a process has the potential to achieve an energy conversion
efficiency of over 46%.23 To date, the PFBC demonstrations have
shown relatively low plant availability. In addition, the capital
investment for PFBC is higher than PC power plants with
a similar efficiency.25 Other potential challenges to the PFBC
technology include scale-up, high temperature particulates/
alkali/sulfur removal for gas turbine operation, and mercury
removal from the flue gas.22,26 Table 1 compares the performance
of different coal combustion technologies. The energy penalties
250 | Energy Environ. Sci., 2008, 1, 248–267
Table 1 Energy conversion efficiencies (HHV) of various coal
combustion technologies and energy penalty for CO2 capture using
MEA17,27–32
Technology
Sub-CPC
SCPC
USCPC
AFBC
PFBC/
APFBC
Base case
efficiency
(%) HHV
3337
3740
4045
3438
3845
MEA retrofit
derating (%)a
30–42
24–34
21–30
35b
30b
a
Percentage decrease in energy conversion efficiency when a retrofit
MEA system is used to capture 90% of the CO2 in the flue gas.b Estimated
based on ASPEN simulation by authors.
for the 90% CO2 capture using a retrofit monoethanolamine
(MEA) scrubber as discussed in Section 2.3 are also shown in
Table 1.
2.2 Flue gas pollutant control methods
Modern coal combustion power plants need to be able to capture
environmentally hazardous pollutants released from coal
combustion. Such pollutants include sulfur oxides, nitrogen
oxides, fine particulates, and trace heavy metals such as mercury,
selenium, and arsenic. Methods for capturing these contaminants
from the flue gas streams abound. The challenges, however, lie in
the efficient and cost effective removal of these contaminants.
The traditional method for SOx removal utilizes wet scrubbers
with alkaline slurries. The wet scrubber is effective; however, it is
costly and yields wet scrubbing wastes that must be disposed of.
Alternative methods have included more cost effective lime spray
drying and dry-sorbent duct-injection. The lime spray drying
method employs slurry alkaline spray yielding scrubbing wastes
in solid form, easing the waste handling. The dry-sorbent ductinjection employs a dry alkaline sorbent for direct in-duct
injection, circumventing the use of the scrubber. The recent pilot
testing using re-engineered limestone sorbents of high reactivity
yields a sorbent sulfation efficiency of over 90%, compared to
under 70% with ordinary limestone sorbent, indicating a viability
of the dry-sorbent duct-injection method with very active
sorbents.33–35 The NOx is commonly removed by selective catalytic reduction (SCR). Other methods that can be employed
include low NOx burner and O3 oxidation. The recent pilot
testing of the CARBONOx process using coal char impregnated
with alkaline metal revealed a high NOx removal efficiency at low
flue gas temperatures.36 The trace heavy metals such as mercury,
selenium, and arsenic can be removed by calcium based sorbent
and/or activated carbon.33,37
The techniques to control the flue gas pollutants indicated
above are well-developed. An effective capture (and sequestration) of CO2, an important green house gas (GHG) that accounts
for 64% of the enhanced green house effect38 is, however,
a challenging task.
2.3 CO2 capture systems
Coal-fired power plants are responsible for nearly a third of all
anthropogenic CO2 emissions.39 Therefore, cost-effective carbon
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capture technologies for these plants play an important role in
CO2 mitigation.
CO2 represents 15% of the atmospheric pressure flue gas
stream from coal combustion power plant (dry basis). Low CO2
partial pressures combined with the extremely high flue gas
generation rate make the CO2 capture from PC power plants an
energy consuming step. An ideal CO2 capture technology would
incorporate effective process integration schemes while minimizing the parasitic energy requirement for CO2 separation.
The existing CO2 capture techniques from PC power plants
include the well-established MEA scrubbing technology. Fig. 3a
shows the schematic diagram of the MEA scrubbing process
which indicates the key stream conditions of the process.40–42 In
this process, the flue gas is first cooled down to 40 C before
entering the absorber where fresh amine is used to absorb CO2 in
the flue gas stream. The spent amine solution with a high CO2
concentration is then regenerated in the stripper under a higher
temperature (100–150 C), and CO2 is then recovered at low
pressure (0.1–0.2 MPa). A large amount of high temperature
steam is required to strip the CO2 in the regeneration step.42,43
Therefore, a significant amount of energy will be consumed for
steam generation and the subsequent CO2 compression step. It is
estimated that the CO2 capture (separation and compression)
using amine scrubbing will reduce the power generated from the
entire plant by as much as 42%,29 which amounts to 70–80% of
the total cost in the overall three-fold carbon management steps,
i.e. carbon capture, transportation, and sequestration.44,45 As
a result, a process that can reduce the energy consumption in the
CO2 capture step will be vital for CO2 management in coal fired
power plants.
The chilled ammonia process, illustrated in Fig. 3b, is another
solvent based CO2 capture technology where ammonia
carbonate and bicarbonate slurries are used to capture the CO2
in the flue gas stream at 0–10 C and atmospheric pressure. The
CO2 rich solvent is then regenerated at 110–125 C and 2–4 MPa.
The capability to regenerate CO2 at elevated pressures reduces
the energy consumption for CO2 compression. Based on the
studies by the Electric Power Research Institute (EPRI) and
ALSTOM, the overall energy penalty for CO2 capture is estimated to be lower than 16% when the chilled ammonia process is
used.46,47 A 5 MWth (megawatts thermal) equivalent chilled
ammonia process demonstration plant, jointly supported by
ALSTOM and EPRI, is currently under construction at We
Energies’ Pleasant Prairie Power Plant in Wisconsin.48 American
Electric Power (AEP) is also planning to demonstrate the chilled
ammonia process at the 20 MWe (megawatts electricity) scale,
starting in 2009, before building a 200 MWe commercial level
chilled ammonia retrofit system in 2012.49
Similar to solvent based CO2 scrubbing techniques, high
temperature sorbents such as limestone, potassium carbonates,
lithium silicates, and sodium carbonates can be used to capture
CO2 in the flue gas at elevated temperatures.50,51 With better heat
integration, these strategies can potentially decrease the energy
consumption in the CO2 separation step. One scheme for heat
integration is based on the calcium based carbonation–calcination reaction (CCR) process which uses hydrated lime, and
natural or re-engineered limestone sorbents at 600–700 C for
CO2 separation.52 Fig. 4 delineates the heat integration strategies
for retrofitting the CCR process to an existing PC power plant.
In the CCR process, both CO2 and SO2 in the flue gas are
captured by the CaO sorbent in the carbonator operated at 650
C, forming CaCO3 and CaSO3/CaSO4 The carbonated sorbent,
CaCO3, is then regenerated to calcium oxide (CaO) sorbent in the
calciner at 850–900 C, yielding a pure CO2 stream. The sulfated
sorbent and fly ashes are removed from the system by means of
a purge stream. Due to an optimized energy management
scheme, the CCR process consumes 15–22% of the energy
generated in the plant.53,54 The process is being demonstrated in
a 120 kWth (kilowatts thermal) pilot plant located at The Ohio
State University (OSU). A similar process is being demonstrated
at CANMET Energy Technology Center in Canada.55 Studies or
reviews on the post combustion CO2 capture using solid sorbents
can be found in other literature sources.56–59
In addition to the absorption–adsorption based technologies,
oxy-fuel combustion technology provides another means for
carbon management in coal fired power plants. In this technology, pure oxygen instead of air is used for coal combustion.
As a result, a concentrated CO2 stream is generated, avoiding
the need for CO2 separation. However, the energy-consuming
cryogenic air separation step will reduce the overall plant efficiency by 20–35%.17,30,45,60 This process has been successfully
demonstrated by the Babcock & Wilcox Company on a 1.5
MWth pilot scale PC unit. Demonstration on a 30 MWth unit is
currently under way. The on-going pilot scale studies on oxy-fuel
combustion include those carried out by ALSTOM, FosterWheeler, CANMET Energy Technology Center, Vattenfall, and
Ishikawajima-Harima Heavy Industries (IHI).61
To generalize, a number of retrofit systems under different
stages of development can be used to capture CO2 from existing
power plants. Since PC power plants will continue to provide
Fig. 3 Conceptual schematic of (a) the MEA scrubbing technology for CO2 separation; (b) the Chilled Ammonia technology for CO2 separation.
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Fig. 4 Conceptual schematic of Carbonation–Calcination Reaction (CCR) process integration in a 300 MWe coal fired power plant depicting heat
integration strategies.
a significant portion of the electricity needs well into the 21st
century,7 these CO2 capture systems are essential to mitigate the
environmental impact from coal burning. In general, however,
CO2 capture and compression from a coal combustion flue gas is
costly and energy intensive. A more promising approach to
reduce the overall carbon footprint of a coal based plant is to
adopt coal conversion processes that are intrinsically advantageous from a carbon management and energy conversion
standpoint. Among the various options, coal gasification
described below offers such attraction.
3. Coal gasification processes
For years, the commercial efforts on clean coal processes have
been centered on coal combustion for power generation.
However, new process developments with a focus on higher
energy conversion efficiencies for electricity generation as well as
variability in product formation have generated considerable
interest. Coal gasification schemes can provide a variety of
products—e.g. hydrogen, liquid fuels and chemicals—besides
electricity. Further, gasification is a preferred scheme from
a pollutant and carbon management viewpoint.
(WGS) reaction can be 80 times higher than that in the PC boiler
flue gas (dry basis). The significantly reduced gas flow rate and
increased gas partial pressures make the pollutant and CO2
control an easier task for gasification processes when compared
to coal combustion processes.
Fig. 5 shows the modern coal gasification process that generates a variety of products. In the coal gasification process, coal
first reacts with oxygen (and steam) to produce raw syngas. The
raw syngas, with pollutants such as particulates, H2S, COS, HCl,
ammonia, and mercury, is purified before it is sent to a gas
turbine–steam turbine combined cycle system for electricity
generation. This syngas route is known as the Integrated Gasification Combined Cycle (IGCC). The electricity generation
efficiency of the IGCC process can be higher than 45% (HHV)
without CO2 capture.62,64 In a carbon constrained scenario,
however, the CO in the syngas stream will be further converted to
CO2 and H2 through the water–gas shift (WGS) reaction:
CO + H2O / CO2 + H2
(1)
Thus, the resulting gas stream contains a high CO2 concentration (up to 40% by volume on the dry basis). The CO2 (and
H2S) can be captured using either chemical absorption based
3.1 Overview
Compared to combustion, coal gasification is relatively new.
Commercial gasification processes date back to the late 18th
century when coal was converted into town gas for lighting and
cooking. Since the 1920s, the gasification process has been used
to produce chemicals and fuels.62 Unlike traditional combustion
processes which fully oxidize carbonaceous fuels to generate
heat, modern coal gasifiers convert coal into syngas via partial
oxidation reactions with oxygen or with steam and oxygen under
elevated pressures.14,62 The high pressure syngas stream, undiluted by N2 in the air, has a much lower volumetric flow rate
when compared to that of the flue gas from coal-fired power
plants. As a result, the partial pressure of the contaminants is
significantly increased. For instance, the volumetric flow rate of
syngas generated from a dry feed, oxygen blown gasifier can be
two orders of magnitude lower than that from a PC boiler with
similar coal processing capacity (dry basis). Meanwhile, the
partial pressure of CO2 in the syngas after the water gas shift
252 | Energy Environ. Sci., 2008, 1, 248–267
Fig. 5 Schematic diagram of coal gasification processes.63
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acid gas removal processes such as monoethanolamine (MEA) or
methyldiethanolamine (MDEA) described in Section 2.3 or
physical absorption based processes such as Selexol and Rectisol,
yielding concentrated H2.65 The H2 can be used to generate
electricity through a combined cycle system with minimal carbon
emissions.
Alternatively, the H2 stream can be further purified using
pressure swing adsorption (PSA) units. The resulting high-purity
H2 can be used for fuel cell applications. Besides electricity and
H2 generation, syngas can also be converted to chemicals and
liquid fuels such as diesel and naphtha through the Fischer–
Tropsch (F–T) reactions, which can be represented by:66–68
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(2n + 1)H2 + nCO / CnH2n
+ 2
+ nH2O
(2)
The process that converts coal to liquid fuels via coal gasification and F–T synthesis is also referred to as the indirect coalto-liquid (CTL) process. Unlike the indirect CTL process, the
direct CTL process liquefies coal directly by reacting it with
hydrogen at elevated pressure.69,70 The direct CTL process can
achieve a high liquid fuel yield—close to 3 barrel liquids per ton
of coal when coal is also used as the hydrogen source.71 The pilot
demonstrations of CTL processes took place during the 1970s to
1990s and included the H–Coal process (by Hydrocarbon
Research Inc.) and the Integrated Two-Stage Liquefaction
process (by Lummus Company).71 The first commercial direct
CTL process plant is being built in Inner Mongolia, China by
Shenhua Group Corporation. The production cost for the direct
CTL process is higher than for the indirect CTL process.71
Processing of coal using the gasification approach has the
advantages in product versatility and pollutant controllability
when compared to the combustion approach. However, gasification is more capital intensive. A study conducted in 2001
indicated that an IGCC system required 6–10% more capital
investment when compared to an ultra-supercritical PC plant.72
Both plants have similar energy conversion efficiencies. Although
CO2 capture from the gasification process is easier when
compared to a PC plant, the CO2 capture, nevertheless, represents an energy and capital intensive step in the process. The CO2
capture can derate the energy conversion efficiency of the IGCC
system by 13–24%, increasing the cost of electricity by 25–
45%.28,31,73–75 Other issues related to gasification include large
parasitic energy consumption in the WGS step due to the need
for the excessive steam as well as the temperature and pressure
swing requirement in the process for sulfur and mercury removal.
Gasification, like other technologies, has undergone evolution
since its inception. Over the years, different types of gasifiers have
been developed which provide a higher carbon conversion, cold
gas and thermal efficiencies, and flexibility in the type of fuel
used. These gasifier types include the fixed/moving bed gasifier,
fluidized-bed gasifier, entrained-flow gasifier, and transport
gasifier.62 Most of the modern gasifiers adopt an entrained-flow
design due to better fuel flexibility, carbon conversions, and
syngas quality.76 Other ongoing research activities include the use
of an Ion Transport Membrane (ITM) instead of the cryogenic
separation technique to reduce the energy consumption of the air
separation unit (ASU),77,78 the increase in the gas turbine inlet
temperature to increase the combined cycle efficiency, and the
development of a warm and hot gas clean up system to efficiently
remove pollutants such as particulates, sulfur and mercury.79–81
As there is a large degree of operational variation in individual
units and in an integrated process system, optimization of the
gasification process requires elaborate consideration of all the
viable process configurations. For this purpose, simulation
software such as ASPEN Plus is often used to aid in the analysis
of the process configurations under various process variables. In
the following section, a case study is presented which illustrates
the energy conversion efficiency for an IGCC system with CO2
capture through simulation using the ASPEN plus software.
3.2 ASPEN analysis on IGCC system with CO2 capture –
a case study
Aspen Plus has been widely used to simulate energy conversion
systems.41,82–87 Based on appropriate assumptions and relevant
experimental data of the individual units, the ASPEN Plus
software can assist in the evaluation of the process performance,
and in the optimization of the process configuration. The IGCC
system illustrated in this case study uses a GE/Texaco slurryfeed, entrained flow gasifier with total water quench syngas
cooler. The flow diagram of the process is shown in Fig. 6.
In this process, coal is first pulverized and mixed with water
to form coal slurry. The coal slurry is then pressurized and
introduced to the gasifier to be partially oxidized at 1500 C and
3.04 MPa (30 atm). The high temperature raw syngas after
gasification is then quenched to 250 C with water. The
quenching step solidifies the ash. Moreover, most of the NH3
and HCl in the syngas are removed during this step. After
quenching, the syngas is sent to a Venturi scrubber for further
particulate removal. The particulate-free syngas, saturated with
Fig. 6 IGCC process with CO2 capture.
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steam, is then introduced to the sour WGS unit. The syngas
exiting the WGS unit contains mainly H2 and CO2 with small
amount of CO, H2S, and mercury. This gas stream is then
cooled down to 40 C and passed through an activated carbon
bed for mercury removal. The CO2 and H2S in the syngas are
then removed using an MDEA unit, resulting in a concentrated
hydrogen stream with small amounts of CO2 and CO. The
hydrogen rich gas stream is then compressed, preheated, and
combusted in a combined cycle system for power generation.
The combined cycle system consists of a gas turbine with an
inlet firing temperature of 1430 C and a two stage steam
turbine working at 550 C and 3.55 MPa (35 atm). The CO2
obtained from the MDEA unit is compressed to 15.20 MPa
(150 atm) for sequestration.
ASPEN modeling on coal conversion systems has been
extensively discussed in various literature.41,82,84–87 The following
section briefly recapitulates the key steps to set up an ASPEN
simulation model on the IGCC system described above.
Prior to the simulation, a representative process flow sheet that
contains all the major units is developed (Fig. 6). The appropriate assumptions for the simulation are then determined. The
key assumptions are listed as follows:
- 132.9 tonne/h of Illinois #6 coal is fed into the system
(1000 MW in HHV)
- Energy consumed for units such as acid gas removal are
simulated based on performance data of the commercial units
- The GE slurry feed gasifier has a carbon conversion of
99%, heat loss in the gasifier is 0.6% of the HHV of coal
- A GE 7H gas turbine combined cycle system is used, all
the exhaust gas is cooled down to 130 C before exiting the Heat
Recovery Steam Generator (HRSG)
- At least 90% of the CO2 generated needs to be captured
and compressed to 15.20 MPa (150 atm) for sequestration
- The mechanical efficiency of pressure changers is 1,
whereas the isentropic efficiency is 0.80.9
In order to accurately simulate the individual unit in the flow
sheet, appropriate ASPEN Plus model(s) for each unit is determined. These models are listed in Table 2.
Aspen Plus has a comprehensive physical property database.
Therefore, most of the chemical species involved in the process
can be selected directly from the build-in database. The
nonconventional components such as coal and ash can be
specified conveniently using the general coal enthalpy modulus
embedded in the ASPEN software. After the chemical species in
the process are defined, the related physical property methods are
selected according to the simulator’s category. In this simulation,
the global property method is PR–BM, whereas local property
methods are specified whenever necessary.
The ASPEN model is finalized by establishing detailed operating parameters based on the operating conditions and design
specifications of the individual unit. The units are then connected
in the same arrangement as shown in the flow sheet. An appropriate convergence setting is determined to ensure accurate
simulation results. Table 3 generalizes the simulation results of
the IGCC system described above.
The results shown in Table 3 can replicate the performance of
existing IGCC power plants reported by Higman.62 The ASPEN
simulation can be effective for evaluating the performance of
various coal conversion systems based on a common set of
assumptions.
4. Advanced coal conversion processes
Although with various improvements, as discussed in section 3,
the efficiency of the conventional gasification systems is still
limited due to the elaborate steps needed such as syngas cleaning
and conversion, and gas separation and compression. Advanced
coal conversion processes, which adopt novel process intensification strategies, streamline the conversion processes thereby
yielding high energy conversion efficiency. Such techniques,
which are currently at various stages of demonstration, encompass the membrane based approach and the chemical looping
Table 3 Power Balance in a 1000 MWth IGCC plant with CO2 capture
Thermal
energy
Parasitic energy
input
consumption (MWe)
(MWth)
Power generation
(MWe)
Steam
turbine
Coal
CO2
Gas
CO2
ASU removal compression turbine IP
1000
39.4
9.4
17.7
LP
Net
power
(MWe)
249.1 86.4 79.1 348.1
Table 2 ASPEN models for the key units in the IGCC process
Unit operation
Aspen Plus model
Comments / specifications
Air separation unit
Sep
Coal decomposition
Ryield
Coal gasification
Quench
WGS
Rgibbs
Flash2
Rstoic or Rgibbs
MDEA
Burner
HRSG
Gas compressors
Heater and cooler
Turbine
Sep or Radfrac
Rgibbs or Rstoic
MHeatX
Compr or Mcompr
Heater
Compr
Energy consumption of the ASU is based on specifications of commercial ASU/
compressors load.
Virtually decompose coal into various components (pre-requisite step for gasification
modeling)
Thermodynamic modeling of gasification
Phase equilibrium calculation for cooling
To simulate conversion of WGS reaction based on either WGS design specifications
or thermodynamics
Simulation of acid gas removal based on design specifications
Modeling of H2/syngas combustion step
Modeling of heat exchanging among multiple streams
Determines power consumption for gas compression
Simulates heat exchange for syngas cooling and preheating
Calculates power produced from gas turbine and steam turbine
254 | Energy Environ. Sci., 2008, 1, 248–267
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based approach. Both approaches can process syngas derived
from coal or any other carbonaceous feedstock. The chemical
looping approach can also process coal or other carbonaceous
feedstock directly. These approaches are elaborated below.
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4.1 Membrane based gasification systems
A membrane is a selective barrier between two phases. The molecules or small particles can transport from one phase to the other
through the membrane. A H2 or CO2 selective membrane can be
utilized in gasification processes to reduce the energy penalty for
CO2 capture and to enhance the hydrogen/electricity generation.
The selective nature of a membrane can be attributed to one or
more of the following mechanisms: (a) Knudson diffusion; (b)
surface diffusion; (c) capillary condensation; (d) molecular
sieving; (e) solution diffusion; and (f) facilitate transport.88 As the
smallest diatomic molecule, hydrogen can be separated from
other gaseous species involved in the coal gasification process
based on all the mechanisms stated above. On the other hand,
most CO2 selective membranes are based on either solution
diffusion or facilitate transport mechanism since the CO2 molecule is significantly larger. An amine based carrier is often used to
facilitate the transportation of CO2 from the retentate side to the
permeate side.88,89 As a result, a hydrogen selective membrane
can be made of metallic, inorganic (ceramic), porous carbon,
polymer, or hybrid materials while most of the CO2 selective
membranes for separating CO2 from hydrogen are polymeric.
The desirable features of a membrane include good permeability, selectivity, reliability, and tolerance to contaminants. For
commercial applications in gasification processes, it should
also be affordable, thermally stable, and durable. Of all the
H2-selective membranes, metallic membranes and ceramic
membranes are the most extensively studied.90–95
The metallic H2-selective membranes generally have a very
high selectivity and thermal stabilities. The potential candidates
include palladium, platinum, tantalum, niobium, and vanadium.88,90,93 Among these metals, Pd-based membranes, although
relatively costly, have demonstrated the highest selectivity and
good permeability and thermal stability. However, the presence
of hydrogen at below 300 C can cause the embrittlement of the
Pd-based membrane due to the Pd–H phase transition. In order
to reduce the membrane degradation as well as to reduce the cost,
Pd-based membranes are often alloyed with Ag, Au, Y, Cu, or
Se. These alloys are processed into a layer as thin as blow 1 mm
and then doped on top of a porous ceramic or metallic
support.94,96 By alloying and supporting, the usage of Pd is
minimized with increased physical strength of the membrane.94
One major challenge to Pd-based membranes is that the presence
of sulfur compounds such as H2S and COS under elevated
temperatures can poison the Pd-based membranes. Recent
studies indicate that alloying can increase the sulfur tolerance of
the membrane.97 However, a high sulfur content that is close to
or beyond the thermodynamic limit for the formation of stable
sulfides will nevertheless deactivate the membrane.92 In addition,
when ceramic support is used in the Pd-based metallic
membrane, it will be necessary to resolve such issues as the
mechanical strength of the support and the large difference in
thermal expansion coefficients between the metallic membrane
and the ceramic support. For metallic support, the challenge lies
This journal is ª The Royal Society of Chemistry 2008
in the stability of the crystal structure due to inter-metallic
diffusion. Therefore, desirable improvements in the Pd-based
membrane for gasification applications include further reduction
in cost coupled with increased durability, sulfur tolerance, and
H2 flux. Besides the Pd-based metallic membranes, non Pd-based
alloys98 and amorphous metals93,99 are also under investigation
with the prospect of developing less costly metallic membranes
with satisfactory performance.
Ceramic H2-selective membranes such as porous silica- and
zeolite-based membranes represent another category of promising hydrogen separation materials.100–102 Both membranes are
microporous inorganic membranes comprised of a membrane
layer, an intermediate layer, and a support. These membranes
have several advantages when compared to metallic membranes
including low cost, ease of fabrication, and less susceptibility to
H2 embrittlement. Moreover, very high hydrogen permeability
can be achieved using an ultra-thin amorphous silica membrane.
However, improvements that need to be made in these
membranes include selectivity, defect reduction, thermochemical
stability and operational stability. Table 4 generalizes the
performances of existing H2-selective membranes as compared to
the 2010 performance target set by the US DOE.
Although zeolite-based membranes can be used to selectively
remove CO2 from other gases such as N2 and CH4 based on
adsorption preference,105,106 very limited studies have been performed on the separation of CO2 from H2 using such
membranes.51 Other attempts include those performed by Air
Products and Chemical Inc. that use nanoporous carbon-based
membranes to separate CO2 from the tail gas of the Pressure
Swing Adsorption (PSA) unit.107,108 However, these membranes
have relatively low CO2 selectivity over H2.107–109 To date, most
CO2-selective membranes for separating CO2 from H2 are polymeric membranes based on either solution diffusion mechanism
or facilitate transport mechanism.89,110–113 The challenges to the
polymeric CO2-selective membranes include limited operating
temperature and relatively low CO2/H2 selectivity and flux.
As mentioned in Section 3, the WGS reactor(s) and the CO2
separation units consume a significant amount of parasitic
energy for the coal to hydrogen process and IGCC process with
CO2 capture. The applications of the H2- or CO2-selective
membranes in coal gasification systems for the intensification of
the CO shift and hydrogen purification steps have been extensively studied during the last decade.
Table 4 Performances of H2-selective membranes88,92,101,103,104
Membrane type
Metallic
Porous
ceramic
DOE 2010
target
T/ C
300–900
300–700
300–600
Operating DP/MPa
0.69
0.4
2.75
Selectivity
>1000
5–139
N/A
Maximum flux/
SCFH ft2
60–300
60–300
200
Sulfur tolerance/ppm
Low
> Metallic
20
Cost/USD ft2
>1500 (Pt-based)
400
100
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Fig. 7 Multiple stage membrane system for CO2 recovery.114
Several different configurations using different types of
membranes have been investigated, exhibiting promising results.
Fig. 7 shows a multi-stage membrane system that recovers CO2
from a shifted syngas stream proposed by Kaldis et al.114 In this
process, the clean syngas stream resulting from the coal gasifier
and gas cleanup units is first shifted in a series of WGS units,
resulting in a gaseous mixture consisting mainly of H2, CO2, CO,
and N2. The mixed gas is then introduced to a series of
H2-selective membranes to recover a concentrated CO2 stream
on the retentate side. The permeate side, with concentrated
hydrogen, is combusted in the gas turbine for electricity generation. The performances of both polymer and ceramic
membranes are investigated using ASPEN Plus simulations.
The results indicated that the CO2 emission can be reduced by
over 50% using the multi-stage membrane system but with 17–
28% parasitic energy consumptions.114
More advanced membrane systems integrate the function of
both WGS and CO2 separation using either H2- or CO2-selective
membranes. Such configurations are shown in Figs. 8a and
b.63,92,115–120
Fig. 8 (a) Schematic of H2-selective membrane enhanced IGCC process.118 (b) Schematic of CO2-selective membrane enhanced IGCC process.118
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Fig. 8a illustrates a specific configuration when a H2-selective
membrane is used.63,92,115,117–119 In such a configuration,
a conventional gasifier and a gas clean up system is used to
produce clean syngas. The clean syngas is then sent to the
membrane–WGS reactor. The membrane–WGS reactor has two
compartments, i.e. reaction side and product side. The two
compartments are segregated by a semi-permeable membrane
that is selective to hydrogen. In the reaction side, the CO in the
syngas is converted to H2 and CO2 via WGS reaction. The H2
produced in the reaction side is continuously permeated through
the membrane to the product side. As a result, a high purity H2
product can be obtained without engaging traditional separation
techniques. Such hydrogen can either be used as a product or
combusted with air for power generation. In addition, due to the
removal of the hydrogen product, the WGS reaction, which is
limited by thermodynamic equilibrium, can be enhanced. The
tail gas from the reaction side, with a high CO2 concentration
mixed with residual CO and H2, is combusted in a combined
cycle system with O2 to generate electricity. The resulting CO2 is
then sequestered.
The underlying principle for the membrane-based system
shown in Fig. 8b116,118 is similar to that of the system shown in
Fig. 8a. The only difference lies in the type of membrane used for
separating the shifted syngas. In this configuration, a CO2selective membrane is used to divide the reaction side and the
product side in the membrane reactor. As a result, the CO2 rather
than the H2 will be transferred from the reaction side to the
product side. The simultaneous removal of CO2, which is
another product of the WGS reaction, can also enhance the
reaction. The CO2 stream in the product side, swept by steam,
can be directly sequestered while the H2-rich stream in the
reaction side can either be purified to obtain a hydrogen product
or combusted with air for power generation.
Extensive studies have been performed to analyze the performance of gasification processes integrated with membrane
systems. Chiesa et al. (2007)119 indicated that although a significant
energy penalty has to be paid for CO2 capture, a Pd-based
membrane system such as that shown in Fig. 8a is thermodynamically advantageous when compared to commercial WGS–
CO2 capture systems. A process analysis carried out by Amelio
et al. (2007)115 indicated that if integrated with an IGCC system
using a GE gasifier, an energy penalty around 17.5% (46.0% before
capture to 39.3% HHV after capture) will incur when a Pd-based
H2-selective membrane system is used to capture 90% of the CO2.
Grainger et al. (2008)116 studied the performance of a CO2-selective
polyvinylamine membrane in an IGCC system identical to the
Puertollano plant. The results revealed a 22.9% energy penalty for
85% CO2 capture. Carbo et al.118 compared the performance of
a H2-selective membrane system to that of a CO2-selective
membrane in an IGCC process with an entrained flow, oxygen
blown gasifier. The results indicated that the energy penalty is
merely 11.2% when a H2-selective membrane is used for 100% CO2
capture. In contrast, a 19.4% energy penalty will incur when a CO2selective membrane is used for 90% CO2 capture. The selectivity of
both membranes was assumed to be infinity in this study.
A more advanced approach integrates a H2-selective
membrane into the gasifier for H2 generation (Fig. 9).121 In this
case, a membrane is installed in the coal gasifier to separate out
the hydrogen generated. The rest of the syngas is combusted with
oxygen for power generation. Such a process, although potentially more efficient, requires a membrane that tolerates ultrahigh temperatures and various contaminants. The development
of such high performance membranes may not be feasible in the
near future.
To generalize, although the membrane systems can not eliminate the energy penalty for CO2 capture in gasification plants,
they have the potential to reduce such a penalty when compared
to the traditional approach. The parasitic energy consumed for
CO2 capture using a membrane-based system lies in the need for
gas compression, and in some cases, the generation of extra
oxygen to combust the CO2 rich tail gas and the need for extra
steam as sweep gas. It is also worth noting that from the
economic standpoint, the membrane-WGS reactor can replace
both the shift unit and CO2 separation unit. Therefore, notable
cost reduction can be realized provided that a membrane with
good reliability and durability can be mass-produced at
a reasonable cost.
4.2 Chemical looping based gasification systems
As discussed in Section 4.1, membrane-based systems intensify
the syngas conversion scheme by integrating the CO shift and
Fig. 9 Integrated membrane separation with gasifier.121
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the CO2 removal step. Due to the limited tolerance of
membranes towards pollutants such as sulfur and halogen
compounds, the raw syngas from the gasifier needs to be
extensively cleaned before entering the membrane system.
Chemical looping based systems have the potential to simplify
the syngas cleaning procedures. Moreover, the pressure drop due
to the membrane separation can be reduced in chemical looping
systems.
The chemical looping strategy that generates the end products
with the aid of chemical intermediates through a series of reaction schemes was proposed many years ago. One example is the
steam-iron process used for commercial hydrogen production
from coal derived producer gas in the early 20th century.122,123
Another example is the CO2 generation, reported a half-century
ago, for the beverage industry using the chemical looping process
with the oxides of copper or iron as the looping particles.124,125
Although the adoption of the chemical looping strategy in the
early years was mainly prompted by the lack of effective chemical
conversion/separation techniques in the product generation,
modern applications of chemical looping processes are prompted
by the need for developing an optimized reaction scheme that
minimizes the exergy loss involved in the chemical/energy
conversion system.126–128 Also driven by the envisaged CO2
emission control, the recent development in chemical looping
systems have focused on the efficient conversion of gaseous
carbonaceous fuels such as natural gas and coal derived
syngas,53,128–131 and solid fuels such as petroleum coke and
coal132,133 while separating CO2 readily through the looping
reaction scheme. In this section, chemical looping systems using
coal derived syngas will be discussed. Looping systems that
directly convert coal will be presented in Section 4.3.
In this section, two types of chemical looping based
approaches that enhance the performance of the coal gasification
processes are given. Type A chemical looping such as the Syngas
Chemical Looping Combustion (Syngas–CLC) processes and the
Syngas Chemical Looping (SCL) process use oxygen carrier
particles, typically metal oxides, to convert coal derived syngas,
whereas Type B chemical looping such as the Calcium Looping
Process (CLP) and the Thermal Swing Sorption Enhanced
Reaction (TSSER) process utilize solid CO2 sorbents to enhance
the syngas conversions.
4.2.1 Type A chemical looping. Based on the type of the end
product, the Type A chemical looping processes can be divided
into two sub-categories, i.e., chemical looping combustion85,134–136
where the chemical intermediate is first reduced and then combusted with air to generate heat, and chemical looping gasification131,137–139 where fuel gas such as hydrogen is produced.
Syngas chemical looping combustion. Fig. 10 shows a typical
chemical looping combustion process using coal derived syngas
as feedstock. As can be seen, coal is first gasified into raw syngas.
A set of gas cleanup units is then used to remove the contaminants
to a level below the tolerance limit of the oxygen carrier particle
used in the process. The cleaned syngas then reacts with the
oxygen carrier particles in the first reactor which is noted as the
reducer or the fuel reactor. The main reactions in this reactor are:
MeO + H2 / Me + H2O
(3)
MeO + CO / Me + CO2
(4)
As can be seen from reaction 3 and 4, the syngas is oxidized to
CO2 and steam by the metal oxide particles before exiting the
reducer. A concentrated CO2 stream can then be readily obtained
by condensing out the steam in the reducer. The CO2 stream can
be further pressurized and transported for sequestration.
Meanwhile, the reduced metal oxide particles will be introduced
to the second reactor, i.e. the combustor or the air reactor, to
react with air:
Me + 1/2O2(Air) / MeO
(5)
The oxidization reaction in the combustor is highly
exothermic. As a result, a high temperature, high pressure,
oxygen depleted exhaust gas stream is generated from the
combustor. Such an exhaust gas stream is used to drive
a combined cycle system for electricity generation. Meanwhile,
Fig. 10 Schematic flow diagram of syngas chemical looping combustion processes.
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the particles, fully regenerated by air, are recycled to the reducer
for another redox (reduction–oxidation) cycle.
In the CLC process, the coal derived syngas is combusted with
air indirectly through the looping particles, i.e., metal oxide.
Hence, the fuel combustion products, i.e., CO2 and steam are not
diluted by nitrogen in the air, and the CO2 separation from
nitrogen is, therefore, avoided. Moreover, the syngas cleanup
steps can potentially be simplified since the metal oxide particles
can be more robust towards contaminants when compared to
membranes.85 As a result, the acceptable level of the contamination in the syngas for chemical looping processes can be higher
than the membrane based systems. An additional advantage for
the looping system is that the difference between the pressure of
the concentrated CO2 exhaust and that of the syngas feedstock is
merely the pressure drop of the reducer, which can be significantly lower than the pressure drop in the solvent-based and
membrane-based CO2 separation system.
The focal areas of the research and development activities on
the CLC processes are on the oxygen carrier particle design and
synthesis, looping reactor design and operation, and looping
process analysis and demonstration. Various types of oxygen
carrier particles, including the oxides of Ni, Fe, Mn, Cu, and Co,
have been investigated for syngas chemical looping combustion.129,140–142 Most of the studies focus on developing particles
that maintain good reactivity for multiple redox (reduction–
oxidation) cycles. Other factors being considered include particle
strength improvements and carbon deposition reduction. In
order to obtain particles with the desirable properties, ceramic
materials are often used to support the oxygen carrier. These
supporting materials include alumina, MgAl2O4, yttria-stabilized zirconia (YSZ), TiO2, bentonite, and barium–hexaaluminate (BHA). Metal oxide particles that can sustain
multiple redox cycles in atmospheric reactor systems have been
successfully synthesized. Important areas that need to be further
explored include the pollutant tolerance of the particles and
particle reactivity under elevated pressures. For instance,
experiments in a high pressure TGA indicated that an increase in
total pressure may have negative effects on the reduction rates of
Cu, Ni, and Fe based oxygen carriers.143 This finding, however,
was inconsistent with that obtained by Siriwardane et al. (2007)
using NiO supported on bentonite.141 Jin and Ishida (2004)
studied the pressure effect on the reactivity of NiO supported on
MgAl2O4 under 0.1–0.91 MPa (1–9 atm) using a fixed bed
reactor.129 They found that an increased carbon deposition under
elevated pressures, which was consistent with that predicted from
thermodynamic principles.85 An increased oxidation reaction
rate was also observed under higher pressure by Jin and Ishida
(2004);129 however, the pressure effect on the reduction reaction
rate was not reported.
The syngas CLC process was tested in a 300 Wth (watts
thermal) circulating fluidized bed chemical looping combustor at
Chalmers University in Sweden.144–146 Different types of oxygen
carrier particles including NiO supported on MgAl2O4,144 Fe2O3
supported on Al2O3,147 and Mn3O4 supported on Mg stabilized
ZrO2148,149 have been used, yielding 99% or higher syngas
conversions. Other CLC testing facilities include the 10 kWth
circulating fluidized bed unit at Chalmers University,130 the 50
kWth circulating fluidized bed unit at Korea Institute of Energy
Research (KIER),150 and the 120 kWth circulating fluidized bed
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unit at Vienna University of Technology.151 The published
experimental results obtained from these testing facilities focus
on the conversion of methane.
Both thermodynamic and ASPEN plus simulations have
been performed for the chemical looping combustion systems
with syngas as feedstock. The exergy analysis conducted by
Anheden and Syedberg (1998) indicated that when a CLC system
with a Fe2O3-based oxygen carrier particle is used to a retrofit
IGCC plant, a 7.8% increase in exergetic efficiency compared to
a base case can be realized (from 45.19 to 48.72%).126 In their
study, however, the energy for CO2 compression was not
considered. The ASPEN simulation conducted by Xiang et al.
(2008) indicated that the gasification–CLC system has the
potential to achieve 43.2% (LHV) efficiency for electricity
generation with 99% CO2 captured.134
The performance of the syngas chemical looping combustion
processes is dependent on two closely related factors, i.e. the
oxygen carrier particle performance and the reactor design.
Many research efforts on the CLC system have focused on the
development of reactive and recyclable particles, given that
fluidized bed reactors are to be used as the looping reactors. In
fact, various factors need to be considered in selecting a particle,
i.e., particle oxygen carrying capacity, reactivity, recyclability,
cost, physical strength, oxygen carrying capacity, contaminant
tolerance, melting points, and environmental effects. On the
looping reactor, the use of fluidized bed reactor is evidenced by
extensive on-going studies of high density circulating fluidized
bed systems in which the riser serves as the combustor and the
downer in bubbling or turbulent mode of operation serves as the
reducer in chemical looping combustion applications.44,144,149,152
It should be noted, however, that reactor design can have
a significant effect on particle conversion, and hence the process
efficiency. Table 5 illustrates the effect of the flow pattern, i.e.,
fluidized bed or countercurrent moving bed in the fuel reactor on
the solid particle conversion when a Fe based oxygen carrier
particle is used. The results given in the table are based on the
thermodynamic analysis and the assumptions presented in the
table.
It is seen that the theoretical solid conversion in the moving
bed is nearly five times higher than that in the fluidized bed,
resulting in significantly reduced solid circulation rate for the
Table 5 Reducer performances using different reactor designs
Reactor type
Oxygen carrier
Maximum metal
oxide conversionb (%)
Effective oxygen
carrying capacityc (wt %)
CO + H2 concentration
in gas exhaust (%)
Countercurrent
moving bed
Fluidized bed/CSTRa
Fe2O3
51.5
Fe2O3
11.27
10.82
2.37
0.005
0.005
a
To account for back mixing in the fluidized bed reducer, the fluidized
bed reactor is considered as CSTR.b Maximum metal oxide reduction at
850 C when more than 99.9% syngas (CO : H2 ¼ 2 : 1) is converted.
Results were obtained based on thermodynamic analysis.153c Effective
oxygen carrying capacity ¼ Maximum oxygen carrying capacity Metal
oxide loading Maximum theoretical metal oxide conversion (metal
oxide loading is 70% in this case).
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Fig. 11 Simplified schematic of the Syngas Chemical Looping process.
moving bed design and hence minimized reactor volume. Thus,
for a successful CLC system operation, flow pattern consideration for the reactor is deemed important.
Syngas chemical looping gasification. Compared to the CLC
processes, the Syngas Chemical Looping (SCL) process has the
flexibility to co-produce hydrogen and electricity.131,137–139 Fig. 11
shows a simplified block diagram of the SCL process developed
at the Ohio State University.
The SCL process can convert syngas with moderate levels of
HCl, NH3, sulfur, and mercury; therefore, existing hot gas
cleanup units (HGCU) will be adequate for raw syngas cleaning.
The raw syngas exiting the HGCU will be introduced to the
reducer, which is a moving bed of specially tailored iron oxide
composite particles operated under a pressure similar to that of
the syngas. In this reactor, the syngas is completely converted
into carbon dioxide and water while the iron oxide composite
particles are reduced to a mixture of Fe and FeO under 750–
900 C:
Fe2O3 + CO / 2FeO + CO2
(6)
FeO + CO / Fe + CO2
(7)
Fe2O3 + H2 / 2FeO + H2O
(8)
FeO + H2 / Fe +H2O
(9)
Fe + H2O (g) / FeO + H2
(10)
3FeO + H2O (g) / Fe3O4 + H2
(11)
The steam used in the oxidizer is produced from the heat
released from syngas cooling and reducer/oxidizer exhaust gas
cooling. In the SCL process, the oxidizer is slightly exothermic
while the reducer can either be slightly exothermic or slightly
endothermic depending on the syngas composition. Therefore,
both reducer and oxidizer are operated under the adiabatic
conditions. Heat is provided to or removed from the reactors by
the oxygen carrier particles and the exhaust gas. The Fe3O4
formed in the reducer reactor is regenerated to Fe2O3 in an
entrained flow combustor which also transports solid particles
discharged from the oxidizer to the reducer. A portion of the heat
produced from the oxidation of Fe3O4 to Fe2O3 can be transferred to the reducer through the particles:
4Fe3O4 + O2 / 6Fe2O3
Similar to the CLC processes, an exhaust stream with
concentrated CO2 can be obtained from the reducer. The
contaminants in the syngas will also exit the reducer with the CO2
stream without attaching to the particle. These contaminants can
be compressed and sequestered along with CO2 if allowed by
regulation. As a result, the gas cleaning procedures are greatly
simplified.
The Fe/FeO particles leaving the reducer are then introduced
into the oxidizer which is operated at 500–750 C at a pressure
similar to that of the reducer. In the oxidizer, the reduced
260 | Energy Environ. Sci., 2008, 1, 248–267
particles react with steam to produce a gas stream that contains
solely H2 and unconverted steam. The steam can be easily
condensed out to obtain a high purity H2 stream. The reactions
involved in the oxidizer include:
(12)
The high pressure (>2.5 MPa, depending on the gasifier type),
high temperature (>1000 C), spent air produced from the
combustor can be used to drive a gas turbine–steam turbine
combined cycle system to generate electricity for parasitic energy
consumptions. In yet another configuration, a fraction or all of
the reduced particles from the reducer can bypass the oxidizer
and be introduced directly to the combustor if more heat or
electricity is desired. Hence, both chemical-looping reforming
and chemical-looping combustion concepts are applied in the
SCL system, rendering it a versatile technology for H2 and
electricity co-production.
The SCL process has been tested at Ohio State University
(OSU) in a 2.5 kWth bench scale moving bed unit for a combined
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operating time of >100 h.154 Current testing results indicate) >99.9% syngas conversion in the reducer and >99.95%
purity hydrogen stream from the oxidizer. Nearly full conversion
of gaseous hydrocarbons such as CH4 was also obtained. A 25
kWth SCL demonstration unit is being constructed at OSU. The
process analysis based on the bench scale testing results indicated
that the overall efficiency for the SCL process can exceed 64%
(HHV) with 100% CO2 capture. For comparison, the efficiency
of a traditional coal-to-hydrogen process with 90% CO2 capture
is estimated to be 57% (HHV).155
Besides serving as a stand alone hydrogen/electricity producer,
the SCL process can be integrated into other processes to
improve the overall energy conversion scheme. Fig. 12 exemplifies the integration of the SCL process to the state-of-the-art
Coal-to-Liquids (CTL) process.156 In this configuration, the SCL
system converts the C1–C4 products from the Fischer–Tropsch
(FT) reactor into H2 and recycles it to the F–T reactor as feedstock, resulting in a 10% increase in the liquid fuel yield and
a 19% reduction in CO2 emissions.157
Oxygen carriers other than iron oxide such as NiO were also
explored for hydrogen generation from syngas. The experiments
carried out in a 20 mm I.D. fixed bed reactor, however, indicated
that Fe is a more favorable choice than Ni.158,159 Svodoba et al.
(2007,2008)160,161 also examined, using thermodynamic principles,
the feasibility of using Fe, Mn, Ni, Cr, and Co based particles for
hydrogen production. They concluded that Fe–Fe3O4 is more
suitable for chemical looping gasification compared to other
particles; however, they further stated that Fe3O4 is more difficult
to reduce based on a fluidized bed design. Xiang et al. (2007)
performed ASPEN Plus simulation on an iron-based looping
system for hydrogen generation.162 In their system, reduced iron
oxide is only regenerated to Fe3O4 rather than Fe2O3. As a result,
a significant amount of syngas will leave the reducer unconverted.
Based on the simulation results, the system has an energy
conversion efficiency as high as 58.33% (LHV).
4.2.2 Type B chemical looping systems. The Type B chemical
looping system uses a CO2 sorbent to enhance the WGS reaction
of syngas by simultaneous removal of the CO2 generated during
the shift reaction. The sorbents include CaO, which is used in the
Calcium Looping Process (CLP), and K2CO3 promoted hydrotalcite and Na2O promoted alumina, both used in the thermal
swing sorption–enhanced reaction (TSSER) process.
Calcium looping process (CLP). Fig. 13 shows the schematic
integration of the calcium looping process in a typical coal
gasification system for the production of hydrogen.52,156,163,164
As shown in Fig. 13, the calcium looping process comprises
two reactors: the carbonation reactor (carbonator), which
produces high purity hydrogen while removing contaminants,
and the calciner, where the calcium sorbent is regenerated and
a concentrated CO2 stream is produced. The carbonator is
operated at 550–650 C and 2–3 MPa (20–30 atm). In the carbonator, the CO2 generated by the WGS reaction is simultaneously removed by a CaO sorbent. The mesoporous,
precipitated calcium carbonate (PCC–CaO) sorbent has much
higher reactivity and CO2 capture capacity (40–36 wt % for 50th–
100th cycles) when compared to most of the high temperature
Fig. 13 Schematic flow diagram of the calcium looping process.
Fig. 12 Syngas Chemical Looping enhanced Coal-to-Liquids (SCL–CTL) process.
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sorbents reported in the literature. Moreover, it is capable of
capturing the sulfur and halides in the raw syngas stream. Hence,
the high performance PCC–CaO sorbent captures the pollutants
in the syngas while driving the thermodynamic equilibrium of the
WGS reaction towards the formation of hydrogen until 100% of
the CO is consumed. As a result, high purity hydrogen with very
low concentration of H2S, COS, and HCl can be produced with
drastically reduced steam consumption (H2O : CO ¼ 1 : 1).
The reactions occurring in the carbonator are as follows:
CO + H2O / H2 + CO2
(13)
CaO + CO2 / CaCO3
(14)
CaO + H2S / CaS + H2O
(15)
CaO + COS / CaS + CO2
(16)
CaO + 2HCl / CaCl2 + H2O
(17)
The spent sorbent, consisting mainly of CaCO3, is then recycled to the calciner, where heat is provided to regenerate the
carbonated sorbent. The calciner operates at 800–1000 C and
ambient pressure.
CaCO3 / CaO + CO2
(18)
A mixture of CO2 and steam will be produced from the
calciner. After condensing the steam, CO2 can be compressed
and transported for sequestration.
Hence, this technology provides an efficient ‘‘one box’’ mode
of operation for the production of high purity hydrogen with
CO2, sulfur and chloride capture that integrates the WGSR, CO2
capture, sulfur removal and hydrogen separation in one
consolidated unit. High purity hydrogen (>99.9%) was produced
from a lab scale testing unit. ASPEN Plus simulations showed
that the overall efficiency of the process for hydrogen production
is 63% (HHV).156 The large amount of heat required for the
calcination reactor and the sorbent reactivity after regeneration
under an elevated temperature represents a major challenge to
the CLP.
Thermal swing sorption-enhanced reaction (TSSER) process.
The TSSER process also uses CO2 sorbent to enhance the WGS
reaction and H2 production. The differences between the TSSER
process and the CLP lie in the sorbent properties, reactor system
design, and operating conditions. The sorbents used in the
TSSER process such as K2CO3 promoted hydrotalcite and Na2O
promoted alumina cannot capture pollutants from syngas;
therefore, the contaminants in the syngas need to be removed
before entering the sorbent bed. Moreover, the TSSER is
composed of multiple (fixed) sorbent beds operating in
a sequential manner, which is similar to the operations of the
PSA system. The TSSER process is currently under the lab scale
testing. Fuel cell grade hydrogen has been produced from a 17.3
mm diameter fixed bed reactor.165,166 The potential challenges to
the TSSER process include a relatively low CO2 capture capacity
of the sorbent (<4.4 wt %)166 and constant temperature and
pressure swings in fixed beds under relatively high temperature
(300–550 C).
262 | Energy Environ. Sci., 2008, 1, 248–267
Sorbent regeneration represents a crucial step to Type B
chemical looping processes. Since a significant amount of heat is
required for sorbent regeneration, an optimized energy integration scheme is necessary in order to achieve high energy
conversion efficiency. Moreover, regeneration conditions can
have notable effects on the sorbent recyclability.
4.3 Direct coal chemical looping processes
Both the membrane and the syngas chemical looping approaches
discussed in the previous sections enhance the conventional coal
gasification processes by integrating the WGS and CO2 removal
steps into the looping scheme. The advanced coal gasification
processes discussed in this section incorporate, not only the WGS
and CO2 removal steps, but also the coal gasification step. As
a result, the coal conversion process is further simplified.
4.3.1 Type A coal chemical looping processes. Type A chemical looping processes react coal directly with oxygen carrier
particles, resulting in reduced particles along with an exhaust gas
stream with concentrated CO2. Therefore, particle reduction and
coal gasification are performed in the same unit. Compared to
the chemical looping processes discussed in Section 4.2, a dedicated coal gasifier is avoided. The Type A chemical looping
gasification processes can be divided into two sub-categories, i.e.
the Chemical Looping Combustion of Coal (CLCC) process, and
the Coal Direct Chemical Looping (CDCL) process.
Chemical looping combustion of coal. Compared to syngas,
coal is more difficult to react. The contaminants in coal that may
react with oxygen carrier particles make a direct oxidation of
coal an even more challenging task. Zhao et al. (2008) proposed
to use NiO based oxygen carrier particles (NiO 60% by weight)
obtained from sol–gel technique to convert coal char.167 A TGA
experiment indicted noticeable coal char–NiO conversion over
a period of 120 min As noted, the major challenge associated
with NiO based looping processes is the high oxygen carrier cost,
which is especially the case when the elaborate sol–gel technique
is used for synthesizing the particle. Further, the slow reaction
kinetics between NiO and char indicates the necessity for a char
gasification promoter.
Yang et al. (2007) proposed to use Fe2O3 as the oxygen carrier
particles to covert coal.168 Fixed bed studies were performed
which indicate that Fe2O3 can be converted to Fe3O4 using coal
volatiles and gasified coal gas (CO and H2). However, reduction
from Fe2O3 to Fe3O4 only utilizes 11.13% of the maximum
oxygen carrying capacity of Fe2O3. Scott et al. (2006) also
utilized Fe2O3 as an oxygen carrier particle169 to convert char in
a small fluidized bed. In their experiments, char was fed into
a small fluidized bed. With the presence of CO2, char was gasified
and then reacted with Fe2O3. It was found that Fe2O3 can only be
reduced to Fe3O4 in the fluidized bed due to thermodynamic
limitations. Cao et al. (2006) proposed to use CuO as an oxygen
carrier particle to combust coal170,171 in a circulating fluidized bed
with only the available data obtained from TGA. It is noted that
the low melting point of Cu/CuO can be a serious issue in its
applications. Studies carried out by others indicate that copper
based particles will deactivate beyond 800 C.172 The low
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operating temperature will lead to significantly reduced energy
conversion efficiency.
The direct coal CLC processes are at the early stage of
development and further studies in particle development, process
design, and analysis are necessary in order to assess the technical
feasibility and the commercial readiness for these processes.
Chemical looping gasification of coal—coal direct chemical
looping process. The coal direct chemical looping (CDCL)
process, illustrated in Fig. 14, is capable of converting coal into
hydrogen and/or electricity at any relative proportions.137,138,156,173 In the CDCL process, composite Fe2O3 particles are introduced into the reducer to react with pulverized coal.
The reducer is a two-stage moving bed reactor, which provides
a desired gas–solid contacting pattern. In the reducer, coal is
gasified in-situ and reacted with Fe2O3 particles. Thus, a mixture
of Fe and FeO is produced along with a flue gas stream
composed of CO2, H2O, and contaminants such as H2S and
elemental mercury. After condensing out the steam, the flue gas
can be compressed and sequestrated. A portion of the reduced
Fe/FeO particle from the reducer will enter the oxidizer to react
with steam to form hydrogen. The resulting Fe3O4 exiting the
oxidizer along with the remaining portion of the reduced Fe/FeO
particle will be combusted with air in the entrained flow
combustor. The combustor conveys the particle back to the
reducer pneumatically while regenerating the particle to its
original oxidized form. Part of the heat released in the combustor
will be carried to the reducer by the hot particles to compensate
the endothermic heat required in the reducer. The remaining heat
released in the combustor heats up the exhaust gas, which can be
used for steam or electricity generation.
The CDCL process testing has been carried out in the 2.5 kWth
bench scale moving bed unit at OSU. Different feedstock such as
coal volatiles (simulated), lignite coal char, bituminous coal char,
and anthracite coal have been tested. Coal/coal char conversion
of as high as 95.5% has been obtained. The CO2 concentration in
the exhaust stream was >97% (dry basis) in all cases. Moreover,
the reactivity of the particles was maintained after three redox
cycles in which coal was used as the reducing agent. ASPEN
Plus simulation showed that the energy conversion efficiency of
Fig. 14 Schematic diagram of Coal-Direct Chemical Looping process.
This journal is ª The Royal Society of Chemistry 2008
the CDCL process was higher 80% (HHV) for hydrogen
production and over 50% for electricity generation with zero
carbon emissions.156,174
4.3.2 Type B coal chemical looping process. The Type B coal
chemical looping process utilizes high temperature CO2 sorbents
such as calcium oxide to enhance the coal gasification and
hydrogen production.
HyPr-Ring process. Similar to the CO2 Acceptor process
developed by the Consolidation Coal Company in the 1960’s, the
HyPr-Ring process developed in Japan involves coal gasification
using pure oxygen and steam.175–178 Fig. 15 illustrates the HyPrRing process. In this process, coal is fed to the gasifier along with
calcium oxide, steam and oxygen. The presence of excessive
steam and the in-situ CO2 removal by calcium oxide drives the
equilibrium in the gasifier towards the formation of H2. As
a result, a product gas stream of up to 90% H2 mixed with
methane, other hydrocarbons, and sulfur and nitrogen based
contaminants is generated.178 The solids from the gasifier consist
mostly of saturated CaO sorbents (CaCO3) and unconverted
carbon that is to be introduced to a regenerator along with
oxygen. The heat generated by combusting the unreacted carbon
by oxygen allows the calcination reaction to be carried out for
CaO regeneration while producing high purity CO2 for sequestration. The challenges for the HyPr-Ring process include the
deactivation of CaO in the presence of coal ash176 and relatively
low purity hydrogen product from the gasifier. The HyPr-Ring
process is currently under demonstration in a pilot scale unit with
a coal processing rate of 3.5 kg h1. Process analysis showed that
a 77% cold gas efficiency (HHV) can be achieved when CO2
compression was not taken into account.175
Different from either Type A or Type B chemical looping
systems, the GE Fuel–Flexible Process179,180 and the ALSTOM
Hybrid Combustion–Gasification Chemical Looping process181
employ two separate looping particles, i.e., an oxygen carrier and
a CO2 sorbent, to carry out the coal conversion. Thus, there are
two separate looping schemes in each of these two looping
processes. In these processes, the CO2 sorbent is used to enhance
the hydrogen generation while the oxygen carrier is either used
for indirect combustion of fuel to provide the heat needed for
spent sorbent reactivation or used for coal gasification. These
processes can convert coal into a variety of products with in-situ
carbon dioxide capture. The mixing between the oxygen carrier
Fig. 15 Schematic diagram of HyPr-Ring process.175
Energy Environ. Sci., 2008, 1, 248–267 | 263
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particles and sorbent particles as well as significantly large solid
handling requirements render these processes more difficult to
operate as compared to chemical looping processes that involve
single chemical reaction loop.
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5. Concluding remarks
Coal will remain to be an important energy source well into the
21st century. With a strong demand for an affordable energy
supply which is compounded by the urgent needs for CO2
emission control, the clean and efficient utilization of coal
represents both a major opportunity and challenge to current
global R&D efforts in this area.
The coal conversion processes of the future prospect are
plotted in Fig. 16 along with the current or demonstrated
processes for electricity and/or H2 production. These efficiencies
are given considering a CO2 controlled environment. The
processes considered in the figure include sub-critical and ultra
supercritical PC processes retrofit with either MEA or chilled
ammonia system for CO2 capture, coal gasification processes
using the SELEXOL system for CO2 capture, the H2-selective
membrane based gasification process, syngas chemical looping
processes, and the coal direct chemical looping process (CDCL).
It is seen that in terms of electricity or H2 generation, the
efficiencies for syngas chemical looping processes and H2-selective membrane process are comparable and could be considered
as near term retrofit technology for current coal gasification
processes. Of particular noteworthiness is the CDCL process,
which shows considerably higher energy conversion efficiency
than all the other processes considered. The direct coal chemical
Fig. 16 Efficiency comparisons among various coal conversion technologies with >90% CO2 capture†
† Key Assumptions for Fig. 16:
Illinois #6 coal is used in all cases;
For SCL, Syngas–CLC, IGCC–Selexol, and Gasification–WGS, a GE
quench gasifier is used. A GE 7H gas turbine combined cycle system is
used to generate electricity;
Sub-critical plant operates at 17.5 MPa/538 C/538 C, ultra-supercritical
plant operates at 26 MPa/600 C/600 C;
CO2 is compressed to 15.20 MPa (150 atm) for sequestration.
264 | Energy Environ. Sci., 2008, 1, 248–267
looping processes can emerge as attractive clean coal conversion
systems for the intermediate term.
Coal is used as the feedstock in the current discussion. The
application of the technologies discussed in this paper, however,
is extendable to other carbonaceous feedstock such as petroleum
coke, biomass, and refuse derived fuel. From the small scale
testing results, it is encouraging that the novel coal conversion
process based on chemical looping and membrane concepts may
become commercially viable in the foreseeable future. And the
direct coal chemical looping processes may become a reality.
Acknowledgements
This work has been supported by the Ohio Coal Development
Office of the Ohio Air Quality Development Authority, U. S.
Department of Energy, Ohio State University and an industrial
consortium.
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