IEA/ETO Working Paper

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1 IEA/ETO Working Paper ETO/2005/01 Alternative Fuels: An Energy Technology Perspective Dolf Gielen Fridtjof Unander Office of Energy Technology and R&D International Energy Agency March 2005 The views expressed in this Working Paper are those of the author(s) and do not necessarily represent those of the IEA or IEA policy. Working Papers describe research in progress by the author(s) and are published to elicit comments and to further debate. INTERNATIONAL ENERGY AGENCY

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3 Abstract Report Number EET/2005/01 Paris, March, 2005 Alternative fuels: An Energy Technology Perspective Dolf Gielen and Fridtjof Unander This paper was presented at the IEA workshop on Technology Issues for the Oil and Gas Sector, Paris, January The paper was also presented to the IEA Committee on Energy Research and Technology (CERT), 1-2 March The World Energy Outlook 2004 projects that while there is sufficient conventional oil reserves to meet the demand increase expected over the next three decades, this will require significant investments and it will imply increasing dependence in the Middle East. Last year oil prices peaked well above 50 $/bbl for the US WTI and North Sea Brent and above 40$/bbl for the OPEC basket, and prices have been rising again in recent months. This price hike can to some extent be linked to increased risk premiums on oil from the Middle East combined with short-term supply constraints in meeting rapidly growing demand. The generally higher prices and the increased price fluctuations have again raised interest in substitutes to conventional oil. Oil substitutes do exist, but their expansion is a matter of sufficiently high oil prices. The prospect of alternatives to conventional oil sources has in itself a moderating effect on oil markets in that it reduces the incentive for oil producers to collaborate to raise prices. While alternatives to conventional oil may be costly in the beginning, their cost may decline rapidly due to technology development and learning-by-doing. However, experience has shown that energy technology development including R&D, demonstration and market introduction is often a slow process that may take decades. Refinery oil products will dominate the transportation fuel market in the next three decades, but a substantial share of alternative fuels may be needed beyond Between 55 and 105 EJ per year may be needed by Given growth constraints for all alternatives, a global mix of alternative fuels may emerge, which may differ by region. Certain alternatives that are ready for the market (non-conventional oil, GTL, CTL, LNG) can mitigate oil supply problems. However, they do not help to meet the combined energy policy targets of enhanced long-term supply security and significant CO 2 emission mitigation. Therefore the combination of oil supply security and deep CO 2 emissions reduction poses a strategic energy policy challenge. The use of CCS should be considered for all oil, gas, coal and biomass based fuel supply systems. Such development can make the supply alternatives that are ready for the market into suitable transition options. Hydrogen and biofuels (ethanol from cellulose and wood crops) are the only two supply alternatives that can meet both supply security and ambitious CO 2 targets. In both cases, further technology development is needed. 3

4 Hydrogen could capture 10-15% of the transportation fuel market by However, important obstacles remain on the vehicle side, and in the transition to a hydrogen fuelled transportation sector. Government action is needed now to develop these technologies further and establish a favourable long-term business environment so industries can develop. The views expressed in this Working Paper are those of the author(s) and do not necessarily represent those of the IEA or IEA policy. Working Papers describe research in progress by the author(s) and are published to elicit comments and to further debate. 9, rue de la Fédération, Paris Cedex 15 Dolf.Gielen@iea.org International Energy Agency 4

5 Alternative fuels: An Energy Technology Perspective TABLE OF CONTENTS 1. The Need for Oil Alternatives 7 2. The Technology Characteristics of Alternative Fuels CO 2 Balance of Alternative Fuels Potential Oil Market Impacts Policy Modelling Issues Conclusions References 27 5

6 TABLES AND FIGURES Figures Figure 1: Stranded gas resources, by region 13 Figure 2: Meeting transportation fuel demand in 2050 in case of various supply scenarios. 22 Figure 3: Remaining efficiency potentials for light duty vehicles (global average) 23 Figure 4: Direct and indirect emissions from the transportation sector in 2030 and Tables Table 1: Screening criteria for enhanced oil recovery methods. 9 Table 2: Overview of supply cost of alternative fuels 19 Table 3: Fuel chain CO 2 emissions, with and without CCS 21 6

7 1. THE NEED FOR OIL ALTERNATIVES Alternative fuels includes in this analysis non-conventional oil and synfuels for the transportation sector. 1 The analysis focuses on transportation fuels because the transportation fuel market (including international marine bunkers) represents about 53% of the world refinery product demand. If upstream oil product use in transportation fuels production, bitumen use for asphalt and lubricants are included, the share of the transportation sector is even higher, about 60%. The share of transportation fuels in the oil market is projected to increase further in the next decades. The remainder of the oil products is used for heating, by industry (notably feedstocks for the production of plastics and other synthetic organic materials in the petrochemical industry), and for the production of electricity (from heavy fuel oil, petcoke, Orimulsion and diesel use for aggregates). A refinery produces a mix of light products (mainly transportation fuels) and heavy products. So far no large-scale alternatives exist for oil products (gasoline, diesel and LPG), and the shift in refinery product mix to transportation fuels of increasing quality results in an increasing refinery energy use. Therefore transportation fuel demand will increasingly determine the demand for crude oil. According to the World Energy Outlook 2004 there are sufficient oil resources in place for the period up to 2030, provided that sufficient investments are made and that new technologies for improved oil recovery (IOR) or enhanced oil recovery (EOR) are available (IEA, 2004a). WEO 2004 projects in its Reference Scenario an unabated growth of oil supply from 151 EJ 2 in 2000 to 241 EJ in 2030, which is equivalent to a growth from 77 million barrels per day (mb/d) to mb/d in 2030 (IEA 2004a) 3. This supply includes non-conventional oil. Non-conventional oil production is projected to grow from 1.6 mb/d in 2002 to 10.1 mb/d in This includes 6 mb/d of oil sands and tar sands, 2.4 mb/d of gas-to-liquids (GTL) and the remainder (1.7 mb/d) oil shales, coal-to-liquids and biofuels. In the WEO Reference Scenario, the OPEC Middle East share in world oil production would grow from 24.7% to 42.7% in 2030 (IEA, 2004a). It is not clear how oil production will develop beyond Apart from the resource base uncertainty, there is uncertainty regarding the resource development potential. Given the political instability of the Middle East a strong output growth in the Middle East may not materialize (Clingendael, 2004). The same may apply to Russia and other countries with significant oil resources, such as Venezuela. Apart 1 Various definitions exist for conventional oil (Haider, 2000). In this paper, conventional oil includes all light and medium density oil that can be produced economically based on current or future technology. It includes new improved oil recovery (IOR, e.g. horizontal drilling, better reservoir management) and enhanced oil recovery (EOR, e.g. steam/gas/co 2 /polymer injection) technologies that are not yet economic. It includes natural gas liquids. 2 1 EJ = 1 ExaJoule = Joule 3 This includes 3 mb/d processing gains 7

8 from the political instability, the opinions diverge how much of the original oil in place can be recovered through IOR and EOR. Only EOR will be discussed in more detail. Following primary and secondary oil production, tertiary production technologies can be applied. These are also called enhanced oil recovery technologies. A number of such technologies exist. Their suitability and effectiveness depends on the reservoir and oil characteristics (table 1). To some extent, they are (implicitly) included in the assessment of ultimately recoverable oil reserves, and therefore in the category of conventional oil. However, EOR is not yet widely applied. In the US, EOR oil production amounted to 0.66 mb/d in 2004, with a similar production level in the rest of the world (excluding oil and tar sands processing, see below) (Moritis, 2004). Total EOR (excluding oil sands and tar sands) amounts to 1-1.5% of global oil production. More than half of this is thermal recovery of heavy oil (using steam). Only CO 2 EOR will be discussed in more detail, as this is an emerging option that could be applied to many oil fields. Supercritical CO 2 is injected into a depleted oil reservoir. CO 2 and water injection are usually alternated. The CO 2 and the oil mix in the reservoir, and more oil can be recovered. CO 2 that is produced with the oil is re-cycled into the reservoir. CO 2 EOR can be split into miscible and immiscible flooding. Miscible CO 2 flooding is limited to reservoirs with a temperature of less than 120 C. At higher temperatures, immiscible flooding can be applied. However, the oil recovery factor halves in case of immiscible flooding. The additional recovery amounts to 8-15% of the total quantity of original oil in place. Depending on the geology of the oil field and the oil type, the enhancement of the oil recovery can range from 10% to 100%. An estimate for Norway is that EOR can increase ultimate oil production by 300 million m 3 (Mathiassen 2003), which represents about 10% of production to date and the remaining reserves. So new technology such as CO 2 EOR can increase the quantity of recoverable conventional oil substantially. About 3.3% of US oil production is based on CO 2 enhanced oil recovery (EOR). This equals 28% of total US enhanced oil recovery (Berge, 2003). 32 Mt CO 2 per year is used from natural resources and 11 Mt from industrial processes. A few CO 2 EOR projects exist outside the USA. A detailed field-by-field analysis is required for proper assessment of its potential on a global scale. Especially in mature oil production regions such as the North Sea, this option could be applied soon. CO 2 EOR could mitigate the dependency on inputs from the Middle East. 8

9 Table 1: Screening criteria for enhanced oil recovery methods. Second figure indicates current average conditions (Green and Willhite, 1998, p. 9, DOE 2002). PV = Pore Volume. EOR method ºAPI Viscosity [cp] N2 (&flue gas) >35/ 48 Hydrocarbon >23/ 41 CO 2 >22/ 36 Micellar/ >20/ polymer/ 35 alkaline Polymer >15/ flooding <40 Combustion >10/ 16 Steam >8/ 13.5 <0.4/ 0.2 <3/ 0.5 <10/ 1.5 <35/ 13 <150/ >10 <5000/ 1200 <200,000/ 4,700 Composition High % C1-C7 High % C2-C7 High % C5-C12 Light, intermediate Oil saturation [% PV] Formation type >40/75 Sandstone/ Carbonate >30/80 Sandstone/ Carbonate Net thickness [m] Thin unless dipping Thin unless dipping Permeability [md] Depth [m] - > > >20/55 Sandstone/ Carbonate >35/53 Sandstone - >10/450 <3000/ 1100 T [ºC] - - > <95/ 25 Cost [USD/bbl] - >70/80 Sandstone - >10/800 <3000 <95/ >50/72 High porosity >3 >50 <4000/ >40/ 3-6 sand/sandstone >40/66 High porosity >6 >200 <1500/ sand/sandstone 500 CO 2 EOR investment costs have been halved in the last 25 years. Project costs vary depending on field size, pattern spacing, location and existing facilities, but in general, total operating expenses (exclusive of CO 2 cost) range from 2 to 3 $/bbl, or about 10% more than waterflood operating expenses. Costs can be split into capital costs (about 0.8 $/bbl), operating cost (2.7 $/bbl), royalties taxes and insurance (3.6 $/bbl) and CO 2 costs (3.25 $/bbl, if CO 2 from natural reservoirs is used). Production costs excluding CO 2 costs are approximately 7 USD/bbl oil (about 50 USD/t oil) (Kinder Morgan, 2002). CO 2 can be captured from power plants for $/t (IEA, 2004b) t CO 2 are needed per tonne of oil recovered, so this would add $/bbl. Total production cost would amount to $/bbl. Depending on the government take and the world oil price, this cost level may or may not be attractive for oil companies. The CO 2 cost will decline in the future, and certain lowcost capture opportunities exist outside the electricity sector. Future use of CO 2 -EOR could increase substantially if the CO 2 is stored permanently, and this storage is valued properly. The feasibility of long-term CO 2 storage in combination with EOR is currently being tested in a number of demonstration projects such as the Canadian Weyburn project CO 2 -EOR can enhance supply security, increase oil reserves and reduce CO 2 emissions, while the cost are competitive. This combination of features makes it an attractive option. However, while it can delay oil peaking, it will not prevent the peaking of conventional oil production. Apart from supply security, environmental concerns play and increasingly important role. Policies aiming for climate change mitigation can result in a need for CO 2 emissions reduction in the transportation sector and in the production of the transportation fuels. This may result in an increasing demand for CO 2 -free transportation fuels, such as biofuels and hydrogen. Other environmental issues 9

10 such as local air pollution are to a certain extent fuel dependent, but the emissions of SO 2, NO x, particulates and hydrocarbons could be reduced through proper measures without fuel switching (WBCSD, 2004). It is beyond the scope of this paper to discuss engine technology and exhaust gas cleaning technology in detail. The following discussion of environmental impacts is limited to CO THE TECHNOLOGY CHARACTERISTICS OF ALTERNATIVE FUELS At this moment, gasoline, diesel, kerosene (jet fuel) and bunker oil are the transportation fuels of choice. These are all refinery products. Minor quantities of LPG, natural gas, ethanol and biodiesel supplement these. The following alternatives will de discussed: - Non-conventional oil reserves - Fischer-Tropsch production of diesel and gasoline from coal, natural gas or biomass - Natural gas - Bioethanol - Hydrogen - Methanol and DME - Electricity The discussion of the technology status and perspectives in this section is followed by an analysis how the aggregate of these alternatives can affect the global oil market on the long term ( ). NON-CONVENTIONAL OIL Three types of non-conventional oil reserves can be discerned: heavy oil, tar sands bitumen and oil shales. Medium heavy oil and extra heavy oil have a density ranging from 25º API to 7 ºAPI, and a viscosity ranging from 10 to 10,000 centipoise (cp). These resources are mobile at reservoir conditions. Tar sands and bitumen have a density ranging from 12º API to 7 ºAPI, and a viscosity above 10,000 cp. They are not mobile at reservoir conditions. The reserves of extra heavy oils are concentrated in Venezuela, while the tar sands and bitumen are concentrated in Canada 5. The amount of oil in place is 1,200 Gigabarrels (Gbbl) and 1,630 Gbbl, respectively. This represents about 80% of worldwide reserves. For both the recoverable reserves are in the order of the oil reserves of Saudi Arabia (310 Gbbl for Canada and 270 Gbbl for Venezuela). 4 For miscible CO 2 floods 5 Estimates suggest there is another 1,350 Gbbl in place in Russia, which have not been taken into account 10

11 Oil sands contain 10-15% bitumen. 10% of the tar sands is situated within 50 meters of the surface and can be mined in open pits. The oil sands recovery for surface mined resources is good, up to 90%. The remaining 90% of the oil sands can be mined using in-situ technologies (with much lower recovery rates of 10-20%). A number of underground production techniques can be discerned: cyclic steam stimulation (CSS), pressure cyclic steam drive (PCSD), cold heavy oil production with sand (CHOPS), solvent injection and steam assisted gravity drainage (SAGD). Open cast mining is currently the main production technology in Canada (about 80% of total production). The mined sand is transported to a processing plant where the bitumen is removed using mixing and cleaning processes involving water, caustic soda and some form of agitation. Following the cleaning bitumen is diluted with naphthalene and sent to an upgrader. Heating the bitumen to about 500 C yields about 70% syncrude. The syncrude gives good yields of kerosene and other middle distillates. The remaining fraction either thermally cracks to form gaseous products or it is converted into petcoke. The main CSS application is the Imperial Oil Cold Lake project (0.11 Mbpd in 2002). Steam is injected for some time, followed by production of the heated liquid bitumen (about 80 ºC). In case of SAGD, another well below the steam injection well is used for recovery of the liquefied bitumen. SAGD has been tested on a pilot plant scale (0.05 Mbpd in 2002 in 10 projects), solvent injection has not yet been tested. SAGD could increase the recovery efficiency from less than 10% to 40%, which would increase the recoverable reserves substantially: the global reserves of oil sand and heavy oil would increase to the level of the conventional oil reserves. However, the production of oil sands is energy and CO 2 intensive. CSS requires approximately GJ natural gas per barrel of bitumen produced, and 20 kw of electricity ( GJ/GJ bitumen produced). Approximately 75 kilograms of CO 2 are released per barrel of bitumen produced, up to 109 kilograms per barrel for steam assisted extraction (12-18 kg CO 2 /GJ) (Foley, 2001). The CSS steam-to-oil ratio is about 5:1. For SAGD, it is 2:1 to 4:1, with a potential for further reduction to 2:1 or even 1:1 for solvent based processes (Ali, 2003). So a significant potential exists to decrease energy use and emissions. On top of the emissions in bitumen production there are the emissions from the bitumen upgrading. In case residues from upgrading are used to generate the steam, no additional gas is needed (e.g. in case of the Long Lake project). The total emission is substantially higher than for conventional oil production. The operating cost for SAGD would be about 3 US$/bbl, if gas is used to generate the steam, and 1 $/bbl if upgrading residues are used. Investment cost and upgrading cost must be added. Total technical cost (production and upgrading) are about 15 US$/bbl. The cost may increase 5 $/bbl if CO 2 capture is added in order to mitigate upstream emissions (Cupcic, 2003). 11

12 In the case of the Venezuelan Orinoco tar sands, the temperature of the reservoirs at 1000 m depth is 55 ºC. The high reservoir temperature reduces the viscosity. As a consequence the oil can be recovered without or with very limited thermal stimulation (0.3 bbl steam/bbl oil) (Ali, 2003). The heavy oil, which has an average gravity of 9.5 API (1.00 t/m 3 ), is extracted from wells that are arranged in clusters, using screw pumps. Note that the production costs are well below the price for conventional oil. This explains the rapidly increasing production. 829 million barrels of bitumen were produced in Canada in 2002 (Alberta 2003). By 2011, Alberta s oil sands are expected to generate nearly two mbpd of crude oil representing more than half (57 per cent) of Canada s projected total crude oil production. In Venezuela plans are to apply deep conversion technology to the tar sands in order to produce highvalue transportation fuels. Delayed coking is the primary conversion technology. Plans are to produce 622,000 barrels or syncrude by Total Canadian and Venezuelan production would roughly amount to 3 mbpd of crude oil equivalent in 2010, 3% of world oil production. The IEA World Energy Outlook projects a total syncrude production from both sources of 6 mbpd by 2030 (IEA, 2004a). This production is based on very large multi-billion dollar projects, whose planning takes time. Such projects require a stable policy environment. Such an environment is given for Canada, but less evident in the case of Venezuela. Oil shale is an inorganic rock that contains kerogen, a type of immature oil that has never been exposed to high temperatures. Lean shale contains about 4% kerogen. Rich shale contains about 40% kerogen. When the rock is heated to ºC is yields litres of oil per ton of shale. Advanced oil shale processing would generate roughly 286 kg CO 2 /bbl (54 kg/gj) compared to 59 kg CO 2 /bbl (11 kg/gj) for conventional oil. Reductions to 169 kg/bbl (32 kg/gj) are planned (Innovest Strategic Value Advisors, 2001). The raw shale oil produced would constitute a relatively light crude with a 42 API gravity, 0.4wt% sulphur and 1.0wt% nitrogen. The oil is further processed into hydrotreated naphtha and low sulphur medium shale oil of 27º API. The world s largest oil shale project was the Stuart shale oil project in Australia. The plant was heavily opposed by NGO s. In July 2004 it was announced that the plant will be closed down. There are some oil shale mining activities in Estonia, Brazil and China, but they are of secondary importance. The bulk of the global oil shale resources are located in the US. There is more than 500 Gbbl in place of more than 25 gallon/ton in a layer at least 3 metres thick. About twice as much is lower quality resource (DOE 2004a). Mining and upgrading of the oil shale to syncrude costs 11 US$/bbl. The industry would be similar to the Canadian oil sand production. In-situ recovery methods are under development that could reduce environmental impacts dramatically. However, there are no plans as of yet to develop this resource. It is unlikely that an industry of more than 1 mbpd will be operational by

13 Fischer-Tropsch synthesis from natural gas and coal Fischer-Tropsch synthesis for production of synfuels is an established technology. Fossil fuels or biomass are converted into syngas via steam reforming, autothermal reforming or gasification. This syngas is converted into diesel and naphtha in a catalytic Fischer-Tropsch reaction. South Africa has established this technology on a large scale during the past 50 years, and Sasol is operating a 0.15 mbpd coal-to-liquids plant. The product mix consists of 80% diesel and 20% naphtha. China has expressed interest in an advanced version of the Sasol conversion process, which could add 1.2 mbpd by A number of other, smaller scale projects have already started operation or are under construction (Coaltrans, 2003). FT-synthesis from natural gas is another established technology. Further expansion up to 1 mbpd is planned for 2010, the bulk of this capacity being located in the Middle East (Qatar) (Chemical Market Reporter, 2004). The conversion efficiency is about 55%, with a theoretical maximum of about 78%. Due to the energy loss, this process makes only economic sense for cheap stranded gas. As the cost for LNG transportation decline and demand increases, such options decline as well. The IEA WEO projects 2.3 mb/d GTL by 2030 (IEA, 2004a). It is not evident that FT-synthesis based on Middle Eastern stranded gas, or LNG from the Middle East would also enhance the security of supply on the long term. Outside the Middle East, the longterm availability of sufficient stranded gas to fuel the world transportation fleet is less evident. The total amount of stranded gas in figure 1 amounts to 6,000 EJ, half of the global gas reserves, which equals 60 years of current gas use. However, figure 1 suggests that the bulk of the stranded gas resources are also in politically less stable regions. CSA 7% Other 12% Africa 8% FSU 20% Meast 53% Figure 1: Stranded gas resources, by region 13

14 At the moment a 40% liquid product yield (in energy terms) can be attained for coal based FT processes (Steynberg and Nel, 2004). Coal based production is less sensitive to feedstock prices than the gas based production, but capital cost are considerably higher due to the additional cost for coal gasification, oxygen production etcetera. In case of gas feedstock use, between 17 and 25% of the carbon entering the process is released as a process emission (the remainder is in the liquid synfuel product). In the case of coal feedstocks the process emission amounts to more than 50% of the carbon in the feedstock. CO 2 capture and storage could be applied in order to reduce CO 2 emissions drastically. Current gas based FT production costs are $25-30/bbl (5-6 US$/GJ), given a gas price of 0.5 $/GJ (Marsh et al. 2002). For coal based processes, production cost would amount to about 8-10 US$/GJ at a coal price of 1 US$/GJ (Williams and Larson, 2003). In recent years there has been increasing attention for coproduction of electricity and synfuels such as methanol, FT-diesel and hydrogen from coal. Coproduction would allow a high average load factor, which would reduce capital cost per unit of product. A study by Sasol points out that the coproduction of FT transportation fuels and electricity from coal raises the energy conversion efficiency from 40 to 50%, compared to the same plant without electricity cogeneration. Such plants would produce fuels and electricity in an 8:1 ratio (Steynberg and Nel, 2004). Static analysis suggests that synfuel production costs may be reduced by 10 percent if a coproduction strategy is applied (Yamashita and Barreto, 2003, Williams and Larson, 2003). NATURAL GAS Car engines can run on natural gas. This requires some minor modifications to gasoline engines. The use of gas requires a gas tank, and it shortens the life span of the engine. Retrofit of midsize gasoline cars to natural gas costs currently 3400 $/car. The power output of the car is reduced by 15-20%. At the moment such a retrofit is attractive in e.g. Germany because natural gas is not taxed, contrary to oil fuels. However, its expansion is limited by the availability of natural gas refuelling stations, and natural gas supply, but on the vehicle side the challenges are limited. Cost-wise, the retrofit investment can be translated into 35 $cents/litre gasoline equivalent, or 10 $/GJ. These capital cost are not negligible, and must be taken into account for proper comparison of alternative fuels. 14

15 Worldwide there are about 3.8 million natural gas fuelled vehicles, mainly in Argentina, Brazil, Pakistan, Italy, India and the US (IANGV, 2004). This equals about 0.5% of the world vehicle stock. BIOETHANOL AND OTHER BIOFUELS In 2003, world fuel ethanol production amounted to 28 billion litres. At 21.1 MJ/l (LHV), that equals 0.4 mb/d (about 0.5% of global oil consumption). The production is mainly concentrated in Brazil and the United States. This production is based on sugar cane (in the case of Brazil) or on corn (in the case of the US). The resource base is gradually widening to cellulosic crops, and even wood. Such low cost feedstock would result in an global increased production potential for low cost ethanol. Various countries and regions are planning a rapid expansion of ethanol production. Some scenarios suggest that a tenfold increase (to 4 mbd) by 2020 would be feasible, based on sugar cane ethanol alone (IEA 2004c). Also biomass can be converted via FT-processes. Cost are higher than for gas and coal because of the unfavourable economies of scale, related to the dispersed nature of the biomass resource. Production cost amount to 90 US$/bbl (19 $/GJ) for a biomass feedstock price of 3 $/GJ (Hamelinck et al., 2004). These cost could be reduced to $/bbl (14-16 $/GJ). Due to the high cost this process is applied nowhere, and there are no plans to establish such production. The long-term prospects of bioethanol, or any other biofuels such as methanol and biodiesel, depend on biomass availability. This availability depends on future food demand and food patterns, other types of land use and agricultural productivity. Analysis that takes these factors into account suggests at an emission reduction incentive of 80 USD/t CO 2 a cost-effective potential for new primary biomass ranging from 50 to 100 EJ by 2050, with roughly half being used for biofuels production (Gielen et al., 2002, 2003). Given a biomass conversion efficiency of about 50% (in energy terms), this allows for EJ biofuels production. This result assumes a global convergence of agricultural yields and global free trade of agricultural products, and it assumes a quite high CO 2 reduction incentive. Therefore the lower end of this range (25 EJ) will be used as an upper limit for the biofuels potential. HYDROGEN At this moment, hydrogen production from natural gas is the cheapest large-scale production option for this fuel. Large-scale centralized production units could be equipped with CO 2 capture, which 15

16 would result in a CO 2 -free transportation system. However, the transition to a hydrogen transportation system may imply a transition period with more costly hydrogen that is produced through electrolysis. On the long term, coal or nuclear energy could be used for hydrogen production with low or zero CO 2 emissions. The US FutureGen project is planned to operate a net 275 MW facility that produces both electricity and hydrogen from coal and sequesters 1 Mt of CO 2 per year. The project will cost 950 million US$ (3450 $/kwel). The plant is projected to be ready in 2012, and tests are planned till 2015 (DOE, 2004b). High temperature nuclear heat (above 850 ºC) can be used to drive a sulphur-iodine cycle for hydrogen production. The cost of this type of reactors could decrease to 5-10 $/GJ, provided very large scale systems can be used, and innovative nuclear reactor cost (Modular Helium Cooled Reactors MHR) can be reduced to 1000$/kW (excluding decommissioning and nuclear waste treatment cost) (Schulz, 2003). However, the S-I cycle will need further development. The same cycle could be driven by solar heat. Hydrogen could be used in internal combustion engines, but it is a fuel that is especially suited for high-efficiency fuel cells. However, at this moment the fuel cells are not yet ready for large-scale market introduction. Fuel cell cost need to be reduced from around 2000 $/kw to 50 $/kw, and the life span needs to be improved. Moreover better hydrogen on-board storage systems are needed (in terms of energy efficiency and/or volumetric density and weight). On the long term, hydrogen could play an important role, given its inherent supply security and CO 2 emission benefits. METHANOL AND DME FROM NATURAL GAS AND COAL Other fuels that are being discussed are methanol and DiMethylEther (DME). DME is non-toxic, contrary to methanol. Both fuels could be produced from a wide range of feedstocks, including coal, natural gas and biomass. Methanol production from natural gas is an established technology. However, the bulk of this methanol is used for chemicals. DME can be used as a fuel for power generation turbines, diesel engines, or as an LPG replacement in households. Current global DME production amounts to 0.15 Mt/yr. Its main use is as aerosol propellant for hair spray. Two coal-based DME plants are in operation in China, with a total capacity of 40 kt/yr. A rapid expansion of Chinese DME production is planned, to more than 1 Mt/yr (0.03 EJ/yr) in 2009 (Fleisch, 2004). Further gas based projects are planned and proposed in the Middle East. Current DME production takes place in two-steps. First methanol is produced from syngas. Next the methanol is catalytically dehydrated to DME. New production processes are under development 16

17 where DME is directly produced from syngas in a single step. Various process designs have been proposed for methanol/dme co-production, and for cogeneration of DME and electricity. Such designs circumvent the problem of recirculation of products because of incomplete conversion of feedstock into DME (Air Products, 2002; Ogawa et al., 2003). ELECTRICITY Hybrid electric vehicles (HEVs) have recently gained a lot of interest. These vehicles use a combustion engine to generate electricity. This electricity is used to drive an electric motor. The energy efficiency of this type of vehicles is up to 50% higher than for conventional ICEs. Especially in the case of urban drive cycles with a lot of stop-and-go traffic, the savings can be considerable. As these vehicles contain a battery, it would be possible to charge them with electricity from the grid 6 for short rides (so-called plug-in HEVs). As most trips are short distance, this would allow for a substantial part of the fuel being electricity, while not compromising the drive range. The share of fuel and electricity use will depend on the specific drive range. A mid-size plug-in HEV with a battery powered range of 35 km would cost $ 4000 to 6100 more (21 to 32%) and a plug-in HEV with a range of 100 km would cost $ 7400 to 10,300 more (given production volumes of 100,000 cars per year). The battery cost amount to $ 5,800 for a 100 km range, the remainder being additional cost for the hybrid system. This assumes $270/kWh 7 (75 $/MJ) (for 100 km), and 800 $ balance-of-plant cost for the battery stack. Cost would be similar for Nickel Metal Hydride and Lithium-ion batteries (EPRI, 2003). However, at the moment the deep cycle characteristics of the Lithium ion battery are not yet proven. Plug-in HEV passenger cars are not yet offered for sale. Their performance under road conditions needs to be tested. For the sake of this brief overview, this option has not been considered in more detail. 6 But they would require a battery with a much larger storage capacity. 7 In 2003, the cost amounted to 500 US$/kWh storage capacity. 17

18 SUPPLY COST AND SUPPLY SECURITY The introduction of alternative fuels depends on the cost compared to oil based transportation fuels. However, governments play an important role in the fuel price setting. In Europe more than two thirds of the cost for the consumer are government taxes. A variation of tax levels for different fuels can affect the cost-effectiveness considerably. Moreover the future oil price is uncertain. Much higher prices for gasoline and diesel may occur in case of fuel scarcity. The vehicle efficiency varies for different fuels. Diesel engines achieve about 20% higher efficiency than gasoline vehicles. Especially hydrogen fuelled fuel cell vehicles may achieve more than twice the fuel efficiency of internal combustion engines. However, if hybrid vehicles are introduced on a large scale, the fuel efficiency gap between hydrogen and other fuels will narrow. 18

19 Table 2: Overview of supply cost of alternative fuels (production + distribution + refuelling). Accuracy +/- 25%. With existing vehicle/fuel supply infrastructure Gasoline from crude oil imported from OPEC countries Gasoline CO 2 - EOR Gasoline nonconventional oil Feedstock US$/GJ 2005 Imported OPEC oil Indigenous oil resources Indigenous oil sands US$/GJ 2030 Comments US$/bbl crude US$/bbl crude Upgrading+delivery 5.5 US$/GJ US$/bbl crude US$/bbl crude Upgrading +delivery 5.5 US$/GJ US$/bbl crude US$/bbl crude Upgrading + delivery 5.5 US$/GJ 2005 cane sugar; 2030 lignocellulose Gas feedstock 0.5 US$/GJ Delivery 3.8 $/GJ Coal feedstock 0.5 US$/GJ Delivery 3.8 $/GJ Biomass feedstock 3 US$/GJ Delivery 3.8 $/GJ Ethanol Biomass Gasoline/diesel FT-synthesis Natural gas Gasoline/diesel FT-synthesis Coal 12.9 Gasoline/diesel FT-synthesis Biomass New vehicle/fuel supply infrastructure needed Gas feedstock 0.5 US$/GJ Methanol Natural gas 9.8 Delivery 3.8 $/GJ Gas feedstock 0.5 US$/GJ DME Natural gas 10.2 Delivery 3.8 $/GJ Gas 5 US$/GJ CNG Natural gas 10.0 Delivery 4.8 $/GJ Electricity 5 cents/kwh in Hydrogen Electricity cents/kwh in 2030 Hydrogen decentralized Natural gas Gas 5 US$/GJ Hydrogen Natural Gas 4 US$/GJ centralized gas/coal 15.0 or coal 1 US$/GJ Resource location Middle East US, Canada, North Sea Canada CSA, North America, Asia Middle East China, US, Australia CSA, North America, Asia Middle East Middle East North America, Europe, Japan North America, Europe, Japan North America, Europe, Japan North America, Europe, Japan Because of vehicle efficiency and vehicle cost differences, a comparison of fuel cost per unit of energy can be deceiving. For certain fuel types a number of engine systems can be used, with different efficiencies and a different status of development. The cost of different types of vehicles differ. Therefore life cycle costing is the only true measure. But future cost of e.g. fuel cell vehicles are highly uncertain. For the sake of this analysis, the life cycle cost are not elaborated in more detail. Any feedstock price is location and time dependent. Especially the future availability of cheap stranded gas depends on competing gas use, e.g. liquefaction (LNG) or new high-pressure pipelines. Given the increasing link of the gas price to the oil price, and dropping cost of gas liquefaction, transportation and re-gasification (about 2 US$/GJ), the price of stranded gas may gradually increase 19

20 from 0.5 to 1 $/GJ, and possibly even more. This would make gas based liquid fuels uneconomical. Also a lot of the stranded gas is in the Middle East. The development of low-cost gas based oil alternatives may not be in the interest of the countries that own both oil and gas reserves. With regard to biomass, any price depends on competing land use and progress in crop production technology. Table 2 suggests that all alternatives but FT-synfuels from biomass and hydrogen can achieve similar production cost as gasoline and diesel, provided the production facilities achieve sufficient economies of scale, and technological hurdles are taken. Especially CO 2 -EOR and non-conventional oil seem very attractive at the current oil price levels. A significant part of these resources are located outside the Middle East. As a consequence their development would add to the supply security. In conclusion, the supply security characteristics of alternative fuels are different than for conventional oil from the Middle East. Canadian oil sands and biofuels clearly enhance the supply security, if the mitigate the need for oil imports. For a large-scale transition to stranded gas, enhanced supply security is not a given fact. Coal, nuclear and renewable electricity based fuels can enhance the supply security, but each is fraught with specific problems. Coal based alternative fuels will only become a viable alternative if the CO 2 emissions in fuels processing can be reduced (i.e., if CCS is applied). Nuclear is fraught with waste and acceptance problems. The use of nuclear energy and renewable electricity would require the development of a hydrogen economy, unless better electricity storage systems are developed. The challenges for such development are both on the vehicle side and in the transition to an affordable hydrogen supply system. 3. CO 2 BALANCE OF ALTERNATIVE FUELS The CO 2 emissions of fuels can be split into emissions during use and upstream emissions. For oil fuels, the emissions during use are the most important ones. Hydrogen does not result in CO 2 emissions during use, and the emissions from biofuels such as ethanol are balanced by the CO 2 captured during biomass growth. The upstream emissions for many alternative fuels can be substantial. However, for large-scale production processes, CO 2 can be captured and stored underground. This can reduce upstream emissions by 85-95%. Depending on the primary fuel choice and the use of CCS, upstream emissions can vary substantially. 20

21 Table 3 provides an overview of the CO 2 emissions in the production and use of the various fuels. It is split into process emissions (in the manufacturing of the fuel, and in the production of the electricity that is needed for this manufacturing process) and the emissions during fuel use. Without CCS the emissions of most alternative fuels are higher than for refinery products, with the exception of ethanol. This can be explained by the higher upstream energy losses and thus emissions, compared to existing oil refineries. The gas based methanol, DME and CNG allow for some modest emission reductions. Hydrogen without CCS is only an option if electricity from nuclear or renewables is used, which results in high-cost hydrogen. If CCS is considered, the picture changes dramatically. Synfuels from gas and coal result in similar emissions as existing refinery fuels. Substantial emissions reductions are possible in case biomass and hydrogen from fossil fuels with CCS are introduced. In the case of biomass, even negative fuel chain emissions can be achieved: more CO 2 is removed from the atmosphere than there is emitted in the fuel chain. Table 3: Fuel chain CO 2 emissions, with and without CCS Process 8 Total Total with Use emissions CCS Index emissions w/o CCS CCS Index [kg CO 2/GJ] [kg CO 2/GJ] [kg CO 2/GJ] [kg CO 2/GJ] [kg CO 2/GJ] With existing vehicle/fuel supply infrastructure Gasoline from crude oil Gasoline CO2-EOR Gasoline non-conventional Ethanol (biomass) FT Gasoline/diesel (gas) FT Gasoline/diesel (coal) FT Gasoline/diesel (biomass) New vehicle/fuel supply infrastructure needed Methanol (gas) DME (gas) CNG (gas) Hydrogen (electricity) Hydrogen decentralized (gas) Hydrogen centralized (gas) Hydrogen centralized (coal) It will depend on the urgency of CO 2 emissions reduction which of these alternatives is viable. A growth of emissions per unit of energy seems undesirable. That means in many cases that CCS must be applied. In case a substantial emissions reduction in the fuel life cycle is aimed for, hydrogen and biofuels (with or without CCS) depending on the primary energy source pose the only viable alternative. 8 Excludes emissions from primary fuels mining and transportation 21

22 4. POTENTIAL OIL MARKET IMPACTS Many scenarios can be drawn with sufficient fuel supply without changes on the demand side. However, few of these meet all of the energy policy goals. For the back-of-the-envelope analysis presented here, it is assumed that between 30% and 60% of the transportation fuels in 2050 will be alternative fuels. Total transportation fuel demand in a business-as-usual scenario would be about 175 EJ/yr in 2050 (WBCSD, 2004). So between 55 and 105 EJ alternative fuels (or energy efficiency) would be needed. This implies between 70 and 125 EJ transportation fuels from conventional oil. This represents a range from a stabilisation of conventional oil production and use at 2000 levels, to an increase by two thirds. The developments till 2030 can be projected based on planned and proposed investment plans, as discussed in the WEO2004 (IEA, 2004a). However, the development beyond 2020 is uncertain. In this analysis it is assumed that additional environmental policies will be put into place to maximise biofuels and hydrogen use. Given the projections till 2030 and reasonable assumptions of annual expansion of production in the period , it is possible to meet fuel demand on the long term (2050) without changes on the demand side. Natural gas and natural gas based alternative fuels can be considered as backstop solution, in case conventional oil supply is lower than assumed in these scenarios. 125 [EJ/yr] Hydrogen Biofuels Natural gas FT+DME/methanol gas/coal HO/tar sands/bitumen/shale % AF 60% AF 60% AF+eff Figure 2: Meeting transportation fuel demand in 2050 in case of various supply scenarios. AF share of alternative fuels. Eff 25% additional efficiency gains. 9 Renewables, nuclear or natural gas based electricity production 22

23 In the calculations, the global average stock efficiency of cars increases by 22% between 2000 and It is assumed that demand growth for transportation services is the same in both scenarios. Only the efficiency for hydrogen fuelled vehicles is set twice as high as for other vehicles. However, further efficiency gains are feasible without a move to fuel cells. For example a switch to diesel and a switch to hybrids would both result in significant efficiency gains, even if the autonomous efficiency gains for gasoline ICEs are taken into account (figure 3). Fuel economy index [-] Gasoline ICE -26% Gasoline ICE -30% Gasoline Hybrid Diesel ICE -36% Diesel hybrid H2 FCV -46% Present stock Figure 3: Remaining efficiency potentials for light duty vehicles (global average) (WBCSD, 2004). Leftmost bar represents the stock average, other bars refer to new cars in Figure 2 shows the fuel demand in case of oil peaking in 2015, where the efficiency for the whole sector increases gradually by up to 25% in 2050 (i.e., a total efficiency gain of 41%, compared to 2000). These gains can be achieved through a combination of measures such as introduction of hybrid vehicles, light weighting and a switch to smaller cars, a switch from gasoline to diesel, better route planning, engine switch-off during stops, etc.. 25% should be considered as an optimistic estimate of efficiency potentials. Transportation fuel demand is lower in this scenario, and stabilizes around 120 EJ per year. As a consequence there is less need for alternative fuels. 23

24 The cost of demand side measures such as a switch to smaller cars is difficult to assess, and its costeffectiveness depends on the time preference of the car buyer. In case of hybrid vehicles, the additional costs are around 4000 USD. Given a 10% annuity, the annualised cost would amount to 400 USD per year. This would allow for 250 to 500 litres of fuel savings per year, which equals 0.6 to 1.2 tonnes of CO 2 per year. If the fuel is priced at the cost level (0.5 USD/l), the CO 2 saving would cost 125 to 460 USD per tonne of CO 2. However, higher fuel cost levels that may occur in case of scarcity could reduce the cost substantially. The resulting CO 2 emissions are shown in figure 4 for the two alternative fuel share cases, for the case with and without CCS, with and without additional efficiency gains. In all cases the emissions are higher than in This is especially a result of increased direct emissions (from vehicles). The future upstream emissions (in fuels production) will depend on the technology that is applied. They would rise substantially if there is no CCS. In case CCS is applied, the upstream emissions would rise till 2030, but they would decline in 2050, compared to 2000 levels. Note that the goal of 30 or 60% alternative fuels does not affect the CO 2 emissions substantially. This analysis provides a sobering picture of supply side emission reduction potentials. However, in case of oil peaking in 2015 in combination with CCS in fuels production and additional efficiency gains, the emissions in 2050 are almost back to the 2000 level. This result shows the need for both fuel switching and efficiency gains, in case supply security and CO 2 targets should be met. Note that fuel scarcity and CO 2 emission reduction work in this scenario in the same direction. [Gt CO2/yr] Upstream Direct %AF 60%AF 60%AF 30%AF 60%AF 60%AF CCS CCS CCS +25%eff +25%eff Figure 4: Direct and indirect emissions from the transportation sector in 2030 and

25 5. POLICY MODELLING ISSUES The preceding analysis shows that future development of alternative fuels is subject to a large number of uncertainties. Depending on energy policy targets (supply security and CO 2 targets), the outcome can look quite different. The most important uncertainties that policy makers should consider are: How large are the ultimately recoverable conventional oil resources; How much of this can actually be recovered, and at what cost; What are the supply security implications of increased dependence on conventional oil from the Middle East? How fast can the supply of various types of alternative fuels expand; What will be the future price of stranded gas; What will be the efficiency and cost characteristics of alternative fuels production; How much biomass is available for biofuels production; How fast will a market develop for hydrogen FCVs; These questions can not be answered conclusively. Scenario analysis, with varying sets of consistent assumptions, are the only way to deal with these uncertainties. In the ETP model analysis these topics will be further elaborated during the next months. 6. CONCLUSIONS It is likely that refinery oil products will dominate the transportation fuel market in the next three decades, but a substantial share of alternative fuels may be needed beyond 2030; Certain alternatives are ready for the market (non-conventional oil, GTL, CTL, LNG) but the planning time horizon for a significant expansion is at least 10 years. However, they do not provide significant CO 2 emission mitigation; Therefore, the combination of oil supply security and deep CO 2 emissions reduction poses a strategic energy policy challenge; The cost of all fuel alternatives considered in this paper, except hydrogen, is by 2030 comparable to oil. However, for fuels based on gas feedstock, availability of low-cost stranded gas is a precondition; Given growth constraints for all alternatives, a global mix of alternative fuels may emerge, which may differ by region. This is a difference with the current oil-based transportation system. It may affect the global organization of the energy industry; 25