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Power generation from coal and biomass based on integrated gasification combined cycle concept with pre- and post-combustion carbon capture methods.

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Asia-Pac. J. Chem. Eng. 2009; 4: 870–877
Published online 20 July 2009 in Wiley InterScience
( DOI:10.1002/apj.354
Special Theme Research Article
Power generation from coal and biomass based on
integrated gasification combined cycle concept with
pre- and post-combustion carbon capture methods
Calin-Cristian Cormos,* Ana-Maria Cormos and Serban Agachi
Babes-Bolyai University, Faculty of Chemistry and Chemical Engineering, Arany Janos Street, No. 11 RO-400028, Cluj-Napoca, Romania
Received 1 April 2008; Revised 27 April 2009; Accepted 28 April 2009
ABSTRACT: Gasification technology is a process in which solid fuel is partially oxidised by oxygen and steam/water
to produce a combustible gas called syngas (mainly a mixture of hydrogen and carbon monoxide). Syngas can be
used either for power generation or processed to obtain various chemicals (hydrogen, ammonia, methanol, etc.). This
article evaluates the possibilities of solid fuel decarbonisation by capturing carbon dioxide resulted form thermochemical conversion of solid fuel using gasification. Evaluation is focused on power generation technology using
syngas produced by solid fuel gasification (so-called integrated gasification combined cycle – IGCC). Case studies
analysed in the article are using a mixture of coal and biomass (sawdust) to produce around 400 MW electricity
simultaneously with capturing about 90% of the feedstock carbon. Various carbon dioxide capture options (post- and
pre-combustion) are compared with situation of no carbon capture in terms of plant configurations, energy penalty,
CO2 emissions, etc. Plant options are modelled using ChemCAD, and simulation results are used to assess the plant
performances. Plant flexibility and future improvements are also discussed.  2009 Curtin University of Technology
and John Wiley & Sons, Ltd.
KEYWORDS: gasification; IGCC; coal and biomass; carbon capture and storage (CCS)
Energy issue is important and actual considering the
need of security for energy supply, environmental
protection and climate change prevention by reducing
the greenhouse gas emissions. It is known that solid
fossil fuels reserves (mainly coal and lignite) ensure
a greater energy independence compared with liquid
fossil fuels (oil) or gaseous fossil fuels (natural gas),[1]
but coal utilisation is looked with concern because of
bigger greenhouse gas emissions (CO2 ). For example,
for production of 1 MW electricity, the carbon dioxide
emission in case of natural gas is about 350–400 kg
and in case of coal, the carbon dioxide emission is
about 800–900 kg.[2,3] The main aim of this study is
to evaluate various methods for CO2 capture applicable
to energy conversion process by solid fuel gasification.
Considering the need to increase the primarily energy
source supply and the reduction of greenhouse gas emissions (mainly carbon dioxide), an option is the utilisation of renewable energy sources (RES). More and more
*Correspondence to: Calin-Cristian Cormos, Babes-Bolyai University, Faculty of Chemistry and Chemical Engineering, Arany Janos
Street, No. 11, RO-400028, Cluj-Napoca, Romania.
 2009 Curtin University of Technology and John Wiley & Sons, Ltd.
accent is put on large-scale utilisation of renewable and
non-polluting energy sources (solar energy, wind, tides,
biomass, etc.) in power generation sector. In this context at European level, European Commission has set
as a target for the whole community block that until
2020, 20% from the energy mix should be covered
by RES.[4] Along this line, the present study evaluates the gasification process using a mixture of fossil
fuel (coal) and RES (biomass), more specifically sawdust, considering the wide distribution of this biomass
For climate change mitigation, a special attention is
given to the reduction of CO2 emissions by capture and
storage techniques (CCS). From the point of view of
CO2 capture, there are several technological options,
the most important are the following: post-combustion
capture from flue gases, pre-combustion capture, oxycombustion, chemical looping, etc.[5,6]
After capturing, carbon dioxide must be stored safely
for a long period of time, several practical options
are under evaluation: storage in geological reservoirs,
storage in exhausted oil and gas reservoirs, enhanced
oil recovery (EOR) or injection in coal beds that cannot
be mined due to the high depth (enhanced coal bed
methane recovery (ECBM)).[6]
Asia-Pacific Journal of Chemical Engineering
The study analyses carbon dioxide post-combustion
and pre-combustion capture options using gas–liquid
absorption process in physical and chemical
solvents.[7,8] These two carbon capture options are at the
moment in the development stage to be implemented
within power sector in the following years.[3] Power
plant concepts evaluated in this study generate about
400 MW electricity using a combined cycle gas turbine
Three plant configurations were analysed in detail by
modelling and simulation:
Case 1: Conventional integrated gasification combined
cycle (IGCC) technology, no carbon capture;
Case 2: IGCC technology, carbon dioxide precombustion capture using physical absorption
(Selexol), 90% carbon capture rate;
Case 3: IGCC technology, carbon dioxide postcombustion capture using chemical absorption
(methyl-diethanol-amine (MDEA)), 90% carbon capture rate.
Conventional IGCC technology for power production is
a thermo-chemical process in which the solid feedstock
is partially oxidised with oxygen and steam to produce
syngas (a mixture of H2 and CO). Syngas is then
desulfurised in an acid gas removal (AGR) system in
which H2 S is captured from syngas and sent to a Claus
plant to be partially oxidised to sulfur. Desulfurised
syngas is then burned in a gas turbine (GT) to generate
power (syngas-fuelled GT). Hot flue gases from the GT
are used to raise steam in heat recovery steam generator
(HRSG). The superheated steam is then expanded in a
steam turbine (ST) to generate extra power in addition
to the one generated by the GT.
Conceptual layout of a modified IGCC scheme for
power generation with carbon dioxide capture using
pre-combustion option is presented in Fig. 1.[9,10] The
main differences of this scheme compared with a
conventional IGCC scheme without carbon capture are
the presence of catalytically conversion stage of carbon
monoxide (having the role to concentrate the carbon
species in the form of carbon dioxide that can be later
captured) and a bigger AGR system that captures, in
addition to hydrogen sulfide as in the conventional
technology, also carbon dioxide.[11] Decarbonised gas
(hydrogen-rich gas) is then used in a combined cycle to
generate power (hydrogen-fuelled GT).
The use of hydrogen in GTs rises significant issues
compared with syngas operation: different combustion
properties of hydrogen, significant difference between
hydrogen higher and lower heating values (LHV)
(∼18%), the need to dilute hydrogen with nitrogen or
 2009 Curtin University of Technology and John Wiley & Sons, Ltd.
Figure 1. Layout of IGCC scheme for power production
with pre-combustion capture.
steam for decreasing the flame temperature (and subsequently NOx emissions) and for power augmentation.
All these issues relating to hydrogen-fuelled GT are at
the moment under extensive evaluation of GT manufacturers.
The other capture option evaluated in the article is
the post-combustion method in which carbon dioxide
is captured from the flue gases produced by syngas
burning in the GT. In principle, this plant concept
is similar with conventional IGCC technology without
carbon capture, the only difference being that flue gases
are treated for CO2 capture using a chemical solvent
(e.g. alkanolamines). The conceptual layout of an IGCC
scheme for power generation with carbon capture using
post-combustion option is presented in Fig. 2.[12]
For the case studies analysed in this article, a mixture
of coal and sawdust in the ratio or 80–20 (wt%)
was considered as feedstock. The choice of sawdust
as renewable energy sort and its characteristics takes
into account the wide distribution of this biomass sort.
For both feedstocks, proximate and ultimate analysis
Figure 2. Layout of IGCC scheme for power production
with post-combustion capture.
Asia-Pac. J. Chem. Eng. 2009; 4: 870–877
DOI: 10.1002/apj
Asia-Pacific Journal of Chemical Engineering
and calorific values (LHV) are presented in Table 1
(reported in as received base).
As gasification reactor, the option was in favour of
entrained flow type operating at high temperature (slagging conditions) that gives a high conversion of solid
fuel (∼99%). From different gasification technologies
available on the market, Siemens technology (previously known as Future Energy) was chosen, the main
factors for consideration were dry feed design of the
gasifier (solid fuel is transported to the gasifier with
nitrogen) and water quench configuration that ensure
the optimal condition for shift conversion of carbon
monoxide.[12] For all three investigated case studies
based on IGCC concept, the GT was running at nominal load having a net power output of 334 MW and the
hot flue gas temperature was set to 588 ◦ C (all GT characteristics are reported to ISO conditions). Other main
subsystems of the plant and theirs design assumptions
used in the modelling and simulation are presented in
Table 2.[11 – 14]
As solvents used, in all three cases, Selexol was
considered for syngas desulfurisation and also for precombustion capture (Case 2). Selexol solvent was chosen based on its advantages (good H2 S and CO2 solubility, low heat duty for solvent regeneration and suitability for pre-combustion capture).[14 – 16] MDEA was
used for post-combustion capture (Case 3). The choice
of MDEA as a solvent used for post-combustion capture was based on this amine advantages compared with
other alkanolamines (e.g. mono-ethanol-amine (MEA)):
increased CO2 capture capacity (higher amine concentration), lower energy duty for solvent regeneration,
lower corrosion and lower environmental impact.[14 – 16]
Captured carbon dioxide stream has to comply with
a quality specification considering the final use. Considering transport (pipeline) and storage option (EOR
or aquifers), carbon dioxide stream has to have very
low concentration of water (<500 ppm) and hydrogen
Table 2. Main plant design assumptions.
Air separation unit
Gasification reactor
Shift conversion (Water
Gas Shift (WGS))
Two fixed adiabatic
reactor beds
Pressure drop: 1
Solvent: Selexol; H2 S
capture only
H2 S removal efficiency:
–Only for Case 2
Acid gas removal
–All cases (syngas
CO2 pre-combustion
–Only Case 2
Table 1. Feedstock (coal and sawdust) characteristics.
Proximate analysis (wt%)
Volatile matter
Ultimate analysis (wt%)
Lower heating
value – LHV
(MJ/kg a.r.)
CO2 post-combustion
–Only Case 3
 2009 Curtin University of Technology and John Wiley & Sons, Ltd.
Oxygen purity: 95.00%
Delivery pressure: 2.37
Power consumption:
225 kW/ton O2
No integration of ASU
with gas turbine
Oxygen/solid fuel ratio
(kg/kg): 0.84
Steam/solid fuel ratio
(kg/kg): 0.12
Nitrogen/solid fuel ratio
(kg/kg): 0.09
Pressure: 40 bar
Temperature: >1400 ◦ C
Carbon conversion:
Pressure drop: 1.5 bar
Water quench
Electric power for
gasification aux.: 1%
of input fuel LHV
Sulfur tolerant catalyst
CO2 compression and
–Only for Case 2 and 3
Claus plant and tail gas
Solvent regeneration:
thermal (heat)
Solvent: Selexol
(dimethyl ethers of
polyethylene glycol)
Separate H2 S and CO2
Solvent regeneration by
pressure flash in four
12 bar/5 bar/2 bar and
1.05 bar
Solvent: MDEA
Solvent regeneration:
thermal (heat)
Delivery pressure: 100
Compressor efficiency:
Solvent used for
drying: TEG
Asia-Pac. J. Chem. Eng. 2009; 4: 870–877
DOI: 10.1002/apj
Asia-Pacific Journal of Chemical Engineering
Table 2. (Continued).
Gas turbine
Heat recovery steam
generator (HRSG)
and steam cycle
Heat exchangers
H2 S-rich gas
composition: >20%
Tail gas recycled to
H2 S absorption stage
Type: M701G2
(Mitsubishi Heavy
Net power output: 334
Electrical efficiency:
Pressure ratio: 21
Turbine outlet
temperature: 588 ◦ C
Three pressure levels:
118 bar/34 bar/3 bar
Medium Pressure (MP)
steam reheat
Steam turbine
efficiency: 85%
Steam wetness ex.
steam turbine: max.
Tmin . = 10 ◦ C
Pressure drop: 1% of
inlet pressure
The following indicators were used to asses the plant
• Cold gas efficiency (CGE) shows the overall efficiency of the gasification process (conversion of solid
fuel into syngas) and it is calculated with the formula:
The three gasification-based energy conversion processes described above, Case 1 – Conventional IGCC
without carbon capture, Case 2 – IGCC with precombustion capture and Case 3 – IGCC with postcombustion carbon capture, were mathematically modelled and simulated using ChemCAD software for evaluation of the plant performances and environmental
As thermodynamic package used in simulations,
Soave-Redlich-Kwong (SRK) model was chosen considering the chemical species present and process operating conditions (pressure, temperature, etc.). Simulation of plant configurations yields all necessary process
data (mass and molar flows, composition, temperatures, pressures, power generated and consumed) that
are needed to assess the overall performance of the
 2009 Curtin University of Technology and John Wiley & Sons, Ltd.
• Syngas treatment efficiency (STE) indicates the
energy losses through the syngas conditioning line
(shift conversion) and AGR system. This indicator is
calculated with the formula:
Syngas thermal energy ex. AGR [MWth ]
× 100 (2)
Syngas thermal energy ex. quench [MWth ]
• Gross and net electrical efficiency (ηgross and ηnet )
shows the overall plant performance in terms of
overall energy conversion process. These indicators
are calculated as follow:
ηgross =
Gross power output [MWe ]
× 100
Feedstock thermal energy [MWth ]
ηnet =
Net power output [MWe ]
× 100
Feedstock thermal energy [MWth ]
• Carbon capture rate (CCR) is calculated considering
the molar flow of captured carbon dioxide divided by
carbon molar flow from the feedstock:
sulfide (<100 ppm) as these components could give
corrosion problems along the pipeline network.[14,17]
Syngas thermal energy [MWth ]
× 100
Feedstock thermal energy [MWth ]
Captured CO2 molar flow [kmole/h]
× 100
Feedstock carbon molar flow [kmole/h]
• Specific CO 2 emissions (SECO2 ) are calculated considering emitted carbon dioxide mass flow for each
MW of generated power:
Emitted CO2 mass flow [kg/h]
× 100
Net power generated [MWe ]
Simulation results of all investigated case studies
were used to perform heat and power integration studies
of the CCGT (power island) for optimisation (maximisation) of power generation. The steam generated in the
gasification island and syngas conditioning line (low
pressure (LP) steam for Case 1 and 3 and high pressure (HP) and LP steam for Case 2) were integrated in
the steam cycle of the combined cycle. Also, the heat
duties (steam) for various units in the plant (gasification
island, AGR system, power island) were extracted from
the steam cycle. The cold condensate was pre-heated
in syngas conditioning line and then the hot condensate
was used for steam generation in HRSG.
For example, for Case 1 (conventional IGCC no
carbon capture) and Case 2 (IGCC with pre-combustion
capture), optimised steam flows generated in the plant
were as follow:
Asia-Pac. J. Chem. Eng. 2009; 4: 870–877
DOI: 10.1002/apj
Case 1: 339.2 t/h HP steam; 67 t/h MP steam; 301 t/h
LP steam;
Case 2: 437 t/h HP steam; 69 t/h MP steam; 180 t/h
LP steam.
Case 3 is similar with Case 1, the only difference
being that some extra steam is extracted from
steam cycle to be used for chemical solvent (MDEA) regeneration. As a result of
important heat load of MDEA regeneration
(2.5–2.7 MJ/kg of captured carbon dioxide),
the ST in Case 3 produces significant less
power than Case 1 and Case 2.
Hot and cold composite curves, noted HCC and
CCC, of syngas-fuelled GT (Case 1) and hydrogenfuelled GT (Case 2) are presented in Figs 3 and 4,
respectively. As minimum approach temperature used
in pinch analysis for both cases, a conservative value
of 10 ◦ C was chosen.[18 – 20] The GT exhaust temperature
was considered the same in all cases (588 ◦ C). However,
when using hydrogen as a fuel (Case 2), the expected
GT outlet temperature would be higher than on syngas
(Case 1), so there would be no negative pinch point
implications. As can be noticed from Figs 3 and 4, in
both cases, the steam flows (high, medium and low
pressure) were optimised with multiple utility targeting
procedure for maximisation of power generation.[21,22]
Table 3 presents overall plant performance indicators
of analysed case studies (Case 1: IGCC no carbon
capture, Case 2: IGCC with pre-combustion capture and
Case 3: IGCC with post-combustion capture).
As can be noticed from the Table 3, comparing IGCC
scheme without carbon capture (Case 1) with the same
technology but with carbon capture step (Case 2 – precombustion capture and Case 3 – post-combustion capture), the penalty in overall plant energy efficiency of
the carbon capture process is about 6.33% for the case
of pre-combustion capture (Case 2 vs Case 1) and
7.52% for the case of post-combustion capture (Case 3
vs Case 1). The main reason of this fact is the significant
Asia-Pacific Journal of Chemical Engineering
increase in ancillary power consumption of the AGR
system and captured CO2 compression step for Case 2
and 3 compared with Case 1 (in this case, AGR system
only separate the hydrogen sulfide form the syngas).
Another fact that it worth mention analysing Table 3
is that for gasification process, the pre-combustion capture technology ensures less energy penalty compared
with post-combustion capture (about 1.2% in terms of
net energy efficiency). This is explained by the fact that
carbon dioxide concentration in the syngas (about 40%
vol.) and syngas pressure (about 30 bar) is much higher
compared with post-combustion case when carbon dioxide concentration in the flue gases is about 8–10% vol.
and the pressure is close to the atmospheric pressure.
From the point of view of greenhouse gas emission, the implementation of carbon capture technology for an IGCC scheme is resulting in a substantial reduction of the specific carbon dioxide emission (71.19 kg CO2 /MW for pre-combustion capture,
94.64 kg CO2 /MW for post-combustion capture vs
826.05 kg CO2 /MW for the case without capture).
IGCC technology has also other important benefits from
environmental point of view: very low SOx and NOx
emissions, possibility to process lower-grade coals or
lignites or other solid fuels (biomass of almost every
sort, solid waste having energetic value) that are difficult
to handle by conventional energy conversion process
(e.g. steam plant).
It has also to be mentioned the fact that although
the carbon capture rate of the schemes evaluated in
the article is about 90%, in fact the overall capture
rate is higher considering also that the RES used in
addition to coal (sawdust) can be considered CO2 free
since the wood ‘captured’ CO2 from air during normal
photosynthesis process. For plant concepts evaluated
in this study, 88% of the feedstock total carbon is
coming from coal (fossil source) and 12% from biomass
(renewable source, non-fossil).
Figure 3. Composite curves for syngas-fuelled CCGT (Case 1).
 2009 Curtin University of Technology and John Wiley & Sons, Ltd.
Asia-Pac. J. Chem. Eng. 2009; 4: 870–877
DOI: 10.1002/apj
Asia-Pacific Journal of Chemical Engineering
Figure 4. Composite curves for hydrogen-fuelled CCGT (Case 2).
Table 3. Overall plant performance indicators.
Main plant data
Coal and biomass flow rate (a.r.)
Coal/Biomass LHV (a.r.)
Feedstock thermal energy – LHV (A)
Thermal energy of the syngas (B )
Cold gas efficiency (B /A × 100)
Thermal energy of syngas exit AGR (C )
Syngas treatment efficiency (C /B × 100)
Gas turbine output (1 × M701G2)
Steam turbine output (1 ST)
Expander power output
Gross electric power output (D)
ASU consumption + O2 compression
Gasification island power consumption
AGR + CO2 drying and compression
Power island power consumption
Total ancillary power consumption (F )
Net electric power output (G = D − F )
Gross electrical efficiency (D/A × 100)
Net electrical efficiency (G/A × 100)
Carbon capture rate
CO2 specific emissions
Case 1
Case 2
Case 3
161 350.00
180 455.00
161 350.00
Every power plant is designed with the ability to vary
its power output to follow the demand pattern. In the
future, this need will be intensified due to the higher
penetration in the energy sector of variable solar and
wind energy technologies that will put an additional
burden to the flexibility requirements of fossil fuel
electricity supply.[23,24]
Plant flexibility in the context of this article means
the capability to vary the output, whilst maintaining
acceptable efficiency and also the ability to start up
and shut down the plant reasonably quickly without
endangering the operating staff or the integrity of
the plant. Obviously, when comparing different power
plant concepts operated in flexible conditions, the main
 2009 Curtin University of Technology and John Wiley & Sons, Ltd.
performance indicators need to be quantified against the
degree of flexibility.
For IGCC concepts, either conventional design for
power generation without carbon capture or modified
for carbon capture, the flexibility is important considering the plant particularity (e.g. difficulty to adjust the
load with instant demand variations). Also, it has to
be mentioned the fact that designing a flexible plant,
this plant will be able to run full load most of the
time with significant benefits in terms of economics and
plant life (reducing thermal stress generated by plant
For Case 1 and Case 3, the flexibility in terms of
energy output is achieved by reducing the load of the
GT. From operational reasons, GT load can be reduce
down only to 80% which means that for syngas-fuelled
Asia-Pac. J. Chem. Eng. 2009; 4: 870–877
DOI: 10.1002/apj
GT (Case 1 and Case 3) the plant flexibility is limited
within 80% and 100% range of the nominal load.
From point of view of plant flexibility, Case 2 offers
a much wider flexibility.[25,26] Apart from flexibility
generated by reducing the GT load (mentioned already
for Case 1 and Case 3), Case 2 has the possibility to
extract a hydrogen-rich stream that can be then purified
to a level of 99–99.95% (vol.) using membrane or
pressure swing adsorption processes. Co-production of
power and hydrogen increases plant flexibility to the
extent allowed by the maximum amount of hydrogen
the plant is designed to operate as it allows the plant
to operate continuously producing more hydrogen that
could be temporarily stored, at times of low electricity
demand. This plant energy output in the form of
hydrogen can be used to cover peak electricity loads
or to be used in oil and chemical industry or in the
future for transport sector as a fuel for proton exchange
membrane fuel cells.
Flexible plant that co-produces power and hydrogen offers also significant advantages considering the
emerging hydrogen market. For the first stage of developing the hydrogen economy, such flexible power plants
could operate mostly in electricity mode with low or
even zero hydrogen outputs but gradually when hydrogen applications begin to be deployed in practice, more
plant energy could be delivered in the form of hydrogen.
In this paragraph, the discussion is focused on energy
conversion processes based on gasification with precombustion carbon dioxide capture (Case 2) as this
plant concept appears to be the most promising. Possible
ways that could improve the energy efficiency of IGCC
plant concept with pre-combustion capture are briefly
discussed below.
For instance, one possible way to improve flue gas
temperature and subsequently the steam parameters (e.g.
temperature) is the duct burning.[27] This option helps
to maintain the power output and efficiency of the plant.
Unfortunately, the high exhaust temperatures from the
GT, in combination with the high flame temperatures
associated with hydrogen combustion, will result in
high NOx levels. There is a need for research and
development work in this area. Fortunately, because
hydrogen fed to the burners is heavily diluted with
nitrogen, the problem may not be very significant.
Further dilution may also be practical and not difficult to
arrange. This aspect becomes more and more important
as the degree of plant flexibility is increasing.
Other possible options for improvement could be
increasing the hydrogen production from the gasifier and efficiency improvements. In terms of gasifier
improvements, two practical suggestions could be made
that are best used in combination. These are the usage of
 2009 Curtin University of Technology and John Wiley & Sons, Ltd.
Asia-Pacific Journal of Chemical Engineering
99.5% oxygen purity (vol.) rather than 95.0% and substituting carbon dioxide for nitrogen as a coal transport
gas in dry feed gasifiers.[28] This combination of techniques improves hydrogen production from the gasifier.
An investigated method for both improving the plant
energy efficiency by better thermal integration and
simultaneously enhancing carbon dioxide capture process is to compress the syngas after the quench stage and
before the water gas shift reactors.[28] This option will
integrate the heat of compression in the shift conversion stage and reduces the cost of CO2 capture because
of higher AGR running pressure. Other methods of
improving efficiency focus on improved heat recovery from the flue gases as they leave the stack. One
important aim is the recovery of the latent heat in the
combustion products of hydrogen. If this proves to be
practical, the condensed water would provide a useful
high-grade feed for the gasifier. A preliminary evaluation suggests that this is best done by utilising the heat
in the flue gas for heating up the boiler feed.
This study analyses from technical point of view,
using modelling and simulation techniques and heat and
power integration analysis, the possibility of applying
the gasification technology for decarbonisation of solid
fuels (coal blended with RES – sawdust) in power
generation sector.
Two different carbon dioxide capture technologies by
gas–liquid absorption were investigated: precombustion capture using a physical solvent (Selexol)
and post-combustion capture using a chemical solvent
(MDEA). The main differences in terms of plant configurations, energy efficiency, heat and power integration and plant flexibility between a conventional
IGCC scheme without carbon capture compared with a
scheme with pre-combustion capture or a scheme with
post-combustion capture were analysed in details using
computer-aided process engineering (CAPE) tools.
The simulation results of the analysed plant concepts were used for evaluation of plant performances
and environmental impact of gasification-based energy
conversion processes with carbon capture and storage
(quantification of specific CO2 emissions, fuel decarbonisation rate). As main conclusion of the study, precombustion carbon dioxide capture method is more
suitable for gasification process than post-combustion
capture (lower energy penalty, possibility to co-generate
power and hydrogen, higher degree of plant flexibility,
This work has been supported by Romanian National
University Research Council (CNCSIS) through grant
Asia-Pac. J. Chem. Eng. 2009; 4: 870–877
DOI: 10.1002/apj
Asia-Pacific Journal of Chemical Engineering
no. 2455: ‘Innovative systems for polygeneration of
energy vectors with carbon dioxide capture and storage
based on co-gasification processes of coal and renewable energy sources (biomass) or solid waste’.
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DOI: 10.1002/apj
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combined, generation, pre, method, capture, post, cycle, combustion, base, integrated, coal, biomasa, power, concept, carbon, gasification
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