Hydrogen Production From Fossil Fuels With Carbon Capture
description
Transcript of Hydrogen Production From Fossil Fuels With Carbon Capture
i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 1
Avai lab le at www.sc iencedi rect .com
journa l homepage : www.e lsev ie r . com/ loca te /he
Hydrogen production from fossil fuels with carbon captureand storage based on chemical looping systems
Calin-Cristian Cormos*
Babes-Bolyai University, Faculty of Chemistry and Chemical Engineering, 11 Arany Janos Street, RO-400028 Cluj-Napoca, Romania
a r t i c l e i n f o
Article history:
Received 25 November 2010
Received in revised form
25 January 2011
Accepted 30 January 2011
Available online 27 March 2011
Keywords:
Hydrogen production
Chemical looping
Fossil fuels
Carbon capture and storage
* Tel.: þ40 264 593833; fax: þ40 264 590818E-mail address: [email protected]
0360-3199/$ e see front matter Copyright ªdoi:10.1016/j.ijhydene.2011.01.170
a b s t r a c t
This paper analyzes innovative processes for producing hydrogen from fossil fuels
conversion (natural gas, coal, lignite) based on chemical looping techniques, allowing
intrinsic CO2 capture. This paper evaluates in details the iron-based chemical looping
system used for hydrogen production in conjunction with natural gas and syngas produced
from coal and lignite gasification. The paper assesses the potential applications of natural
gas and syngas chemical looping combustion systems to generate hydrogen. Investigated
plant concepts with natural gas and syngas-based chemical looping method produce
500 MW hydrogen (based on lower heating value) covering ancillary power consumption
with an almost total decarbonisation rate of the fossil fuels used.
The paper presents in details the plant concepts and the methodology used to evaluate
the performances using critical design factors like: gasifier feeding system (various fuel
transport gases), heat and power integration analysis, potential ways to increase the
overall energy efficiency (e.g. steam integration of chemical looping unit into the combined
cycle), hydrogen and carbon dioxide quality specifications considering the use of hydrogen
in transport (fuel cells) and carbon dioxide storage in geological formation or used for EOR.
Copyright ª 2011, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights
reserved.
1. Introduction traditional processes such as natural gas reforming, coal gasi-
Hydrogen is considered as an attractive energy carrier and
storagemedium for developing a clean and sustainable energy
source. The use of hydrogen in energy sector is offering
significant advantages including reduction of greenhouse gas
emissions at the point of end use, enhancement of the secu-
rity of energy supply, improvement of economic competi-
tiveness, potential fuel for transport sector (e.g. PEM fuel cells)
etc. [1e3]. However, numerous technical, economical and
infrastructure challenges in the areas of production, distri-
bution, storage and end usemust be solved before hydrogen to
play a central role in future energy systems.
Regarding to hydrogen production, a transition to
a hydrogen-based energy system is likely to be achieved using
..2011, Hydrogen Energy P
ficationorwater electrolysis [2,4e8]before innovativehydrogen
production processes to become available on industrial scale
(e.g. water splitting based on solar thermo-cycles, fermentative
methods etc.) [9e11]. In order to be both economically
competitive and environmentally sustainable, hydrogen could
beproducedvia theseprocessesusingdecarbonized fossil fuels.
Hydrogen introduction in energy systems will ensure
a significant reduction of the greenhouse gas emissions
(mainly carbon dioxide). In the last decade, a special attention
is given to the reduction of carbon dioxide emissions by large
scale deployment of carbon capture and storage techniques
(CCS). In term of carbon dioxide capture from energy conver-
sion processes, there are several technological options, the
most important are: post-combustion capture, pre-combustion
ublications, LLC. Published by Elsevier Ltd. All rights reserved.
Steam Turbine
Purified hydrogen
CO2 to storage
Ancillary power
H2 compression
CO2 Drying and Compression
Fuel (syngas) reactor
Natural gas
Steamreactor
Steam
H2
Condensate
Fe/FeO
Condensate
Air reactor
Fe3O4
Air
Exhaust air
Fig. 1 e Layout of natural gas scheme for hydrogen
production with carbon capture and storage using an iron
based chemical looping system.
i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 1 5961
capture, oxy-combustion, chemical looping etc [12,13]. After
capture process, the carbon dioxide must be stored safely for
a long period of time in geological reservoirs, storage in
exhausted oil and gas reservoirs, enhanced oil recovery (EOR)
or injection in coal beds (Enhanced Coal BedMethane Recovery
- ECBM) [13].
The present paper evaluates the potential usage of chem-
ical looping process for hydrogen production based on fossil
fuel conversion with carbon capture and storage. The paper
investigates natural gas and syngas-based chemical looping
applications for hydrogen production. The chemical looping
method consists in two processes (oxidation and reduction)
undertaken in two separate reactors. In the reduction step, the
fuel (either hydrocarbons or syngas as evaluated in this paper)
is reacted with an oxygen carrier (metallic oxide) to form
carbon dioxide and water. After condensing the water vapour,
the captured carbon dioxide stream can be sent to the storage
sites. The reduced form (lower oxidation stage or even metal)
of the chemical looping agent is re-oxidised in an oxidation
reactor to its original formusing steamand/or air and recycled
back to the reduction reactor [14e19].
The first option evaluated in this paper is based on natural
gas used in a chemical looping system for hydrogen produc-
tion. Considering this case, in the first reactor (fuel reactor) the
methane and other hydrocarbons are oxidised with iron oxide
(magnetite) according to the following reaction:
Fe3O4 þ CH4/3Feþ CO2 þ 2H2O (1)
The reduced form of the oxygen carrier (iron) is oxidised
back in the oxidation reactor using steam to regenerate the
iron oxide and to produce hydrogen according to the reaction:
3Feþ 4H2O/Fe3O4 þ 4H2 (2)
For the energy (heat) management of the whole process,
some part of the reduced form of the oxygen carrier can be
oxidised with air (exothermic process) to produce the heat
needed for fuel reactor (reaction (1) is endothermic).
Another option evaluated in this paper is to use syngas,
generated from coal or lignite gasification process, as fuel for
chemical looping system. Considering the iron based chem-
ical looping system applied to the syngas resulted from gasi-
fication, in the fuel reactor the syngas is oxidised with iron
oxide (magnetite) according to the following reactions:
Fe3O4 þ 4CO/3Feþ 4CO2 (3)
Fe3O4 þ 4H2/3Feþ 4H2O (4)
The reduced form of the oxygen carrier (iron) is oxidised
back in the oxidation reactor using steam to regenerate the
iron oxide (recycled back to the fuel reactor) and to produce
hydrogen according to the reaction (2) mentioned above.
An important advantage of this chemical looping process is
that iron and iron oxides are non-toxic and very inexpensive
materials which are easy to handle because they are stable at
ambient conditions. After the oxygen carrier has been reduced
and re-oxidized in a number of cycles, it can be recycled in the
steel industry and no waste material is thus accumulated.
The evaluated hydrogen plants with iron based chemical
looping presented in the paper are producing 500 MW thermal
hydrogen (considering thehydrogen lowerheatingvalueeLHV)
with no external power requirement (all ancillary power is
generated using some of the hydrogen stream produced in the
plant). Regarding the carbon capture rate of the plant, the
decarbonisation ratio is almost 100% considering that the fuel
reactor gaseous stream is containing most of the feedstock
carbon.
This paper proposes an integrated methodology for assess-
ing from technical point of view hydrogen production plant
concepts based on natural gas and syngas chemical looping
system. The critical design factorswith significant influence on
overall plant energy efficiency are discussed in details. The
focus of the paper is put on gasifier feeding system (various fuel
transport gases), heat and power integration analysis, potential
ways to increase the overall energy efficiency (e.g. steam inte-
gration of chemical looping unit into the combined cycle),
hydrogen and carbondioxidequality specifications considering
the use of hydrogen in transport (fuel cells) and carbon dioxide
storage in geological formation or used for EOR.
2. Natural gas and syngas iron-basedchemical looping systems
The first option investigated in this paper for hydrogen
production based on fossil fuels with chemical looping was
using natural gas as feedstock. The hydrocarbons (mainly
methane) are converted into carbon dioxide and water in the
fuel reactor by reactingwith theoxygencarrier. The gas stream
from the fuel reactor is then cooled to ambient temperature
and the condensedwater is separated followedby a drying and
compression step of the captured carbon dioxide stream. The
mostof the iron isoxidizedback in thesteamreactorproducing
hydrogen, the rest being oxidized with pressurised air in air
reactor for generating theheatneeded to balance theheat duty
of the whole plant (especially the fuel reactor).
The sensible heat of hot gas streams resulted from all
reactors are used for steam generation. Part of the generated
steam is used for covering the chemical looping needs (steam
reactor), the rest being expended in a steam turbine to
generate the power to run the plant. The conceptual layout of
Gasification Air Separation Unit (ASU)
O2
Coal / Lignite + Transport gas (N2 / CO2)Air
Syngas Quench and Cooling
Steam
Slag
Acid Gas Removal (AGR)
Claus Plant and Tail gas Treatment
Sulphur
Combined Cycle Gas Turbine
Purified hydrogen
CO2 to storage
Ancillary power
H2 compression
O2N2
CO2 Drying and Compression
Fuel (syngas) reactor
Desulphurised syngas
Steam reactor
Steam
H2
CondensateFe3O4
Fe/FeO
Condensate
Fig. 2 e Layout of IGCC scheme for hydrogen production with carbon capture and storage using an iron based chemical
looping system.
i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 15962
a natural gas scheme for hydrogen production with carbon
capture using an iron based chemical looping system is pre-
sented in Fig. 1 [16,20,21].
The second option investigated in this paper for hydrogen
production based on fossil fuels with chemical looping was
using solid fuels (coal and lignite) in an Integrated Gasification
Combined Cycle (IGCC) scheme. The solid fossil fuel is oxi-
dised partially with oxygen and steam to produce syngas.
Syngas is then desulphurised in an Acid Gas Removal (AGR)
system in which hydrogen sulphide is captured from syngas
and send to a Claus plant to be partially oxidised to sulphur.
Desulphurised syngas is then used in an iron-based chemical
Raw lignite
Dry lignite
Blower
Mill
Cyclone
Drier
Vapour Compressor
Electrostatic Precipitator
Condensate toPower island
X
FLUIDISED BED
Fig. 3 e WTA lignite drying process.
looping system to produce hydrogen simultaneous with
capturing the carbon from the feedstock. The conceptual
layout of a modified IGCC scheme for hydrogen production
with carbon capture using an iron based chemical looping
system is presented in Fig. 2 (for the case of dry feed gasifier of
Shell type) [15,17,18,21].
For the case of lignite used as feedstock, a fuel drying
process must be performed prior gasification due to its high
moisture content (40 wt.% on as received basis). An advanced
solid fuel drying process based on fluidized-bed drying with
internal waste-heat utilization (WTA) was considerate in this
paper [22]. WTA process (presented in Fig. 3) enables highly
energy efficient drying of the raw lignite and creates the
conditions for making the conversion of lignite into
Table 1 e Quality specification for captured carbondioxide stream.
Component Concentration (vol.%)
Carbon dioxide min. 95
Carbon monoxide max. 2000 ppm
Hydrocarbons max. 2%
Hydrogen max. 4% (all non-condensable gases)
Oxygen max. 100 ppm
Water max. 250 ppm
Sulphur oxides (SOx) max. 50 ppm
Hydrogen sulphide max. 100 ppm
Nitrogen max. 4% (all non-condensable gases)
Argon max. 4% (all non-condensable gases)
Table 2 e Na tural gas composition and thermalproperties.
Parameter Value
Composition (vol.%)
Methane 89.00
Ethane 7.00
Propane 1.00
I-Butane 0.05
N-Butane 0.05
I-Pentane 0.005
N-Pentane 0.004
N-Hexane 0.001
Carbon dioxide 2.00
Nitrogen 0.89
Sulphur <5 ppm
Calorific value (kJ/kg)
Gross (HHV) 51 473
Net (LHV) 46 502
Table 4 e Main design assumptions (Case 1: Hydrogenproduction from natural gas).
i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 1 5963
electricity/hydrogen evenmore environmentally friendly. The
moisture content of the dried lignite prior to gasification is
10% and the specific power consumption of the drying stage is
about 120e140 kWh/t removed water.
Main differences of hydrogen production scheme based on
IGCC concept with chemical looping system for carbon
capture compared with conventional IGCC scheme without
carbon capture are the following [23,24]: introduction of an
Table 3 e Coal and lignite compositions and thermalproperties.
Parameter Coal Lignite
Proximate analysis (wt.%)
Moisture (a.r.) 8.10 40
Volatile matter (dry) 28.51 50.10
Ultimate analysis (wt.% dry)
Carbon 72.04 27.10
Hydrogen 4.08 2.20
Nitrogen 1.67 0.20
Oxygen 7.36 13.00
Sulphur 0.65 0.70
Chlorine 0.01 0.00
Ash 14.19 16.80
Calorific value (kJ/kg)
Gross (HHV) 28 704.40 (dry) 10 363 (a.r.)
Net (LHV) 27 803.29 (dry) 9210 (a.r.)
Ash composition (wt.%)
SiO2 52.20 33.47
Al2O3 27.30 14.08
Fe2O3 5.10 5.32
CaO 6.40 33.14
MgO 2.10 3.34
TiO2 1.50 0.60
K2O 1.00 0.97
Na2O 0.30 0.29
SO3 2.40 8.46
P2O5 1.30 0.30
MnO2 0.00 0.03
iron based chemical looping system to transfer the thermal
energy of the syngas to almost pure hydrogen with simulta-
neous carbon dioxide capture, conditioning stage of captured
carbon dioxide (drying and compression steps), hydrogen
compression stage for the stream to be delivered to external
customers (hydrogen purity for export was set at more than
99.95 vol.% to be compatible with PEM fuel cells [25]) and
a combined cycle gas turbine (CCGT) running on hydrogen-
rich gas for covering the ancillary power consumption.
As gasification reactor evaluated in this paper, the option
was in favour of entrained-flow type operating at high
temperature (slagging conditions) which give a high fuel
conversion (>99%) and a clean syngas, free frommethane and
other pyrolysis products [23]. From different commercial
gasification technologies available on the market, Shell
reactor was considered, the main reason being high thermal
efficiency due to dry feed design and gas quench configura-
tion. As solid fossil fuels evaluated in this paper for the IGCC-
based hydrogen production, coal and lignite were evaluated.
For the dry feed gasifiers as Shell, the usage of nitrogen as
inert gas for solid fuel transport to the gasifier make a signifi-
cant improvement in term of cold gas efficiency compared
with slurry feed gasifiers (e.g. GE-Texaco). The nitrogen
Unit Parameters
Chemical
looping (CL) unit
Chemical looping agent:
magnetite (Fe3O4)
Fuel reactor parameters:
30.5 bar/800e900 �CSteam reactor parameters:
29.5 bar/700e800 �CAir reactor parameters:
26.5 bar/600e900 �CGibbs free energy minimization
model for all reactors
Pressure drop fuel and steam
reactors: 1 bar/reactor
CL unit fully thermally
integrated with the rest
of the plant
CO2 compression
and drying
Delivery pressure: 120 bar
Compressor efficiency: 85%
Solvent used for drying:
TEG (Tri-Ethylene-Glycol)
Hydrogen
compression
Delivery pressure: 60 bar
Compressor efficiency: 85%
Heat Recovery
Steam Generator
(HRSG) and steam
cycle (Rankine)
Two pressure levels (MP/LP):
34/3 bar
Condensation pressure:
0.046 bar
Integration of steam generated
in plant sub-systems
Steam turbine isoentropic
efficiency: 85%
Steam wetness ex. steam
turbine: max. 10%
Heat exchangers DTmin. ¼ 10 �CPressure drop: 1% of inlet
pressure
i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 15964
contamination of the syngas is particular important for
carbon capture process based on chemical looping, since the
nitrogen will end up as an impurity in the captured carbon
dioxide stream with negative implications regarding to the
Table 5 e Main design assumptions (Case 2: Shell gasification
Unit
Air Separation Unit (ASU)
Gasification reactor (Shell)
Syngas quench and conditioning
COS hydrolysis
Acid Gas Removal (AGR) unit for H2S capture
Claus plant and tail gas treatment
Chemical looping (CL) unit
CO2 compression and drying
Hydrogen compression
Gas turbine (GT)
Heat Recovery Steam Generator (HRSG)
and steam cycle (Rankine)
Heat exchangers
transport and storage (see Table 1 for the proposed quality
specification for the captured carbon dioxide stream [26]).
A solution to reduce the level of nitrogen contamination in the
syngas (and subsequently in the captured carbon dioxide
, N2 used as transport gas).
Parameters
Oxygen purity: 95% (vol.)
ASU oxygen and nitrogen delivery pressure: 2.37 bar
Power consumption: 225 kWh/ton O2
No integration with gas turbine (GT)
Oxygen/solid fuel ratio (kg/kg): 0.84
Steam/solid fuel ratio (kg/kg): 0.11
Nitrogen/solid fuel ratio (kg/kg): 0.09
O2 pressure to gasifier: 48 bar
Gasification pressure: 40 bar
Gasification temperature: >1400 �C (slagging conditions)
Carbon conversion: 99.9%
Pressure drop: 1.5 bar
Gas quench type
Electric power for gasification aux.: 0.5% of input fuel LHV
Syngas temperature after gas quench: w800 �CTemperature of the quench gas: 250 �CQuench gas ratio: 60%
Quench gas compressor efficiency: 80%
Pressure drop for fly ash removal system: 1 bar
HP steam raised in Gasification Island: 120 bar/570 �CLP steam raised in the gasification island: 3 bar/200 �CHeat exchanger pressure drop: 1% of inlet pressure
Syngas temperature after gas boiler: 220 �COne catalytic bed
Reactor thermal mode: adiabatic
Pressure drop: 1 bar
Solvent: Selexol� (dimethyl ethers of polyethylene glycol)
H2S absorption/desorption columns: 24 stages/10 stages
Overall H2S removal yield: 99.5e99.9%
Solvent regeneration: thermal (heat)
Oxygen-blown type
H2S-rich gas composition: >20% (vol.)
Tail gas recycled to H2S absorption stage
Chemical looping agent: magnetite (Fe3O4)
Fuel reactor parameters: 30.5 bar/750e900 �CSteam reactor parameters: 29.5 bar/500e700 �CGibbs free energy minimization model for both reactors
Pressure drop fuel and steam reactors: 1 bar/reactor
CL unit fully thermally integrated with the rest of the plant
Delivery pressure: 120 bar
Compressor efficiency: 85%
Solvent used for drying: TEG (Tri-Ethylene-Glycol)
Delivery pressure: 60 bar
Compressor efficiency: 85%
Net power output: 15.8 MW
Electrical efficiency: 39.5%
Pressure ratio: 21
Turbine inlet temperature (TIT): 1280 �CTurbine outlet temperature (TOT): 590 �CThree pressure levels (HP/MP/LP): 118/34/3 bar
MP steam reheat
Condensation pressure: 0.046 bar
Integration of steam generated in gasification island, syngas
treatment line and chemical looping unit with CCGT
Steam turbine isoentropic efficiency: 85%
Steam wetness ex. steam turbine: max. 10%
DTmin. ¼ 10 �CPressure drop: 1% of inlet pressure
Table 6 e Characterisation of main plant streams (Case 1: Hydrogen production from natural gas).
Stream Natural gas Gas stream ex.fuel reactor
Steam to steamreactor
Gas stream ex.stream reactor
Air to airreactor
Purifiedhydrogen
CapturedCO2 stream
Pressure (bar) 31.5 29.5 34 27.5 27.5 60 120
Temperature (�C) 15 800 400 781.55 240 35 35
Mass flow (kg/h) 49 552.66 232 787.80 145 750.00 26 647.66 285 996.60 15 094.35 130 258.30
Molar flow (kmol/h) 2750.00 8604.80 8090.48 8090.48 9912.00 7449.00 2968.64
Composition (vol.%)
H2 See Table 2 0.00 92.01 99.95 0.00
CO 0.00 0.00
CO2 34.66 0.03 99.17
N2 0.28 77.28 0.82
O2 0.00 20.73 0.00
H2S 1 ppm <1ppm
H2O 65.05 100 7.99 1.02 0.05 5 ppm
Other 0.01 0.94 0.01
i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 1 5965
stream) in case of Shell gasifier can be made by replacing the
nitrogen by carbon dioxide as a transport gas. The carbon
dioxide stream used to transport the solid fuel to the gasifier
can be taken from the captured carbon dioxide stream.
All evaluated plant options (either based on natural gas or
on syngas) were designed to have a null net power generation
(the power generatedwithin the plant is only used for covering
the ancillary consumption of the plant and not for export).
An important factor which influences the ancillary power
consumption of the plant fittedwith carbon capture step is the
compressionwork of captured carbon dioxide stream. In order
to have the needed pressure for transport and injection of the
captured carbon dioxide to geological storage or utilized for
Enhanced Oil Recovery (EOR), a compression step to more
than 100 bar is required (120 bar delivery pressure at the plant
gate was considered in this paper). This additional compres-
sion step gives a significant difference between energy
conversion processes equipped with CCS compared with the
same processes without CCS (about 0.02e0.03 kWh/kg
captured CO2 for the cases evaluated in this paper).
Table 7 e Characterisation of main plant streams (Case 2: Hydnitrogen used as transport gas).
Stream Coal Oxygen(gasifier)
Steam(gasifier)
Nitrogen(gasifier)
Rasyn
Pressure (bar) Ambient 48.00 41.00 40.00 38.50
Temperature (�C) Ambient 80.00 425.00 80.00 1441
Mass flow (kg/h) 108 000 91 000 11 000 9575 205 7
Molar flow
(kmole/h)
2829.79 610.60 341.79 9598
Composition (vol.%)
H2 25.77
CO 57.99
CO2 3.99
N2 2 100 4.76
O2 95 0.00
Ar 3 0.88
H2S þ COS 0.21
H2O 100 6.36
Other 0.04
The quality specification of captured carbon dioxide is also
a major factor to be taken into consideration for an energy
conversion process with CCS. In the literature, several critical
issues in the transport part of carbon capture and storage
chain have been identified and covered such as safety and
toxicity limits, compression work, hydrate formation, corro-
sion and free water formation including cross-effects (e.g.
hydrogen sulphide and water) [13,22]. The proposed quality
specification for captured carbon dioxide stream considered
in presented in Table 1.
3. Modelling and simulation of iron basedchemical looping system for hydrogenproduction schemes
Different options for hydrogen production from fossil fuels
with carbon capture and storage based on chemical looping
systems were evaluated as follow:
rogen production based on Shell coal gasification with
wgas
Syngasex. AGR
CapturedCO2
Hydrogen(ex. CL)
Purifiedhydrogen
Flue gas(ex. GT)
31.50 120.00 26.6 60 1.15
.89 30.00 35.00 30.00 35 590.05
55.9 194 155.4 276 667.5 16 366.11 15 146.83 124 776.8
.71 8970.18 6460.65 8051.86 7452.00 4580.29
27.54 <0.01 99.91 99.95 0.00
62.08 <0.01 0.00 0.00 0.00
4.27 91.59 0.00 0.00 0.02
5.09 7.07 0.00 0.00 74.45
0.00 0.00 0.00 0.00 11.46
0.95 1.31 0.00 0.00 0.78
5 ppm 7 ppm 0.00 0.00 0.00
0.02 11 ppm 0.09 0.05 13.27
0.05 0.03 0.00 0.00 0.02
Fig. 4 e Composite curves for Case 1: Hydrogen production
from natural gas with carbon capture and storage using an
iron based chemical looping system.
i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 15966
Case 1 : Hydrogen production from natural gas;
Case 2 : Hydrogen production from coal (Shell gasifier, N2 used
as transport gas);
Case 3 : Hydrogen production from coal (Shell gasifier, CO2
used as transport gas);
Case 4 : Hydrogen production from lignite (Shell gasifier, N2
used as transport gas).
The compositions and thermal characteristics of evaluated
fuelsarepresented inTable2 (natural gas) andTable3 (coal and
lignite). As main design assumptions, all plant concepts eval-
uated in the paper produce 500 MW hydrogen calculated on
LHV basis (10.795 MJ/Nm3) with zero net power generation (all
generated power is used to cover the ancillary consumption).
Theevaluatedcase studiesaredesigned to capturealmost total
carbon in the feedstock.Descriptionofmainplant sub-systems
for Cases 1 and 2 and theirs design assumptions used in the
modelling are presented in Tables 4 and 5 [16,18,21,27].
In term of process thermodynamic used in the simulations,
for analysis of all case studies presented in the paper, thermo-
dynamicequilibriumhasbeingassumedforcalculations. Stream
property evaluations are based on the SoaveeRedlicheKwong
(SRK) equation of state with BostoneMathiasmodifications.
Regarding the chemical looping unit (fuel, steam and air
reactors), chemical and phase equilibrium based on a Gibbs
free energy minimization model was used in the simulations
(Tables 4 and 5 are presenting the main model assumptions).
Base on existing experimental results and literature infor-
mation [14e16,19,21] and the optimised simulation results
(e.g. fuel reactor temperature in the range of 800e900 �C with
optimisation of the process conditions for maximisation of
conversion), the hydrogen and carbon monoxide are almost
totally removed in the fuel reactor (conversion rate of more
than 99.8%). Similar results are obtained for natural gas-based
system (methane conversion superior to 97e98%) [14,21].
For the steam reactor, high hydrogen yields are obtained at
moderate temperature (in the range of 700e800 �C), which
Table 8 e Steam cycle (Case 2: Hydrogen production based on
Stream Flowrate
HP steam from process units (gasifier boiler) 138.0
HP steam from process units (gasifier reactor) 4.6
HP steam to HP Steam Turbine 157.6
MP steam to MP reheater 81.1
Hot reheated MP steam 81.1
MP steam to process units (gasifier, chem. loop.) 80.0
MP steam used in chemical looping unit 148.8
LP steam from process units (gasifier boiler) 8.3
LP steam from process units (chem. loop. unit) 29.0
LP steam to LP steam turbine 104.9
LP steam (6.5 bar) to process units (AGR) 11.3
LP Steam Turbine exhaust 104.9
Cooling water to steam condenser 5750.0
Cooling water from steam condenser 5750.0
Hot condensate returned to HRSG 134.6
BFW to HP BFW pumps 142.6
BFW to MP BFW pumps 101.9
BFW to LP BFW pumps 41.0
Flue gas at stack 124.7
produce, after condensation of the excess steam, an almost
pure hydrogen stream (higher than 99.95 vol.%) suitable to be
used not only for power generation but also for emerging
hydrogen economy applications (e.g. PEM fuel cells for trans-
port sector). In addition, the utilisation of an additional air
reactor to complete the re-oxidation process of the oxygen
carrier before the fuel reactor simplify considerably the
process. The developed chemical looping models were vali-
dated with experimental data [14e17,21,27].
The whole plant concepts analysed in the paper are
modelled and stimulated in a fully thermally integrated
design, which means that all the heating duties needed for
various processes (e.g. steam rising for gasification, syngas
desulphurisation, chemical looping etc.) are based on avail-
able hot streams within the plant (e.g. raw syngas from the
gasifier, the effluents from the fuel, steamand air reactors, hot
gas turbine effluent etc.). The only energy input of the plant
Shell coal gasification).
(t/h) Temperature (�C) Pressure (bar)
0 579.28 120.00
5 586.56 118.00
5 578.01 118.00
6 386.23 34.00
6 401.70 33.50
0 420.00 41.00
2 400.00 34.00
6 193.79 3.00
4 190.00 3.00
5 162.84 3.00
0 215.96 6.50
5 31.32 0.046
0 15.00 2.00
0 25.00 1.80
2 115.00 2.80
5 115.00 2.80
1 115.00 2.80
9 115.00 2.80
7 130.04 1.05
i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 1 5967
being the fossil fuel feedstock (natural gas for Case 1 and coal
or lignite for Cases 2e4). The utilisation of an additional air
reactor for Case 1 (Cases 2e4 based on solid fuel gasification
do not have an air reactor) was based on the need to generate
heat for the fuel reactor (reaction (1) is endothermic) using the
oxidation of part of reduced form of the oxygen carrier (iron)
with air (exothermic process). The ancillary power needed to
run the plant was generated onsite based on available hot
streams; no net (external) power is generated or imported. For
natural gas case (Case 1), ancillary power is generated based
on expanding the excess steam produced in the plant. For
IGCC-based cases (Cases 2e4), the ancillary power is gener-
ated based on small combined cycle gas turbine (which inte-
grated the excess steam from the rest of the plant).
The two gaseous products of the plant (hydrogen and
captured carbon dioxide) have to comply with certain quality
specifications considering the final use of these streams.
Hydrogen produced by the plant is intended to be used in PEM
fuel cells for transport sector which imply very strict quality
specification (>99.95% H2 and virtually no CO and H2S) due to
COMPOSITE
0
100
200
300
400
500
600
700
800
900
Entha
Tem
pera
ture
(°C
)
HCC CCC
COMPOSITE
0
100
200
300
400
500
600
700
0 5000 0 1 0 000 0 15
0 2000 4000 6000 8000 1
Entha
Tem
pera
ture
(°C
)
a
b
Fig. 5 e Composite curves for Case 2: Hydrogen production from
using an iron based chemical looping system. a. Composite curv
looping unit (Case 2). b. Composite curves for combined cycle g
the possibility of fuel cells poisoning [28]. Asmentioned before
the captured carbon dioxide stream will have to comply with
quality specification presented in Table 1. To comply with
water content (lower than 250 ppm), a dehydration step using
tri-ethylene-glycol (TEG) was considered.
The following plant performance indicators were used in
analysis of various case studies:
- Cold gas efficiency e CGE (for Cases 2e4) shows the energy
efficiency of gasification process (conversion of solid fuel
into syngas) and it is calculated with the formula:
CGE ¼ Syngas thermal energy ½MWth
��� 100 (5)
Feedstock thermal energy ½MWth
- Gas treatment efficiency (GTE) indicates the energy losses
through the natural gas/syngas conditioning line, acid gas
removal (AGR) and chemical looping (CL) units. This indi-
cator is calculated with the formula:
CURVES
lpy (kW)
CURVES
000 0 20000 0 25000 0 30000 0
0000 12000 14000 16000 18000 20000
lpy (kW)
HCCCCC
coal gasification (Shell) with carbon capture and storage
es for gasifier island, syngas conditioning line and chemical
as turbine e CCGT (Case 2).
i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 15968
GTE ¼ Syngas thermal energy ex: CL unit ½MWth
�
Syngas thermal energy ex: quench ½MWth
�� 100 (6)
- Net power output is calculated as follows:
Net power output ¼ Gross power
�Ancillary power consumption (7)
- Hydrogen efficiency ðhH2Þ is an indicator for hydrogen
production and it is calculated as follows:
hH2¼ Hydrogen thermal energy ½MWth
�
Feedstock thermal energy ½MWth
�� 100 (8)
- Carbon capture rate (CCR) is calculated considering the molar
flow of captured carbon dioxide divided by carbon molar
flow from the feedstock:
CCR ¼ Captured CO2 molar flow�kmole=h
�
Feedstock carbonmolar flow ½kmole=h� � 100 (9)
- Specific CO2 emission ðSECO2 Þ is calculated considering the
emitted CO2 mass flow for each MW of hydrogen produced
(LHV):
Table 9 e Overall plant performance indicators.
Main Plant Data Units Ca
Fossil fuel flowrate kg/h 49
Fuel LHV (NG/coal/lignite) MJ/kg
Feedstock thermal energy e LHV (A) MWth 640
Thermal energy of the syngas (B) MWth e
Cold gas efficiency (B/A � 100) % e
Thermal energy of gas exit CL (C) MWth 500
Gas treatment efficiency (C/B � 100) % 78.
Gas turbine output MWe e
Steam turbine output MWe 12.
Expander (air turbine) power output MWe 31.
Gross electric power output (D) MWe 43.
Hydrogen output � LHV (E) MWth 500
Fuel (lignite) drying MWe e
ASU consumption þ O2 compression MWe e
Gasification island power consumption MWe e
AGR þ CL þ CO2 drying & compression MWe 37.
Hydrogen compression MWe 5.6
Power island power consumption MWe 0.5
Total ancillary power consumption (F) MWe 43.
Net electric power output (G ¼ D � F) MWe 0
Hydrogen efficiency (E/A � 100) % 78.
Carbon capture rate % 98.
CO2 specific emissions kg/MWh 2.6
SECO2¼ Emitted CO2 mass flow ½kg=h�
Hydrogen thermal energy ½MWth
�� 100 (10)
4. Results and discussion
Hydrogen production schemes based on various fossil fuels
(natural gas, coal and lignite) with iron oxides chemical
looping system used for carbon capture were modelled and
simulated using process flowmodelling software (ChemCAD).
As thermodynamic package used in all simulations, Soa-
veeRedlicheKwong (SRK) model with BostoneMathias modi-
fications was chosen considering the chemical species
present and process operating conditions (pressure, temper-
ature etc.) [21,29]. The analysis has assumed thermodynamic
equilibrium. Simulation of various plant configurations yields
all necessary process data (mass and molar flows, composi-
tion, temperatures, pressures, power generated and
consumed) that are needed to assess the overall performance
of the processes. The simulation results were compared with
experimental data for model validation. No significant differ-
ences were found between the simulation results and the
experimental results [14e17,21,30e33].
All four case studies were simulated for hydrogen
production with carbon capture using an iron based chemical
looping process. Tables 6 and 7 present the stream properties
in selected key points of the plant diagram for an illustrative
example for Case 1 (hydrogen production from natural gas)
and Case 2 (hydrogen production based on Shell coal gasifi-
cation with nitrogen used as transport gas). It can be noticed
that for Case 1, the captured CO2 stream is complying with
se 1 Case 2 Case 3 Case 4
552 108 000 107 950 308 700
46.502/25.353/9.21
.07 760.59 760.23 789.75
606.36 606.28 633.95
79.72 79.75 84.07
540.26 539.90 585.11
11 89.09 89.05 92.29
15.80 15.80 33.75
19 39.42 38.44 62.65
67 0.02 0.01 0.03
86 55.24 54.25 96.43
500 500 500
0.00 0.00 14.31
29.34 29.35 32.68
6.18 5.28 8.96
68 12.71 12.65 32.65
8 5.68 5.68 5.68
0 1.33 1.29 2.15
86 55.24 54.25 96.43
0 0 0
11 65.73 65.76 63.31
72 99.40 99.35 99.45
2 2.57 2.56 2.60
Table 10 e Comparison of performance indicatorschemical looping vs. Selexol� (Shell gasifier).
Main Plant Data Units Chemicallooping
Selexol�
Coal flowrate kg/h 108 000 121 115
Coal LHV MJ/kg 25.353
Feedstock thermal
energy � LHV (A)
MWth 760.59 852.95
Thermal energy
of the syngas (B)
MWth 606.36 683.21
Cold gas efficiency
(B/A � 100)
% 79.72 80.10
Thermal energy of
gas exit CL (C)
MWth 540.26 607.10
Gas treatment
efficiency (C/B � 100)
% 89.09 88.86
Gas turbine output MWe 15.80 41.20
Steam turbine output MWe 39.42 35.26
Expander (air turbine)
power output
MWe 0.02 0.03
Gross electric power
output (D)
MWe 55.24 76.49
Hydrogen
output � LHV (E)
MWth 500 500
ASU consumption þ O2
compression
MWe 29.34 32.55
Gasification island
power consumption
MWe 6.18 6.25
AGR þ CL þ CO2 drying
and compression
MWe 12.71 29.09
Hydrogen compression MWe 5.68 6.55
Power island power
consumption
MWe 1.33 2.05
Total ancillary power
consumption (F)
MWe 55.24 76.49
Net electric power
output (G ¼ D � F)
MWe 0 0
Hydrogen efficiency
(E/A � 100)
% 65.73 58.62
Carbon capture rate % 99.40 92.35
CO2 specific emissions kg/MWh 2.57 44.95
i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 1 5969
proposed specification but for Case 2, due to the nitrogen used
for coal transport, the captured CO2 stream is not complying
with proposed specification. A way to overcome this problem
is to use some of the captured carbon dioxide as coal transport
gas. In this situation (Case 3), the captured carbon dioxide
stream is complying with proposed specification having the
following composition (vol.%): 96.81% CO2, 1.83% N2, 1.34% Ar,
10 ppmH2O and 6.5 ppmH2S. The substitution of the nitrogen
with carbon dioxide as fuel transport gas to the gasifier has
minor influence on the overall plant performance.
In all investigated case studies, the plant models were
optimised by performing heat and power integration analysis
for maximization of energy efficiency [34e36]. Steam gener-
ated in various plant sub-systems (e.g. gasification island,
syngas conditioning line and chemical looping unit) was
integrated in the steam cycle (Case 1) and in the steam cycle of
the combined cycle gas turbine (Cases 2e4). As an illustrative
example for Case 2 (hydrogen production based on Shell coal
gasification process), detailed simulation data referring to the
steam (Rankine) cycle can be found in Table 8.
For the illustrative examples of Cases 1 and 2, hot and cold
composite curves (HCC and CCC) are presented in Figs. 4 (Case
1) and 5 (Case 2). For Case 2, Fig. 5.a presents hot and cold
composite curves for gasifier island, syngas conditioning line
and chemical looping unit and Fig. 5.b presents hot and cold
composite curves for combined cycle gas turbine (CCGT). As
minimum approach temperature used in pinch analysis,
a conservative value of 10 �C was chosen [34]. As can be
noticed from Figs. 4 and 5, the energy flows were optimised
with multiple utility targeting procedure for maximisation of
plant energy efficiency [35].
After process optimisation by heat and power integration
studies, the overall plant performance indicators were calcu-
lated. An overview of the main plant indicators for all four
investigated case studies is presented in Table 9. For IGCC-
based cases, the power needed to cover the ancillary
consumptions is generated onsite based on a CCGT configu-
ration with the gas turbine running on hydrogen-rich gas
(diluted with nitrogen) [37]. The combined cycle is integrating
also the excess steam from the rest of the plant e.g. chemical
looping unit, gasification island, syngas conditioning line, air
reactor exhaust etc. Due to this aspect, the GT size is rather
small; most of the combined cycle power being generated by
the steam turbine (see Table 9). The usage of a combined cycle
for power generation to cover the ancillary consumption is
a more energy efficient solution than a hydrogen-fuelled
boiler coupled with a steam turbine.
As can be noticed from Table 9, all evaluated case studies
produce 500MWth hydrogen (LHV)with zero net power output.
The hydrogen efficiencies are in range of 63.31e78.11% with
almost total decarbonisation rate of the fossil fuel used (carbon
capture rate 98.72e99.45%). Regarding the plant hydrogen
efficiency, the Case 1 (natural gas-based) is by far the best
option taking advantage of processing a gaseous fuel with
significant higher hydrogen content (natural gas). Regarding
the gasification options, there is little difference between Case
2 andCase 3 in termof overall plant performance indicators; in
addition Case 3 (which considers fuel transport using CO2) is
ensuring the compliance with the quality specification of the
captured carbon dioxide stream. Lignite option (Case 4) is less
efficient that corresponding coal option (Case 2) with about
2.42% hydrogen efficiency (mainly due to the lower calorific
value and the drying process of the lignite).
Comparing the hydrogen production based on natural gas
chemical looping system investigated in this paper with more
traditional steam reforming processes with carbon capture
based on gaseliquid absorption, one can notice that the plant
efficiency is higher in case of chemical looping systemwith at
least 5% in term of net hydrogen efficiency (78.11% vs. an
average value of about 73% for pre-combustion capture using
MDEA and an average value of about 65% for post-combustion
capture after furnace using MEA) [4,38,39].
The comparison of hydrogen efficiency of the whole IGCC
scheme which uses iron based chemical looping system for
carbon capture with classical technology of carbon dioxide
capture by gaseliquid absorption (e.g. Selexol� process
[6,40e44]) is presented in Table 10. One can notice that the
chemical looping system gives a lower energy penalty for
i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 15970
carbon capture than gaseliquid absorption with at least 7% in
term of plant hydrogen efficiency. Specific carbon dioxide
emissions in case of using chemical looping systemare almost
negligible, being in the range of 2e3 kg/MWhwith almost total
carbon capture rate while for pre-combustion capture using
gase liquid absorption in Selexol�, the specific carbon dioxide
emissions are about 45 kg/MWh (92.32% carbon capture rate).
This analysis is showing the very good potential of the
chemical looping systems for efficient decarbonisation of
various fossil fuels simultaneously with lower energy penal-
ties compared with more traditional methods (e.g. gaseliquid
absorption).
5. Conclusions
The paper assesses the technical aspects of hydrogen
production schemes based on conversion of various fossil
fuels (natural gas, coal and lignite) considering an iron based
chemical looping as carbon capture option. The paper
assesses in details using modelling and simulation methods,
the potential applications of natural gas and syngas-based
chemical looping systems to generate purified hydrogen.
Investigated plant concepts produce 500 MWhydrogen (based
on lower heating value) covering all ancillary power
consumptions with an almost total decarbonisation rate of
the fossil fuels used.
The paper presents in details the plant concepts and the
methodology used to evaluate the performances using critical
design factors like: gasifier feeding system (various fuel
transport gases), heat and power integration analysis of the
chemical looping unit in the rest of the plant, potential ways
to increase the overall energy efficiency (e.g. steam integration
of chemical looping unit into the combined cycle), hydrogen
and carbon dioxide quality specifications considering the use
of hydrogen in transport (fuel cells) and carbon dioxide
storage in geological formation or used for EOR.
One of the main conclusions of the paper is that chemical
looping systems used for carbon capture imply significantly
lower energy penalties compared with more classical carbon
capture technologies like gaseliquid absorption (used either
in pre- or post-combustion capture arrangement). This is
particularly interesting for producing very high purity
hydrogen and carbon dioxide capture based on fossil fuels
conversion without having a huge AGR plant based on
gaseliquid absorption process.
A technical analysis regarding the quality specification of
captured carbon dioxide stream from iron based chemical
looping system in various case studies (natural gas, dry feed
gasifiers using nitrogen or carbon dioxide as transport gas)
was made considering the constraints imposed by the trans-
port and storage (geological storage or EOR). For natural gas
case, the captured CO2 is complying with proposed specifica-
tion but for IGCC-based cases which use nitrogen as fuel
transport gas to the gasifier, the captured CO2 stream is not
complying with the proposed specification due to the nitrogen
contamination. To overcome most of the nitrogen contami-
nation in case of dry feed gasifiers, carbon dioxide can be used
to transport the solid fuel to the gasifier with minor effect on
the overall plant performance indicators.
Acknowledgements
This work has been supported by Romanian National
University Research Council (CNCSIS-UEFISCDI), project
number PNII e IDEI code 2455/2008: “Innovative systems for
poly-generation of energy vectors with carbon dioxide capture
and storage based on co-gasification processes of coal and
renewable energy sources (biomass) or solid waste”.
r e f e r e n c e s
[1] European hydrogen and fuel cell technology platform.Strategic research agenda, https://www.hfpeurope.org/; 2010.
[2] Muller-Langer F, Tzimas E, Kaltschmidtt M, Peteves S.Techno-economic assessment of hydrogen productionprocesses for the hydrogen economy for the short andmedium term. Int J Hydrogen Energy 2007;32:3797e810.
[3] European Commission. DG energy and transport (DG TREN).Strategic energy review, http://ec.europa.eu/energy; 2010.
[4] International Energy Agency (IEA). Greenhouse Gas R&DProgramme (GHG). Decarbonisation of fossil fuels. Report PH2/2; 1996.
[5] International Energy Agency (IEA), Greenhouse Gas R&DProgramme (GHG). Co-production of hydrogen and electricityby coal gasification with CO2 capture. Report 13/2007; 2007.
[6] Cormos CC, Starr F, Tzimas E, Peteves S. Innovative conceptsfor hydrogen production processes based on coal gasificationwith CO2 capture. Int J Hydrogen Energy 2008;33:1284e94.
[7] Zhang H, Lin G, Chen J. Evaluation and calculation on theefficiency of a water electrolysis system for hydrogenproduction. Int J Hydrogen Energy 2010;35:10851e8.
[8] Zeng K, Zhang D. Recent progress in alkaline waterelectrolysis for hydrogen production and applications. ProgEnergy Comb Sci 2010;36:307e26.
[9] Pregger T, Graf D, Krewitt W, Sattler C, Roeb M, Moller S.Prospects of solar thermal hydrogen production processes.Int J Hydrogen Energy 2009;34:4256e67.
[10] Rosen MA. Advances in hydrogen production bythermochemical water decomposition: a review. Energy2010;35:1068e76.
[11] Hallenbeck PC. Fermentative hydrogen production:principles, progress, and prognosis. Int J Hydrogen Energy2009;34:7379e89.
[12] Figueroa JD, Fout F, Plasynski S, McIlvired H, Srivastava R.Advances in CO2 capture technology e The U.S. Departmentof Energy’s Carbon Sequestration Program. Int J GreenhouseGas Control 2008;2:9e20.
[13] Intergovernamental Panel on Climate Change (IPCC). Specialreport: carbondioxidecaptureandstorage,www.ipcc.ch; 2010.
[14] Johansson E, Mattisson T, Lyngfelt A, Thunman H.Combustion of syngas and natural gas in a 300 W chemical-looping combustor. Chem Eng Res Des 2006;84:819e27.
[15] Cleeton JPE, Bohn CD, Muller CR, Dennis JS, Scott SA. Cleanhydrogen production and electricity from coal via chemicallooping: identifying a suitable operating regime. IntJ Hydrogen Energy 2009;34:1e12.
[16] Chiesa P, Lozza G, Malandrino A, Romano M, Picollo V.Three-reactors chemical looping process for hydrogenproduction. Int J Hydrogen Energy 2008;33:2233e45.
[17] Gnanapragasam NV, Reddy BV, Rosen MA. Hydrogenproduction from coal using coal direct chemical looping andsyngas chemical looping combustion systems: assessment ofsystem operation and resource requirements. Int J HydrogenEnergy 2009;34:2606e15.
i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 5 9 6 0e5 9 7 1 5971
[18] Cormos CC. Evaluation of iron based chemical looping forhydrogen and electricity co-production by gasificationprocess with carbon capture and storage. Int J HydrogenEnergy 2010;35:2278e89.
[19] Svoboda K, Slowinski G, Rogut J, Baxter D. Thermodynamicpossibilities and constraints for pure hydrogen production byiron based chemical looping process at lower temperatures.Energy Convers Manage 2007;48:3063e73.
[20] Kang KS, Kim CH, Bae KK, Cho W, Kim SH, Park CS. Oxygen-carrier selection and thermal analysis of the chemical-looping process for hydrogen production. Int J HydrogenEnergy 2010;35:12246e54.
[21] Fan LS. Chemical looping systems for fossil energyconversions. Wiley-AIChE; 2010.
[22] Rwe AG. The WTA technology: a modern process for treatingand drying lignite, www.rwe.com; 2010.
[23] Higman C, Van der Burgt M. Gasification. 2nd ed. GulfProfessional Publishing, Elsevier Science; 2008.
[24] Cormos CC. Decarbonizarea combustibililor fosili solizi pringazeificare. Cluj University Press; 2008.
[25] Besancon BM, Hasanov V, Imbault-Lastapis R, Benesch R,Barrio M, Mølnvik MJ. Hydrogen quality from decarbonizedfossil fuels to fuel cells. Int JHydrogenEnergy2009;34:2350e60.
[26] De Visser E, Hendriks C, Barrio M, Mølnvik MJ, De Koeijer G,Liljemark S, et al. Dynamis CO2 quality recommendations.Int J Greenhouse Gas Control 2008;2008(2):478e84.
[27] Abad A, Adanez J, Garcia-Labiano F, de Diego LF, Gayan P.Modelingof thechemical-loopingcombustionofmethaneusinga Cu-based oxygen-carrier. Combust Flame 2010;157:602e15.
[28] Hoogers G. Fuel cell technology handbook. CRC Press; 2003.[29] ChemCAD.Chemicalprocesssimulationeversion6.01.Huston,
USA: Chemstations, http://www.chemstations.net; 2010.[30] McGlashan NR. The thermodynamics of chemical looping
combustion applied to the hydrogen economy. IntJ Hydrogen Energy 2010;35:6465e74.
[31] Cormos CC. Evaluation of power generation schemes basedon hydrogen-fuelled combined cycle with carbon captureand storage (CCS). Int J Hydrogen Energy 2010;35(5):3726e38.
[32] Xiang W, Chen S, Xue Z, Sun X. Investigation of coalgasification hydrogen and electricity co-production plantwith three-reactors chemical looping process. Int J HydrogenEnergy 2010;35:8580e91.
[33] Mattisson T, Garcia-Labiano F, Kronberger B, Lyngfelt A,Adanez J, Hofbauer H. Chemical-looping combustion usingsyngas as fuel. Int J Greenhouse Gas Control 2007;1:158e69.
[34] Smith R. Chemical processes: design and integration. WestSussex, England: Wiley; 2005.
[35] Varghese J, Bandyopadhyay S. Targeting for energyintegration of multiple fired heaters. Ind Eng Chem Res 2007;46:5631e44.
[36] CormosCC. Evaluation of energy integration aspects for IGCC-based hydrogen and electricity co-production with carboncapture and storage. Int J Hydrogen Energy 2010;35:7485e97.
[37] Lee MC, Seo SB, Chung JH, Kim SM, Joo Y, Ahn DH. Gasturbine combustion performance test of hydrogen andcarbon monoxide synthetic gas. Fuel 2010;89:1485e91.
[38] Damen K, van Troost M, Faaij A, Turkenburg W.A comparison of electricity and hydrogen productionsystems with CO2 capture and storage. Part A: review andselection of promising conversion and capture technologies.Prog Energy Comb Sci 2006;32:215e46.
[39] ChenWH, Lin MR, Lu JJ, Chao Y, Leu TS. Thermodynamicanalysis of hydrogen production frommethane viaautothermal reforming andpartial oxidation followedbywatergas shift reaction. Int J Hydrogen Energy 2010;35:11787e97.
[40] Cormos CC. Assessment of hydrogen and electricity co-production schemes based on gasification process withcarbon capture and storage. Int J Hydrogen Energy 2009;34:6065e77.
[41] Chiesa P, Consonni S, Kreutz T, Williams R. Co-production ofhydrogen, electricity and CO2 from coal with commerciallyready technology. Part A: performance and emissions. Int JHydrogen Energy 2005;30:747e67.
[42] Erlach B, Schmidt M, Tsatsaronis G. Comparison of carboncapture IGCC with pre-combustion decarbonisation and withchemical-looping combustion. Energy, in press. doi:10.1016/j.energy.2010.08.038.
[43] Gnanapragasam NV, Reddy BV, Rosen MA. Hydrogenproduction from coal gasification for effective downstreamCO2 capture. Int J Hydrogen Energy 2010;35:4933e43.
[44] Cormos CC, Agachi PS. Hydrogen production from coal andbiomass co-gasification process with carbon capture andstorage. 18-th World Hydrogen Energy Conference (WHEC),Essen, Germany; 2010.