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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: cormos@chem.ubbcluj.ro

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”.

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