Prospective Analysis of the Potential Non Conventional World Oil Supply: Tar Sands, Oil Shales and Non Conventional Liquid Fuels from Coal and Gas
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1 TECHNICAL REPORT SERIES Prospective Analysis of the Potential Non Conventional World Oil Supply: Tar Sands, Oil Shales and Non Conventional Liquid Fuels from Coal and Gas EUR EN Institute for Prospective Technological Studies
2 European Commission Joint Research Centre (DG JRC) Institute for Prospective Technological Studies Legal notice Neither the European Commission nor any person acting on behalf of the Commission is responsible for the use which might be made of the following information. European Communities, 2005 Reproduction is authorised provided the source is acknowledged.
3 Prospective Analysis of the Potential Non-conventional World Oil Supply: Tar Sands, Oil Shales and Non-conventional Liquid Fuels from Coal and Gas Institut Français du Pétrole Direction des Etudes Economiques Jean François Gruson Sébastien Gachadouat, Guy Maisonnier and Armelle Saniere December 2005 Technical Report EUR EN
4 European Commission Joint Research Centre (DG JRC) Institute for Prospective Technological Studies Legal notice Neither the European Commission nor any person acting on behalf of the Commission is responsible for the use which might be made of the following information. Technical Report EUR EN European Communities, 2005 Reproduction is authorised provided the source is acknowledged. Printed in Spain
5 Table of contents TABLE OF CONTENTS... 1 TABLE OF FIGURES... 3 PREFACE... 4 EXECUTIVE SUMMARY TAR SANDS AND EXTRA-HEAVY OILS EVALUATION OF RESOURCES IN PLACE AND RECOVERABILITY Tar sands Extra-heavy oils EXISTING, PAST AND FUTURE PROJECTS FOR COMMERCIAL EXPLOITATION Tar sands Extra-heavy oils KNOWN EXTRACTION AND UPGRADING TECHNOLOGIES, INVESTMENT AND OPERATING COSTS Extraction technologies Transportation technologies Upgrading technologies CO 2 EMISSIONS AND OTHER ENVIRONMENTAL ISSUES Atmospheric emissions Water use and conservation Tailings and by-products MAIN INPUTS FOR THE DATABASE AND MODEL MAIN REFERENCES OIL SHALE EVALUATION OF RESOURCES IN PLACE AND RECOVERABILITY WORLDWIDE PRODUCTION AND EXPLOITATION PROJECTS Worldwide oil shale and synthetic oil production Present and future production projects Past production projects KNOWN PRODUCTION TECHNOLOGIES AND THE PYROLYSIS PROCESS Surface pyrolysis In-situ pyrolysis Summary of pyrolysis process ENVIRONMENTAL ISSUES CO 2 emissions - from oil well to petrol tank Air quality Water quality Spent shale disposal MAIN INPUTS FOR THE DATABASE AND MODEL MAIN REFERENCES WORLD GTL PROSPECTS BACKGROUND TECHNICAL AND ECONOMIC BACKGROUND COUNTRIES WITH GTL POTENTIAL Analysis by country Analysis by field PROJECTS UNDER DEVELOPMENT, PLANNED OR ANNOUNCED END-MARKET TRENDS (DIESEL) GAS-TO-LIQUIDS AND CO International action on greenhouse gases Kyoto Protocol implementation
6 3.6.3 "Well-to-wheel" analysis Impact of Kyoto on GTL development CONCLUSION - GTL DEVELOPMENT POTENTIAL MAIN INPUTS FOR THE DATABASE AND MODEL MAIN REFERENCES COAL TO LIQUIDS EVALUATION OF WORLDWIDE COAL RESERVES KNOWN PRODUCTION TECHNOLOGIES, INVESTMENT AND OPERATING COSTS Carbonisation and pyrolysis Direct liquefaction Indirect liquefaction Underground gasification EXISTING PLANTS AND FUTURE PROJECTS Existing Plants Future projects CO 2 EMISSIONS MAIN INPUTS FOR THE DATABASE AND MODEL MAIN REFERENCES ANNEX I - OVERVIEW OF THE FT GTL PROCESS CHAIN / THE ELEMENTAL STEPS IN THE FT GTL CHAIN Syngas - first elemental step FT - second elemental step HCI - third elemental step / FT GTL PROJECT ALLIANCES / AREAS FOR FURTHER DEVELOPMENT AND STUDY ANNEX 2 NON-CONVENTIONAL FUEL SOURCES IN THE POLES MODEL
7 Table of figures Table 1. Worldwide bitumen resources in place and recoverability... 9 Table 2. Worldwide extra-heavy oil resources in place and recoverability Table 3. Canadian bitumen mining - ongoing projects Table 4. Canadian in-situ bitumen production - ongoing projects Table 5. Venezuela extra-heavy oil - ongoing integrated projects Table 6. Venezuelan tax regime for Orinoco extra-heavy oil projects Table 7. Summary of extraction technologies Table 8. Residual upgrading technologies and licensors Table 9. Worldwide oil contained in oil shale Table 10. Worldwide oil shale extraction Table 11. Australian Stuart Project - phased development Table 12. Australian Stuart Project - saleable products Table 13. Pyrolysis processes, including commercialisation stage Table 14. First step - countries with over 200 Bcm of proven reserves or four times the minimum for a b/d plant Table 15. Second step - GTL potential by country Table 16. GTL potential based on fields of over 50 Bcm Table 17. GTL potential based on fields of 50 to 100 Bcm, e.g b/d b/d Table 18. GTL potential based on fields of 100 to 200 Bcm, e.g b/d b/d Table 19. GTL potential based on fields of over 200 Bcm e.g. potential production of b/d 47 Table 20. Main GTL projects in Table 21. Possible GTL trend based on several sources Table 22. Worldwide proven coal reserves at end 2004 (million tonnes) Table 23. Worldwide coal reserves at end 1999 Proven amount in place (million tonnes) Table 24. Companies developing direct liquefaction technologies Table 25. Direct coal liquefaction - economics Table 26. Companies developing gasification technologies Table 27. Companies developing indirect liquefaction technologies Table 28. Indirect coal liquefaction - economics Table 29. Standard bituminous coal and crude oil
8 Preface One of the duties of the Energy and Climate Change Group at IPTS is the elaboration of analyses and policy making guidance reports in the field of energy resources, and its implications for the economy and environment. Recent events on crude oil markets are the manifestation of emerging tensions that may lead to a drastic mismatch between growing demand and shrinking pumping capacity. Oil price fluctuations obey both to short term perturbations due to market expectations and momentary asymmetric information, as well as long term trends that reflect the overall evolution of the crucial indicators like the reserve-to-production ratio, proven reserves and improvement in recovery factors. There are signs that conventional crude oil resources are approaching exhaustion, and the cut-off date is within the span of a few decades. Many alternative fuels to mitigate the resulting energy shortage should be considered. Some technological forecasts have considered technologies such as solar electricity, nuclear alternatives, or other which are not likely to be implemented in nearest future. However, there are technologies close to commercialisation or even already used, that have been abandoned as uncompetitive during the years of cheap crude oil. This report is devoted to the analysis of reserves and technologies for treatment of tar sands and oil shale, as well as conversion of relatively abundant fossil fuels gas and coal, to liquid fuels. They all constitute not only a future substitute for vanishing oil but a feasible alternative for this increasingly expensive energy. Their main advantage comparing to other options is that they could use already well developed infrastructure for oil treatment and products distribution. Having identified the importance of this emerging issue, IPTS launched a project aiming at characterise the economic potential of those non-conventional oil reserves. The Institut Francais du Pétrole (IFP), a well-know institution in the field of the economics of fossil fuel resources has carried out this analysis and elaborated the synthesis report presented hereafter. The report is published as background material to inform decision-makers and energy planners hoping it may help in the design of options to face security of energy supply problems. This report accompanies a software development aiming at the development of a new and detailed model representing the foreseen exploitation pattern of these resources. This modelling tool is conceived as an improvement of the POLES global energy model, and its characteristics will be described in a separate report. Antonio Soria Co-ordinator, Energy and Climate Change IPTS, DG JRC 4
9 Executive Summary Coal, petroleum and natural gas are the traditional fossil fuels whose direct use today accounts for most of the world's energy consumption. These fuels are rich in carbon and hydrogen. A relatively large amount of energy is stored in them and they have a high calorific value. As they are depleted, or their price increases, other fossil fuels can become more attractive for commercial exploitation. Crude oil has a major role amongst these fossil fuels. It is, of course, a limited resource whose fundamental importance is based on the fact that oil products account for more than 90% of energy consumption by the global transportation sector, not to mention their industrial applications in chemicals, manufacturing and construction. Estimates of undiscovered oil reserves range from 300 to 1,500 billion barrels (Bb), depending on the source. However, these numbers must be treated with caution, as they include economically recoverable reserves, which may increase as new technologies are introduced. About 77% of crude oil has already been discovered, and 30% of it used so far. Between 1860 and the first oil crisis in the 1970 s, 200 Bb of oil were used, since when oil production has roughly stabilized at Bb per year. Reserves are expected to become progressively scarcer, and the recent surge in prices reflects market expectations of this. Higher oil prices make the exploitation of non-conventional oil resources, such as heavy and extraheavy oils, tar sands and oil shales, more attractive. This study addresses the potential market for these products. Technologies also exist for obtaining liquid fuels from fossil fuels other than petroleum, e.g. coal and natural gas. These technologies are also examined in the study. Monitoring and estimates of coal and gas reserves are less of an issue for this study, since they are well covered by standard energy prospective analysis. The purpose of this study is rather to take a more general look at the technological options, assess their commercial viability compared with the other non-conventional liquid fuel options, and address the potential niche for each in the global energy market, with a particular focus on the role they could play in security of energy supply. The report goes on to outline the main characteristics of the commercial and experimental methods available for exploiting these non-conventional resources, discuss the technical characteristics in use at each exploitation site and provide comprehensive technical and economic data. Identified volumes in place of tar sands are estimated at between and Bb, the bulk of them in Canada, which has an estimated to Bb. Smaller volumes have been identified worldwide, mainly in Asia (270 Bb), Russia (260 Bb), Venezuela (230 Bb) and the US (60 Bb in Utah, Texas and California). Bitumen deposits would also seem to be present in Africa but the figures are contradictory and estimates of resources in place vary from 50 to 430 Bb. In Russia, very large resources are present in Eastern Siberia in the Lena-Tunguska basin. The available technologies allow 9-15% of these reserves to be recovered, but with advanced technologies the recovery rate could ultimately reach 30% (depending on the characteristics of the reservoirs). Some reserves are located at a shallow depth and can be exploited using mining technologies, whereas others can only be exploited with petroleum technologies. As regards extra-heavy oils, the United States Geological Survey (USGS) estimates worldwide resources to be around Bb. About 90% are located in Venezuela (1 200 Bb). Estimates are that 20% of Venezuelan resources in place are ultimately recoverable, i.e. some 240 Bb. Extra-heavy oil has also been identified in other countries, in particular Ecuador (5 Bb), Iran (8 Bb) and Italy (1.5 Bb). In Russia, small amounts have been identified in the Volga-Urals and North Caucasus-Mangyshlak basins, but the lack of accurate and up-to-date information precludes reliable estimates. 5
10 Technologies for extracting tar sands include direct mining (which tends to be the most economic method of extraction when the oil sands are close to the surface), with total costs estimated at between 9 and 12 $/b; in-situ cold heavy-oil production (CHOPS process); Steam Assisted Gravity Drainage (SAGD), and Cyclic Steam Stimulation (CSS). The costs of these technologies, applicable to different reservoir characteristics and yielding different recovery rates, range between 7 and 16 $/b. Processing heavy and light crude oils yields the same range of refined products but in very different proportions and qualities. Heavy oils produce much greater vacuum residues than lighter ones. Several processes exist to convert vacuum residues, either thermal, catalytic or both. An attractive route for exploiting heavy oil is gasification, which involves partial oxidation of the feed, liquid or solid to convert it into a synthesis gas in which the major components are H 2 and CO. Gasification is a clean, flexible technology already proven on coke or heavy crude. It is now receiving global interest due to the development of the integrated gasification combined cycle (IGCC), in which gasification can be used to process low-value refinery streams. Oil shales are sedimentary rocks containing a high proportion of seaweed organic matter. Since the transformation of this material was not complete, the shales are rich in kerogen, making them a potential source of energy. The kerogen can be converted into synthetic oil or gas by industrial processing. Identified oil shale volumes in place are estimated to be around billion tonnes. Different sources put their oil content at between and Bb. About 70% of these in-place resources are concentrated in the USA, in the Green River Formation, and 14% in Russia. The other main locations are Zaire (100 Bb), Brazil (82 Bb) and Italy (73 Bb). At present, about 69% of world oil shale production is used for electricity and heat generation, some 6% for cement production and 25%, mainly the higher-yield varieties, is upgraded into jet fuel, gasoline, light fuel, bitumen, coke, phenols and other products. Oil shale can be exploited in two ways: - direct combustion - oil shale is directly burnt to provide thermal energy or electricity; - pyrolysis - extracts the oil contained in the shale or transforms the organic matter into gas or ethylene components. These technologies are less mature than those for exploiting tar and oil, and none are yet commercially available. The in-situ conversion process (ICP) converts kerogen with high yields into high-quality oil and hydrocarbon gases. ICP significantly reduces (and in some case eliminates) the environmental impact of previous shale-oil recovery methods. Shell believes its technology could be profitable at 25 $/b, once steady-state production is reached. GTL (Gas to Liquids) is a generic technology cluster designed to convert natural gas into petroleum products (mainly diesel, kerosene, naphtha and waxes). Recent years have seen a real take-off in this industry, with the construction of many pilot plants. Successive developments have finally produced a technology that can be considered to be operational, although its technical and economic viability remains to be demonstrated on a large scale. Economically, conditions are favourable: - high crude oil prices, likely to remain well above $/b in future; - the (declared) unit cost of GTL technology has dropped sharply: from over $/b/d to between approx and $/b/d, with some operators targeting a figure under $/b/d. The profitability of these installations largely depends on the cost of gas, which must be around 0.5/1 $/Mbtu (5 to 10 $/b product equivalent) if a production cost lower than 20/25 $/b is to be attained. This represents a big difference from refining - unit investment is substantially lower (10/ $/b), giving scope for higher raw material costs (crude oil). 6
11 The largest share of GTL production is intended for the transport market in the form of very high-quality diesel fuel. Apart from diesel, FT plants also produce naphtha (petrochemical feedstock), kerosene and waxes. The outlook for GTL would be jeopardised only by technical or commercial problems with the first plants, scheduled to come online from Another factor is the CO 2 balance (throughout the chain), which is relatively unfavourable compared with conventional refining. This factor could impact negatively on the development of this system, or on costs, if CO 2 sequestration becomes mandatory. Finally, a depressed oil market, with prices under 25 $/b, would also hinder the development of these plants. Such prices, while occasionally conceivable for relatively short periods, now seem unlikely for many years to come. Liquid fuels have long been produced from coal via the generic Coal to Liquid (CTL) technology cluster. Being a relatively expensive technology, its deployment would depend on the price of the raw feedstocks (i.e. cheap coal vs expensive crude oil). With demand for oil products continuing to grow, and oil stocks becoming depleted, there will come a time when demand begins to exceed supply. Coal liquefaction is an alternative source, and is backed by large recoverable coal reserves globally. Indeed, these reserves are significantly larger than for other fossil fuels. Direct coal-liquefaction processes have been developed to obtain liquid fuels from solid coal. The technique basically consists of dissolving coal in an adequate solvent at high temperature and pressure, followed by hydrocracking of the mix with hydrogen gas (H 2 ) and catalyst. According to studies of market prospects, direct coal liquefaction investment costs are estimated to be about $ per daily barrel (bbl/d) in the US, for output of bbl/d of liquid fuels and with tonnes per day (t/d) of coal feed. The required threshold price of the liquid fuels would be around $35/bbl, or in the range $25-30/bbl on a crude-oil-equivalent basis. In emerging economies, the estimated capital cost of the first phase of a bbl/d direct coal-liquefaction plant is $800 million, and the required selling price of the liquid fuels is estimated to be $24/bbl, or $15-20/bbl on a crude-oil equivalent basis. For instance, lower labour and equipment costs in China would result in capital costs of about $45 000/bbl/d, compared to $60 000/bbl/d in the US. If these cost estimates prove accurate, the cost of fuel produced will be lower than the cost of imports, given the current high price of crude oil on world markets. Indirect liquefaction processes are based on a two-step approach. First, coal is gasified, then the syngas is converted into liquid fuel by means of a GTL Fischer-Tropsch (FT) process. One example of a commercialised process is South Africa's Sasol technology, with three operational plants producing gasoline, diesel fuel and a wide range of chemical feedstocks and waxes. The typical mixed output of the FT process is napthas (20-30%), kerosene (25-35%), diesel (35-45%) and fuel oils (0-5%). According to Sasol, indirect coal liquefaction investment costs are 1.5 to 2 times higher than for GTL, i.e. $ /bbl/d., and with low-cost coal operating costs may be comparable to GTL (which uses more expensive feedstock). A recent study quoted in this report puts capital costs for indirect coal liquefaction at $67 000/bbl/d for output of bbl/d of liquid fuels and 100 MW of power in the US, with t/d of coal feed. This would translate into a required selling price of the liquid fuels of approx. $40/bbl, or $29-34/bbl on a crude-oil-equivalent basis. The figures in this summary clearly indicate how close these technologies are to being economically viable. At the time of writing, international oil prices have been above $50/bbl for over a year, reaching peaks of $65/bbl (August 2005). At these price levels, most of the methods described in this report are commercially attractive and likely to play a role in future. The economic and environmental impact of their deployment needs to be addressed, as well as the implications for international energy markets and security of supply. As a standardised technical and economic analysis, this study provides the data needed to examine these issues. 7
12 1 Tar sands and extra-heavy oils Heavy crude, often the result of the bacterial oxidation of conventional oils inside the reservoir rock, has different physical and chemical properties, which are generally degraded: much higher viscosity, higher heavy metals and higher sulphur and nitrogen content than conventional crude. Heavy, extra-heavy oils and bitumen Density 20 API Heavy oils Extra-heavy oils 10 API Bitumen and tar sands < cp Viscosity > cp IFP/Economics Division/2004 Different categories of heavy crude are usually defined according to their density: - heavy oils, with an API degree of between 10 and 20; - extra-heavy oils and bitumen, with an API degree of less than 10. The difference between extra-heavy oils and natural bitumen is their in-situ viscosity: - extra-heavy oils have a viscosity below centipoise (cp), i.e. they flow under reservoir conditions; - natural bitumen, also called tar sands or oil sands, has a viscosity above cp; it does not flow under reservoir conditions. This section will concentrate on extra-heavy oils and tar sands. Their specific properties require specific, advanced technical solutions throughout the process of exploitation, from production to transport and refining; that is why they are called "non-conventional oil". 1.1 Evaluation of resources in place and recoverability Tar sands Identified in-place reserves of tar sands are estimated to be between and Bb, the bulk of them in Canada, which has an estimated to Bb. Smaller volumes have been identified worldwide, mainly in Asia (270 Bb), Russia (260 Bb), Venezuela (230 Bb) and USA (60 Bb in Utah, Texas and California). Bitumen deposits would also seem to be present in Africa but the figures are contradictory and estimates of resources in place vary from 50 to 430 Bb. In Russia, very large resources are present in Eastern Siberia in the Lena-Tunguska basin. Only the Olenek deposit has been studied in sufficient detail to permit an estimation of discovered bitumen in place. Another example is the Siligir deposit. Most of the other Russian deposits are in the Timan-Pechora and Volga-Urals basins. However these deposits are scattered and the recoverable volumes not large. Other deposits are located in the Tatar Republic and have been extensively studied. Recoverable volumes outside Canada are estimated at between 90 and 130 Bb. 8
13 Canada's bitumen resources are situated almost entirely within the province of Alberta, with only minor oil sand deposits found on Melville Island in Canada's Arctic Island region. Alberta's oil sand deposits, grouped by geology, geography and bitumen content, are the Peace River, Fort McMurray and Cold Lake Oil Sands Areas. The Alberta Energy & Utilities Board (AEUB) estimates the initial volumes-in-place to be Bb. The AEUB further estimates the ultimate volume in place - i.e. the volumes expected to be found by the time all exploratory and development activity has ceased - to be Bb. Of this amount: Bb are amenable to surface mining; they are located in the Fort McMurray Oil Sands Area; Bb are amenable to in-situ recovery or underground mining methods. According to the AEUB, current technologies can recover some 178 Bb of bitumen. With anticipated technologies, the ultimately recoverable volume could be 300 Bb. About 20% (35 Bb) of the recoverable resources of bitumen are located at a shallow depth and can be exploited using mining technologies. Exploiting the remaining 80% (140 Bb) will require the use of petroleum technologies. Worldwide bitumen resources in place and the recoverable volumes are summarised in the table below: Table 1. Worldwide bitumen resources in place and recoverability Country/area Bitumen in place Bb Recovery rate % Recoverable resources Bb Canada USA Venezuela Africa Romania Jordan Asia Russia TOTAL Extra-heavy oils According to the USGS, worldwide extra-heavy oil resources are estimated to be around Bb. About 90%, an estimated Bb, are in the Orinoco Belt in Venezuela. 20% of the resources in place in Venezuela are thought to be ultimately recoverable, i.e. about 240 Bb. With current technology and prices, recoverable volumes are estimated to be about 3% (36 Mb), according to the Energy Intelligence Group. Extra-heavy oil has also been identified in other countries, in particular Ecuador (5 Bb), Iran (8 Bb) and Italy (1.5 Bb). In Russia, small amounts have been identified in the Volga-Urals and North Caucasus-Mangyshlak basins, but the lack of accurate and up-to-date information precludes reliable estimates. Worldwide extra-heavy oil resources in place and recoverable volumes are summarised in the table below: 9
14 Table 2. Worldwide extra-heavy oil resources in place and recoverability Country/area Oil in place Bb Recoverable resources Bb Venezuela Peru Ecuador Colombia Cuba Mexico Latin America Iran Oman Middle East Russia n.d Azerbaijan n.d FSU n.d Italy Albania Europe China Asia TOTAL > Existing, past and future projects for commercial exploitation Tar sands Projects for bitumen exploitation are mainly located in Canada. The Alberta deposits are so concentrated that they are the only ones that are economically recoverable. Small amounts of bitumen are still produced for road materials and mastic, e.g. from the Trinidad Pitch Lake deposit. In the US, no deposits are being commercially exploited. The geological conditions of the Utah deposits have made recovery difficult and expensive. Similarly, the Texan deposits, mostly deep and relatively thin, have also proved difficult to recover. Since 1967, there has been production from the oil sands in the Western Canada Sedimentary Basin, in Athabasca. The first company to start mining production was Suncor in 1967, followed by Syncrude in The first production using in-situ methods started in the early 1980s, with the initial expansion driven by the high oil prices during those years. Major in-situ bitumen producers are Imperial Oil (an Exxon Mobil affiliate), Canadian Natural Resources Ltd (CNRL) and EnCana. Tar sand resources in Canada are developed in very small quantities. In fact, according to the AEUB, 80% of possible oil sand areas are still available for exploration and leasing. That means that only 36 Bb of reserves are covered by ongoing or future development projects. 20% of the recoverable resources of bitumen are located at a shallow depth and can be exploited using mining technologies, and 8% of those volumes are already being produced. The remaining 80% of recoverable resources can be extracted with in-situ technologies of these, only 1% are already being produced. 10
15 Mining production projects 20% of recoverable bitumen resources are located at a shallow depth (less than 100 m) in the Fort McMurray Oil Sands Area and can be exploited using mining technologies. This production method currently accounts for 53% of Canadian bitumen production i.e b/d in These projects are very capital-intensive, but on such a scale, the installation of an upgrading unit for the extracted bitumen is commercially viable. In all the projects, the bitumen is upgraded at the production site and sold in the form of synthetic crude oil (SCO), with an API degree of between 29 and 36 and sulphur content between 0.1 and 0.2%. This sector is currently dominated by two companies, Syncrude and Suncor, who are both significantly expanding their operations, to increase their bitumen output. Syncrude, which produced b/d in 2004, expects to double production in 2015 thanks to its "Syncrude 21" project. It will then be the leading company in the mining industry, well ahead of its rivals. Suncor, for its part, produced some b/d in 2004 using mining methods. With its ongoing Project Millennium, the company s output should reach b/d in Shell Canada, through Albian Sands Energy Inc., has also been producing oil sands by mining methods at Muskeg River since With the development of its Athabasca Oil Sands Project, Albian Sands Energy will become the second largest mining producer in In the Northern Lights project, there are large, high-quality coal deposits in the lease area that are also mineable at surface. In future, coal may be used for coal gasification, as a source of hydrogen for upgrading and for power generation. 4 other projects are under development. In 2015, they should all be up and running, with the total production of synthetic crude oil reaching some 1.8 Mb/d. Project Table 3. Canadian bitumen mining - ongoing projects Operator production production '000 b/d '000 b/d 2015 production '000 b/d Investment B Can$ Syncrude 21 Syncrude* Steepbank, Millenium, Voyager Suncor Athabasca Oil Sands Project (Muskeg River & Jackpine) Albian Sands Energy Inc** Horizon CNRL Fort Hills PetroCanada Northern Lights Synenco Kearl Imperial Oil to 8 TOTAL * Syncrude ownership: Canadian Oil Sands Trust (36.74%), Imperial Oil (25%), PetroCanada (12%), ConocoPhilips (9.03%), Nexen (7.23%), Mocal (5%), Murphy Oil (5%). ** Albian Sands Energy Inc. was created to operate Muskeg River on behalf of its joint venture owners: Shell (60%), Chevron (20%) and Western Oil Sands (20%). In-situ production projects 80% of recoverable bitumen resources are located at a greater depth and must be exploited using in-situ technologies (i.e. recovery by petroleum methods). Some twenty projects, either currently underway or being studied, are expected to be set up in coming years. In 2004, in-situ production of bitumen in Canada was about b/d. By 2015, this could reach Mb/d. The biggest current project is Imperial Oil s Cold Lake operation, which produced b/d of bitumen in It should remain the biggest into
16 In-situ production projects are generally on a smaller scale than mining projects and cannot accommodate the cost of a dedicated upgrader. In almost all such projects, the extra-heavy oil is blended with a lighter, less viscous hydrocarbon (diluent) and sold as bitumen blend (BB), with an API degree of 21 and sulphur content between 2 and 4%. Diluent typically constitutes 24-50% of the bitumen blend. Only two projects include on-site upgrading, producing SCO (Synthetic Crude oil) instead of bitumen blend: Firebag (Suncor) and Long Lake (Nexen/OPTI). Project Table 4. Canadian in-situ bitumen production - ongoing projects Operator production production production '000 b/d '000 b/d '000 b/d Investment B Can$ Fort MacMurray In-situ projects Kirby CNRL Surmont ConocoPhilips Joslyn Deer Creek En Jackfish Devon Christina Lake EnCana Hangingstone JACOS* Long Lake Nexen / OPTI MacKay River PetroCanada Meadow Creek PetroCanada Lewis PetroCanada Firebag Suncor Cold Lake oil sands In-situ projects Orion Black Rock Venture Primerose/Wolf Lake CNRL Foster Creek EnCana Sunrise Husky Energy Tucker Lake Husky Energy Cold Lake Imperial Oil Peace River oil sands In-situ projects > 0.83 Seal Black Rock Venture n.d. Peace River Shell TOTAL *JACOS: Japan Canadian Oil Sands All of these in-situ projects are using or intend to use steam-injection methods to recover the bitumen; and almost all of them are using or intend to use natural gas as a source of energy to produce steam. The cost of supplying water and gas to bitumen production regions is becoming an issue, and the pressure on the gas market is set to become even greater with all the projects planned. To reduce their gas-dependency, some companies are starting to use other feeds: - in its Firebag plant, Suncor has added the capability to burn diesel fuel instead of natural gas to produce steam. The company is a net producer of both and will therefore choose to use the commodity with the lowest market value. - Deer Creek s Joslyn Creek facilities were planned to include a small steam generator to test the feasibility of using bitumen instead of natural gas as a fuel source. - the Nexen/OPTI Long Lake project is expected to employ its proprietary gasification technology to create synthetic fuel gas and hydrogen from the low-value, heaviest portion of the bitumen barrel. This process will more or less eliminate the need to purchase natural gas. 12
17 To optimise energy use and reduce their operating costs, other companies have installed heat and power (CHP) plants on their production sites: combined - PetroCanada has built a CHP plant on the MacKay River site operated by TransCanada Pipelines. On Meadow Creek, the company intends to install a CHP facility too. - Imperial Oil has installed a 170 MW CHP facility at its Cold Lake project. It expects to use about 60% of the power and will make the surplus available to the Alberta Power Pool. - Suncor is considering a CHP plant for stages 2 to 4 of its Firebag project. All except 3 of the projects in the table above use Steam Assisted Gravity Drainage (SAGD) to recover the oil (see section "Extraction technologies" for details): - CNRL on Primerose/Wolf Lake and Shell on Peace River use a combination of CSS and SAGD. - Imperial Oil on Cold Lake uses CSS. There are two other projects in operation testing new technologies (see section "Extraction technologies" for details): - Petrobank s Whitesands pilot project will test Toe-to-Heel Air Injection technology. Production is scheduled to begin towards end-2004 and last about 5 years. - The Devon Canada Corporation is leading a consortium conducting field trials to develop and test vapour extraction (VAPEX). Operations began in 2003 and are expected to continue into Altogether, more than 25 Canadian tar sand and bitumen exploitation projects have been or are about to be developed. If all are implemented, they will be producing 2.05 Mb/d of synthetic crude and 1.06 Mb/d of bitumen blend by 2015, increasing 2004 Canadian heavy oil and bitumen production by a factor of 3.4. Today, most of this production is exported to the USA, but deals are currently being negotiated to build pipelines from Alberta to deep-water ports on the British Columbia Coast (Prince Rupert or Kitimat), for tanker shipment to Chinese refineries. Enbridge and Terasen, Canada's dominant crude pipeline companies, are each working on projects to supply the Asian market: - Enbridge s Gateway pipeline, scheduled to start in 2010, is designed to carry b/d of synthetic crude from Edmonton to the British Columbia coast. PetroChina signed an agreement with Enbridge to receive b/d, making it the anchor tenant for the C$2.5 Bn pipeline. Enbridge also hopes to ship b/d to markets in California and b/d to other customers in China, Japan or South Korea. - Terasen claims to have support from Asian interests, including the Chinese, for its plans to build a parallel b/d crude pipeline. 13
18 1.2.2 Extra-heavy oils Projects to extract extra-heavy oil are in operation in Venezuela, in the Orinoco Belt. No such projects are reported in Russia. The Orinoco Belt is the largest extra-heavy oil deposit in the world, with an estimated Bb of oil in place. Exploration in the Orinoco Belt began in 1920 but with disappointing results: the oil discovered was too heavy for commercialisation given the available technologies and economic conditions. In 1930, 45 wells were drilled; however, for the same reasons, the area was abandoned once more. A third attempt was made in , which resulted in up to b/d of heavy oil going into production. Finally in the late 1960s and 1970s the Ministry of Energy and Mines (MEM) conducted an intensive exploration program, drilling 116 wells. Following the nationalisation of the Venezuelan oil industry, the MEM handed over the Orinoco oil belt to PDVSA to carry out a more detailed exploration. It was at this juncture that PDVSA divided the km 2 area into the four sections that exist today, assigning one to each of its subsidiaries (from west to east): Machete area to Corpoven, Zuata area to Maraven, Hamaca area to Meneven and Cerro Negro area to Lagoven. Between 1979 and 1983 the company drilled around 662 exploratory wells. Extra-heavy oils are liquid at reservoir conditions, but above ground, at normal temperature and atmospheric pressure, they cease to flow and transporting them is an issue. There are four options for transporting extra-heavy oil by pipeline: heating, blending, mixing with water or mixing with a diluent. As the latter is most economical it is this option that is most widely used today, especially by the four joint ventures (see below). The four joint ventures ( strategic associations ) exploiting the Orinoco Belt In the last ten years, joint ventures involving major international oil companies have proposed or studied integrated projects to develop and exploit extra-heavy oil resources in the Orinoco Belt. Given the huge volumes of recoverable reserves, these joint ventures are contracted for 35 years, and four extra-heavy oil projects are currently underway. In all of these the heavy crude is extracted by cold production and transported by pipeline via dilution to an upgrader on the Coast at San Jose. There, the crude is upgraded to a greater or lesser degree, depending on the project (see table below): in the Sincor and Hamaca projects, extra-heavy crude is upgraded to a API crude which can then be exported and used as feed in common refineries. In the Petrozuata and Cerro Negro projects, the crude is only partially upgraded and then exported to specific U.S. refineries dedicated to the upgrading of heavy oil. The upgrader produces upgraded crude, which is exported, as well as coke and sulphur (also exported), and recovers the diluent that was added upstream. This is then send back to the production plant (about 200 km away) in a dedicated pipeline, to be reused for the same purpose. Recycling the diluent reduces operating costs. However, investment costs are higher, as a return pipeline has to be constructed. Cold production is the cheapest and the most environmentally-friendly method. Its disadvantage is that it gives the lowest recovery rate (5 to 10%), but the oil in place is so huge that the reserves are still very large. Concerning investment costs, in projects with deep conversion of extra-heavy oil, one third of the investment is on the upstream side of the project and the remainder on the downstream side. The 4 projects are today producing at maximum rate - total output of synthetic crude is close to b/d. 14
19 Table 5. Project partners Sincor Total - 47% PDVSA - 38% Statoil - 15% Petrozuata ConocoPhillips % PDVSA % Cerro Negro ExxonMobil % PDVSA % VebaOel % Hamaca ConocoPhillips - 40% PDVSA - 30% Chevron - 30% Venezuela extra-heavy oil - ongoing integrated projects Reserves Investment Gb Synthetic crude production b/d Synthetic crude API US G$ Productions tart TOTAL The four ongoing projects have been given special tax advantages, with a royalty rate of 1% compared with 16.66% or even 30% elsewhere. In 2001, Caracas decided unilaterally to raise the royalty rate for future extra-heavy oil projects to 16.66%. This new law has been in force since The fiscal impact of this measure is about 1 $/b and in today's high oil-price environment it has not undermined the profitability of the projects. In fact, according to the operators, the current production cost of synthetic crude is less than 10 $/b. In 2005, a new reform was proposed by Petroleum Minister Rafael Ramirez, seeking to increase the tax rate from 34% to 50%. To enter into force, this proposal must be passed by the Venezuelan Parliament. Table 6. Venezuelan tax regime for Orinoco extra-heavy oil projects Initial conditions (before 2001 law 2005 reform (proposed) 2004) Royalty rate 1% 16.6% 16.6% Tax rate 34% 34% 50% Another point to note is that synthetic crude produced from heavy oil is considered to be refined oil and is not, therefore, subject to OPEC quotas, unlike Venezuela s conventional oil production. Future development of Orinoco Belt In early 2005, four international oil companies were showing interest in the extra-heavy oil of the Orinoco Belt and it is possible that new projects will be launched in the near future: - Total has discussed an extension of the Sincor project with the Venezuelan government. The company intends to produce with thermal methods instead of cold production, to increase recovery rates. - Shell has held negotiations with PdVSA on forming a joint venture to exploit extra-heavy oil in the Orinoco Belt. The proposal was to use proprietary Shell technology, including solvent injection and in-situ refining. The recovery rate is claimed to be more than 20%. The contract should be signed towards end finally, in April 2005, Chevron and Repsol-YPF signed a memorandum of understanding on the exploitation of a new block in the Orinoco Belt. The agreement provides for the construction of a new pipeline, the conversion of extra-heavy oil into synthetic crude and even the construction of a refinery. 15
20 Orimulsion Orimulsion is a branded product that is used as a boiler fuel. It is an emulsion made up of approximately 70% extra-heavy oil, 30% water, and less than 1% surfactant to stabilise the emulsion. Although the original objective of mixing extra-heavy oil with water was to solve a transport problem, Intevep's research revealed that this mixture could be used as a fuel in power stations, in competition with residual fuel oil and coal. Orimulsion has been in commercial use since 1991 and customers exist in Denmark, Italy, Germany, Finland, Lithuania, Canada, Japan, the UK and China. Bitor, a subsidiary of PdVSA, manages the processing, shipping and marketing of Orimulsion. It operates one Orimulsion plant in Cerro Negro with a capacity of 5.2 million metric tons per year. The future of Orimulsion production, however, is unclear. In September 2003, PDVSA announced it was dissolving Bitor into PDVSA's Eastern Operating Division and would not be expanding production of Orimulsion. PDVSA's decision was based on economics: the company said that at today's high oil prices, it could make more profit by selling fuel oil than Orimulsion. PDVSA sells Orimulsion at less than US$4 a barrel, plus 1% royalty, whereas the basic product could instead be sold with conventional blends or processed in Venezuela's four heavy crude upgrade units and sold at over US$17/b. Consequently, crude will no longer be used for manufacturing Orimulsion but will be blended or upgraded for export. PDVSA also announced that it intended to honour Bitor s outstanding long-term contracts with utilities but would not sign any new Orimulsion contracts or carry through with contracts that were under negotiation. PDVSA's plan to stop Orimulsion production has met with an outcry from foreign power companies, including Canada's NB Power and Italy's Enel, and both companies have taken legal action against PDVSA. NB Power is suing PDVSA for US$2 billion for breaking a 20-year agreement to supply Orimulsion to its Coleson Cove plant, while an international arbitration court recently accepted a request against PDVSA from Enel for US$200 million. In December 2001, Orifuels Sinoven, S.A. (Sinovensa) was created jointly by China National Petroleum Corporation (CNPC) (40%), PetroChina Fuel Oil Company (30%) and PDVSA (through Bitor) (30%). The partners invested $330 million to develop blocks producing 6.5 Mt/year of Orimulsion by the end of Construction on the Sinovensa project began in April On November 2000, CNPC began constructing China's first Orimulsion-fired power plant in Zanjiang city, Guandon Province. 1.3 Known extraction and upgrading technologies, investment and operating costs Extraction technologies Due to their extremely high viscosity under reservoir conditions, heavy oils and bitumen have very low mobility and ability to flow through porous media. This makes primary in-situ production of these oils very difficult and the recovery rate generally low, less than 10%. Most reservoirs produce with enhanced recovery methods, which allow a higher recovery rate. Most extraction methods are thermal, to reduce the oil viscosity, with steam injection the most common. Others technologies have been proposed, e.g. injection of a diluent (lighter hydrocarbon) or additives (polymer). Horizontal drilling, as introduced in the mid-80s in Canada by the Institut Français du Pétrole (IFP) and Elf Aquitaine, has the greatest impact on unconventional oil production and is currently used in all recovery methods, both primary and enhanced. 16
21 Mining Mining tends to be the most economic method of extraction when oil sands are close to the surface (less than 100 metres). Today this technology is only used for Canadian bitumen extraction. First the overburden is removed, then the oil sand is stripped using diggers and shovels. It is then transported to crushers where the ore is sized before the bitumen is extracted. Using cyclo-feeders and froth extraction, the bitumen is separated from the sand and water. The bitumen slurry is then piped to an upgrader where it can be processed into Synthetic Crude Oil (SCO), a high-quality, marketable product. Large scale mining operations allow operators to produce large volumes of SCO over a long period of time. Early total costs (operating expenses, capital expenditure, taxes and royalties) are estimated to have been 35$/b (cf National Energy Board) or more. Substantial cost reductions have been achieved through continual process improvement, but more dramatically through two major innovations in the 1990s. First, there was a move towards replacing the draglines and bucketwheel reclaimers with more flexible, robust and energy efficient trucks and power shovels. Second, hydrotransport systems were introduced to replace the conveyor belts used to transport oil sands to the processing plant. Currently, much attention is being focussed on maintaining stable production by minimising unplanned maintenance, which can significantly reduce production capabilities and increase operating costs. Presently there are no productive oil sand mining and extraction projects that do not include an on-site upgrader. Capital expenditure for ongoing projects varies from 3.5 to 4 $/b and operating expenses from 14 to 16. If we consider only extraction by mining methods, total costs can be estimated to be in the range 9 to 12 $/b. Integrated mining projects use natural gas to produce heat energy and electric power and as a source of hydrogen for hydrotreating during the upgrading process. The required purchase of natural gas is substantial, at approximately 0.75 Mscf per barrel of SCO produced. A 15% change in the price of natural gas results in a change of about 0.5 $/b in SCO cost. In-situ cold production Cold Heavy Oil Production with Sands (CHOPS) involves the intentional co-production of sand with oil, as it has become apparent that the exclusion of sand results in uneconomic production rates. The main conditions for successful CHOPS are: continuous sand failure (unconsolidated sands), active foamy oil mechanism (sufficient gas in solution), no free water zones in the reservoir and the use of progressive cavity pumps. "Foamy oil" occurs when gas in the oil expands, giving it a foamy aspect as the bubbles are trapped by the oil this happens with solution gas-drive, and enhances recovery. The CHOPS process produces large volumes of sands and other types of fluid waste. Managing this waste is one of the major components of operating costs; therefore, successful minimization of disposal-related costs is critical to overall project economics. Low capital investment and lower operating costs, because steam generation is not required, generally makes cold production more profitable than thermal methods. In fact, costs for cold production are estimated at between 7 and 11 $/b. The drawback is the recovery rate, which is very low, between 5 and 10%. For extra-heavy oils in Venezuela, horizontal wells are used to achieve a comparable production rate to the CHOPS process but without producing sand on the same scale. Generally, lower viscosity is associated with lower rates of sand production. In such cases, the dominant recovery mechanism is foamy oil rather than sand production. 17
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