CO 2 Capture and Storage
VGB Report on the State of the Art
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ech
CO
2Capture and Storage
PowerTech PowerTech
Source: Scientific American
Reference Power Plant North Rhine-Westfalia
CO 2 Capture and Storage
A VGB Report on the State of the Art
Published by VGB PowerTech e.V.
Obtainable from:
VGB PowerTech Service GmbH Verlag technisch-wissenschaftlicher Schriften
Postfach 10 39 32, D-45039 Essen Tel. +49-(0)201 8128-200 Fax +49-(0)201 8128-329
e-mail: [email protected]
VGB PowerTech e.V.
VGB PowerTech e.V. is a voluntary association of companies for which the operation of power stations and heating plants and the associated technology form an important basis of their corporate activity. The common aim of all the members – and therefore of VGB – is to promote and improve the operational safety and environmental compatibility and the availability and economic efficiency of both existing and new power plants.
Approximately 420 utilities and industrial companies as well as institutions operating or manufacturing power and heating plants or dealing with related issues are members of VGB. Approximately 150 of VGB’s member companies are located in 29 countries worldwide. The majority are in Europe and represent more than 440,000 MW installed capacity of nuclear, fossil, hydro and other renewable power plants.
VGB Homepage: http://www.vgb.org
According to the Kyoto Protocol of December 1997 the developed countries are obliged to reduce their greenhouse gas emissions by an average of 5.2 % below 1990 levels by 2008 / 2012. Among the measures to reach this goal the capture and storage of CO2 could be a useful future technology. For this reason capture and storage of CO2 have been studied for a number of years. This report provides an overview of the relevant state of the art at fossil fired power plants. It has been prepared by the VGB Working Panel
“CO2 Capture and Storage”. The members of this group are:
Duncan Clarke ESB Electricity Supply Board, Ireland Branko Debeljak Holding Slovenske Electrarne, Slovenia Vasco de Janeiro EURELECTRIC
Gerold Göttlicher MVV Energie, Germany David Graham E.ON UK, United Kingdom Niels Kirkegaard Elsam Engineering, Denmark Michael Madsen Energi E2, Denmark
Sauro Pasini ENEL, Italy
Bennie Stortelder KEMA, The Netherlands Lars Strömberg Vattenfall, Sweden Wolfgang vom Berg VGB PowerTech Volker Hamacher VGB PowerTech With further valuable contributions from:
Marie Anheden Vattenfall, Sweden Ole Biede Energi E2, Denmark Clas Ekström Vattenfall, Sweden
Essen, 25. August 2004
The views and judgements expressed in this report reflect a consensus reached by the members of the Working Panel and do not necessarily reflect those of the companies to which the members belong.
Whilst every care has been taken in compiling the information in this report, none of the members or organisations referred to above can be held responsible for any errors or omissions.
Table of Contents
Page0 LIST OF ABBREVIATIONS 9
1 INTRODUCTION 11
1.1 Scope 11
1.2 Global warming and CO2 11
1.3 Dependence of CO2 emission on fuel type and energy
conversion technology 13
1.4 Factors influencing power technology selection and fuel
choice 15
1.5 The EU greenhouse gas emissions trading scheme 16 2 TECHNICAL OPTIONS FOR CO2 CAPTURE 19
2.1 Background 19
2.2 Overview 19
2.3 Post combustion capture 21
2.3.1 Basic principle 21
2.3.2 Components and special considerations 23 2.3.3 Technology status and R&D needs 26
2.4 Pre-combustion carbon capture 29
2.4.1 Basic principle 29
2.4.2 Components and special considerations 30 2.4.3 Technology status and R&D needs 33 2.5 O2/CO2 recycle combustion (Oxyfuel combustion) 35
2.5.1 Basic principle 35
2.5.2 Boiler steam cycle 36
2.5.3 Circulating fluidized bed concepts 39 2.5.4 Gas turbine cycles with CO2 as the working fluid 40 2.5.5 Technology status and R&D needs 43
2.6 CO2 conditioning 44
2.7 Overview of other concepts 45
2.7.1 Chemical looping combustion 45
2.7.2 Fuel cells 49
2.7.3 Dry regenerative CO2 absorption 50
2.7.4 ZECA process 53
2.8 Industrial and academic bodies active in CO2 capture
technology 54
2.9 Efficiencies and costs for CO2 capture 56
2.10 Conclusions 59
2.11 References 61
3 COSTS ANALYSIS OF SELECTED CAPTURE OPTIONS 65
3.1 Introduction 65
3.2 Coal fired power plants 65
3.3 Natural gas fired power plants 68
3.4 Recalculated cases with CO2 emission avoidance costs 71
3.5 Results 73
3.6 Conclusions 81
3.7 References 81
4 CO2 STORAGE 83
4.1 Storage in geological formations 83
4.1.1 Aquifers 83
4.1.2 Oil and natural gas fields 85
4.1.3 Coal seams 87
4.2 CO2 storage in the sea 88
4.3 Storing CO2 as carbonate 89
4.4 Legality of CO2 storage 89
4.4.1 Introduction 89
4.4.2 Under-ground storage 90
4.4.3 Ocean storage 90
4.5 Concluding remarks 91
4.6 References 95
5 TRANSPORTATION SYSTEMS FOR CO2 – APPLICATION
TO CARBON CAPTURE AND STORAGE 98
5.1 General 98
5.2 Transportation systems 98
5.2.1 Existing CO2 transportation systems 99
5.2.2 Intermediate storage 99
5.2.3 Safety issues 100
5.3 Transportation costs 100
5.4 Summary 105
5.5 References 106
6 OVERALL CONCLUSIONS 108
Table 1-1 Greenhouse gases in the Kyoto Protocol ... 11
Table 1-2 Actual list of European R&D projects for CO2 capture and storage... 12
Table 1-3 CO2 from fossil fuel combustion (per unit of thermal energy) ... 14
Table 2-1 Commercial CO2 plants... 27
Table 2-2 Comparison of the membrane processes for separating CO2 from waste gases and the production of a carbon-free fuel ... 32
Table 2-3 Salient data of IGCC with CO2 removal compared to the reference case ... 34
Table 2-4 Process flow rates and capture efficiency for Alstom’s regenerative wheel applied to a 250 MWe coal fired boiler ... 52
Table 2-5 Examples of reported efficiencies and costs for power plants with CO2 capture... 58
Table 3-1 Comparison of efficiencies and costs for post- combustion capture from coal fired power plants ... 66
Table 3-2 Comparison of efficiencies and costs for pre- combustion capture from coal fired power plants ... 66
Table 3-3 Comparison of efficiencies and costs for oxyfuel combustion capture from coal fired power plants ... 67
Table 3-4 Comparison of efficiencies and costs for post- combustion CO2 capture from natural gas fired power plants... 69
Table 3-5 Comparison of efficiencies and costs for pre- combustion CO2 capture from natural gas fired power plants... 69
Table 3-6 Comparison of efficiencies and costs for oxyfuel combustion CO2 capture from natural gas fired power plants... 70
Table 3-7 Data for the six reference cases (1, 3, 5, 7, 10, 12) and the ten cases with CO2 capture (2, 4, 6, 8, 9, 11, 13, 15, 17, 19) ... 73
Table 4-1 Estimated European underground CO2 storage capacities ... 84
Table 4-2 Capacity of CO2 storage – estimates for all North Sea fields... 86
Table 4-3 World ECBM CO2 storage potential ... 88
Table 4-4 Summary of storage techniques... 93
Table 5-1 Compiled costs for intermediate storage ... 101
Table 5-2 Module combinations evaluated in the different scenarios... 103
Figure 1-1 Carbon dioxide emissions from various fuel and
technology options... 14
Figure 2-1 The three main options for CO2 capture from power plants ... 20
Figure 2-2 The amine absorption process – basic process layout for Fluor Econamine process... 23
Figure 2-3 Scheme of a power plant with SO2 and CO2 flue gas scrubber and steam extraction for solvent regeneration ... 28
Figure 2-4 IGCC with pre-combustion decarbonisation ... 30
Figure 2-5 Principle of O2/CO2 recycle combustion illustrated for coal ... 35
Figure 2-6 Example of O2/CO2 recycle combustion applied to a coal fired power plant ... 37
Figure 2-7 O2/CO2 CFB concept ... 40
Figure 2-8 Combined cycle with combustion in O2/CO2. ... 41
Figure 2-9 Quasi-combined cycle with internal recuperation and liquefaction. ... 42
Figure 2-10 Gas turbine process with oxygen supply by membrane reactor (Advanced Zero Emission Plant – AZEP) ... 43
Figure 2-11 CO2 phase diagram ... 44
Figure 2-12 The concept of chemical looping combustion (CLC) with nickel oxide as the oxygen carrier ... 46
Figure 2-13 Chemical-looping combustion systems... 47
Figure 2-14 Principle of a SOFC ... 49
Figure 2-15 Principle of the ALSTOM CO2 wheel ………...51
Figure 2-16 High temperature carbonation process... 52
Figure 2-17 Schematic representation of ZECA process ... 53
Figure 3-1 Net electric efficiencies for coal fired power plants with and without CO2 capture. ... 68
Figure 3-2 Net electric efficiencies for natural gas fired power plants with and without CO2 capture... 71
Figure 3-3 CO2 emission avoidance costs for the 10 cases... 74
Figure 3-4 Specific CO2 emission for the 10 cases... 75
Figure 3-5 Electricity costs with CO2 emission costs of 0, 10 and 40 Euro/tonne CO2 emitted... 76
Figure 3-6 Influence from fuel price on CO2 emission avoidance costs ... 77
Figure 3-7 Influence from fuel price on electricity costs ... 77
Figure 3-8 Influence from fuel price ratio on CO2 emission avoidance costs... 78
Figure 3-9 Influence from fuel ratio on electricity costs ... 79
Figure 3-10 Influence from interest rate on CO2 emission avoidance costs... 80
Figure 3-11 Influence from interest rate on electricity costs... 80
Figure 4-1 Possibilities of geological CO2 storage ... 83
Figure 4-2 Storage cost estimates - aquifers ... 92
Figure 4-3 Storage cost estimates - depleted gas fields ... 92
Figure 5-1 Cost and capacity for transportation alternatives at 250 km transport distance. ... 101 Figure 5-2 Development of large scale CO2 transportation
infrastructure. ... 102 Figure 5-3 Accumulated costs for different transportation
scenarios... 102
0 LIST OF ABBREVIATIONS ASU Air Separation Unit
AZEP Advanced Zero Emission Plant BAT Best Available Technique BEP Best Environmental Practice
BGR Federal Office for Geo-sciences and Raw Materials (Germany) BOA Innovative Technology for Lignite-fired Power Plants
BPEO Best Practical Environmental Option CAR Ceramic Auto-thermal Recovery
CC Combined Cycle
CENS CO2 for EOR in the North Sea CFB Circulating Fluidised Bed CLC Chemical Looping Combustion CMB Circulating Moving Bed
CSIRO Commonwealth Scientific and Industrial Research Organisation (Australia)
CTH Chalmers Technical High School
DEA Diethanolamine
DMPEG Dimethylether-polyethylene-glycol DTI Department of Trade and Industry (UK) ECBM Enhanced Coalbed Methane
ECCP European Climate Change Programme
EOR Enhanced Oil Recovery
EU FVI European Commission: EU Framework VI R&D Programme FGD Flue Gas Desulphurisation
GEO-SEQ Geological Sequestration of CO2
GESTCO Geological Storage of CO2
GHG Greenhouse Gas
GT Gas Turbine
HHV High Heating Value
HRSG Heat Recovery Steam Generator
HTW Hochtemperatur (High Temperature) Winkler Process IEA International Energy Agency
IEA GHG International Energy Agency, Greenhouse Gas Research &
Development Programme
IGCC Integrated Gasification Combined Cycle
IP Intermediate Pressure
IPPC Integrated Pollution Prevention and Control
LHV Low Heating Value
LP Low Pressure
LPG Liquefied Petroleum Gas MBHX Moving Bed Heat Exchanger MCFC Molten Carbonate Fuell Cell MDEA Methyldiethanolamine
MEA Monoethanolamine
NAP National Allocation Plan
NG Natural Gas
NGCC Natural Gas Fired Combined Cycle NMP N-methyl-2-pyrrolidon
O&M Operation and Maintenance
OSPAR Convention on the Protection of the North Sea and North East Atlantic
PAFC Phosphoric Acid Fuel Cell
PC Pulverized Coal
PEM Polymer Electrolyte Membrane
PF Pulverized Fuel
R&D Research and Development
RITE Research Institute of Innovative Technology for the Earth (Japan) SACS Sleipner Aquifer for CO2 Storage
SINTEF Foundation for Scientific and Industrial Research at the Norwegian University of Science and Technology
SOFC Solid Oxide Fuel Cell
TNO The Netherlands Organisation for Applied Scientific Research UNFCCC United Nations Framework Convention on Climate Change US DOE US Department of Energy
ZECA Zero Emission Coal Alliance
1 INTRODUCTION 1.1 Scope
This review firstly considers carbon capture technologies (Chapter 2) since these are judged to be the most costly and least well developed components of the carbon removal process. Chapter 3 then considers the cost
implications of applying the more advanced of these technologies to various plant types and firing configurations. The following chapters then consider transport and storage issues (Chapters 4 and 5), including legal and
economic aspects, prior to a consideration of the overall conclusions related to the various technology/fuel choices. The remainder of this introductory chapter considers the driving forces for a low carbon economy, including the development of a European wide CO2 trading scheme, and the place of CO2
capture and storage within the basket of measures adopted by the EU, particularly in relation to the continuing use of coal for power generation.
1.2 Global warming and CO2
The driving force behind international efforts to tackle global environmental issues such as climate change has been the United Nations, mainly the United Nations Framework Convention on Climate Change (UNFCCC).
The 1992 ‘Earth Summit’ in Brazil produced the Framework Convention on the Atmosphere (Climate Treaty) which came into force on 21/3/1994. This led to the Kyoto Protocol of December 1997 which has yet to be ratified by either the U.S. or the Russian Federation. The Protocol specifies legally binding cuts in emissions of six greenhouse gases: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur
hexafluoride. Between 2008-2012 developed countries will reduce their emissions by an average of 5.2 % below 1990 levels. Different targets have been set for individual countries or regions – e.g. 8 % for the European Union. The Protocol also permits emissions trading between countries as a means of meeting targets.
Gas Qualifying Sources Lifetime
(years) Global Warming Potential (relative to CO2)
% GHG1) 1990 Carbon dioxide
(CO2) Fossil fuel burning,
Cement Variable,
~100 1 81.2
Methane
(CH4) Rice, livestock, biomass decay & combustion, fossil fuel production
12.2 + 3 21 13.7
Nitrous oxide
(N2O) Fertilizers, fossil fuel
combustion, agriculture 120 310 4.0
Hydrofluorocarbons
(HFCs) Industry, refrigerants 1.5-264 140-11,700 0.56
Perfluorocarbons
(PFCs) Industry, aluminium, electronic industries, fire fighting, solvents
2,600-
50,000 Average 6,770 0.29
Sulphur hexafluoride
(SF6) Electronic industries
insulation 3,200 23,900 0.30
1) Contribution to the greenhouse warming effect
Source: Grubb (1999) (100 year time horizon for Global Warming Potential)
Table 1-1 Greenhouse gases in the Kyoto Protocol
The first three of the greenhouse gases are important from a fossil fuel/
combustion standpoint and it can be seen, from Table 1-1, that CO2 is the most important of these, accounting for about 80 % of the enhanced global warming effect, even though it has the lowest Global Warming Potential and a relatively short life-time in the atmosphere.
Despite the lack of ratification of the Kyoto Protocol, and some uncertainty in the impacts of enhanced global warming, the EU is therefore maintaining the position that CO2 emissions should be reduced in line with the ‘Precautionary Principle’. Measures to reduce CO2 include: improved energy efficiency, financial incentives for renewable energy sources and CO2 trading (described briefly in this report). Research efforts within the EU have focused or focus on clean coal technologies, including efficiency improvements associated with advanced super-critical coal fired plant. More recently, the focus is shifting towards carbon capture and storage technologies, in recognition of a) the need for development effort and b) the potential importance of these technologies in meeting long term commitments to reduce CO2. However, there is obviously a need to also maintain research effort in more
conventional areas that can produce short-term, incremental, improvements in energy efficiency.
A selection of R&D projects relevant to CO2 capture and storage is given in Table 1-2.
Project Objective Status
Capture GRACE
Grangemouth Advanced CO2
Capture Project Development of membranes and looping combustion to achieve a step change in the capture cost
finished in 2003
AZEP
Advanced Zero Emission Power
Plant Development of a gas turbine based cycle to
lower pre-combustion capture costs in power plants
launched in 2001 to be finished in 2004
ENCAP
Enhanced Capture of CO2 Process and power systems
Pre-combustion decarbonisation technologies OxyFuel boiler technologies
Chemical looping combustion
High-temperature oxygen generation for power cycles
Novel pre-combustion capture concepts
launched in 2004 to be finished in 2008
Storage SACS 2
Sleipner Aquifer CO2 Storage (2) –
Demonstration in the Sleipner Field Investigation of CO2 injection in the Utsira aquifer under the North Sea; CO2 bubble monitoring, prediction of long-term CO2 behaviour
finished in 2002
GESTCO
Geological Storage of CO2 from
Fossil Fuel Combustion A study involving many EU geological societies
to estimate geol. storage potential in Europe finished in 2003
NASCENT
Natural Analogues to the Storage of
CO2 in the Geological Environment A study of naturally occurring CO2 reservoirs to
understand long term stability finished in 2003 ICBM
Development of Advanced Reservoir Characterisation and Simulation Tools for Improved Coalbed Methane Recovery
Investigation of the basic scientific phenomena of
CO2 injection and retention in coal launched in 2000 to be finished in 2004
RECOPOL
Reduction of CO2 Emission by means of CO2 Storage in Coal Seams in the Silesian Coal Basin of Poland
A demonstration project for the use of CO2 for
ECBM in a Polish coal field launched in 2001 to be finished in 2004
CO2STORE
On-Land and Long Term Saline
Aquifer CO2-Storage Investigation of properties of a number of new storage reservoirs in DK, D, N, and the UK, and continuation of the investigation of CO2 injection in the Utsira aquifer under the North Sea
launched in 2003 to be finished in 2006
CO2SINK
In-situ R&D Laboratory for Geological Storage of CO2
Practical test of geological storage Real case risk assessment
Monitoring techniques (calibration / novel ones) Practical experience with regulatory procedures
launched in 2004 to be finished in 2008
Capture and Storage CASTOR
CO2, from Capture to Storage Cost reduction of CO2 post-combustion capture Pilot testing for capture
Improving performance, safety and acceptance of the geological storage concept
Detailed studies of future storage sites
launched in 2004 to be finished in 2007
Table 1-2 European R&D projects related to CO2 capture and storage
1.3 Dependence of CO2 emission on fuel type and energy conversion technology
A difficulty in comparing emissions from systems employing differing technologies and fuel types is that any emission reduction level (up to
practically 100 % removal) level can be achieved with a sufficiently high level of expenditure. The question is whether or not this is a reasonable measure when balancing the benefit to the environment against a greatly increased cost and risk.
For illustration, Klein (1999a) provides a comparison of the emissions performance of conventional cycles (steam raising boilers) and advanced combined cycles based on gas turbine technology. A similar approach, shown in Figure 1-1, has been used to compare CO2 emissions from coal, oil and gas fired boiler systems with those from a natural gas fired combined cycle (NGCC) plant and an integrated gasification combined cycle (IGCC) plant. The assumed efficiencies are: lignite 45 %, coal 46 %, oil 45 %, gas 47 %, NGCC 58 %, IGCC 45 %.
Figure 1-1 Carbon dioxide emissions from various fuel and technology options
The detailed assumptions relating to plant efficiency and technology status can always be debated. However, there are a number of general points that can be made:
• switching from coal to gas almost halves the carbon dioxide emission simply due to the chemical composition of the fuel (see also Table 1-3);
• the improved efficiency of the combined cycle gives a further CO2
reduction (now totalling 60 to 65% reduction when compared with conventional coal);
• co-generation improves the actual emissions performance due to the very high overall thermal efficiency.
Fuel t CO2/TJ
Lignite
Sub-bituminous Coal Coking Coal
Residual Fuel Oil Diesel/Gas Oil Natural Gas
101.2 96.1 94.6 77.4 74.1 56.1
Table 1-3 CO2 from fossil fuel combustion (per unit of thermal energy)
(Source: EU Guidelines for the monitoring and reporting of greenhouse gas emissions (2004), after IPPC (1996))
1.4 Factors influencing power technology selection and fuel choice The IEA has identified the following factors influencing power plant selection:
Financing. Capital cost; financial arrangements; fuel costs; income (power purchase agreements); O&M costs; load factor and availability (influenced by technology status and risk).
Fuel selection. Availability (90% of coal production is used in country of origin) and security of supply price (future uncertainty in coal/gas prices but coal is more stable due to abundance of supply; transportation and storage).
Environment. Emissions to land, water and the atmosphere; local environmental concerns (noise/visibility/amenity value and planning
consents); linkage with environmental legislation; inter-relationship with local- regional air quality/acid deposition and environmental impact assessments.
Influencing factors. The above, inter-related, factors may be profoundly influenced by the regime governing the power generation industry: state owned monopoly vs. free market; energy policy (fuel mix-plant type-district heating requirement-location); legislative regime clean-up technologies (cost), time-scales ….; economy – local production required which may limit the technology employed.
It is evident that, when suitably priced natural gas is available, it is the first choice from an environmental perspective since, in addition to achieving the lowest release rates of CO2, emissions of SO2 and particulate are negligibly small and NOx emissions are also reduced when compared with oil and coal firing. Combined Cycle Gas Turbine plant also offers reduced build times, lowest capital cost and flexibility of operation. This explains the ‘dash for gas’
in parts of Europe and the U.S.
However, there are a number of factors that will ensure the continuing use of coal within the energy mix:
Security of supply. Coal reserves are much larger than oil and gas reserves (230 years compared with about 60 years at current consumption levels) and many countries within the EU are currently heavily dependant on coal for electricity production since the fuel is locally available. The
anticipated new build in Europe is 550 GWe by 2030, and these plants will be operating through the period of declining oil and gas supplies. In addition, gas supplies will be from fewer sources with greater vulnerability of supply.
Quite apart from availability and cost concerns, it is unlikely that renewable energy technology will be deployed at a suitable scale to meet either CO2
reduction targets or increased electricity demand. Nor does it seem likely that nuclear capacity will be greatly expanded across this time period, for socio-political reasons in addition to concerns regarding nuclear waste processing.
Fuel pricing. Natural gas prices have traditionally shown greater volatility than coal prices and this has a major impact on the viability of power generation schemes.
Technology development. The thrust of clean coal technology research is towards ever lower emissions and increased efficiency at an acceptable cost and with a high availability. However, it may prove difficult to deploy novel generating technologies when the power industry has shown an aversion to risk and the possibility of compromising availability.
Fuel switching (to natural gas) is unsustainable in the longer term and increasing the efficiency of coal fired plant alone may be insufficient to achieve CO2 reduction targets against a back drop of increased demand.
The development of CO2 capture and storage is therefore being considered as a medium term option for achieving a low carbon economy, particularly when taking into account financial incentives offered by a carbon emission trading scheme.
1.5 The EU greenhouse gas emissions trading scheme
Greenhouse gases are good candidates for international emissions trading since climate change is a global problem. Also, emissions of the main greenhouse gases are easy to measure and control, e.g., CO2 is directly related to the quantity of fuel burnt, although this is not the case for carbon sinks and agriculture in general.
As of 1 January 2005, companies from sectors covered by EU Directive 2003/87/EC must limit their greenhouse gas emissions to allocated levels in the two periods from 2005-2007 and 2008-2012. The Directive establishes a scheme for greenhouse gas emission allowance trading within the
Community. The Directive can also be adopted by the European Economic Area countries and Switzerland, bringing the coverage to a potential 28 countries. The EU scheme will be the first multi-national emissions trading scheme in the world and is considered a forerunner of the international emissions trading scheme under the Kyoto Protocol.
The sectors covered by the scheme comprise: energy (e.g. combustion installations with a rated thermal input exceeding 20 MW); minerals (e.g.
cement, lime, glass and ceramics); metals (e.g. iron and steel) and pulp and paper. Around 10,000 installations will be covered representing about half of the EU’s total greenhouse gas emissions.
The rationale behind emissions trading is that it will allow each Member State to regulate the level of their country’s emissions by setting an overall cap, while giving companies the flexibility to trade their own emissions
‘allowances’ within the cap. Each company will need to have a permit and be able to monitor and report its CO2 emissions (based on fuel consumption in most cases). Companies will have a ceiling for their allowances, but will be able to exceed the cap providing they buy an allowance for each excess
tonne or pay the penalty, i.e. 40 /tCO2 in the period 2005 – 2007 and 100 /tCO2 from 2008 to 2012. Similarly, companies which are within their limit can sell or ‘bank’ their surplus allowances.
Thus, the overall level of emissions remains within the cap so the benefit to the environment is still the same, but the reduction takes place where cost is lowest. Clearly, a company's strategy will largely depend on the price at which emission reductions are traded.
The emissions trading scheme will have a profound effect on the European electricity industry by affecting production costs and future investment decisions. As a result of the scheme, fossil fuel power plants (i.e. coal, gas and oil) will have to internalise the cost of emitting greenhouse gas
emissions, which will have an impact on electricity prices.
A key consequence of the emissions trading scheme is that CO2 emissions will have a price. This price will provide a signal to sectors covered by the Directive on which CO2 abatement measures they should implement. It is expected that the emissions trading market will start off with modest prices, but, overtime, as scarcity of allowances will increase, CO2 prices will rise.
This probable market development will influence investment behaviour. In parallel, the cost of CO2 capture, transport and storage technologies will drop and, in the medium to long-term, these will eventually become a competitive option for electricity companies to reduce greenhouse gas emissions.
Some of the main elements of the emissions trading scheme comprise the following:
Method of allocating allowances: For the period 2005-2007 Member States shall allocate at least 95 % of the allowances free of charge and in the period 2008-2012 at least 90 % of the allowances free of charge.
Quantity of allowances allocated: Member States must show that they are on a path to meeting their Kyoto Protocol obligations (2008-2012) when proposing the quantity of allowances to be allocated to
companies in the first phase (2005-2007). Member States must prepare their National Allocation Plans (NAP) setting out the allowances that each sector and installation will be issued.
Temporary exclusion of certain installations: Member States may apply to the Commission for installations to be temporarily excluded until 31 December 2007. However, it should be ensured that there will be no distortion of the market.
Credits from the Kyoto Protocol project mechanisms (Joint Implementation and the Clean Development Mechanism): the Directive states that linking project-based mechanisms and the emissions trading scheme is desirable and important to achieve emissions reductions in a cost-effective way. The Directive also
provides for the scheme to be linked to compatible trading schemes in other countries that have ratified the Kyoto protocol.
Future extension of the scheme to other sectors and gases: The
Commission will assess the coverage of the scheme with a view to the possible inclusion of other sectors, for example, the chemical,
aluminium and transport sectors, and other greenhouse gases.
Furthermore, the Commission Decision from 29 January 2004 that
establishes guidelines for the monitoring and reporting of greenhouse gas emissions pursuant to the emissions trading Directive, states that the Commission is stimulating research into the capture and storage of CO2. This research will be important for the development and adoption of
guidelines on the monitoring and reporting of CO2 capture and storage. Such guidelines will take into account the methodologies developed under the UNFCCC and Member States interested in the development of such
guidelines were invited to submit their research findings to the Commission.
Subject to the approval of the Commission, the capture and storage of CO2
may be subtracted from the calculated level of emissions from installations covered by the emissions trading scheme in accordance with the future guidelines.
2 TECHNICAL OPTIONS FOR CO2 CAPTURE 2.1 Background
In the chain needed to eliminate CO2 emissions from fossil fuelled plants - capture, transport and storage - transport is already reasonably well
established, while capture and storage require demonstration. Capture has been identified as the most costly part of the chain and has the least well established technology. However, development is progressing rapidly and large-scale demonstration plants will probably appear within the decade.
The capture process should take the gaseous CO2 from the combustion process and produce a reasonably clean liquid CO2 stream, although the final purity required for transport and storage is not yet established. A dense form of the captured CO2 is needed for rational transport scenarios - possibly as a supercritical or cooled liquid.
Of course, the fuel choice places different demands on the capture process in relation to differing carbon content and contaminants. Further, solid fuels cannot be processed directly but have to either be combusted or gasified prior to carbon removal. The commercial choice between coal and gas will be a trade off between price and availability compared with ease of reforming and direct use. Note also that CO2 capture from coal fired processes
obviously results in a greater CO2 reduction than when applied to gas firing (since the carbon to hydrogen ratio of coal is higher than for gas).
The calculated capture cost varies widely depending on the literature source and there are commercial interests at work when “scientific” reports are published. The basis for comparison should be very stringent and the data treated carefully. Here, an attempt is made to define and utilize consistent data. However, it must be borne in mind that everything is based on early studies, i.e., practical experience from small scale or industrial applications in which the CO2 removal is a secondary consideration.
2.2 Overview
There are three main technology options for CO2 capture from power plants:
- post-combustion capture - pre-combustion capture
- technologies where the nitrogen is excluded from the combustion process (more commonly known as oxy-fuel combustion or O2/CO2
recycle combustion but also covering approaches like chemical looping).
Figure 2-1 illustrates the basic principle of these three capture technologies.
Figure 2-1 The three main options for CO2 capture from power plants In post-combustion capture, the CO2 is removed from the power plant flue gas. Commercially available technology includes CO2 capture using
absorption in an aqueous amine solution. The CO2 is then stripped from the amine solution and dried, compressed and transported to the storage site.
In pre-combustion capture, the CO2 is removed prior to combustion. For coal this can be done via gasification. After reforming, the product gas is then shifted to produce a hydrogen-rich fuel gas mixed with CO2. The CO2 is removed by physical absorption and the hydrogen combusted in a gas turbine. In this way the CO2 is removed at a higher concentration in the gas stream and at high pressure. A similar scheme can be applied to natural gas, where the gasification step is replaced with a reforming stage to produce the synthesis gas.
In the O2/CO2 recycle combustion process, nitrogen is removed from the air using, in the more conventional process schemes, an air separation unit, and the fuel is combusted with oxygen in an atmosphere of CO2 which is
recirculated to control the combustion temperature. This gives a flue gas consisting mainly of CO2 and water vapor which can be condensed to give a highly concentrated CO2 stream for transport and storage.
In the case of natural gas, a commonly specified gas turbine combined cycle power plant generates a low CO2 concentration in the flue gas. The CO2
emissions per unit of generated electricity are low due to the low carbon content of natural gas compared to coal and the high efficiency of the combined cycle (see also Chapter 1).
It is possible to apply all these technologies using commercially available equipment with some modification and development. However, a significant equipment scale-up is required in most cases. The near future solutions based on these methods result in an efficiency penalty of 8 to 13 percentage points for coal fired processes or 9-12 % points for gas fired processes. Of this, about 3 to 4 % points when coal firing or 2 % to 3 % points when gas firing are a result of compression of CO2 to the desired storage pressure (about 100 bar) and the remainder is related to the capture process. Cost penalty is in the range of 10-50 EUR/MWh. However, this figure varies considerably between different studies.
All of the technical options described above have the potential for performance and efficiency improvements. Primarily, in relation to the generating efficiency but also in the reduction of the additional investment and O&M costs. The need for technological development of the different capture options will be further described in the following chapters. The technical risks introduced when employing these new technologies, and subsequent concerns relating to plant reliability and availability, are especially important and are considered in parallel.
CO2 capture technology should preferably be included at the design-stage of a new power plant in order to effectively optimize the overall plant efficiency and performance but it could also be added to existing power plants as a retrofit option. The post combustion concept is the primary option for retrofits but it has also been suggested that a) pre-combustion capture technology could be retrofitted to natural gas fired combined cycles and b) the O2/CO2
recycle concept could be applied to existing coal fired plants. Existing IGCC- plants could also be retrofitted with pre-combustion capture technology.
2.3 Post combustion capture 2.3.1 Basic principle
Following the combustion process, CO2 can be separated from the other combustion species found in the flue gas. Technologies based on separation principles such as absorption (chemical and physical), adsorption, cryogenics and membranes have been proposed.
Selection of the preferred capture technology depends on the flue gas properties - temperature, pressure, concentration and volume flow rate which is very high from power plants and is emitted at a pressure close to atmospheric. The CO2 concentration varies from typically around 5 vol%
(dry) for a natural gas combined cycle plant to about 15 % by volume (dry) for a pulverized coal fired power plant.
Physical solvents commonly in commercial use include cold methanol polyethylene glycol, propylene carbonate calcium oxide, sodium hydroxide and potassium hydroxide. These solvents are better suited for applications at a higher pressure than that of power plant flue gases. Some materials with high surface areas, such as zeolites and activated carbon, can be used
to adsorb CO2 from a flue gas. The adsorbent is regenerated by either an increase in temperature (temperature swing adsorption) or by lowering the pressure (pressure swing adsorption). However, adsorption methods are not yet applicable for large-scale operation, their capacity and CO2 selectivity are low and the energy required for regeneration is high.
Cryogenic separation of CO2 requires a high concentration of CO2 in the flue gas to be economical. Gas separation membranes are thin films that
selectively transport gases through the membrane based on interaction with the membrane and the difference in partial pressure of the gases across the membrane. However, this is a rather new technology and it has not yet been optimized for large scale applications (see also Section 2.7). Bearing this in mind, chemical absorption, using a reactive liquid solvent, is the technology which presently seems to be most feasible for CO2 capture from power plants. The only commercially available absorbents active enough for recovery of dilute CO2 from atmospheric pressure are aqueous solutions of alkanolamines such as monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA) and the newly developed sterically hindered amines. Therefore, the following text will only cover post combustion CO2
capture using amine solutions.
A continuous scrubbing system is used to separate the CO2 from the flue gas stream by chemical absorption. As illustrated in Figure 2-2, the system consists of two main elements - an absorber in which the CO2 is removed and a regenerator (stripper) in which the CO2 is released in a concentrated form and the solvent is recovered. Prior to the CO2 removal, the flue gas is typically cooled to about 50°C and then treated to reduce particulates, that cause operational problems, and other impurities (SOx, NOx, HCl, Hg …), which would otherwise cause costly loss of the solvent. The amine solvent absorbs the CO2 (together with traces of SOx and NOx) by chemical reaction to form a loosely bound compound.
A key feature of the amine system is the large amount of heat required to regenerate the solvent. The temperature level for regeneration is normally around 120°C. This heat is typically drawn from the steam cycle and reduces the net efficiency of the power plant significantly. As for all other
technologies producing CO2 electrical energy is also needed to compress the captured CO2 for transportation to the storage site.
Figure 2-2 The amine absorption process – basic process layout for Fluor Econamine process (Roberts, after Fluor Daniel, 2002)
2.3.2 Components and special considerations
The largest plants commissioned at present fall below 1000 tonnes of recovered CO2/day. Large-scale carbon dioxide capture projects are
currently being planned. With absorber diameters of 40 to 50 feet considered feasible, CO2 recovery plant capacities of up to 8000 tonnes/day are
achievable, depending on the inlet flue gas CO2 concentration. Even larger plants can be realized by employing multiple absorbers that share a common stripper (Roberts, 2002). As a comparison, a 500 MWe coal fired power plant produces about 8900 tonnes/day, whilst a 400 MWe natural gas fired power plant produces about 3400 tonnes/day. These numbers of course vary somewhat with electric efficiency, fuel composition and CO2 capture rate.
Amine absorption can be designed to capture from 85 - 95 % of the CO2 in the flue gas and produce a CO2 with a purity of > 99.95 %. Both the level of recovery and the CO2 purity require optimization since there are no
theoretical limitations on these parameters.
The choice of amine(s) used for the absorption is also an issue for
optimization. Important considerations for choice of absorbent include CO2- loading (mol CO2/mol amine), high solvent concentration in the aqueous solution, heat of reaction, heat of vaporization, reaction rate, the temperature level required for regeneration, corrosion issues and also cost. All of these parameters are obviously not optimal simultaneously for any one solvent;
high absorption rates generally cause high reaction heat rates etc. Finding the optimal solvent is thus a question of compromise. For example, MDEA
would offer energy savings compared to MEA but the reaction rate is lower and the absorption column would have to be much taller.
Aqueous solutions of amines are used to avoid excessive plant corrosion.
However, the water is a diluent that places additional demands on the process sizing and energy requirements. These factors need to be considered alongside the associated economics. Increasing the amine concentration by means of corrosion inhibitors and advanced amine formulations is therefore a high priority for the manufacturers.
Kansai Electric Power Company and Mitsubishi Heavy Industries have been developing sterically hindered amines, the most well known are called KS-1 and KS-2. These amines have the advantage of a lower circulation rate due to a higher CO2 loading differential, a lower regeneration temperature and a lower heat of reaction. They are also non-corrosive to carbon steel at 130°C in the presence of oxygen. A first commercial plant using KS-1 for Petronas Fertiliser Kedah Sbn Bhd’s fertilizer plant in Malaysia has been in operation since 1999 (Mimura et al., 2001).
Chemical absorption can be complemented with gas absorption membranes that act as contacting devices between the gas flow and the liquid flow. The gas and the amine solution are thereby not brought into direct contact and elements in the flue gas that deteriorate the amine solution, such as oxygen, are not transferred to the amine solution to the same extent. The problem of evaporation into the cleaned flue gas is reduced. The column pressure drop is also reduced, when compared with conventional packing, and the
efficiency reduction can therefore be smaller. The equipment can also be made more compact, due to the increased gas-liquid contact area, which is of particular importance in off-shore applications. The membrane technology was developed by Aker Kvaerner and used in gas separation applications within the oil and gas industry (Herzog and Falk-Pedersen, 2001). Scale-up to sizes required to capture CO2 from large power plants is considered to be a difficult issue.
As mentioned earlier, the CO2 concentration is the most important parameter that controls the absorption process. By applying supplementary firing before the HRSG the efficiency of the steam cycle increases and the CO2
concentration also increases. This has a positive effect on the overall plant efficiency.
Design issues relevant to CO2 recovery processes using amine solutions are discussed below. Most information is taken from Chapel et al. (2001) and is related to the Fluor Econamine process.
The absorption technology is described relatively detailed including many reported considerations to avoid potential problems and minimize costs. In section 2.3.3 reference is made to two commercial CO2 absorption plants operated on coal flue gas in US. Here no major problems are reported.
Regeneration energy
Absorption processes that are active at low partial pressures are those with higher reaction energies that require the most energy for regeneration. The design challenges are to a) minimize regeneration energy by selecting a solvent or mixture of solvents with a low reaction energy and b) to use low value heat source to provide this energy. MEA-based absorbent solutions generally require regeneration energies of 3 - 4 GJ/tonne CO2. Goals for ongoing development in the CASTOR project is to reach 2 GJ/tonne. (Note:
Cost calculations in Chapter 3 are based on 5 GJ/tonne CO2 according to IEA report). Steam with a pressure of about 3 - 4.5 bar is used to regenerate the solvent in the reboiler and steam at 4 - 6 bar is used in the reclaimer.
The steam for the reboiler has to be extracted from the steam turbine and thereby reduces the mass flow through the turbine and the power output of the turbine by up to 20%.
Uninhibited MEA is generally limited by corrosion problems to about 15-20 % by weight concentration. The low concentration raises the reboiler duty substantially. By applying inhibitors the concentration can be increased to about 25-30 % by weight, thus lowering the heat demand.
Flue gas temperature
Hot flue gases can cause solvent degradation and decrease absorber efficiency. For MEA based solvents the inlet flue gas must have a temperature of max. 50°C.
Oxygen
Presence of oxygen in the flue gas can increase corrosion and solvent degradation in the absorption system. Uninhibited alkanolamines such as MEA and DEA can be oxidized to give carboxylic acids and heat-stable amine salts. A solution to this problem is to apply an inhibitor to both
passivate the metal and inhibit amine degradation. An alternative approach would be to remove all of the oxygen by applying a near stoichiometric combustion and a catalytic reactor.
SOx
SOx reacts irreversibly with MEA based solvents to produce non-reclaimable corrosive salts. For MEA-based processes it is estimated that it is less expensive to install a SOx scrubber than accept the solvent loss at flue gas SOx levels exceeding 10 ppm(v). This is especially a problem for high sulphur fuels like coal but a less problem for natural gas. The acceptable SOx content in the flue gas and the investment in additional de-SOx plant is an optimisation issue in relation to the price of the absorbent.
SO3 presents additional problems in that it not only causes solvent loss through formation of heat stable salts but it also forms corrosive sulphuric acid aerosol in wet scrubbers. A special mist eliminator or a wet electrostatic precipitator and also flue gas cooling should be used to increase the SO3
removal in the scrubbing system.
NOx
Nitrogen oxides have led to corrosion problems and amine degradation in some absorption plants. The main problem is NO2 (including N2O4 etc.), which reacts to form nitric acid in the amine solvent and ultimately heat stable salts. An NO2-level of < 20 ppm(v) is recommended. Since modern plants are below this critical concentration, the limit on NO2 should be of minor concern.
Fly ash
Fly ash in the absorption solvent may cause foaming in the absorber and stripper, scaling and plugging of equipment, erosion, corrosion and increased solvent loss through chemical degradation and physical association with the waste sludge.
Soot
When amine capture is applied to heavy oil fired plant, soot presents a
special problem in the absorber. The soot stabilises an amine mist above the CO2 absorption zone that is not captured in the water wash zone. In this instance, a special mist eliminator has to be employed to prevent the micron sized MEA mist particles leaving the absorber with the CO2-lean flue gas.
Waste products
Degradation of the amine solution as described above creates a waste product that has to be dealt with, possibly by incineration. The quantity of waste is somewhat uncertain but it is anticipated to be of the order of several tens to hundreds of tonnes per year for a full-scale plant.
2.3.3 Technology status and R&D needs
MEA based absorption systems were developed over 60 years ago to provide a general non-selective solvent process to remove acid gas
impurities, e.g. H2S and CO2, from natural gas streams. The process was then adapted to treat flue gas streams for CO2 capture for subsequent use in the carbonation of brine, dry ice formation, urea production and the
carbonation of drinks. It has also been used for production of CO2 for enhanced oil recovery (EOR) operations (Chapter 4). Table 2-1 gives a summary of a selection of CO2 plants that are in commercial operation.
These plants are typically much smaller than an electric utility scale, however, according to the manufacturers it is considered to be technically feasible to build an absorption plant to separate CO2 from a power plant flue gas stream.
Commercial CO2-absorption plants are available to a size at least fitting a 400 MWe coal fired power plant from 2-3 potential suppliers world wide.
Operator Location Capacity (tonnes/day CO2)
Fuel Sources CO2 Use Technology Status
IMC Global Trona, CA 800 Coal boiler Carbonation of brine (soda ash)
Kerr-McGee MEA Operational since 1978 Mitchell Energy Bridgeport, TX 493 Gas heaters,
engines, turbine
EOR Inhibited MEA Operational since 1991 Northeast Energy
Associates Bellingham, MA 320 Gas turbines PURPA
(food-grade) Fluor Daniel Operational since 1991 Applied Energy
Systems Poteau, OK 200 Coal boiler
(fluidized bed) PURPA
(food grade) Kerr-McGee MEA Operational since 1991 Sumitomo
Chemicals Chiba,
Japan 165 Gas boilers
plus oil/ coal boiler
Food-grade Fluor Daniel Operational since 1994 Luzhou
Natural Gas China 160 NH3 plant
reformer exhaust
Urea Fluor Daniel Operational since 1998 Indo Gulf
Fertilizer Co. India 150 NH3 plant reformer exhaust
Urea Dow MEA Operational
since 1988 Prosint Rio de Janeiro,
Brasil 90 Gas boiler Food-grade Fluor Daniel Operational since 1997 Liquid air
Australia Australia 2 x 60 Gas boiler Food-grade Dow MEA Operational since 1985 AES, Shady Point
Power Station Panama, OK 190 Coal fired CFB
boiler Food-grade ABB Lummus Operational since 1991 AES, Warrior Run
Power Station Cumberland, MA 150 Coal fired CFB
boiler Food-grade ABB Lummus Operational since 1999
Table 2-1 Commercial CO2 plants (main source: IEA GHG data base, see www.co2sequestration.info)
The US-based power company AES operates two CO2 absorption plants located at coal-fired units at Shady Point Power Station, Oklahoma and Warrior Run Power Station, Maryland. Both absorption plants are designed and constructed by the same supplier. The CO2 absorption plant at Warrior Run was commissioned in year 2000 and the plant at Shady Point was commissioned in year 1991. The CO2-absorption plants have nearly the same capacity.
The Shady Point plant is located at a coal fired CFB with two boiler units.
Local coal is fired (HHV 26.2 MJ/kg, ash 18 % and sulphur 2.7 %) and the power output is 320 MWe. The CO2 plant is located adjacent to the power plant and captures CO2 from a flue gas slipstream using MEA scrubbing technology. For CO2 capture the SO2 concentration is reduced from 500 ppm to 2 ppm by scrubbing with caustic soda. The capacity of the plant is 200 tonnes CO2/day for food grade use.
Elsam representatives visited Shady Point plant in May 2003 and report that the plant has been in operation without problems. There has only been very minor corrosion even though the main material is mild steel. In the absorber, only the top is made of stainless steel. The original absorber packings are present after 12 years of operation and the plant is equipped with anti- foaming plant which has never been used.
Power plant integration
One of the advantages of using the post combustion capture approach with amine absorption is that it can be added on to a conventional power plant
without incurring any major modifications. It can therefore be used for retrofitting existing plants to include CO2 capture capabilities. The main change is to the steam cycle where the major part of the steam exiting the IP turbine is extracted and expanded to the reboiler pressure to supply the heat for regeneration of the solvent. The power output is thereby reduced by up to 20 %. Due to the drastically reduced mass flow in the LP section of the steam turbine, some modifications on the turbine may be required. Figure 2.3 shows a scheme of a power plant with SO2 and CO2 flue gas scrubber and steam extraction for solvent regeneration.
Figure 2-3 Scheme of a power plant with SO2 and CO2 flue gas scrubber and steam extraction for solvent regeneration R&D needs
Below follows a summary of the research and development needs that have been identified for amine-based CO2 absorption.
R&D related to absorbents
• Reduce steam consumption and temperature requirement for regeneration
o More energy efficient amines required (lower energy
requirement for regeneration, lower regeneration temperature, higher concentration)
o Optimise blend of amines
• Reduce power consumption
o Develop amines with a higher CO2 loading that could be
applied at a higher concentration to reduce pump requirements and equipment size
o Optimise blend of amines
• Decrease loss of amine into the flue gas or CO2
o Amines with a lower vapour pressure are desirable
• Reduce degradation of amines
o Develop amines less sensitive to high temperature, SOx, NOx, O2
o Develop inhibitors, process modifications, membranes
• Develop other types of absorbents
Existing plant
SO2 absorber CO2 absorber
CO2 compressor
stripper
Other areas for development
• Integration possibilities with power plant should be investigated o Integration between reboiler and reclaimer and IP steam
extraction
o Use of heat from CO2 compression intercooling for feedwater preheating
o Find integration possibilities for use of heat from flue gas cooler, lean amine solution cooler, reflux condenser and CO2
dryer (e.g. district heating, feed water preheating etc.)
• Reduced flue gas blower requirement
o More efficient packing to reduce absorber pressure drop
• Process optimisation for large scale plant
o Process modifications, e.g. split flow solvent process (lean and semi-lean solution)
o Improve simulation tools used for optimisation to better predict performance
o Investigate possibilities for cost reductions due to economy of scale
• Demonstration of long-term operational availability and reliability on a full-scale power plant using relevant fuels.
2.4 Pre-combustion carbon capture 2.4.1 Basic principle
In pre-combustion de-carbonization, the carbon content of the fuel is
removed prior to combustion in order to produce a hydrogen rich fuel and a CO2 by-product stream. The concept can be used for both H2 production and electricity generation.
In the first step a synthesis gas has to be produced consisting mainly of CO and H2. When coal is used as the fuel, it is first gasified. Synthesis gas can also be produced from natural gas through steam reforming or partial
oxidation. The CO is then further reacted with steam in a catalytic reactor according to the exothermal water-shift reaction to form more H2 and CO2: CO + H2O CO2 + H2 + 41 kJ/mol
After the shift reaction and removal of condensate, the process gas consists mainly of CO2 and H2. As the resulting CO2 concentration of around 30 % volume fraction is much higher than in a flue gas, the energy effort for CO2
separation is much lower. The partial pressure of the CO2 in this case is significantly higher than in the post-combustion case since the process is pressurized (20-30 bar) in addition to the higher CO2 concentration. The most appropriate H2/CO2 separation process for these conditions is currently physical absorption for CO2 removal. The H2-rich fuel can thereafter be used in a gas turbine combined cycle to produce electricity. In future it will also be possible to extract the H2 from the shifted gas by membranes, leaving the remaining CO2 rich stream to be sent to storage. An IGCC scheme with pre-
combustion decarbonisation including methanol synthesis is shown in Figure 2-4.
Methanol synthesis CO2
(optional) (optional) external H2
Power Heat
Methanol
Figure 2-4 IGCC with pre-combustion decarbonisation 2.4.2 Components and special considerations
In principle, the individual components of the pre-combustion capture concept have been successfully used in the industry for many years.
However, it still remains to be seen if this technology can be applied to power plants with acceptable reliability and availability in parallel with economic operation.
Coal gasification
Coal has been gasified in industrial scale for many years. Principally as the Lurgi moving bed, the Lurgi-British Gas slagging gasifier, the High
Temperature Winkler gasifier, Koppers-Tozek, Texaco and Shell with all being very well established for a multitude of industrial purposes at
atmospheric pressure. Integration in an IGCC scheme requires pressurized operation and intensive gas cleaning.
Natural gas reforming or partial oxidation
For synthesis gas production, natural gas can be reformed at a temperature of around 850°C with the addition of water steam and heat. The heat has to be either supplied by heat exchangers or by internal partial oxidation
following the addition of oxygen. If the reforming process is externally heated, a higher H2 concentration in the syngas can be attained, although this is not necessary. In addition, in a CO2 emission free process, a proportion of the decarbonized fuel is burnt to supply heat and this would have first undergone all of the fuel conversion steps with associated exergy losses. Therefore, direct internal oxidation is to be preferred to avoid these exergy losses, giving much lower efficiency penalties. Both reforming and internal oxidation are well proven commercial processes.