and Fisher, B.S. 2005, Near Zero Emissions Technologies, ABARE eReport. 05.1 Prepared for the ... Costs and outlook for renewable energy. 29. Grid connection .... usually expressed as a percentage and in terms of lower. (thermal) or higher ...
NEAR ZERO Emissions Technologies
abare eReport 05.1 Prepared for the Australian Government Department of Industry, Tourism and Resources
Anna Matysek, Melanie Ford, Guy Jakeman, Robert Curtotti, Karen Schneider, Helal Ahammad and Brian S. Fisher
January 2005
abare
© Commonwealth of Australia 2005 This work is copyright. The Copyright Act 1968 permits fair dealing for study, research, news reporting, criticism or review. Selected passages, tables or diagrams may be reproduced for such purposes provided acknowledgment of the source is included. Major extracts or the entire document may not be reproduced by any process without the written permission of the Executive Director, ABARE. ISSN 1447-817X ISBN 1 920925 29 5 Matysek, A., Ford, M., Jakeman, G., Curtotti, R., Schneider, K., Ahammad, H. and Fisher, B.S. 2005, Near Zero Emissions Technologies, ABARE eReport 05.1 Prepared for the Department of Industry, Tourism and Resources, Canberra, January.
Australian Bureau of Agricultural and Resource Economics GPO Box 1563 Canberra 2601 Telephone +61 2 6272 2000 Facsimile +61 2 6272 2001 Internet www.abareconomics.com ABARE is a professionally independent government economic research agency. ABARE project 2916
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foreword Projected increases in world population and economic wealth in the coming decades are expected to lead to an expansion in global energy demand as nations aspire to meet a variety of economic and social goals. Assuming no constraints on greenhouse gas emissions, it is projected that fossil fuels will continue to supply much of this additional demand, leading to a rapid increase in global emissions of greenhouse gases and a corresponding rise in the atmospheric concentrations of these gases. Higher atmospheric greenhouse gas concentrations could result in human induced climate change, potentially causing a range of globally significant, but regionally differentiated, environmental, economic and health impacts. The purpose in this study is to assess the role that carbon capture and storage technologies in the electricity sector might play in reducing global carbon dioxide emissions in a carbon dioxide constrained world. The results of this study indicate that these technologies could provide significant opportunities to reduce carbon dioxide emissions over the projection period to 2050. The use of carbon capture and storage technologies could reduce the costs of meeting a carbon dioxide constraint by providing moderate abatement cost opportunities within the electricity sector, which is a major source of carbon dioxide emissions. While the role of carbon capture and storage technologies in reducing emissions is expected to be significant, substantial reductions in carbon dioxide emissions can only be achieved by utilising a variety of abatement opportunities throughout the economy.
BRIAN S. FISHER Executive Director January 2005
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acknowledgments The authors wish to thank Hom Pant for helpful comments and modeling advice, Gail Condy, who produced the graphs and Julie Stalker, who formatted the report.
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contents Summary
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Introduction
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Background Global energy consumption Global electricity demand Greenhouse gas emissions
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Options for reducing carbon dioxide emissions Fuel switching Efficiency improvements Carbon capture and geological storage Advanced fossil fuel fired electricity generation technologies Technology descriptions Cost of electricity generation with and without carbon capture Electricity generation costs Regional cost variations Carbon transport and geological storage Transport Carbon storage and utilisation options Other utilisation options Carbon injection and geological storage costs Global and regional geological carbon storage capacity Carbon capture and geological storage issues Renewable energy Costs and outlook for renewable energy Grid connection, distributed generation and energy storage Nuclear power Costs of nuclear power Outlook for nuclear power
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Standard representation of electricity production in GTEM 32 Representation of other industries in GTEM 34 35 Model developments
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Issues in technology development, adoption and transfer 38 Technology R&D Technology adoption Technology transfer
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Reference case
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Key assumptions and indicators of growth Energy demand Electricity generation Carbon dioxide equivalent emissions and emissions intensity 51
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Emissions abatement scenarios The abatement task Description of emissions abatement scenarios Results of emissions abatement simulations Macroeconomic impacts Impacts on electricity generation Sources of abatement Impacts in Australia Future developments
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Conclusions
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Appendixes A
B
Framework of analysis Global trade and environment model Macroeconomic overview Emissions modeling in GTEM Sensitivity analysis
References
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boxes 1 2 3 4
Calculating the cost of CO2 avoided, cost of CO2 captured and generation cost Energy penalty Weyburn enhanced oil recovery project Sleipner carbon capture and storage saline aquifer demonstration project
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figures 1 2 3 4 A B C D E F
G H I J K L M
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The carbon dioxide abatement task Change in global real GDP, relative to the reference case Global electricity production by fuel Projected global coal demand Production technology in GTEM – electricity, iron and steel industries Production technology in GTEM – all industries other than electricity and iron and steel Modified electricity technology bundle with CCS technologies Global carbon dioxide equivalent emissions – reference case The carbon dioxide emissions abatement task Percentage difference in the carbon dioxide penalty under the policy without CCS relative to the policy with CCS Change in global real GDP, relative to the reference case Change in global average electricity price, relative to the reference case Projected global electricity production Global electricity production by fuel Projected global electricity production from nonhydro renewables Projected global coal demand Sources of abatement in global carbon dioxide emissions under the assumed carbon dioxide constraint, with CCS Change in Australia’s real GDP, relative to the reference case
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Change in Australia’s electricity price, relative to the reference case Change in Australian exports of coal, relative to the reference case Change in global average electricity price, relative to the reference case Change in global real GDP, relative to the reference case
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tables A 1 2 3 4 5 6 7 8 9 10 11 12 13 14
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Modeled scenarios Current or likely costs in the near term and efficiencies of power plants, with and without carbon capture Australian costs and efficiencies of power plants, with and without carbon capture Indicative carbon dioxide transport costs Estimated average transport costs for selected regions Estimated carbon dioxide storage capacities for different geological traps Potential carbon dioxide gelogical storage capacity, by region and storage type Current and projected costs for renewable electricity generation Capacities for renewable electricity generation Nuclear electricity costs Average annual growth in real GDP, reference case Average annual growth in energy demand, reference case Projected average annual growth in electricity demand, reference case Share of electricity generated by fuel specific technologies for selected GTEM regions, reference case. Projected average annual growth in carbon dioxide equivalent emissions and emissions intensity, reference case Projected average annual growth in carbon dioxide equivalent emissions from electricity generation, reference case Regional and commodity coverage
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abbreviations and acronyms CSS CO2 CO2-e COE DFCCC ECBM EOR FBC GW g GHG GDP Gt GTEM GWP HHV IEA IDGCC IGCC IPCC kW kWh LHV NGCC O&M OECD O2 PC ppm SUC SUCPC SC SCPC SRES UCC UCG USC USCPC
carbon capture and storage carbon dioxide carbon dioxide equivalent cost of electricity direct fired coal combined cycle enhanced coalbed methane recovery enhanced oil recovery fluidised bed combustion gigawatts grams greenhouse gas gross domestic product gigatonne (109 tonnes) global trade and environment model global warming potential higher heating value International Energy Agency integrated drying gasification combined cycle integrated gasification combined cycle Intergovernmental Panel on Climate Change kilowatt kilowatt hour lower heating value natural gas combined cycle operations and maintenance Organisation for Economic Cooperation and Development oxygen pulverised coal parts per million subcritical subcritical pulverised coal supercritical supercritical pulverised coal Special Report on Emissions Scenarios ultra clean coal underground coal gasification ultra supercritical ultra supercritical pulverised coal
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glossary abatement
Reduction of carbon dioxide emissions
absorption
The use of chemical or physical solvents that absorb or capture carbon dioxide, typically from flue gas
adsorption
The deposition of carbon dioxide on the surface of granular or porous materials, using materials with very high surface areas such as zeolites and activated carbon to separate carbon dioxide from flue gas mixtures
Annex B countries
Countries listed in Annex B to the Kyoto Protocol — that is, those countries committed to meeting documented emission reduction targets
anthropogenic
Attributable to human activity
atmospheric A per unit volume measure of the amount of greenhouse concentration gases present in the Earth’s atmosphere of greenhouse gases base load electricity
The minimum amount of electricity required over a given period of time at a steady rate, generally to serve demand on an around the clock basis
bottom up model
An economic model using an engineering based approach, with detailed cost and performance data for specific energy technologies and services
carbon capture and storage (CCS)
The capture of carbon dioxide from power generation plants or other sources with subsequent permanent storage in geological sites. In this report, CCS does not include ocean storage
carbon dioxide (CO2)
The principal anthropogenic greenhouse gas
carbon dioxide constraint
A limit on the total amount of carbon dioxide that can be emitted; the constraint may take a variety of forms including a tax or a quantitative restriction
carbon dioxide equivalent (CO2-e)
The conversion of non carbon dioxide greenhouse gases into CO2-e units based on their global warming potential (GWP), relative to carbon dioxide, over a 100 year time horizon; GWPs from the IPCC Second Assessment Report (1996a) are used in GTEM to calculate CO2-e
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carbon intensity of fuels
A measure of the amount of carbon dioxide emitted per unit of combusted fuel
direct fired coal combined cycle (DFCCC)
A gas turbine used to generate electricity by burning ultra clean coal directly in a combined cycle gas turbine, reaching higher efficiencies than pulverised coal turbines
efficiency of generation (thermal)
The ratio of electricity produced to each unit of fuel used, usually expressed as a percentage and in terms of lower or higher heating value (LHV, HHV)
emissions intensity
Emissions per unit of output
flue gas
Exhaust gas produced as a result of combustion activities
fluidised bed combustion (FBC)
An electricity generation plant that burns coal in a reactor of heated particles suspended in a gas flow.
fossil fuel
Fuel extracted from a hydrocarbon deposit, which was derived from living matter in the remote geological past — petroleum, coal and natural gas.
fugitive emissions
Greenhouse gas emissions not resulting from the combustion of fossil fuels, but rather from their mining, transport, storage and distribution.
gigatonne
One billion tonnes (109 tonnes)
greenhouse gas (GHG)
Any gas in the atmosphere that absorbs and re-emits infrared radiation; major greenhouse gases include carbon dioxide, water vapor, methane and nitrous oxides
global warming potential (GWP)
An index that describes the warming potential of a unit mass of a well mixed greenhouse gas, relative to that of carbon dioxide, which is given a GWP of 1
heat rate
The amount of fuel energy required to produce one kilowatt hour of electricity
higher heating value (HHV)
A standard measure of the efficiency of an electricity generation plant and equivalent to gross calorific value. The quantity of heat energy released when a fuel is burned completely in oxygen, and the products of combustion are returned to ambient temperature and pressure. See also lower heating value
hydrogen
Colorless, odorless, flammable gas
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integrated drying gasification combined cycle (IDGCC)
An electricity generation plant that reduces the moisture content of high moisture content fuels before use in a combined cycle turbine; alternatively known as blown coal IGCC
integrated gasification combined cycle (IGCC)
An electricity generation plant that gasifies coal to produce a syngas that is cleaned and burned in a gas turbine; exhaust heat is used to drive a steam cycle to generate additional electricity
levelised generation cost
The discounted sum of fuel, operating and investment costs, ‘levelised’ or ‘averaged’ over the expected lifetime of the capital investment
lignite
Coal with a high moisture content; often referred to as brown coal
lignite dewatering
A drying process to reduce the moisture content of brown coal and increase its combustion efficiency
lower heating value (LHV)
A standard measure of the efficiency of an electricity generation plant and equivalent to net calorific value — corresponds to the number of heat units liberated per quantity of fuel burned in oxygen, minus the latent energy contained in water vapor (exhaust gas) that is produced when hydrogen (from the fuel) is burned. The thermal efficiency of a coal fired plant based on LHV is typically 2–3 per cent higher than its thermal efficiency based on HHV; the thermal efficiency of a gas fired plant based on LHV is typically 10–15 per cent higher than its thermal efficiency based on HHV (Saddler et al. 2004). See also higher heating value
natural gas combined cycle (NGCC)
An electricity generation plant that burns natural gas in a turbine with the waste gases recovered and used to generate additional electricity in a steam cycle
non-Annex B countries
Countries that are not listed in Annex B of the Kyoto Protocol — that is, countries that are not committed to meeting any emission reductions targets
peak load electricity
The supply of electricity to meet maximum demand during a specific period of time
primary energy consumption
Equal to the consumption of commercial energy (excluding biomass in non-OECD countries) in its initial form after production or import
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pulverised coal (PC)
An electricity generation plant that combusts pulverised or milled coal at high temperatures, raising high pressure steam and generating electricity in a steam turbine
renewable electricity
Electricity derived from natural processes that theoretically cannot be exhausted — for example, solar, wind, hydropower, geothermal and biomass
sequestration
The storage of carbon dioxide in terrestrial or geological sites
subcritical (SUC)
Subcritical (steam) refers to steam temperature and pressure below the critical point of water, typically in the range of 520–550°C and 16–18 megapascals respectively
supercritical (SC)
Supercritical (steam) refers to steam temperature and pressure above the critical point of water, typically in the range of 550–566°C and 23–30 megapascals respectively
top down model
An economic model that evaluates the final demand for goods and services, and the supply from major sectors (energy sector, transport, agriculture and industry) using aggregate economic variables
total final energy consumption
The sum of energy consumption by all end use sectors, including industry, transport, agriculture, residential, commercial, public services and nonenergy use
ultra clean coal (UCC)
Coal that contains less than 1 per cent ash and has had virtually all mineral impurities chemically removed — UCCs can be pulverised and fed directly into gas turbines
ultra supercritical (USC)
Ultra supercritical (steam) refers to steam temperature and pressure above 566°C and 30 megapascals respectively
underground coal gasification (UCG)
A process that burns coal underground to produce fuel gas
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summary Projected expansions in global population and economic activity in coming decades are expected to lead to rapid increases in the demand for energy. Continued reliance on fossil fuels to meet this demand is likely to result in a rapid increase in global anthropogenic emissions of greenhouse gases and a corresponding rise in the atmospheric concentration of those gases. The bulk of the scientific literature indicates that rising atmospheric greenhouse gas concentrations have the potential to induce climatic changes, with associated environmental, economic and health impacts. Policy measures designed to reduce emissions growth, such as the Kyoto Protocol, the EU emissions trading scheme and various national directives to improve energy efficiency, demonstrate an increasing awareness of climate change issues. The objective in this report is to analyse the economic impacts of stabilising the atmospheric concentration of carbon dioxide and to determine the role that carbon capture and storage technologies in the electricity sector might play under such a scenario. This report considers the potential for geological sequestration of carbon dioxide and excludes any consideration of ocean sequestration.
Options for reducing carbon dioxide emissions There are opportunities to reduce carbon dioxide emissions throughout the economy. Options include reducing production of goods and services that use energy and hence produce emissions, improving the efficiency of energy technologies, switching to less carbon intensive fuels, and capturing and sequestering carbon dioxide emissions in geological sites. Since the consumption of energy is vital to economic development, technology is projected to play an important role in reducing emissions while allowing the realisation of a range of environmental, economic and social development goals. Near zero emissions technologies, which produce minimal carbon dioxide emissions, are projected to play a substantial role in the stabilisation of carbon dioxide emissions. Emissions of the principal anthropogenic greenhouse gas, carbon dioxide, have been responsible for approximately 70 per cent of total
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positive radiative forcing (a measure of the warming potential of greenhouse gases) since 1750 (IPCC 2001b). The power generation sector currently accounts for around 40 per cent of total anthropogenic carbon dioxide emissions (IEA 2004d). For these reasons, and because the sector is characterised by large stationary emission sources that can be relatively easily monitored and controlled, this report focuses on the potential to reduce carbon dioxide emissions in the electricity sector.
Carbon capture and storage The capture and storage of carbon dioxide emissions from the electricity sector is a near zero emissions technology that is receiving increasing attention in the literature and from commercial interests as a means of mitigating growth in carbon dioxide emissions. Evidence suggests that the global capacity for geological carbon dioxide storage far exceeds current global emissions. However, further research is needed to more accurately assess storage potentials in most regions. The costs of carbon capture and storage vary between regions and the technology used. The economic and environmental characteristics of these technologies are considered in the body of the report.
Methodology To analyse the role that technology, and in particular carbon capture and storage (CCS), could play in reducing emissions in a carbon dioxide constrained world, ABARE’s general equilibrium model of the global economy, GTEM (global trade and environment model), is used. Significant developments have been made to the standard GTEM framework for this analysis. First, reference case or baseline projections were made to 2050, which is a longer time frame than has previously been possible using the GTEM framework. The purpose of extending the modeling time horizon was to capture the impacts of advanced technologies that may not be adopted in the short term. Second, CCS technologies have been incorporated into the representation of electricity technologies and enhancements have been made to the modeling of nonhydro renewable electricity generation technologies to account for the relationship between the demand for, and cost of, these technologies under carbon dioxide constraints.
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Issues in technology development, adoption and transfer Policy issues associated with the uptake of CCS and other advanced technologies are considered. These include the determination of an optimal research and development portfolio and the use of investment criteria that encompass both economic and noneconomic factors when selecting an appropriate electricity generation technology. The drivers of, and impediments to, technology diffusion to developing countries are also examined. This is a particularly important issue given the projected large contribution of developing countries to global greenhouse gas emissions, and represents an important area for further research.
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Emissions abatement scenarios
The carbon dioxide abatement task
In each of the two emissions abatement scenarios implemented in this study an abatement task is specified to constrain global emissions of carbon dioxide. This abatement task is assumed to commence in 2005 and to increase over time, requiring a reduction of about 25 gigatonnes of carbon dioxide in 2050 (figure 1).
25 20 15 10 5 Gt CO2 2000
2010
The assumed abatement task and corresponding emissions pathway is consistent 2020 2030 2040 2050 with stabilising the atmospheric concentration of carbon dioxide at about 550ppm some time after 2100. This is a commonly cited stabilisation goal in emission scenarios in the literature (Morita et al. 2001) and should not be interpreted as a policy recommendation. To achieve the assumed abatement task, a penalty on carbon dioxide emissions is imposed in the model, providing an incentive for producers of carbon dioxide to reduce their emissions to the point where the marginal cost of abatement equals the carbon dioxide penalty. In GTEM, the imposition of a carbon dioxide penalty represents the broad range of least cost economic instruments that can be used by governments to reduce emissions and achieve a given abatement task. The potential role of CCS technologies is analysed by comparing two abatement scenarios against the reference case projections. The modeled scenarios are described in table A.
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A
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Modeled scenarios
Scenario name
Scenario characteristics
Reference case
Projections of the global economy in the absence of any constraints on carbon dioxide emissions.
Carbon dioxide constraints, without CCS
A penalty is imposed on carbon dioxide emissions to achieve the specified abatement task; no regions have access to CCS technologies
Carbon dioxide constraints, with CCS
A penalty is imposed on carbon dioxide emissions to achieve the specified abatement task; all regions have access to CCS technologies at the same cost of US$25 and US$30 a tonne of carbon dioxide captured, for coal and gas fired electricity generation respectively
By comparing the abatement scenario with carbon dioxide constraints and no CCS technologies against the reference case results, it is possible to determine the economic impact of the carbon dioxide constraint when countries have access only to existing technologies. The results from this abatement scenario can be compared with the scenario with carbon dioxide constraints and access to CCS technologies, to determine the impact of CCS technologies on reducing the overall cost of the emissions restriction.
Results To achieve the specified abatement task a penalty is imposed on carbon dioxide emissions from 2005. As the required level of abatement rises over time and lower cost abatement options are exhausted the penalty increases. A constraint on carbon dioxide emissions increases the price of energy as producers of carbon dioxide either reduce their emissions, generally at a cost, or pay the penalty. This has an impact on all sectors of the economy that produce or consume energy and leads to an overall decline in gross domestic product (GDP). The availability of CCS technologies reduces the required carbon dioxide penalty compared with the situation without CCS as CCS provides most regions with additional large scale abatement opportunities that can reduce the cost of meeting the specified abatement task. Because CCS technologies reduce the cost of meeting the specified abatement
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Change in global real GDP
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task, they reduce the loss in GDP associated with the carbon dioxide constraint.
relative to the reference case
%
The change in global GDP under both scenarios, relative to the reference case, is shown in figure 2. In 2050, the loss in global GDP associated with the carbon dioxide penalty is approximately 5 per cent when CCS is not available. By comparison, when CCS is available, the loss in global GDP is just over 1 per cent.
–1 –2
–3 Carbon dioxide constraints without CCS with CCS
–4 –5
2000
The imposition of a carbon dioxide penalty provides an incentive for producers to reduce their carbon dioxide emissions up to the point where the marginal abatement cost equals the carbon dioxide penalty. A comparison of the fuel mix used and the total quantity of electricity generated under carbon dioxide constraints, relative to the reference case, demonstrates that electricity producers achieve the specified abatement task using a range of abatement options, including reducing the total amount of electricity generated, switching to less carbon intensive fuels, including renewables, and capturing and sequestering carbon dioxide emissions (figure 3).
2010
2020
2030
2040
2050
The imposition of a carbon dioxide penalty reduces the demand for coal relative to the reference case because the penalty increases the cost
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Global electricity production, by fuel Reference case
40 30
Carbon dioxide constraints, with CCS
Renewables Hydro Nuclear Gas, without CCS Oil Coal, without CCS
40 30
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10
’000 TWh 2010
Renewables Hydro Nuclear Gas, with CCS Gas, without CCS Oil Coal, with CCS Coal, without CCS
’000 TWh 2020
2030
2040
2050
2010
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2020
2030
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Projected global coal demand Reference case
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Carbon dioxide constraints with CCS without CCS
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of producing and using emissions intensive fuels, including coal. The cost of electricity from carbon intensive fuel sources also increases. The availability of CCS technologies in conjunction with a carbon dioxide penalty does, however, lessen the reduction in coal demand compared with the carbon dioxide constraint without CCS scenario because CCS reduces emissions from coal fired electricity generation, thereby reducing the economic impact of the carbon dioxide penalty, while simultaneously requiring more coal per unit of electricity generation to capture the carbon dioxide emissions (figure 4).
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The impacts of a global carbon dioxide constraint are expected to differ between regions depending on their economic structure, fuel mix, efficiency levels and ability to access low cost abatement opportunities. Because the Australian economy is more heavily reliant on fossil fuels than some other economies the economic impacts of a carbon dioxide constraint without CCS technology are projected to be relatively high for Australia. However, if the low cost abatement opportunities offered by CCS technologies are used, the percentage loss in Australia’s GDP at 2050 relative to the reference case is estimated to be comparable to the global average.
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introduction Since the industrial revolution, human activities such as agricultural and industrial production and the extraction and burning of fossil fuels have led to growing emissions of greenhouse gases. Evidence suggests that human induced increases in atmospheric greenhouse gas concentrations have the potential to alter the Earth’s climate, leading to environmental and economic consequences in the long term in all regions, but with regional differences in the scale and nature of these consequences (IPCC 2001a). Carbon dioxide is the principal anthropogenic greenhouse gas and emissions of this gas have been responsible for approximately 70 per cent of total positive radiative forcing (a measure of the potential of greenhouse gases to warm the Earth’s surface) since 1750 (IPCC 2001b). Globally, carbon dioxide emissions from power generation currently account for around 40 per cent of total anthropogenic carbon dioxide emissions (IEA 2004d). Assuming rising demand for energy and continued reliance on fossil fuels, global carbon dioxide emissions are forecast to increase significantly over the coming decades. Projections also indicate that, while OECD countries will remain major emitters of carbon dioxide, the greatest growth in emissions will be from developing countries. Responding to the climate problem poses several challenges. A key challenge is to design policies that balance the cost of any damage from climate change with the cost of actions to reduce that damage. The significant uncertainties surrounding the causes, nature and impacts of possible climate change magnify this challenge. A second challenge will be for countries to manage adaptation to climate change, which could involve major investments and the management of economic and social change. A further key challenge will be to engage all major emitters in meaningful efforts to reduce net greenhouse gas emissions. The difficulty here is that efforts to reduce greenhouse gas emissions may involve reduced or more expensive energy use that could hamper the development prospects of some major emitters. Therefore, achieving meaningful emissions reductions is likely to involve complex tradeoffs between environmental, economic and social development objectives. Policies that deal with the potential threats of human induced climate change without compromising a country’s ability to develop and improve the wellbeing of its citizens must adhere to three fundamental principles: environmental effectiveness, economic efficiency, and equity. A framework aimed at incorporating all of these elements should focus on long term environmental objectives such as stabilising the atmospheric concentrations of global green-
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house gases. The framework should also be flexible in the light of new knowledge about climate impacts. Ideally, all large emitters should be involved and actions should allow for sustainable economic development. The framework should not involve coercion as this is unlikely to prove conducive to long run success. There are various ways to mitigate the growth in emissions, including: reducing economic growth and therefore energy use, discouraging the use of emissions intensive technologies, and encouraging the development and use of cost effective, low emissions technologies. However, not all of these options incorporate the above stated requirements for a good policy framework. Given the importance of energy in driving economic growth, a technology solution is required to make a significant impact on greenhouse gas emissions without hampering development prospects. In this report, a range of energy technologies is identified that are expected to contribute to a reduction in carbon dioxide emissions by 2050. Emphasis is placed on technology options for electricity generation because of this sector’s large contribution to global emissions and the fact that emissions from stationary sources can be relatively easily monitored and controlled. A number of low emissions technology options are identified, including improvements in the efficiency of existing fossil fuel fired electricity generation technologies, switching to less carbon intensive energy sources, including renewable energy, and the capture of carbon dioxide from fossil fuel plants with subsequent long term storage in geological structures. The costs and emissions profiles of these technology options are examined, along with information on the likely speed of their uptake. Particular emphasis is placed on the possible role of carbon capture and storage in facilitating the transition to a low emissions economy. The key objective in the report is to analyse the economic and greenhouse gas impacts of low emissions technologies and the effectiveness of such technologies in contributing to national and international climate change response measures. For this purpose, ABARE’s global trade and environment model (GTEM) — a dynamic multiregion general equilibrium model of the global economy — has been enhanced and updated to better reflect technological developments in the electricity sector. The inclusion of advanced fossil fuel based technologies such as carbon capture and storage technologies in the GTEM framework better reflects technology options in electricity generation in the mid to long term. These developments significantly enhance ABARE’s capacity to analyse long run policy solutions that include a technology component. Policy issues associated with technology uptake are also considered. Promoting the uptake of technology through research and development is discussed along with factors that may affect technology adoption. Barriers to, and drivers of, technology diffusion to developing countries are also considered. Given the necessity for all large emitters, including developing countries, to be involved in achieving substantial emissions reductions, facilitation of technological diffusion is also discussed.
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background Global energy consumption Global primary energy consumption is projected to increase substantially over the next century as population and GDP continue to rise (IEA 2004d; IIASA and WEC 1998; IPCC 2000). Global energy consumption is projected to increase by about 50 per cent within the first quarter of this century (EIA 2003; IEA 2004d; IPCC 2000). Much of the growth in energy consumption is expected to occur in developing countries, particularly in Asia, as a result of rapid economic and population growth and increasing industrialisation and urbanisation. By 2030, it is expected that developing and transition economies will overtake OECD countries as the biggest consumers of primary energy (IEA 2004d). Fossil fuels are expected to continue to supply the vast majority of total global primary energy in the first half of the century (IPCC 2000), with oil remaining the single largest fuel in the primary energy mix. The share of gas in global energy consumption is expected to increase in coming decades as a result of its favorable environmental characteristics compared with coal and oil, competitive pricing in some applications, advances in natural gas fired power generation technologies and the pursuit of energy security and fuel diversification policies in some key economies (EIA 2003; IEA 2004d). While the share of coal in global energy consumption is projected to decline in the coming decades, coal is expected to remain an important energy source, particularly in India and China, as a result of abundant reserves and a relative cost advantage. Nonhydro renewables are anticipated to have the fastest growth rate of all energy sources, although from a low base (IEA 2004d).
Global electricity demand A key driver of the projected increases in global energy consumption is the forecast expansion in electricity generation. The share of electricity in total final energy consumption is expected to increase over the coming decades as access to electricity improves, particularly in developing and transition economies, as a result of increasing incomes and urbanisation (IEA 2002b; IPCC 2000). Fossil fuels are expected to remain the dominant fuel for electricity generation in the coming decades as a result of their abundant supply, geographic dispersion and relative cost advantages (EIA 2003; IEA 2000, 2004d). Coal is expected to continue to account for the largest share of the electricity fuel mix although its share is expected to decline because of substantial increases in the use of natural gas.
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The share of natural gas in global electricity generation is expected to increase substantially as a result of the economic, efficiency and environmental advantages of new gas fired combined cycle turbines in some regions (EIA 2003; IEA 2004d). However, projected rises in natural gas prices within the first half of the century are expected to reduce the economic advantage of gas fired electricity generation (IEA 2004d). The share of nuclear power in electricity generation is also forecast to decline over the period to 2030. Nuclear investment is expected to be mostly confined to Asia and France (EIA 2003; IEA 2004d). It is likely that nuclear power generation will decline markedly in north America and in some regions of Europe as existing plants are retired as a result of competition from alternative technologies and in response to concerns about safety, security and radioactive waste management. The share of electricity production from hydropower is expected to decline in the coming decades as hydropower potential in developed nations is almost fully exploited and environmental concerns prevent the development of many new large scale facilities. Use of hydropower is, however, expected to increase in developing countries, where its potential remains high (IEA 2004d). The share of nonhydro renewables in electricity generation is projected to expand substantially in the future, albeit from a small base, as technologies mature and costs decline (EIA 2003; IEA 2004d; IPCC 2000).
Greenhouse gas emissions Large increases in the demand for energy, and in particular the continued reliance on fossil fuels for electricity generation, is expected to lead to a sustained increase in global greenhouse gas emissions, and a corresponding rise in the concentration of these gases in the atmosphere. Developing countries are expected to overtake the developed world in the near future as the largest emitters of carbon dioxide, primarily as a result of increases in the consumption of energy and electricity fueled by high economic and population growth rates (IEA 2004d; IIASA and WEC 1998).
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options for reducing carbon dioxide emissions The stabilisation of carbon dioxide emissions is a long term issue requiring a long term solution. Rising global concern about greenhouse gases has led to the development of technologies and mechanisms designed to reduce regional and global carbon dioxide emissions. There are opportunities for carbon dioxide emissions abatement throughout the economy. However, technological improvements in the electricity sector offer one of the most significant options for global emissions abatement because of the large contribution that electricity generation makes to global emissions. The electricity sector is also a prime candidate for emission reduction measures as the limited number of large stationary sources means that it is relatively easy to monitor and control emissions from this sector. There is a range of existing and potential electricity generation technologies or options that offer substantial carbon dioxide reduction potential, including switching from high to low carbon intensive fuels, improvements in the efficiency of electricity generation, and carbon capture and storage.
Fuel switching Switching to less carbon intensive fuels such as natural gas or renewables may slow the growth in carbon dioxide emissions. Natural gas is already an attractive option for power generation in some regions because of its lower carbon content compared with other fossil fuels and its competitive price in some applications. Currently, nonhydro renewables are generally not cost competitive with wholesale fossil fuel fired electricity generation in most applications and may have some capacity disadvantages because of their intermittent nature and current lack of economic storage options. Renewable energy technologies do, however, offer cost competitive electricity generation in some specific applications and regions (IEA 2003). Substantial reductions in cost, improvements in efficiency and developments in storage options are expected as research continues and capacity develops.
Efficiency improvements Increases in the efficiency of existing fossil fuel based electricity generation technologies or the development of more efficient technologies can result in a reduction in greenhouse gas emissions as less fuel is used per unit of electricity generated. Some of these more efficient technologies, such as natural gas combined cycle (NGCC) power plants or integrated
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gasification combined cycle (IGCC) coal power plants, could penetrate the market based on cost effectiveness alone. Other technologies will become more competitive with traditional technologies under constraints on carbon dioxide emissions, which would raise the relative cost of producing electricity using carbon dioxide emitting technologies.
Carbon capture and geological storage The capture and storage of carbon dioxide emissions from power plants represents an option that could potentially result in near zero carbon dioxide emissions from the burning of fossil fuels in the electricity sector. This report considers the potential for geological sequestration of carbon dioxide and excludes consideration of ocean sequestration. If carbon dioxide constraints are imposed by governments, industry regulations or international treaties, advanced fossil fuel technologies, carbon capture and storage technologies and renewable energy technologies could become more competitive with traditional energy sources, although to different degrees. Managing risks to achieve an outcome that is both environmentally and economically sound in a carbon dioxide constrained world is likely to involve adopting a portfolio of the options discussed above.
Advanced fossil fuel fired electricity generation technologies A key option for reducing carbon dioxide emissions in the electricity sector is to improve the efficiency of existing power generation technologies. Improvements in the efficiency of existing plants can be achieved through refurbishment or retrofitting, as well as through changes in operating practices. The major types of current and emerging coal fired and natural gas based electricity generation technologies that could provide efficiency improvements over established technologies are described in this section.
Technology descriptions Pulverised coal (PC): At present, PC electricity generation plants dominate global electricity generation, and account for more than 90 per cent of coal fired electricity generation capacity (IEA Clean Coal Centre 2002). PC plants have been used throughout the world for more than sixty years and are suitable for a wide variety of coal types. In PC plants, coal is pulverised and blown into a furnace where it is combusted at high temperature. This process raises high pressure steam that is used to drive a steam turbine and generate electricity.
PC plants can be either subcritical (SUC) or supercritical (SC) units depending on the temperature and pressure of the steam in the turbine. Supercritical plants achieve higher efficiencies than subcritical plants by operating at higher temperatures and pressures. Supercritical units have efficiencies of around 45 per cent compared with 36 per cent for subcritical units. Supercritical units are now the standard for new plants in many parts of the world (Coal21 2004). However, the average efficiency of coal fired generation in developing countries and the OECD is about 30 per cent and 36 per cent respectively (IEA
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2004d). Ultra supercritical (USC) units, which can operate at efficiencies of up to 55 per cent, are being developed in Europe and Japan. Integrated gasification combined cycle (IGCC) plants: IGCC plants are a relatively new technology for power generation although several demonstration plants are in place in Europe, Japan and the United States. In IGCC plants, coal is not burned directly, but is reacted with oxygen and steam in a gasifier to produce a syngas consisting predominantly of carbon monoxide and hydrogen. The syngas is cleaned of impurities and used to drive a gas turbine, generating electricity. The exhaust heat is also used in a steam cycle, producing additional electricity.
IGCC plants can generate electricity at high levels of efficiency (approximately 50 per cent). The flue gases also contain a more concentrated stream of carbon dioxide than in PC plants, potentially making carbon dioxide capture more efficient and less expensive. IGCC plants can also be used for the coproduction of hydrogen for commercial uses such as in the manufacture of chemicals and liquid fuels. The sale of hydrogen or syngas to produce these products has the potential to offset some of the cost of electricity generation using IGCC plants (Coal 21 2004). Lignite dewatering: Lignite dewatering reduces the water content of low rank (brown) coal for use in IGCC plants and existing brown coal plant technologies. This results in an increase in efficiency and reduces greenhouse intensity to a level that can be similar to black coal plants. A number of different technologies are currently available, including integrated drying gasification combined cycle (IDGCC) plants, which use hot waste gases from the gasifier to dry the coal. Additional research and development is required to further reduce costs (Coal21 2004). Underground coal gasification – integrated gasification combined cycle (UCG–IGCC): UCG is a gasification process that allows coal to be converted into a combustible gas (or syngas) in the coal seam. This gas can then be used as a fuel. UCG–IGCC has been used in commercial size projects for more than forty years but until recently has not received much attention because of low prices of competing fuels and various technological barriers (DTI 2003b). In its simplest form, the UCG process involves drilling two boreholes into an unmined coal seam, injecting air or oxygen through one of the boreholes and igniting the coal seam. The resulting pressurised gases are recovered from the second borehole (Walker et al. 2001). As the UCG process is essentially a mining technology, it creates underground cavities that could be used for subsequent carbon dioxide sequestration.
Like IGCC, the UCG syngas consists primarily of hydrogen, carbon monoxide and methane and can be burned in a gas turbine to generate electricity (UCG–IGCC) (DTI 2004). However, as expensive surface gasification facilities are not required for UCG–IGCC, the capital cost is roughly half of that for IGCC. In addition, as the UCG process can be used on uneconomic coal seams, the fuel cost is negligible (Walker et al. 2001). As with IGCC plants, UCG–IGCC plants can also be used for the coproduction of hydrogen for commercial use.
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The biggest hurdles to further uptake of the UCG process are the quality and consistency of the output gas and the high degree of site specific characteristics that affect the process (Walker et al. 2001; DTI 2004). Fluidised bed combustion (FBC) based plants: FBC plants currently account for 2 per cent of coal fired capacity worldwide and have been used on a small scale since the 1960s (IEA Clean Coal Centre 2003c). In fluidised beds, coal is burned in a reactor in a bed of heated particles suspended in a gas flow. The turbulent state of the gas improves combustion, heat transfer and recovery of waste products. FBC plants have efficiency levels similar to PC plants but produce less nitrogen and sulfur oxides. FBC plants are particularly suited to clean burning of low grade coals and may also be used to fire some other low quality fuels, including biomass. The investment and generation costs of FBC plants are similar to advanced PC plants. Ultra clean coal and direct fired coal combined cycle (DFCCC) turbines: Ultra clean coals contain less than 1 per cent ash and have had virtually all mineral impurities chemically removed. Ultra clean coals are not considered substitutes for conventional coal in traditional power generating systems and are instead used as alternatives in heavy fuel oil and gas turbines. Ultra clean coals are cost competitive with these fuels on an energy equivalent basis (Australian Coal Association 2004). Ultra clean coal can be pulverised and fed into a DFCCC turbine, reaching efficiencies greater than 52 per cent (Coal21 2004). The high efficiency rate compared with conventional coal plants provides an opportunity for reducing carbon dioxide emissions. Natural gas combined cycle (NGCC) plants: In an NGCC plant, natural gas is used to drive a gas turbine to generate electricity. The waste gases in the turbine are recovered and burned to raise steam, which drives a steam turbine generating additional electricity. NGCC plants have efficiencies of around 60 per cent and improvements in gas turbine design are expected to raise this efficiency over time (IEA Clean Coal Centre 2003b).
NGCC is an established technology that now accounts for more than 50 per cent of the market for new generating capacity (IEA Clean Coal Centre 2003b). NGCC plants produce lower greenhouse gas emissions than conventional coal fired power plants without capture equipment because of higher generation efficiency levels and the lower carbon content of natural gas compared with coal.
Carbon capture and geological storage Carbon capture technologies can be used to capture carbon dioxide produced from the combustion of fossil fuels in power plants and can typically reduce electricity plant emissions by between 65 and 95 per cent (table 1). The carbon dioxide can then be transported to a permanent storage site in gaseous or liquid form (DTI 2003a). The three main approaches or technologies used to capture carbon dioxide are described below. Flue gas or post combustion capture: After combusting fossil fuels, carbon dioxide can be separated and captured from the resulting flue gas. Flue gas capture methods include: absorption of carbon dioxide after contact with solvents; adsorption of carbon dioxide on
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activated carbon or other materials; cryogenic separation of carbon dioxide from other gases using temperature and pressure; and membrane separation of carbon dioxide. Post combustion capture techniques require a significant amount of energy to operate and hence result in reduced plant efficiency. Post combustion capture has yet to be optimised on a commercial scale for electricity generation, although it is envisaged that it will be most effectively used in conjunction with PC and NGCC plants. Potential advances in materials technology are likely to improve the prospects for this technique (IEA 2002a). Oxygen combustion: Using the oxygen combustion approach, carbon dioxide concentrations in flue gases are increased to between 55 and 60 per cent by raising the level of oxygen and reducing the nitrogen content in the combustion air. If the flue gas is then recycled in an oxygen rich environment, the concentration of carbon dioxide in the flue gas can be as high as 90 per cent (IEA 2002a).
Oxygen combustion is at present a highly inefficient approach because of high capital and oxygen costs and large losses in energy efficiency when this technique is applied. Substantial research and development is needed to make this a viable technology. Hydrogen or syngas approach: The hydrogen or syngas approach is a precombustion capture technique that reduces the carbon content of fossil fuels and produces a carbon dioxide rich byproduct. The fuel is first reacted with oxygen, air or, in some cases, steam to produce a gas consisting mainly of carbon monoxide and hydrogen. The carbon monoxide is reacted with steam in a catalytic shift converter to produce carbon dioxide and more hydrogen. The carbon dioxide is separated using adsorption or absorption methods and can be used for industrial or beverage production processes. The remaining hydrogen can be used as a chemical feedstock or, in an NGCC plant, to generate electricity. The hydrogen or syngas approach can be used for coal, oil and natural gas, but use with coal and oil requires greater gas purification.
Precombustion capture is a promising technology that results in a small volume of highly concentrated carbon dioxide with lower energy requirements than some other capture methods (DTI 2003a). The production of syngas containing hydrogen is also seen as an added advantage as hydrogen can be used in other industrial processes and may potentially become important as a transport fuel (IEA 2002b). As with other capture technologies, further research and development is required to increase energy efficiency and bring down costs.
Effect of fuel type The type of fuel and generation technology used will determine the type of capture technology that is most suitable. Within these basic capture approaches, there are several techniques that may be used in conjunction with different fuel types and technologies. In this report it is assumed that, typically, post combustion capture is most efficient for pulverised coal (including PC, SC and USC) and NGCC plants, while precombustion capture is best for use with IGCC technology.
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Retrofitting versus new plant application Carbon capture technologies can, in principle, be retrofitted to existing plants or installed in new plants. However, retrofitted capture technologies are generally not as efficient as those installed in new plants. The application of carbon capture and storage technology to a new plant is typically associated with higher efficiency and longer life expectancy than application as a retrofitted technology. Local conditions will, to a large extent, determine the viability of retrofit application. The IEA (2004a) has reported that refurbishing existing plants in the United States has extended the lifespan of plants and has also generated significant improvements in efficiency. As such, retrofits cannot be ruled out in all cases. However, the difficulties associated with retrofitting existing power stations suggest that when constructing new plants, there are benefits to designing them so they are ‘carbon capture ready’ as this may substantially reduce the costs of retrofitting if it is required in the future.
Cost of electricity generation with and without carbon capture Carbon capture and storage technologies are still in the early stages of development and there remains significant uncertainty surrounding investment costs. Estimates of the cost of electricity generation from plants with and without carbon dioxide capture vary significantly. Variations in reported costs result mainly from differences in the assumptions about factors such as plant size, capacity, efficiency, capital costs and financing. Other assumptions about the performance and operation of the carbon dioxide capture unit and other environmental control systems will also influence projected costs (Rubin et al. 2004). The costs of electricity generation and carbon capture technologies also vary across regions as a result of differences in fuel costs, resource and capital endowments and engineering capacity. There are few sources of comprehensive and consistent cost data for a range of technologies across regions. Costs detailed in this report are from a range of sources and are representative of costs from a variety of regions. The costs reported in table 1 are indicative of current and near term costs in some regions and for selected technologies.
Electricity generation costs The investment costs for carbon capture include capture technology and carbon dioxide pressurisation facilities. Carbon dioxide is usually compressed before transport to reduce the required transport volume. Compression costs are generally reported in aggregate with the costs of capture. As shown in table 1, new NGCC plants generally have the lowest initial capital costs compared with other plants even when NGCC plants are equipped with capture technology. Electricity generated by NGCC plants with carbon capture is also cost competitive compared with some plants without capture technologies. This suggests that in regions where natural gas is available at competitive prices, NGCC plants may be the preferred
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new investment option, particularly where importance is placed on a plant being ‘carbon capture ready’. New IGCC plants without capture are generally considered to be competitive with PC plants without capture in terms of initial capital costs, generation costs and efficiency. IGCC plants with carbon capture are, however, more expensive to build than PC plants without capture. PC plants, the most widely used electricity generation plants worldwide, generally have the highest carbon dioxide emissions per kWh of electricity generated (722–789 grams of CO2/ kWh). IGCC plants emit approximately 710–750 grams of CO2/kWh, while NGCC plants represent the cleanest technology with emissions of around 344–430 grams of CO2/kWh. Capture technologies can reduce these emissions substantially.
1
Current or likely costs in the near term and efficiencies of power plants With and without carbon capture
Technology
Total plant capital cost
Efficiency
Energy penalty
Generation cost
US$/kW
% LHV
PC – without CO2 capture – with CO2 capture
1095–1150 1718–2090
41–42 31–36
– 14–24
SCPC – without CO2 capture – with CO2 capture
1020 1860
46 33
– 28
3.7 6.4
USCPC – without CO2 capture – with CO2 capture
1161–1192 1871–2075
48 43
– 10
FBC – without CO2 capture – with CO2 capture
1114 1675
43 35
– 19
IGCC – without CO2 capture – with CO2 capture
1100–1590 1459–2380
42–47 36–43
– 9 –14
–
42
–
2.3–4
UCG–IGCC – without CO2 capture – with CO2 capture
620–756 –
– –
– –
2–5.5 –
NGCC – without CO2 capture – with CO2 capture
400–690 790–1013
55–60 47–54
– 10–15
IDGCC
% USc/kWh
CO2 Cost of emisCO2 sions captured
Cost of CO2 avoided
g/kWh US$/tCO2 US$/tCO2
4–4.5 766–789 6–8 90–105
– 29–44
– 32–49
722 148
– 30–35
– 47
4.2–4.7 6.6–7.2
– –
– 30–35
– –
3.3 5.2
717 –
– –
– –
3.9–5.0 710–750 5.1–6.9 70–152
– 11–32
– 13–37
810
–
–
708 70–142
– –
– –
2.2–3.4 344–430 3.2–4.9 40–150
– 28–57
– 32–49
Note: The cost of compressing the captured CO2 for pipeline transport is included in the above figures. Sources: Audus (2000); David and Herzog (2000); DPM&C (2004); Gielen (2003a); Johnson and Pleasance (1996); Johnson and Young (1999); McFarland and Herzog (2003); Parsons et al. (2000); Roberts et al. (2004); Rubin et al. (2004).
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The cost of carbon dioxide avoided reported in table 1 represents the level at which a penalty on carbon dioxide emissions would provide an appropriate incentive for a producer to implement capture methods rather than pay the penalty. Audus (2000) finds that NGCC plants with capture have the lowest cost of carbon dioxide avoided and hence NGCC capture technology would be implemented at a lower carbon dioxide penalty than other technologies. David and Herzog (2000), however, find that IGCC plants have the lowest cost of carbon dioxide avoided. This difference can be explained by variations in assumptions about the cost of electricity and the level of carbon dioxide emissions from each technology. Calculations for the cost of carbon dioxide avoided, the cost of carbon dioxide captured and the cost of electricity generated are presented in box 1.
Box 1: Calculating the cost of CO2 avoided, cost of CO2 captured and generation cost The cost of carbon dioxide avoided in US$/t CO2 is calculated using the following formula: COEc– COEr Er– Ec where
COEc = cost of electricity in $/kWh from capture plant COEr = cost of electricity in $/kWh from reference (noncapture) plant Er = CO2 emissions in t/kWh from reference plant Ec = CO2 emissions in t/kWh from capture plant.
The cost of carbon dioxide captured in US$/t CO2 is calculated using the following formula: COEc– COEr Cc where
Cc = CO2 emissions in t/kWh captured from capture plant.
The cost of carbon dioxide captured is lower than the cost of carbon dioxide avoided because the energy penalty associated with capture systems increases the emissions per unit of electricity at the capture plant. The generation cost can be calculated as:
GC = [(TCC )( ACF ) + (OC )] / [(CF )(8760)(kW )] + VC + ( HR)( FC ) where
GC = generation cost in $/kWh
TCC = total capital cost in $
ACF = annual fixed charge factor (fraction/year)
OC = fixed operating costs in $/yr
CF = capacity factor (fraction of actual to theoretical maximum output)
8766 = total hours per year
kW = plant power output
VC = variable operating costs in $/kWh
HR = heat rate in kJ/kWh
FC = per unit fuel costs in $/kJ
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Box 2: Energy penalty Carbon capture and compression technologies use energy and result in a reduction in plant output per unit of fuel input. This decline in the efficiency of a capture plant is also known as the energy penalty of carbon capture. The energy penalty is based on the change in the efficiency of a plant and is calculated using the following formula:
(
EP = 1 − ηccs / ηref where
)
EP = energy penalty
ηccs = thermal efficiency of the capture plant ηref = thermal efficiency of the reference plant A more meaningful definition of the energy penalty for assessing the changes in resource requirements and emissions from carbon capture and storage plants is considered to be the change in plant input per unit of output (Rubin et al. 2004). This can be denoted EP* and is related to EP in the above equation by:
(
)
EP* = EP / (1 − EP) = ηref / ηccs − 1 Continued improvements in the efficiency and cost of capture and compression technologies will depend on the continued development of power generation technologies that allow for concentrated carbon dioxide streams and less costly carbon dioxide capture.
2
Australian costs and efficiencies of power plants With and without carbon capture
Approximate generation costs
Capital cost 2002 Technology
2010
2030
A$/kW A$/kW A$/kW
2002
2010
Efficiency (HHV) 2030
Ac/kWh Ac/kWh Ac/kWh
%
%
%
2.2
41
43
45
SCPC
1 151
1 062
960
USCPC
1 210
1 117
1 010
2.5
2.4–3.5
2.0
43
45
52
DFCCC
926
762
689
3.4
3.1
2.7
49
52
60
1 584
1 172
884
3.5
2.7
2.1
43
48
50
825
679
614
3.5
3.2–4.5
2.75
53
56
65
USCPC O2 a – with 95% CO2 capture b 1 868
1 589
1 438
4.6
4.0
3.5
34
37
44
IGCC – with 25% CO2 capture c 1 839 – with 75% CO2 capture c 2 453
1 360 1 814
1 026 1 369
4.4 6.1
3.35 4.5
2.6 3.5
39 33
45 40
60 44
IGCC NGCC
2.45 2.35–4.0
2002 2010 2030
a USCPC O2 with capture is a hypothetical reconfiguration of USCPC replacing the combustion air with a mixture of oxygen and recycled flue gas. Although this technology has not yet been demonstrated it uses mostly proven technology and can result in flue gases with CO2 concentrations of around 95 per cent. b CO2 capture method – flue gas recycle. c CO2 capture method – monoethanolamine (MEA) absorption. Sources: Cottrell et al. (2003); DPM&C (2004).
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Carbon dioxide capture and compression technologies require energy and hence result in a reduction in plant efficiency as electricity output is reduced per unit of fuel input. This is known as the energy penalty of carbon capture. The energy penalty is discussed in box 2.
Regional cost variations The cost of new technologies will vary between countries and will be influenced by the availability, quality and prices of fuel and capital. For example, in Australia, the lowest cost options for plants commissioned in the next few years are SCPC and USCPC based on levelised generation costs (table 2). This reflects the cost advantage of coal over gas in Australia and is in contrast to some international studies that found that NGCC plants represent a cheaper option than USCPC plants (see table 1). Capital and generation costs of IGCC plants are also projected to fall, becoming one of the lowest cost technologies in Australia by 2030. A projected increase in uptake because of the availability of large amounts of relatively cheap coal in Australia is expected to drive learning and innovation and reduce IGCC costs.
Carbon transport and storage Transport Carbon dioxide transport technologies using high pressure land based pipelines are already well established. There are more than 3100 kilometres of carbon dioxide pipelines globally, primarily in north America, that have been used to transport carbon dioxide since the 1980s, typically for use in enhanced oil recovery projects (IEA Clean Coal Centre 2003a). Carbon dioxide can also be transported in tankers using carriers that are similar in design to current LPG carriers. Considerable offshore oil and pipeline infrastructure also exists that may have the potential to support offshore storage of carbon dioxide in geological sites (IEA 2002a). The cost of transporting carbon dioxide to the point of storage depends on the pressure and volume of the carbon dioxide to be transported, the distance between the carbon dioxide source and storage site, the method of transport and the geology through which the Indicative carbon dioxide transport pipelines are built. Transport costs are site costs specific and will vary within and between Average costs regions as a result of differing geography, infrastructure and capital and labor costs. Average distance US$/t CO2
3
Under 50 kilometres 50–200 kilometres 200–500 kilometres 500–2000 kilometres Over 2000 kilometres
Estimated costs for pipeline transport of carbon dioxide over a range of distances are reported in table 3 and are indicative average costs for a range of regions. It is assumed that transport over longer distances will result in larger pipelines and lower specific costs per kilometre traveled.
1 4 6 12 35
Note: Hendriks et al. (2004) quotes original costs in euros. Conversion to US dollars is based on ABARE exchange rate assumptions. Source: Hendriks et al. (2004).
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Estimated average transport costs for selected regions Oil and gas
Canada United States Central America South America North Africa West Africa East Africa South Africa Western Europe Eastern Europe FSU Middle East South Asia East Asia South east Asia Oceania Japan
Aquifers
Onshore
Offshore
Coal basins
US$/t CO2
US$/t CO2
US$/t CO2
US$/t CO2
6 6 4 4 4 4 6 4 4 12 12 4 6 12 6 4 6
6 6 1 4 4 6 6 6 6 1 12 1 12 6 4 35 35
12 35 6 4 4 6 35 4 4 35 35 4 4 12 4 12 12
6 6 12 1 35 35 35 4 4 4 35 35 6 4 12 6 4
Note: Hendriks et al. (2004) quotes original costs in euros. Conversion to US dollars based on ABARE exchange rate assumptions. Source: Hendriks et al. (2004).
In table 4, estimated regional average carbon dioxide transport costs are presented. The range of average costs reflects regional differences in the distance between carbon dioxide emission sources and potential storage reservoirs and also the impact of regional incomes on transport infrastructure and costs. These costs are indicative of average costs. A range of costs would also be expected within regions.
Carbon storage and utilisation options Captured carbon dioxide can be stored in a variety of geological or ocean sites including active and depleted oil and gas reservoirs, deep and unminable coal seams and saline aquifers.
Depleted oil reservoirs and enhanced oil recovery Depleted oil reservoirs represent attractive storage structures for captured carbon dioxide because of their well known geology, proven ability to store hydrocarbons over very long timeframes, and the potential to use established infrastructure for carbon dioxide transport and injection. Carbon dioxide can also be used in enhanced oil recovery (EOR) by injecting it into operational oil fields after primary and secondary production (box 3). Enhanced oil recovery is an established technology that is used commercially, primarily in the United States, although it can only be used in some oil fields of a certain geology and oil type (Gielen 2003a).
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Using carbon dioxide to enhance oil recovery can increase total oil recovery by 33–50 per cent (Gielen 2003a,b). This is associated with an estimated increase in income of about US$25–35/t CO2 injected, which has the potential to offset part or possibly all capture costs (Gielen 2003a).
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Estimated carbon dioxide storage capacities for different geological traps Share of total Global emissions capacity to 2050 a
Storage option
Enhanced oil recovery using carbon dioxide can result in net storage of 2.4–3.0 tonnes of carbon dioxide per tonne of oil produced. The cumulative global carbon dioxide storage capacity of enhanced oil recovery is expected to increase with time as more oil fields are depleted (Gielen 2003a).
Gt CO2
%
Depleted gas fields 690 Depleted oil fields/ CO2 enhanced oil recovery 120 Deep saline aquifers 400–10 000 Unminable coal seams 40
34 6 20–500 2
a Total emissions between 2000 and 2050 represent the IPCC ‘business as usual’ scenario. Storage potentials for oil and gas fields exclude fields that are not yet producing. Source: Davison et al. (2001).
Enhanced gas recovery Unlike enhanced oil recovery, enhanced gas recovery (EGR) is yet to be commercially proven. It is expected that enhanced gas recovery could occur in a manner similar to enhanced oil recovery with the injection of carbon dioxide into natural gas fields, displacing further supplies of gas and increasing production. Enhanced gas recovery using carbon dioxide is expected to increase gas recovery by approximately 10–15 per cent, resulting in an increase in income of about US$1–10/t CO2 injected (Gielen 2003b). The estimated global cumulative storage capacity of gas reservoirs is more than that of depleted oil reservoirs (table 5). However, the benefits derived from using enhanced gas recovery techniques are smaller (Gielen 2003a).
Box 3: Weyburn enhanced oil recovery project The Weyburn project is a large scale demonstration of the geological sequestration of carbon dioxide using enhanced oil recovery. Since 2000, oil recovery at the Weyburn oil field in Saskatchewan, Canada, has been enhanced using carbon dioxide captured as a byproduct from a coal gasification plant in North Dakota, United States. The carbon dioxide is transported to the oil field by a 320 kilometre pipeline and pumped as a compressed liquid into an injection well. The injected carbon dioxide forces oil toward the production well, improving yield and greatly increasing the longevity and economic viability of the oil reservoir. It is estimated that carbon dioxide injection will enhance recovery by 15 per cent of the initial oil in place, in the area of the field to be flooded. This will produce an additional 130 million barrels of oil over the 25 year life of the recovery project (Brown et al. 2001). The aim of the Weyburn monitoring project is to improve knowledge and understanding of geological sequestration by assessing the long term capacity of the reservoir to sequester carbon. Injected carbon dioxide will be monitored for four years for any resulting movements or leakage. The Weyburn project also allows the economic viability of similar projects to be assessed.
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Enhanced coalbed methane recovery Carbon dioxide can be injected into coal seams to enhance the recovery of coalbed methane, a naturally occurring gas, which can be used as a fuel. A large proportion of the injected carbon dioxide will be adsorbed onto the coal, sequestering it permanently provided the coal is never mined. A demonstration project exists in New Mexico, United States where more than 100 000 tonnes of carbon dioxide has been injected over three years. Enhanced coalbed methane recovery using carbon dioxide can increase recovery to around 90–100 per cent, from 40–50 per cent using conventional techniques. This has the potential to increase income by around US$3–20/t CO2 injected (Gielen 2003b). The most attractive coalbeds for methane recovery (shallow coal reserves with thick coal layers) are the least attractive from a carbon dioxide storage perspective since carbon dioxide adsorption generally increases with depth and pressure (Gielen 2003a). The cost of obtaining and using carbon dioxide, the benefits of increased production and the cost of carbon constraints are the major determining factors of the economic viability of enhanced oil, gas and coalbed methane recovery.
Saline aquifers Deep saline aquifers provide the largest potential for storage of all the geological options and are widely distributed below the continents and ocean floor (DTI 2003a). Once injected, carbon dioxide will either partially dissolve in water or slowly react with other minerals, forming carbonates that essentially sequester carbon dioxide permanently. Injecting carbon dioxide into deep saline aquifers uses technology similar to that used for EOR and has been commercially proven in the Sleipner project (box 4).
Ocean storage Carbon dioxide disposal in oceans has also been suggested as an option for permanent storage. Potentially, carbon dioxide could be injected into the deep ocean by land based subsea pipelines or transported by ship to a fixed offshore injection vessel. Computer model simulations predict that retention times of greater than 1000 years could be achieved by injecting at depths of 3000 metres. High costs, uncertain international legal and potential environmental implications and expected public opposition suggest that ocean sequestration is unlikely to be used in the near future. For these reasons, ocean storage of carbon dioxide is not considered in this report.
Other utilisation options Apart from utilisation in enhanced oil, gas and coalbed methane recovery operations, captured carbon dioxide can be used for several commercial purposes, including in food and beverage processing, fertiliser manufacture, chemical synthesis and as an algae and plant growth promoter. Currently, most of the carbon dioxide used for commercial purposes is obtained from naturally occurring carbon dioxide sources, such as natural gas streams or carbon dioxide wells. Reductions in the cost of capturing and transporting carbon dioxide
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Box 4: Sleipner carbon capture and storage saline aquifer demonstration project The Sleipner carbon dioxide capture and storage project is the first commercial scale demonstration of carbon dioxide injection and storage in an aquifer. Since 1996, approximately 1 million tonnes of carbon dioxide a year has been removed from a natural gas stream in the Sleipner oil and gas field in the North Sea and injected into a saline aquifer located about 1000 metres below the North Sea floor (IEA 2002a). The incentive to capture and store carbon dioxide in Norway is provided by a tax on carbon dioxide emissions. This tax was initially about US$50 a tonne of carbon dioxide. The Statoil company found that it was cost effective to invest about US$80 million in a carbon dioxide capture and injection facility in order to gain tax savings of approximately US$50 million a year. Although the tax has since been reduced to US$38 a tonne of carbon dioxide, thereby reducing the annual tax savings, it remains economic for the company to capture and sequester the carbon dioxide (Herzog et al. 2000). Since 1997, the Saline Aquifer CO2 Storage (SACS) project has monitored the reliability, environmental acceptability, movement and safety of carbon dioxide stored at this site. The monitoring project has concluded that to date there are no adverse environmental impacts of carbon dioxide storage at Sleipner on the surrounding environment.
from power plants, along with safety guarantees could encourage the use of captured carbon dioxide over natural carbon dioxide sources and a useful contribution to global carbon dioxide emissions reduction could be made.
Carbon injection and geological storage costs The cost of injecting carbon dioxide into geological reservoirs depends on the type of reservoir and its physical properties, its capacity for storage, the amount of work necessary to access the reservoir (depth and number of wells), flow rate, and the value of any products generated as a result of storage. Costs for offshore storage would be higher because a platform is required for drilling and injection. Carbon dioxide injection into geological reservoirs for permanent storage is a developing technique. Injection costs are still uncertain and average costs are expected to differ between storage types and regions. As a result, estimates of average injection costs range from US$1–3/t CO2 (Wallace 2000) and US$1–13/t CO2 (Hendriks et al. 2004).
Global and regional geological carbon storage capacity Globally, there appears to be an enormous geological storage capacity for carbon dioxide. Estimates for global carbon dioxide storage capacity range from about 500 to 10 000 gigatonnes of carbon dioxide. In 2000, global carbon dioxide emissions were estimated to be approximately 23 gigatonnes (Gale 2002; Hendriks et al. 2004; IEA 2002b; Wildenborg and van der Meer 2002). The IEA (2002a) estimates that there is sufficient geological capacity to sequester hundreds of years of emissions at current emission rates.
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Assuming injection costs of up to US$20 a tonne of carbon dioxide stored (Gale 2002), the indicative economic global capacity for storage substantially exceeds projected global emissions (table 5). Estimates of regional geological carbon dioxide storage capacity are shown in table 6. Potential storage capacities differ between regions primarily as a result of differences in the abundance of suitable geological formations and hydrocarbon reserves. The methods and techniques for assessing regional and global carbon dioxide storage potential are also relatively new and the assumptions and results of these assessments vary considerably. Estimates of potential storage capacity used in this report are taken from Hendriks et al. (2004) and are an initial assessment only. It is difficult to ascertain the accuracy of these figures. Given that the methodology involved no geological groundwork, expert opinion suggests that these figures are highly uncertain and are likely to significantly underestimate storage capacities in many cases (GeoScience Australia personal communication 2004). Although there is significant carbon dioxide storage capacity worldwide, not all emission sources will be located near sites with large storage potential. This means that some potential storage capacity will not be economic because of high transport costs. However, it is typically cheaper to pipe carbon dioxide to a storage site than to transmit the equivalent amount of electricity (Davison et al. 2001). As a result, it is generally considered that under an assumed carbon dioxide constraint, it is cheaper to site power stations close to electricity
6
Potential carbon dioxide geological storage capacity, by region and storage type Oil fields
Gas fields
Remaining Depleted
Canada United States Central America South America Northern Africa Western Africa Eastern Africa Southern Africa Western Europe Eastern Europe Former Soviet Union Middle East Southern Asia Eastern Asia South east Asia Oceania Japan Greenland Total
Enhanced coalbed Remaining Depleted methane
Aquifers
Total
Gt CO2
Gt CO2
Gt CO2
Gt CO2
Gt CO2
Gt CO2
Gt CO2
0.7 6.7 4.9 14.1 5.4 7.7 0.1 1.1 4.1 0.9 24.7 71.3 1.0 3.5 2.4 0.5 0 0
1.1 6.7 7.1 9.7 4.5 8.1 0 0.5 10.5 0.4 12.3 22.1 1.4 2.7 4.7 1.5 0 0
8.9 8.5 10.6 31.9 22.5 14.4 1.6 1.3 37.2 3.9 197.6 253.1 14.1 8.1 38.9 17.1 0 2.2
6.6 7.3 1.6 9.2 13.9 1.6 0.1 0 14.8 2.9 73.2 93.0 4.5 4.0 5.8 0.5 0 0
8.5 31.7 0 2.0 0 2.0 0 7.4 1.0 0.7 25.0 0 2.0 158.0 19.0 11.3 0.1 0
17.3 17.3 7.3 23.0 13.4 15.1 5.5 14.0 7.0 3.4 33.0 9.7 21.2 13.4 6.4 28.1 1.9 3.3
43.1 78.2 31.5 89.9 59.7 48.9 7.3 24.3 74.6 12.2 365.8 449.2 44.2 189.7 77.2 59.0 2.0 5.5
149.1
93.3
671.9
239
268.7
240.3
1662.3
Source: Hendriks et al. (2004).
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demand and transport carbon dioxide to a storage site rather than site the power generation plants close to a storage site and transmit electricity (Freund and Davison 2002).
Carbon capture and geological storage issues The possibility of widespread geological storage of carbon dioxide raises a number of long term storage and regulatory issues. The design and implementation of appropriate regulatory, legislative and administrative frameworks are in the early stages of development and will increase in importance if sequestration projects become more prevalent. Monitoring verification of sequestration activities will be required to assess the safety and long term permanence of carbon dioxide storage. These issues are only briefly discussed in this report as they are outside the main scope of the analysis.
Legal and regulatory framework The capture, transport and subsequent injection of carbon dioxide into geological storage raises a number of domestic and international regulatory and legislative issues on appropriate standards and regulations. An effective legal and regulatory framework would ideally encourage good sequestration practices without forming unintended barriers to its development. Responsiveness and flexibility to improved understanding of climate and sequestration risk would also be desirable characteristics (IPIECA 2003). It is envisaged that some form of regulation will exist to cover all stages of a sequestration project, including initial project siting, carbon dioxide capture, injection, and long term monitoring of sequestered emissions (CSLF 2004; Forbes 2002). A number of countries, including the United States, Australia, Canada, Japan and Norway, are already in the early stages of assessing the applicability of existing legislation to sequestration projects or designing new frameworks (CSLF 2004). Experience in the development of suitable legislation for sequestration differs between countries as a result of varying experiences with similar activities such as natural gas storage, carbon dioxide and gas transport and waste disposal in geological formations. Although existing conventions such as the London Convention on marine pollution and the Basel Convention on transboundary movements of hazardous wastes do not make specific mention of carbon dioxide sequestration since they were drafted before such technology was envisaged, these conventions may still apply to sequestration and could possibly be used to determine the permissibility of carbon dioxide sequestration under international law (Purdy and Macrory 2004).
Long term storage issues For geological storage of carbon dioxide to be a politically viable proposition, the public must perceive that the risks of storing carbon dioxide in geological formations are less than the risks of impacts from climate change. The continued monitoring of carbon sequestration sites to determine storage capabilities, carbon dioxide migration patterns and changes in the amount and form of carbon dioxide stored will help to verify carbon dioxide safety and permanence.
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Natural geological formations have stored oil and gas for millions of years and experience to date at carbon dioxide storage sites such as Sleipner and Weyburn suggests that carbon dioxide can be stored safely without major leaks or environmental damage. However, storage of carbon dioxide in geological formations is site specific and appropriate analysis and risk assessment of geosequestration projects would need to be conducted.
Renewable energy The use of renewable energy sources allows electricity to be generated with little or no greenhouse gas emissions. Currently, the most promising renewable energy sources are hydropower, solar, biomass, geothermal and wind power. Hydropower: Hydropower makes use of the energy created by flowing water to generate electricity. Water is generally diverted through a pipe and forced to flow through a turbine, spinning it and activating a generator that converts the kinetic energy of falling water into electricity. Solar: There are two types of commercially available technologies that use the light energy of the sun to generate electricity — photovoltaics and concentrating solar power. Photovoltaics: Photovoltaic (PV) technologies use semiconductor devices, or solar cells, to convert sunlight directly to electricity. Photovoltaic cells can be connected to form modules typically between 50 and 200 watts (IEA 2003). The electrical output of these modules depends on the amount of incident light reaching the active area, operating temperature, reflectivity and share of diffuse light. The cost of electricity generation from photovoltaic technologies still remains uncompetitive with traditional grid connected electricity generation technologies. Photovoltaics are, however, used in a number of niche applications, including offgrid stand alone systems that supply electricity for telecommunications and lighting in areas where grid connection is prohibitively expensive. Concentrating solar power (CSP) or thermal solar: Concentrating solar power technologies use a system of mirrors or reflectors to capture and concentrate direct solar radiation. The sunlight is transferred to a receiver that absorbs the concentrated sunlight and transfers its heat energy to the power conversion system. This system contains either water or a heat exchange fluid such as oil that generates electricity using a conventional steam generator.
In some concentrating solar power plants, a portion of the thermal energy can be stored for later use allowing electricity generation during cloudy periods or at night. Concentrating solar power plants can also be hybridised and operated in combination with conventional fossil fuels to increase their performance and reduce technological risk by using conventional fuel when required. The three types of concentrating solar power systems are parabolic trough, parabolic dish and power tower. Only the parabolic trough system has been proven on a commercial scale. Biomass: Biomass power is the use of organic matter, such as plant derivatives and industrial and animal waste, to generate electricity. Electricity can be generated by burning biomass directly or by allowing it to decompose and burning the resulting gas. Lifecycle
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carbon dioxide emissions of biomass energy are considered to be near zero if biomass is harvested in a way that allows the carbon dioxide released during combustion to be offset by the uptake of carbon dioxide from the atmosphere during plant growth. The efficiency of a direct fired biomass plant is typically low, at approximately 20 per cent. However, there are more expensive technologies that increase biomass steam generation efficiency to more than 40 per cent (IEA 2003). Biomass that is used as a supplementary energy source in a conventional fossil fuel fired plant can be converted to electricity with the efficiency of a modern coal fired plant at approximately 33–37 per cent (IEA 2003). Geothermal energy: Geothermal energy is derived from heat originating within the earth. Hydrothermal fluids, which are hot aqueous solutions or gases, have been used commercially since the 1950s to generate electricity. Geothermal energy can only be considered a renewable resource if the rate of depletion does not exceed heat replenishment.
To generate electricity using geothermal energy, reservoirs of heat must first be located beneath the Earth’s surface and a well drilled to access the resource. Steam or hot water is then piped to the surface, either for direct heating, including in space heating, aquaculture and industrial applications or to convert the heat into electricity. The capacity of a single geothermal well is usually 4–10 megawatts, while geothermal plants generally consist of a number of wells to achieve a capacity of about 20–60 megawatts (IEA 2003). Wind power: Wind turbines are used to transform the kinetic energy of wind into electrical energy. Wind spins the rotor blades of a turbine, driving a generator that produces electricity. Electricity can then be transferred to the grid or storage system. Most commercial wind farms consist of a large number of individual turbines, with rotor diameters of around 80 metres and individual outputs greater than 1 megawatt. Wind farms can be located on or offshore, with the cost of electricity generation dependent on the geological characteristics of the seabed and increasing with the distance from the shore.
The generating capacity of a wind farm is primarily determined by the number of turbines, the rotor swept area and the local wind speed. It is important that mechanisms are in place to ensure that variations in the wind speed do not lead to large fluctuations in wind generated electricity, which can affect the reliability of the electricity grid.
Costs and outlook for renewable energy Most renewable energy technologies have high upfront investment costs, resulting in capital depreciation and interest costs being a major factor in generation costs. There are generally no fuel costs for renewables, with the exception of biomass and hydropower, and operating and maintenance costs are generally low compared with conventional fossil fuel generation technologies. Currently, renewable electricity production (with the exception of hydropower), is generally not competitive with traditional electricity sources. The future cost of renewables is likely, however, to decline as technology advances and installed capacity increases. Wind power, biomass and geothermal power have the greatest potential to become more cost competitive within the next few decades (table 7).
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Current and projected costs for renewable electricity generation Investment costs Low 2002
Power source Small hydro (capacity
