sources and carriers is reviewed here along with their available resource potential and usage, conversion technologies, costs and environmental impacts. An analysis is made of the potential contributions due to further technological development for each resource to meet the world’s growing energy needs, but also to reduce atmospheric GHG emissions.
Fossil fuels
Fossil fuels supplied 80% of world primary energy demand in 2004 (IEA, 2006b) and their use is expected to grow in
absolute terms over the next 20–30 years in the absence of policies to promote low-carbon emission sources. Excluding traditional biomass, the largest constituent was oil (35%), then
coal (25%) and gas (21%) (BP, 2005). In 2003 alone, world oil consumption increased by 3.4%, gas by 3.3% and coal by 6.3% (WEC, 2004a). Oil accounted for 95% of the land-, water- and air-transport sector demand (IEA, 2005d) and, since there is no evidence of saturation in the market for transportation services (WEC, 2004a), this percentage is projected to rise (IEA, 2003c).
IEA (2005b) projected that oil demand will grow between 2002 and 2030 (by 44% in absolute terms), gas demand will almost double, and CO2 emissions will increase by 62% (which lies between the SRES A1 and B2 scenario estimates of +101% and +55%, respectively.
Fossil energy use is responsible for about 85% of the anthropogenic CO2 emissions produced annually (IEA,
2003d). Natural gas is the fossil fuel that produces the lowest amount of GHG per unit of energy consumed and is therefore favoured in mitigation strategies. Fossil fuels have enjoyed economic advantages that other technologies may not be able to overcome, although there has been a recent trend for fossil fuel prices to increase and renewable energy prices to decrease because of continued productivity improvements and economies of scale. All fossil fuel options will continue to be used if matters are left solely to the market place to determine choice of energy conversion technologies. If GHGs are to be reduced significantly, either current uses of fossil energy will
have to shift toward low- and zero-carbon sources, and/or technologies will have to be adopted that capture and store the CO2 emissions. The development and implementation of lowcarbon technologies and deployment on a larger scale requires considerable investment, which, however, should be compared with overall high investments in future energy infrastructure.
Coal and peat
2005, coal accounted for around 25% of total world energy consumption primarily in the electricity and industrial sectors (BP, 2005; US EIA, 2005; Enerdata, 2004). Global proven recoverable reserves of coal are about 22,000 EJ (BP, 2004; WEC, 2004b) with another 11,000 EJ of probable reserves and an estimated additional possible resource of 100,000 EJ for all types. Although coal deposits are widely distributed, over half of the world’s recoverable reserves are located in the US (27%), Russia (17%) and China (13%). India, Australia, South Africa, Ukraine, Kazakhstan and the former Yugoslavia account for an additional 33% (US DOE, 2005). Two thirds of the proven reserves are hard coal (anthracite and bituminous) and the remainder are sub-bituminous and lignite. Together these resources represent stores of over 12,800 GtCO2. Consumption was around 120 EJ/yr in 2005, which introduced approximately
9.2 GtCO2/yr into the atmosphere.
Peat (partially decayed plant matter together with minerals) has been used as a fuel for thousands of years, particularly in Northern Europe. In Finland, it provides 7% of electricity and 19% of district heating.
Technologies
The demand for coal is expected to more than double by 2030 and the IEA has estimated that more than 4500 GW of new power plants (half in developing countries) will be required in this period (IEA, 2004a). The implementation of modern high-efficiency and clean utilization coal technologies is key to the development of economies if effects on society and environment are to be minimized.
Most installed coal-fired electricity-generating plants are of a conventional subcritical pulverized fuel design, with typical efficiencies of about 35% for the more modern units. Supercritical steam plants are in commercial use in many developed countries and are being installed in greater numbers in developing countries such as China (Philibert and Podkanski, 2005). Current supercritical technologies employ steam temperatures of up to 600ºC and pressures of 280 bar delivering fuel to electricitycycle efficiencies of about 42% (Moore, 2005). Conversion
efficiencies of almost 50% are possible in the best supercritical plants, but are more costly (Equitech, 2005; IPCC, 2001; Danish Energy Authority, 2005). Improved efficiencies have reduced the amount of waste heat and CO2 that would otherwise have been emitted per unit of electricity generation.
Technologies have changed little since the TAR. Supercritical plants are now built to an international standard, however, and a CSIRO (2005) project is under way to investigate the production of ultra-clean coal that reduces ash below 0.25%, sulphur to low levels and, with combined-cycle direct-fired turbines, can reduce GHG emissions by 24% per kWh, compared with conventional coal power stations.
Gasifying coal prior to conversion to heat reduces the emissions of sulphur, nitrogen oxides, and mercury, resulting in a much cleaner fuel while reducing the cost of capturing CO2 emissions from the flue gas where that is conducted. Continued development of conventional combustion integrated gasification combined cycle (IGCC) systems is expected to further reduce emissions.
Coal-to-liquids (CTL) is well understood and regaining interest, but will increase GHG emissions significantly without CCS . Liquefaction can be performed by direct solvent extraction and hydrogenation of the resulting liquid at up to 67% efficiency (DTI, 1999) or indirectly by gasification then producing liquids by Fischer-Tropsch catalytic synthesis as in the three SASOL plants in South Africa. These produce 0.15 Mbbl/day of synthetic diesel fuel (80%) plus naphtha (20%) at 37–50% thermal efficiency. Lower-quality coals would reduce the thermal efficiency whereas co-production with electricity and heat (at a 1:8 ratio) could increase it and reduce the liquid fuel costs by around 10%. Production costs of CTL appear competitive when crude oil is around 35–45 US$/bbl, assuming a coal price of 1 US$/GJ.
Converting lignite at 0.50 US$/GJ close to the mine could compete with production costs of about 30 US$/bbl. The CTL process is less sensitive to feedstock prices than the gas-to liquids (GTL) process, but the capital costs are much higher (IEA, 2005e). An 80,000 barrel per day CTL installation would cost about 5 billion US$ and would need at least 2–4 Gt of coal reserves available to be viable.
Gaseous fuels
Conventional natural gas
Proven global reserves of natural gas are estimated to be 6500 EJ (BP, 2006; WEC, 2004c; USGS, 2004b). Almost three
quarters are located in the Middle East, and the transitional economies of the FSU and Eastern Europe. Russia, Iran and Qatar together account for about 56% of gas reserves, whereas the remaining reserves are more evenly distributed on a regional basis including North Africa (BP, 2006). Probable reserves and possible undiscovered resources that expect to be added over the next 25 years account for 2500 EJ and 4500 EJ respectively (USGS, 2004a), although other estimates are less optimistic.
Natural gas-fired power generation has grown rapidly since the 1980s because it is relatively superior to other fossil-fuel technologies in terms of investment costs, fuel efficiency, operating flexibility, rapid deployment and environmental benefits, especially when fuel costs were relatively low.
Combined cycle, gas turbine (CCGT) plants produce less CO2 per unit energy output than coal or oil technologies because of the higher hydrogen-carbon ratio of methane and the relatively high thermal efficiency of the technology. A large number of CCGT plants currently being planned, built, or operating are in the 100–500 MWe size range. Advanced gas turbines currently under development, such as so-called ‘H’ designs, may have efficiencies approaching 60% using high combustion temperatures, steam-cooled turbine blades and more complex steam cycles.
Despite rising prices, natural gas is forecast to continue to be the fastest-growing primary fossil fuel energy source worldwide (IEA, 2006b), maintaining average growth of 2.0% annually and rising to 161 EJ consumption in 2025. The industrial sector is projected to account for nearly 23% of global natural gas demand in 2030, with a similar amount used to supply new and replacement electric power generation. The share of natural gas used to generate electricity worldwide is projected to increase from 25% of primary energy in 2004 to 31% in 2030 (IEA, 2006b).
LNG
as for power generation will require development and scaleup of liquefied natural gas (LNG) as an energy carrier. LNG transportation already accounts for 26% of total international natural gas trade in 2002, or about 6% of world natural gas consumption and is expected to increase substantially.
The Pacific Basin is the largest LNG-producing region in the world, supplying around 50% of all global exports in 2002 (US EIA, 2005). The share of total US natural gas consumption met by net imports of LNG is expected to grow from about 1% in 2002 to 15% (4.5 EJ) in 2015 and to over 20% (6.8 EJ) in 2025.
Losses during the LNG liquefaction process are estimated to be 7 to 13% of the energy content of the withdrawn natural gas being larger than the typical loss of pipeline transportation over 2000 km.
LPG
of natural gas processing and crude oil refining. Total global consumption of LPG amounted to over 10 EJ in 2004 (MCH/ WLPGA, 2005), equivalent to 10% of global natural gas consumption (Venn, 2005). Growth is likely to be modest with current share maintained.
Unconventional natural gas
Methane stored in a variety of geologically complex, unconventional reservoirs, such as tight gas sands, fractured
shales, coal beds and hydrates, is more abundant than conventional gas . Development and distribution of
these unconventional gas resources remain limited worldwide, but there is growing interest in selected tight gas sands and coalbed methane (CBM). Probable CBM resources in the US alone are estimated to be almost 800 EJ but less than 110 EJ is believed to be economically recoverable (USGS, 2004b) unless gas prices rise significantly. Worldwide resources may be larger than 8000 EJ, but a scarcity of basic information on the gas content
of coal resources makes this number highly speculative.
Large quantities of tight gas are known to exist in geologically complex formations with low permeability, particularly in the US, where most exploration and production has been undertaken.
However, only a small percentage is economically viable with existing technology and current US annual production has stabilized between 2.7 and 3.8 EJ.
Methane gas hydrates occur naturally in abundance worldwide and are stable as deep marine sediments on the ocean floor at depths greater than 300m and in polar permafrost regions at shallower depths. The amount of carbon bound in hydrates is not well understood, but is estimated to be twice as large as in all other known fossil fuels (USGS, 2004a). Hydrates may provide an enormous resource with estimates varying from 60,000 EJ
(USGS, 2004a) to 800,000 EJ (Encyclopedia of Energy, 2004).
Recovering the methane is difficult, however, and represents a significant environmental problem if unintentionally released to the atmosphere during extraction. Safe and economic extraction technologies are yet to be developed (USGS, 2004a). Hydrates also contain high levels of CO2 that may have to be captured to produce pipeline-quality gas (Encyclopedia of Energy, 2004).
The GTL process is gaining renewed interest due to higher oil prices, particularly for developing uneconomic natural gas reserves such as those associated with oil extraction at isolated gas fields which lie far from markets. As for CTL, the natural gas is turned into synthesis gas, which is converted by the Fischer-Tropsch process to synthetic fuels. At present, at least nine commercial GTL projects are progressing through various development stages in gas-rich countries such as Qatar, Iran, Russia, Nigeria, Australia, Malaysia and Algeria with worldwide production estimated at 0.58 Mbbl/day (FACTS, 2005). GTL conversion technologies are around 55% efficient and can help bring some of the estimated 6000 EJ of stranded gas resources to market. Production costs vary depending on gas prices, but
where stranded gas is available at 0.5 US$/GJ production costs are around 30 US$ a barrel (IEA 2006a). Higher CO2 emissions per unit consumed compared with conventional oil products.
Petroleum fuels
Known or proven reserves are those extractable at today’s prices and technologies. Additional probable and possible
resources are based on historical experience in geological basins. While new discoveries have lagged behind production for more than 20 years, reserve additions from all sources including discoveries, extensions, revisions and improvements in oil recovery continue to outpace production (IEA, 2005b).
Various studies and models have been used to forecast future oil production (US EIA, 2004; Bentley, 2005). Geological models take into consideration the volume and quality of hydrocarbons but do not include economic effects on price, which in turn has a direct effect on supply and the overall rate of recovery.
Mathematical models generally use the historical as well as the observed patterns of production to estimate a peak (or several peaks) reached when half the reserves are consumed.
Assessments of the amount of oil consumed, the amount remaining for extraction, and whether the peak oil tipping
point is close or not, have been very controversial (Hirsch et al., 2005). Estimates of the ultimate extractable resource
(proven + probable + possible reserves) with which the world was endowed have varied from less than 5730 EJ to 34,000 EJ (1000 to 6000 Gbbl), though the more recent predictions have all ranged between 11,500–17,000 EJ (2000–3000 Gbbl).
Over time, the prediction trend showed increasing resource estimates in the 1940s and 1950s as more fields were
discovered. However, the very optimistic estimates of the 1970s were later discredited and a relatively constant estimate has since been observed. Specific analyses include Bentley (2002b), who concluded that 4870 EJ had been consumed by 1998 and that 6300 EJ will have been extracted by 2008. The US Geological Survey
(USGS, 2000) the World Petroleum Congress and the IFP agreed that approximately 4580 EJ (800 Gbbl) have been
consumed in the past 150 years and 5730 EJ (1000 Gbbl) of proven reserves remain. Other detailed analyses (e.g. USGS, 2000) also estimated there are 4150 EJ of probable and possible resources still available for extraction. Thus, the total available potential proven reserves plus resources of around 10,000 EJ (BP, 2004; WEC, 2004b) should be sufficient for about 70 years’.
supply at present rates of consumption. Since consumption rates will continue to rise, however, 30 to 40 years’ supply is a more reasonable estimate (Hallock et al., 2004). Burning this amount of petroleum resources would release approximately 700 GtCO2 (200 GtC) into the atmosphere, about two thirds the amount released to date from all fossil-fuel consumption. Opportunities for energy-efficiency improvements in oil refineries and associated chemical plants
Unconventional oil
As conventional oil supplies become scarce and extraction costs increase, unconventional liquid fuels, in addition to CTL and GTL, will become more economically attractive, but offset by greater environmental costs (Williams et al., 2006). Oil that requires extra processing such as from shales, heavy oils and oil (tar) sands is classified as unconventional. Resource estimates are uncertain, but together contributed around 3% of world oil
production in 2005 (2.8 EJ) and could reach 4.6 EJ by 2020 (USGS, 2000) and up to 6 EJ by 2030 (IEA, 2005a). The oil industry has the potential to diversify the product mix, thereby adding to fuel-supply security, but higher environmental impacts may result and investment in new infrastructure would be needed.
Heavy oil reserves are greater than 6870 EJ (1200 Gbbl) of oil equivalent with around 1550 EJ technically recoverable.
The Orinoco Delta, Venezuela has a total resource of 1500 EJ with current production of 1.2 EJ/yr (WEC, 2004c). Plans for 2009 are to apply deep-conversion, delayed coking technology to produce 0.6 Mbbl/day of high-value transport fuels.
Oil shales (kerogen that has not completed the full geological conversion to oil due to insufficient heat and pressure) represent a potential resource of 20,000 EJ with a current production of just 0.024 EJ/yr, mostly in the US, Brazil, China and Estonia.
Around 80% of the total resource lies in the western US with 500 Gbbl of medium-quality reserves from rocks yielding 95 L of oil per tonne but with 1000 Gbbl potential if utilizing lowerquality rock. Mining and upgrading of oil shale to syncrude fuel costs around 11 US$/bbl. As with oil sands (below), the availability of abundant water is an issue.
Around 80% of the known global tar sand resource of 15,000 EJ is in Alberta, Canada, which has a current production of 1.6 EJ/yr, representing around 15% of national oil demand.
Around 310 Gbbl is recoverable (CAPP, 2006). Production of around 2 Mbbl/day by 2010 could provide more than half of Canada’s projected total oil production with 4 Mbbl/day possible by 2020. Total resources represent at least 400 Gt of stored carbon and will probably be added to as more are discovered, assuming that natural gas and water (steam) to extract the hydrocarbons are available at a reasonable cost.
Technologies for recovering tar sands include open cast (surface) mining where the deposits are shallow enough (which accounts for 10% of the resource but 80% of current extraction), or injection of steam into wells in situ to reduce the viscosity of the oil prior to extraction. Mining requires over 100m3 of natural
gas per barrel of bitumen extracted and in situ around 25m3. In both cases cleaning and upgrading to a level suitable for refining consumes a further 25–50m3 per barrel of oil feedstock. The mining process uses about four litres of water to produce one litre of oil but produces a refinable product. The in situ process uses about two litres of water to one of oil, but the very heavy product needs cleaning and diluting (usually with naptha) at the
refinery or sent to an upgrader to yield syncrude at an energy efficiency of around 75% (NEB, 2006). The energy efficiency of oil sand upgrading is around 75%. Mining, producing and upgrading oil sands presently costs about 15 US$/bbl (IEA, 2006a) but new greenfield projects would cost around 30–35 US$/bbl due to project-cost inflation in recent years (NEB, 2006). If CCS is integrated, then an additional 5 US$ per barrel at least should be added. Comparable costs for conventional oil are 4–6 US$/bbl for exploration and production
and 1–2 US$/bbl for refining.
Mining of oil sands leaves behind large quantities of pollutants and areas of disturbed land.
The total CO2 emitted per unit of energy during production of liquid unconventional oils is greater than for a unit of conventional oil products due to higher energy inputs for extraction and processing. Net emissions amount to 15–34 kgCO2 (4–9 kgC) per GJ of transport fuel compared with around 5-10 kgCO2 (1.3-2.7 kgC) per GJ for conventional oil (IEA, 2005d, Woyllinowicz et al., 2005). Oil sands currently produce around 3–4 times the pre-combustion emissions (CO2/GJ liquid fuel) compared with conventional oil extraction and refining, whereas large-scale production of oil-shale processing would be about 5 times, GTL 3–4 times, and CTL around 7–8 times when using sub-bituminous coal. The Athabascan oil-sands project has refining energy expenditures of 1 GJ energy input per 6 GJ bitumen processed, producing emissions of 11 kgCO2 (3 kgC) per GJ from refining alone, but with a voluntary reduction goal of 50% by 2010 (Shell, 2006).
Nuclear energy
natural uranium (WNA, 2006a). As of December 2006, 442 nuclear power plants were in operation with a total installed capacity of about 370 GWe (WNA, 2006a). Six plants were in long-term shutdown and since 2000, the construction of 21 new reactors has begun (IAEA, 2006). The US has the largest number of reactors and France the highest percentage hare of total electricity generation. Many more reactors are either planned or proposed, mostly in China, India, Japan, Korea, Russia, South Africa and the US (WNA, 2006a). Nuclear power capacity forecasts out to 2030 (IAEA, 2005c; WNA, 2005a; Maeda, 2005; Nuclear News, 2005) vary between 279 and 740 GWe when proposed new plants and the decommissioning of old plants are both considered. In Japan 55 nuclear reactors currently provide nearly a third of total national electricity with one to be shut down in 2010. Immediate plans for construction
of new reactors have been scaled down due to anticipated reduced power demand due to greater efficiency and population decline (METI, 2005). The Japanese target is now to expand the current installed 50 GWe to 61 GWe by adding 13 new reactors with nine operating by 2015 to provide around 40% of total electricity (JAEC, 2005). In China there are nine reactors in operation, two under construction and proposals for between 28 and 40 new ones by 2020 (WNA, 2006b; IAEA, 2006) giving a total capacity of 41–46 GWe (Dellero & Chessé, 2006). To meet future fuel demand, China has ratified a safeguards agreement (ANSTO, 2006) enabling the future purchase of thousands of tonnes of uranium from Australia, which has 40% of the world’s reserves. In India seven reactors are under construction, with plans for 16 more to give 20 GWe of nuclear capacity installed by 2020 (Mago, 2004).
Resources:
1. Energy Supply – Ralph E.H. Sims (New Zealand), Robert N. Schock (USA).
