7/30/2019 Eur 22168 En

1/81

Institute forProspectiveTechnological Studies

EUR 22168 EN

T E C H N I C A L R E P O R T S E R I E S

Prospective Analysis of the Potential

Non Conventional World Oil Supply:Tar Sands, Oil Shales and Non

Conventional Liquid Fuels from

Coal and Gas

7/30/2019 Eur 22168 En

2/81

European Commission

Joint Research Centre (DG JRC)

Institute for Prospective Technological Studies

http://www.jrc.es

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.

7/30/2019 Eur 22168 En

3/81

Prospective Analysis of the Potential

Non-conventional World Oil Supply:

Tar Sands, Oil Shales and Non-conventional LiquidFuels from Coal and Gas

Institut Franais du Ptrole

Direction des Etudes Economiques

Jean Franois Gruson

Sbastien Gachadouat, Guy Maisonnier and Armelle Saniere

December 2005

Technical Report EUR 22168 EN

7/30/2019 Eur 22168 En

4/81

European Commission

Joint Research Centre (DG JRC)

Institute for Prospective Technological Studies

http://www.jrc.es

Legal notice

Neither the European Commission nor any person acting on behalf of the Commission is responsible for theuse which might be made of the following information.

Technical Report EUR 22168 EN

European Communities, 2005

Reproduction is authorised provided the source is acknowledged.

Printed in Spain

7/30/2019 Eur 22168 En

5/81

1

Table of contents

TABLE OF CONTENTS...................................................................................................................................... 1

TABLE OF FIGURES..........................................................................................................................................3

PREFACE..............................................................................................................................................................4

EXECUTIVE SUMMARY ...................................................................................................................................5

1 TAR SANDS AND EXTRA-HEAVY OILS ....................................................................................................8

1.1EVALUATION OF RESOURCES IN PLACE AND RECOVERABILITY ...................................................................... 81.1.1 Tar sands............................................................................................................................................... 81.1.2 Extra-heavy oils..................................................................................................................................... 9

1.2EXISTING,PAST AND FUTURE PROJECTS FOR COMMERCIAL EXPLOITATION.................................................. 101.2.1 Tar sands............................................................................................................................................. 10

1.2.2 Extra-heavy oils................................................................................................................................... 141.3KNOWN EXTRACTION AND UPGRADING TECHNOLOGIES, INVESTMENT AND OPERATING COSTS ...................16

1.3.1 Extraction technologies....................................................................................................................... 161.3.2 Transportation technologies................................................................................................................ 201.3.3 Upgrading technologies...................................................................................................................... 21

1.4CO2EMISSIONS AND OTHER ENVIRONMENTAL ISSUES ................................................................................. 231.4.1 Atmospheric emissions........................................................................................................................ 231.4.2 Water use and conservation................................................................................................................ 241.4.3 Tailings and by-products..................................................................................................................... 25

1.5MAIN INPUTS FOR THE DATABASE AND MODEL ............................................................................................ 261.6MAIN REFERENCES...................................................................................................................................... 26

2 OIL SHALE......................................................................................................................................................28

2.1EVALUATION OF RESOURCES IN PLACE AND RECOVERABILITY .................................................................... 282.2WORLDWIDE PRODUCTION AND EXPLOITATION PROJECTS........................................................................... 30

2.2.1 Worldwide oil shale and synthetic oil production............................................................................... 302.2.2 Present and future production projects............................................................................................... 302.2.3 Past production projects..................................................................................................................... 33

2.3KNOWN PRODUCTION TECHNOLOGIES AND THE PYROLYSIS PROCESS.......................................................... 352.3.1 Surface pyrolysis................................................................................................................................. 352.3.2 In-situ pyrolysis................................................................................................................................... 372.3.3 Summary of pyrolysis process............................................................................................................. 38

2.4ENVIRONMENTAL ISSUES............................................................................................................................. 382.4.1 CO2 emissions - from oil well to petrol tank........................................................................................ 382.4.2 Air quality............................................................................................................................................ 382.4.3 Water quality....................................................................................................................................... 392.4.4 Spent shale disposal ............................................................................................................................ 39

2.5MAIN INPUTS FOR THE DATABASE AND MODEL ............................................................................................ 402.6MAIN REFERENCES...................................................................................................................................... 40

3 WORLD GTL PROSPECTS.......................................................................................................................... 41

3.1.BACKGROUND ............................................................................................................................................ 413.2TECHNICAL AND ECONOMIC BACKGROUND ................................................................................................. 413.3COUNTRIES WITH GTL POTENTIAL .............................................................................................................. 42

3.3.1 Analysis by country ............................................................................................................................. 423.3.2 Analysis by field.................................................................................................................................. 46

3.4PROJECTS UNDER DEVELOPMENT,PLANNED OR ANNOUNCED...................................................................... 483.5END-MARKET TRENDS (DIESEL)................................................................................................................... 503.6GAS-TO-LIQUIDS AND CO2.......................................................................................................................... 50

3.6.1 International action on greenhouse gases........................................................................................... 503.6.2 Kyoto Protocol implementation........................................................................................................... 51

7/30/2019 Eur 22168 En

6/81

2

3.6.3 "Well-to-wheel" analysis..................................................................................................................... 513.6.4 Impact of Kyoto on GTL development................................................................................................. 53

3.7CONCLUSION -GTL DEVELOPMENT POTENTIAL .......................................................................................... 543.8MAIN INPUTS FOR THE DATABASE AND MODEL ............................................................................................ 543.9MAIN REFERENCES...................................................................................................................................... 56

4 COAL TO LIQUIDS ....................................................................................................................................... 57

4.1EVALUATION OF WORLDWIDE COAL RESERVES ........................................................................................... 574.2KNOWN PRODUCTION TECHNOLOGIES, INVESTMENT AND OPERATING COSTS .............................................. 60

4.2.1 Carbonisation and pyrolysis................................................................................................................ 614.2.2 Direct liquefaction............................................................................................................................... 624.2.3 Indirect liquefaction............................................................................................................................ 644.2.4 Underground gasification................................................................................................................... 66

4.3EXISTING PLANTS AND FUTURE PROJECTS.................................................................................................... 684.3.1 Existing Plants..................................................................................................................................... 684.3.2 Future projects.................................................................................................................................... 68

4.4CO2EMISSIONS............................................................................................................................................ 694.5MAIN INPUTS FOR THE DATABASE AND MODEL ............................................................................................ 704.6MAIN REFERENCES...................................................................................................................................... 71

ANNEX I - OVERVIEW OF THE FT GTL PROCESS CHAIN...................................................................72

1/THEELEMENTAL STEPS IN THEFTGTLCHAIN ............................................................................................ 721.1 Syngas - first elemental step................................................................................................................... 721.2 FT - second elemental step..................................................................................................................... 731.3 HCI - third elemental step...................................................................................................................... 73

2/FTGTLPROJECT ALLIANCES ....................................................................................................................... 743/AREAS FOR FURTHER DEVELOPMENT AND STUDY ........................................................................................ 75

ANNEX 2 NON-CONVENTIONAL FUEL SOURCES IN THE POLES MODEL ..................................76

7/30/2019 Eur 22168 En

7/81

3

Table of figures

Table 1. Worldwide bitumen resources in place and recoverability ................................................. 9Table 2. Worldwide extra-heavy oil resources in place and recoverability.....................................10Table 3. Canadian bitumen mining - ongoing projects................................................................... 11Table 4. Canadian in-situ bitumen production - ongoing projects.............................................. 12Table 5. Venezuela extra-heavy oil - ongoing integrated projects.................................................. 15Table 6. Venezuelan tax regime for Orinoco extra-heavy oil projects............................................ 15Table 7. Summary of extraction technologies................................................................................. 20Table 8. Residual upgrading technologies and licensors................................................................. 23Table 9. Worldwide oil contained in oil shale................................................................................. 29Table 10. Worldwide oil shale extraction...................................................................................... 30Table 11. Australian Stuart Project - phased development............................................................32Table 12. Australian Stuart Project - saleable products................................................................. 32Table 13. Pyrolysis processes, including commercialisation stage............................................... 38Table 14. First step - countries with over 200 Bcm of proven reserves or four times the minimum

for a 20 000 b/d plant....................................................................................................................44Table 15. Second step - GTL potential by country........................................................................45Table 16. GTL potential based on fields of over 50 Bcm............................................................. 46Table 17. GTL potential based on fields of 50 to 100 Bcm, e.g. 25 000 b/d - 50 000 b/d............ 47Table 18. GTL potential based on fields of 100 to 200 Bcm, e.g. 50 000 b/d - 100 000 b/d........47Table 19. GTL potential based on fields of over 200 Bcm e.g. potential production of 100 000 b/d

47Table 20. Main GTL projects in 2005...........................................................................................49Table 21. Possible GTL trend based on several sources............................................................... 54Table 22.

Worldwide proven coal reserves at end 2004 (million tonnes)..................................... 58

Table 23. Worldwide coal reserves at end 1999 Proven amount in place (million tonnes) ....... 60Table 24. Companies developing direct liquefaction technologies...............................................63Table 25. Direct coal liquefaction - economics............................................................................. 64Table 26. Companies developing gasification technologies.......................................................... 65Table 27. Companies developing indirect liquefaction technologies............................................ 65Table 28. Indirect coal liquefaction - economics.......................................................................... 66Table 29. Standard bituminous coal and crude oil ........................................................................ 70

7/30/2019 Eur 22168 En

8/81

4

PrefaceOne of the duties of the Energy and Climate Change Group at IPTS is the elaboration of analyses andpolicy making guidance reports in the field of energy resources, and its implications for the economyand environment.

Recent events on crude oil markets are the manifestation of emerging tensions that may lead to adrastic mismatch between growing demand and shrinking pumping capacity. Oil price fluctuationsobey both to short term perturbations due to market expectations and momentary asymmetricinformation, as well as long term trends that reflect the overall evolution of the crucial indicators likethe 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 dateis within the span of a few decades. Many alternative fuels to mitigate the resulting energy shortageshould be considered. Some technological forecasts have considered technologies such as solarelectricity, 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 analysisof reserves and technologies for treatment of tar sands and oil shale, as well as conversion of relativelyabundant fossil fuels gas and coal, to liquid fuels. They all constitute not only a future substitute forvanishing oil but a feasible alternative for this increasingly expensive energy. Their main advantagecomparing to other options is that they could use already well developed infrastructure for oiltreatment and products distribution.

Having identified the importance of this emerging issue, IPTS launched a project aiming atcharacterise the economic potential of those non-conventional oil reserves. The Institut Francais duPtrole (IFP), a well-know institution in the field of the economics of fossil fuel resources has carriedout this analysis and elaborated the synthesis report presented hereafter. The report is published asbackground material to inform decision-makers and energy planners hoping it may help in the designof options to face security of energy supply problems.

This report accompanies a software development aiming at the development of a new and detailedmodel representing the foreseen exploitation pattern of these resources. This modelling tool isconceived as an improvement of the POLES global energy model, and its characteristics will bedescribed in a separate report.

Antonio SoriaCo-ordinator, Energy and Climate Change

IPTS, DG JRC

7/30/2019 Eur 22168 En

9/81

5

Executive Summary

Coal, petroleum and natural gas are the traditional fossil fuels whose direct use today accounts formost 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, ortheir 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 whosefundamental importance is based on the fact that oil products account for more than 90% of energyconsumption by the global transportation sector, not to mention their industrial applications inchemicals, manufacturing and construction. Estimates of undiscovered oil reserves range from 300 to1,500 billion barrels (Bb), depending on the source. However, these numbers must be treated withcaution, as they include economically recoverable reserves, which may increase as new technologiesare 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 1970s, 200 Bb of oil were used, since when oil productionhas roughly stabilized at 20-25 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 extra-heavy oils, tar sands and oil shales, more attractive. This study addresses the potential market for theseproducts. 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 ofcoal and gas reserves are less of an issue for this study, since they are well covered by standard energyprospective analysis. The purpose of this study is rather to take a more general look at thetechnological options, assess their commercial viability compared with the other non-conventionalliquid fuel options, and address the potential niche for each in the global energy market, with aparticular 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 methodsavailable for exploiting these non-conventional resources, discuss the technical characteristics in use ateach exploitation site and provide comprehensive technical and economic data.

Identified volumes in place of tar sands are estimated at between 2 200 and 3 700 Bb, the bulk ofthem in Canada, which has an estimated 1 600 to 2 500 Bb. Smaller volumes have been identifiedworldwide, mainly in Asia (270 Bb), Russia (260 Bb), Venezuela (230 Bb) and the US (60 Bb inUtah, Texas and California). Bitumen deposits would also seem to be present in Africa but the figuresare contradictory and estimates of resources in place vary from 50 to 430 Bb. In Russia, very largeresources are present in Eastern Siberia in the Lena-Tunguska basin.

The available technologies allow 9-15% of these reserves to be recovered, but with advancedtechnologies the recovery rate could ultimately reach 30% (depending on the characteristics of thereservoirs). Some reserves are located at a shallow depth and can be exploited using miningtechnologies, whereas others can only be exploited with petroleum technologies.

As regards extra-heavy oils, the United States Geological Survey (USGS) estimates worldwideresources to be around 1 350 Bb. About 90% are located in Venezuela (1 200 Bb). Estimates are that20% of Venezuelan resources in place are ultimately recoverable, i.e. some 240 Bb. Extra-heavy oilhas 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-Mangyshlakbasins, but the lack of accurate and up-to-date information precludes reliable estimates.

7/30/2019 Eur 22168 En

10/81

6

Technologies for extracting tar sands include direct mining (which tends to be the most economicmethod of extraction when the oil sands are close to the surface), with total costs estimated at between9 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 differentreservoir 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 differentproportions and qualities. Heavy oils produce much greater vacuum residues than lighter ones. Severalprocesses exist to convert vacuum residues, either thermal, catalytic or both. An attractive route forexploiting heavy oil is gasification,which involves partial oxidation of the feed, liquid or solid toconvert it into a synthesis gas in which the major components are H2 and CO. Gasification is a clean,flexible technology already proven on coke or heavy crude. It is now receiving global interest due tothe development of the integrated gasification combined cycle (IGCC), in which gasification can beused to process low-value refinery streams.

Oil shales are sedimentary rocks containing a high proportion of seaweed organic matter. Since thetransformation of this material was not complete, the shales are rich in kerogen, making them apotential source of energy. The kerogen can be converted into synthetic oil or gas by industrialprocessing.

Identified oil shale volumes in place are estimated to be around 7 000 billion tonnes. Different sourcesput their oil content at between 2 600 and 4 400 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, some6% 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 orethylene 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 andhydrocarbon gases. ICP significantly reduces (and in some case eliminates) the environmental impactof 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 petroleumproducts (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 30-35 $/b in future;- the (declared) unit cost of GTL technology has dropped sharply: from over 50 000 $/b/d tobetween approx. 25 000 and 35 000 $/b/d, with some operators targeting a figure under20 000 $/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 (10/15 000 $/b),giving scope for higher raw material costs (crude oil).

7/30/2019 Eur 22168 En

11/81

7

The largest share of GTL production is intended for the transport market in the form of veryhigh-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 firstplants, scheduled to come online from 2006. Another factor is the CO2 balance (throughout the chain),

which is relatively unfavourable compared with conventional refining. This factor could impactnegatively on the development of this system, or on costs, if CO2 sequestration becomes mandatory.Finally, a depressed oil market, with prices under 25 $/b, would also hinder the development ofthese plants. Such prices, while occasionally conceivable for relatively short periods, now seemunlikely for many years to come.

Liquid fuels have long been produced from coal via the generic Coal to Liquid (CTL) technologycluster. Being a relatively expensive technology, its deployment would depend on the price of the rawfeedstocks (i.e. cheap coal vs expensive crude oil).

With demand for oil products continuing to grow, and oil stocks becoming depleted, there will come atime 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 forother fossil fuels.

Direct coal-liquefaction processes have been developed to obtain liquid fuels from solid coal. Thetechnique basically consists of dissolving coal in an adequate solvent at high temperature and pressure,followed by hydrocracking of the mix with hydrogen gas (H2) and catalyst.According to studies ofmarket prospects, direct coal liquefaction investment costs are estimated to be about $60 000 per dailybarrel (bbl/d) in the US, for output of 20 000 bbl/d of liquid fuels and with 12 000 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 20 000 bbl/d direct

coal-liquefaction plant is $800 million, and the required selling price of the liquid fuels is estimated tobe $24/bbl, or $15-20/bbl on a crude-oil equivalent basis. For instance, lower labour and equipmentcosts in China would result in capital costs of about $45 000/bbl/d, compared to $60 000/bbl/d in theUS. If these cost estimates prove accurate, the cost of fuel produced will be lower than the cost ofimports, 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 thesyngas is converted into liquid fuel by means of a GTL Fischer-Tropsch (FT) process. One example ofa commercialised process is South Africa's Sasol technology, with three operational plants producinggasoline, diesel fuel and a wide range of chemical feedstocks and waxes. The typical mixed output ofthe 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. $50 000-70 000/bbl/d., and with low-cost coal operating costs may be comparable to GTL (whichuses more expensive feedstock). A recent study quoted in this report puts capital costs for indirect coalliquefaction at $67 000/bbl/d for output of 20 000 bbl/d of liquid fuels and 100 MW of power in theUS, with 15 000 t/d of coal feed. This would translate into a required selling price of the liquid fuels ofapprox. $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 economicallyviable. 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 thisreport are commercially attractive and likely to play a role in future. The economic and environmentalimpact 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 providesthe data needed to examine these issues.

7/30/2019 Eur 22168 En

12/81

8

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.

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 betweenextra-heavy oils and natural bitumen is their in-situ viscosity:

- extra-heavy oils have a viscosity below 10 000 centipoise (cP), i.e. they flow underreservoir conditions;- natural bitumen, also called tar sands or oil sands, has a viscosity above 10 000 cP; itdoes not flow under reservoir conditions.

This section will concentrate on extra-heavy oils and tar sands. Their specific properties requirespecific, advanced technical solutions throughout the process of exploitation, from production totransport and refining; that is why they are called "non-conventional oil".

1.1 Evaluation of resources in place and recoverability

1.1.1 Tar sands

Identified in-place reserves of tar sands are estimated to be between 2 200 and 3 700 Bb, the bulk ofthem in Canada, which has an estimated 1 600 to 2 500 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 alsoseem to be present in Africa but the figures are contradictory and estimates of resources in place varyfrom 50 to 430 Bb. In Russia, very large resources are present in Eastern Siberia in the Lena-Tunguskabasin. Only the Olenek deposit has been studied in sufficient detail to permit an estimation ofdiscovered bitumen in place. Another example is the Siligir deposit. Most of the other Russiandeposits are in the Timan-Pechora and Volga-Urals basins. However these deposits are scattered andthe recoverable volumes not large. Other deposits are located in the Tatar Republic and have beenextensively studied.

Recoverable volumes outside Canada are estimated at between 90 and 130 Bb.

IFP/Economics Division/2004

Heavy, extra-heavy oils and bitumen

10 000 cpViscosity

Density

20API

10API

7/30/2019 Eur 22168 En

13/81

9

Canada's bitumen resources are situated almost entirely within the province of Alberta, with onlyminor oil sand deposits found on Melville Island in Canada's Arctic Island region. Alberta's oil sanddeposits, grouped by geology, geography and bitumen content, are the Peace River, Fort McMurrayand Cold Lake Oil Sands Areas.

The Alberta Energy & Utilities Board (AEUB) estimates the initial volumes-in-placeto be 1 600 Bb.The AEUB further estimates the ultimate volume in place - i.e. the volumes expected to be found bythe time all exploratory and development activity has ceased - to be 2 500 Bb. Of this amount:

- 140 Bb are amenable to surface mining; they are located in the Fort McMurray Oil SandsArea;

- 2 400 Bb are amenable to in-situ recovery or underground mining methods.

According to the AEUB, current technologies can recover some 178 Bb of bitumen. Withanticipated technologies, the ultimately recoverable volume could be 300 Bb. About 20% (35 Bb) ofthe recoverable resources of bitumen are located at a shallow depth and can be exploited using miningtechnologies. 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 tablebelow:

Table 1. Worldwide bitumen resources in place and recoverabilityCountry/area Bitumen in place

BbRecovery rate

%Recoverable resources

BbCanada 1600 11 178USA 60 10 6Venezuela 230 9 23Africa 50 - 430 10 5 43Romania 0.024 14 0.003Jordan 0.24 12 0.03Asia 267 16 43Russia 260 13 34TOTAL 2 260 - 2 640 270 306

1.1.2 Extra-heavy oils

According to the USGS, worldwide extra-heavy oil resources are estimated to be around 1 350 Bb.

About 90%, an estimated 1 200 Bb, are in the Orinoco Belt in Venezuela. 20% of the resources inplace 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 theEnergy Intelligence Group.

Extra-heavy oil has also been identified in other countries, in particularEcuador (5 Bb), Iran (8 Bb)and Italy (1.5 Bb). In Russia, small amounts have been identified in the Volga-Urals and NorthCaucasus-Mangyshlak basins, but the lack of accurate and up-to-date information precludes reliableestimates.

Worldwide extra-heavy oil resources in place and recoverable volumes are summarised in the tablebelow:

7/30/2019 Eur 22168 En

14/81

10

Table 2. Worldwide extra-heavy oil resources in place and recoverabilityCountry/area Oil in place

BbRecoverable resources

BbVenezuela 1 200.00 36.00Peru 0.15 0.05

Ecuador 5.21 0.5Colombia 0.15 0.03Cuba 0.03 0.00Mexico 0.06 0.01

Latin America 1 206.00 36.60Iran 8.80 1.30Oman 0.01 0.00

Middle East 8.81 1.30Russia n.d. 0.90Azerbaijan n.d. 0.70

FSU n.d. 1.60Italy 1.68 0.21Albania 0.15 0.04

Europe 1.83 0.25China 4.20 0.80

Asia 4.20 0.80

TOTAL >1 220 1 350

40.5

1.2 Existing, past and future projects for commercial exploitation

1.2.1 Tar sands

Projects for bitumen exploitation are mainly located in Canada. The Alberta deposits are soconcentrated that they are the only ones that are economically recoverable. Small amounts of bitumenare 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 Utahdeposits have made recovery difficult and expensive. Similarly, the Texan deposits, mostly deep andrelatively thin, have also proved difficult to recover.

Since 1967, there has been production from the oil sands in the Western Canada Sedimentary Basin, inAthabasca. The first company to start mining production was Suncor in 1967, followed by Syncrude in1978. 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 (anExxon 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 36Bb 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 usingmining technologies, and 8% of those volumes are already being produced. The remaining 80% ofrecoverable resources can be extracted with in-situ technologies of these, only 1% are already beingproduced.

7/30/2019 Eur 22168 En

15/81

11

Mining production projects20% of recoverable bitumen resources are located at a shallow depth (less than 100 m) in the FortMcMurray Oil Sands Area and can be exploited using mining technologies.This production methodcurrently accounts for 53% of Canadian bitumen production i.e. 590 000 b/d in 2004.Theseprojects are very capital-intensive, but on such a scale, the installation of an upgrading unit for theextracted bitumen is commercially viable. In all the projects, the bitumen is upgraded at the productionsite and sold in the form ofsynthetic crude oil (SCO), with an API degree of between 29 and 36and sulphur content between 0.1 and 0.2%.

This sector is currently dominated by two companies, Syncrude and Suncor, who are both significantlyexpanding their operations, to increase their bitumen output. Syncrude, which produced 240 000 b/din 2004, expects to double production in 2015 thanks to its "Syncrude 21" project. It will then be theleading company in the mining industry, well ahead of its rivals. Suncor, for its part, produced some215 000 b/d in 2004 using mining methods. With its ongoing Project Millennium, the companysoutput should reach 325 000 b/d in 2010.

Shell Canada, through Albian Sands Energy Inc., has also been producing oil sands by mining

methods at Muskeg River since 2003. With the development of its Athabasca Oil Sands Project,Albian Sands Energy will become the second largest mining producer in 2015.

In the Northern Lights project, there are large, high-quality coal deposits in the lease area that are alsomineable at surface. In future, coal may be used for coal gasification, as a source of hydrogen forupgrading and for power generation.

4 other projects are under development. In 2015, they should all be up and running, with the totalproduction of synthetic crude oil reaching some 1.8 Mb/d.

Table 3. Canadian bitumen mining - ongoing projects

Project Operator

2004

production'000 b/d

2010

production'000 b/d

2015

production'000 b/d

Investment B

Can$

Syncrude 21 Syncrude* 240 382 507 8Steepbank, Millenium,Voyager Suncor 215 325 325 3Athabasca Oil SandsProject

(Muskeg River &Jackpine)

Albian SandsEnergy Inc**. 135 160 360 6

Horizon CNRL 0 150 230 8Fort Hills PetroCanada 0 30 170 7Northern Lights Synenco 0 3 100 4Kearl Imperial Oil 0 0 130 5 to 8

TOTAL 590 1 050 1 822 41 44* 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 ventureowners: Shell (60%), Chevron (20%) and Western Oil Sands (20%).

In-situ production projects80% of recoverable bitumen resources are located at a greater depth and must be exploited usingin-situ technologies (i.e. recovery by petroleum methods). Some twenty projects, either currentlyunderway or being studied, are expected to be set up in coming years. In 2004, in-situ production ofbitumen in Canada was about 327 000 b/d. By 2015, this could reach 1 315 Mb/d. The biggestcurrent project is Imperial Oils Cold Lake operation, which produced 150 000 b/d of bitumen in 2004.It should remain the biggest into 2015.

7/30/2019 Eur 22168 En

16/81

12

In-situ production projects are generally on a smaller scale than mining projects and cannotaccommodate the cost of a dedicated upgrader. In almost all such projects, the extra-heavy oil isblended with a lighter, less viscous hydrocarbon (diluent) and sold as bitumen blend (BB), with anAPI degree of 21 and sulphur content between 2 and 4%. Diluent typically constitutes 24-50% ofthe bitumen blend. Only two projects include on-site upgrading, producing SCO (Synthetic Crudeoil) instead of bitumen blend: Firebag (Suncor) and Long Lake (Nexen/OPTI).

Table 4. Canadian in-situ bitumen production - ongoing projects

Project Operator2004

production'000 b/d

2010production

'000 b/d

2015production

'000 b/d

Invest-ment

B Can$Fort MacMurray In-situ projects 51 545 680 20.9Kirby CNRL 30 30 0.5Surmont ConocoPhilips 50 75 1.1Joslyn Deer Creek En. 2 60 60 0.95Jackfish Devon 35 35 0.45Christina Lake EnCana 7 70 70 1.0Hangingstone JACOS* 7 25 50 0.9

Long Lake Nexen / OPTI 70 70 3.0MacKay River PetroCanada 25 30 30 1.4Meadow Creek PetroCanada 25 40 0.8Lewis PetroCanada 30 60 0.8Firebag Suncor 10 120 160 10.0Cold Lake oil sands In-situ projects 225 500 605 13.3Orion Black Rock Venture 10 20 0.27Primerose/Wolf Lake CNRL 65 135 135 2.2Foster Creek EnCana 30 100 100 1.62Sunrise Husky Energy 45 140 5.1Tucker Lake Husky Energy 30 30 0.4Cold Lake Imperial Oil 130 180 180 3.68

Peace River oil sands In-situ projects 20 31 31 >0.83Seal Black Rock Venture 8 15 15 n.d.Peace River Shell 12 16 16 0.83TOTAL 296 1 076 1 316 35*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 thepressure on the gas market is set to become even greater with all the projects planned.To reduce theirgas-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 toproduce steam. The company is a net producer of both and will therefore choose to use thecommodity with the lowest market value.

- Deer Creeks Joslyn Creek facilities were planned to include a small steam generator to test thefeasibility of using bitumen instead of natural gas as a fuel source.

- the Nexen/OPTI Long Lake project is expected to employ its proprietary gasificationtechnology to create synthetic fuel gas and hydrogen from the low-value, heaviest portion ofthe bitumen barrel. This process will more or less eliminate the need to purchase natural gas.

7/30/2019 Eur 22168 En

17/81

13

To optimise energy use and reduce their operating costs, other companies have installed combinedheat and power (CHP) plants on their production sites:

- PetroCanada has built a CHP plant on the MacKay River site operated by TransCanadaPipelines. 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 useabout 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) torecover the oil (see section 1.3.1 "Extraction technologies" for details):

- CNRL on Primerose/Wolf Lake and Shell on Peace River use a combination of CSS andSAGD.

- Imperial Oil on Cold Lake uses CSS.

There are two other projects in operation testing new technologies(see section 1.3.1 "Extraction

technologies" for details):

- Petrobanks 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 andtest vapour extraction (VAPEX). Operations began in 2003 and are expected to continue into2008.

Altogether, more than 25 Canadian tar sand and bitumen exploitation projects have been or are aboutto be developed. If all are implemented, they will be producing 2.05 Mb/d of synthetic crude and1.06 Mb/d of bitumen blend by 2015, increasing 2004 Canadian heavy oil and bitumenproduction by a factor of 3.4.

Today, most of this production is exported to the USA, but deals are currently being negotiated tobuild pipelines from Alberta to deep-water ports on the British Columbia Coast (Prince Rupert orKitimat), for tanker shipment to Chinese refineries. Enbridge and Terasen, Canada's dominant crudepipeline companies, are each working on projects to supply the Asian market:

- Enbridges Gateway pipeline, scheduled to start in 2010, is designed to carry 400 000 b/d ofsynthetic crude from Edmonton to the British Columbia coast. PetroChina signed an agreementwith Enbridge to receive 200 000 b/d, making it the anchor tenant for the C$2.5 Bn pipeline.Enbridge also hopes to ship 100 000 b/d to markets in California and 100 000b/d to othercustomers in China, Japan or South Korea.

- Terasen claims to have support from Asian interests, including the Chinese, for its plans to

build a parallel 500 000 b/d crude pipeline.

7/30/2019 Eur 22168 En

18/81

14

1.2.2 Extra-heavy oils

Projects to extract extra-heavy oil are in operation in Venezuela, in the Orinoco Belt. No such projectsare reported in Russia.

The Orinoco Belt is the largest extra-heavy oil deposit in the world, with an estimated 1 350 Bb of oilin place.

Exploration in the Orinoco Belt began in 1920 but with disappointing results: the oil discovered wastoo 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 thirdattempt was made in 1956-57, which resulted in up to 20 000 b/d of heavy oil going into production.Finally in the late 1960s and 1970s the Ministry of Energy and Mines (MEM) conducted an intensiveexploration program, drilling 116 wells.

Following the nationalisation of the Venezuelan oil industry, the MEM handed over the Orinoco oilbelt to PDVSA to carry out a more detailed exploration. It was at this juncture that PDVSA divided

the 54 000 km2

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 andCerro Negro area to Lagoven. Between 1979 and 1983 the company drilled around 662 exploratorywells.

Extra-heavy oils are liquid at reservoir conditions, but above ground, at normal temperature andatmospheric pressure, they cease to flow and transporting them is an issue. There are four options fortransporting extra-heavy oil by pipeline: heating, blending , mixing with water or mixing with adiluent. As the latter is most economical it is this option that is most widely used today, especially bythe 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 orstudied integrated projects to develop and exploit extra-heavy oil resources in the Orinoco Belt. Giventhe huge volumes of recoverable reserves, these joint ventures are contracted for 35 years, and fourextra-heavy oil projects are currently underway. In all of these the heavy crude is extracted by coldproduction and transported by pipeline via dilution to an upgrader on the Coast at San Jose. There, thecrude is upgraded to a greater or lesser degree, depending on the project (see table below): in theSincor and Hamaca projects, extra-heavy crude is upgraded to a 26-32API crude which can then beexported and used as feed in common refineries. In the Petrozuata and Cerro Negro projects, the crudeis only partially upgraded and then exported to specific U.S. refineries dedicated to the upgrading ofheavy oil.

The upgrader produces upgraded crude, which is exported, as well as coke and sulphur (alsoexported), and recovers the diluent that was added upstream. This is then send back to the productionplant (about 200 km away) in a dedicated pipeline, to be reused for the same purpose. Recycling thediluent reduces operating costs. However, investment costs are higher, as a return pipeline has to beconstructed.

Cold production is the cheapest and the most environmentally-friendly method. Its disadvantage is thatit gives the lowest recovery rate (5 to 10%), but the oil in place is so huge that the reserves are stillvery large.

Concerning investment costs, in projects with deep conversion of extra-heavy oil, one third of theinvestment 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 to600 000 b/d.

7/30/2019 Eur 22168 En

19/81

15

Table 5. Venezuela extra-heavy oil - ongoing integrated projectsProjectpartners

ReservesGb

Synthetic crudeproduction

b/d

Syntheticcrude API

Investment

US G$

Productionstart

Sincor

Total - 47%PDVSA - 38%Statoil - 15%

2.5 180 000 32 4.2 2000

PetrozuataConocoPhillips - 50.1%PDVSA - 49.9%

1.6 105 000 19 - 25 4.8 1998

Cerro NegroExxonMobil - 41.67%PDVSA - 41.67%VebaOel - 16.67%

1.8 120 000 16 2.5 2000

HamacaConocoPhillips - 40%PDVSA - 30%

Chevron - 30%

2.2 180 000 26 4.4 2001

TOTAL 8.1 585 000 15.9

The four ongoing projects have been given special tax advantages, with a royalty rate of 1% comparedwith 16.66% or even 30% elsewhere. In 2001, Caracas decided unilaterally to raise the royalty rate forfuture extra-heavy oil projects to 16.66%. This new law has been in force since 2004. The fiscalimpact of this measure is about 1 $/b and in today's high oil-price environment it has not underminedthe profitability of the projects. In fact, according to the operators, the current production cost ofsynthetic crude is less than 10 $/b. In 2005, a new reform was proposed by Petroleum Minister RafaelRamirez, seeking to increase the tax rate from 34% to 50%. To enter into force, this proposal must bepassed by the Venezuelan Parliament.

Table 6. Venezuelan tax regime for Orinoco extra-heavy oil projectsInitial conditions (before

2004)2001 law 2005 reform (proposed)

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 oiland is not, therefore, subject to OPEC quotas, unlike Venezuelas conventional oil production.

Future development of Orinoco Belt

In early 2005, four international oil companies were showing interest in the extra-heavy oil of theOrinoco 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. Thecompany intends to produce with thermal methods instead of cold production, to increaserecovery rates.

- Shell has held negotiations with PdVSA on forming a joint venture to exploit extra-heavy oil inthe Orinoco Belt. The proposal was to use proprietary Shell technology, including solventinjection and in-situ refining. The recovery rate is claimed to be more than 20%. The contractshould be signed towards end-2005.

- 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 theconstruction of a new pipeline, the conversion of extra-heavy oil into synthetic crude and eventhe construction of a refinery.

7/30/2019 Eur 22168 En

20/81

16

OrimulsionOrimulsion is a branded product that is used as a boiler fuel. It is an emulsion made up ofapproximately 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 competitionwith residual fuel oil and coal. Orimulsion has been in commercial use since 1991 and customers existin Denmark, Italy, Germany, Finland, Lithuania, Canada, Japan, the UK and China. Bitor, a subsidiaryof PdVSA, manages the processing, shipping and marketing of Orimulsion. It operates one Orimulsionplant in Cerro Negro with a capacity of5.2 million metric tons per year.

The future of Orimulsion production, however, is unclear. In September 2003, PDVSA announced itwas dissolving Bitor into PDVSA's Eastern Operating Division and would not be expandingproduction of Orimulsion. PDVSA's decision was based on economics: the company said that attoday's high oil prices, it could make more profit by selling fuel oil than Orimulsion. PDVSA sellsOrimulsion at less than US$4 a barrel, plus 1% royalty, whereas the basic product could instead besold with conventional blends or processed in Venezuela's four heavy crude upgrade units and sold atover 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 Bitors outstanding long-term contracts withutilities but would not sign any new Orimulsion contracts or carry through with contracts that wereunder negotiation. PDVSA's plan to stop Orimulsion production has met with an outcry from foreignpower companies, including Canada's NB Power and Italy's Enel, and both companies have takenlegal action against PDVSA. NB Power is suing PDVSA for US$2 billion for breaking a 20-yearagreement to supply Orimulsion to its Coleson Cove plant, while an international arbitration courtrecently accepted a request against PDVSA from Enel for US$200 million.

In December 2001, Orifuels Sinoven, S.A. (Sinovensa) was created jointly by China NationalPetroleum 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 ofOrimulsion by the end of 2004. Construction on the Sinovensa project began in April 2004. OnNovember 2000, CNPC began constructing China's first Orimulsion-fired power plant in Zanjiangcity, Guandon Province.

1.3 Known extraction and upgrading technologies, investment and operating costs

1.3.1 Extraction technologies

Due to their extremely high viscosity under reservoir conditions, heavy oils and bitumen have verylow mobility and ability to flow through porous media. This makes primary in-situ production of theseoils very difficult and the recovery rate generally low, less than 10%. Most reservoirs produce withenhanced 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 beenproposed, e.g. injection of a diluent (lighter hydrocarbon) or additives (polymer). Horizontal drilling,as introduced in the mid-80s in Canada by the Institut Franais du Ptrole (IFP) and Elf Aquitaine, hasthe greatest impact on unconventional oil production and is currently used in all recovery methods,both primary and enhanced.

7/30/2019 Eur 22168 En

21/81

17

MiningMining 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 theoverburden is removed, then the oil sand is stripped using diggers and shovels. It is then transported tocrushers where the ore is sized before the bitumen is extracted. Using cyclo-feeders and frothextraction, the bitumen is separated from the sand and water. The bitumen slurry is then piped to anupgrader where it can be processed into Synthetic Crude Oil (SCO), a high-quality, marketableproduct. Large scale mining operations allow operators to produce large volumes of SCO over a longperiod of time.

Early total costs (operating expenses, capital expenditure, taxes and royalties) are estimated to havebeen 35$/b (cf National Energy Board) or more. Substantial cost reductions have been achievedthrough continual process improvement, but more dramatically through two major innovations in the1990s. First, there was a move towards replacing the draglines and bucketwheel reclaimers with moreflexible, robust and energy efficient trucks and power shovels. Second, hydrotransport systems wereintroduced 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-siteupgrader. Capital expenditure for ongoing projects varies from 3.5 to 4 $/b and operating expensesfrom 14 to 16. If we consider only extraction by mining methods, total costs can be estimated to be inthe range 9 to 12 $/b.

Integrated mining projects use natural gas to produce heat energy and electric power and as a source ofhydrogen for hydrotreating during the upgrading process. The required purchase of natural gas issubstantial, at approximately 0.75 Mscf per barrel of SCO produced. A 15% change in the price ofnatural gas results in a change of about 0.5 $/b in SCO cost.

In-situ cold productionCold Heavy Oil Production with Sands (CHOPS) involves the intentional co-production of sand withoil, as it has become apparent that the exclusion of sand results in uneconomic production rates. Themain conditions for successful CHOPS are: continuous sand failure (unconsolidated sands), activefoamy oil mechanism (sufficient gas in solution), no free water zones in the reservoir and the use ofprogressive cavity pumps. "Foamy oil" occurs when gas in the oil expands, giving it a foamy aspectas 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 thiswaste is one of the major components of operating costs; therefore, successful minimization ofdisposal-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 moreprofitable 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 rateto the CHOPS process but without producing sand on the same scale. Generally, lower viscosity isassociated with lower rates of sand production. In such cases, the dominant recovery mechanism isfoamy oil rather than sand production.

7/30/2019 Eur 22168 En

22/81

18

Steam Assisted Gravity Drainage (SAGD)SAGD is the most recent and promising steam injection technology. In SAGD, pairs of horizontalwells are drilled, one above the other. The wells are normally five metres apart and can have a 1 000metre horizontal section. The shallower of the two wells injects low-pressure steam into the reservoir.As the steam moves through the reservoir, it creates a steam chamber which warms the bitumen andreduces its viscosity. The bitumen then flows into the lower of the two wells and is pumped to thesurface. SAGD is now favoured by many companies as it requires lower steam pressures and allowscontinuous rather than intermittent production. Bitumen recovery using SAGD is claimed to be as highas 70%.

EnCana was the first to test the concept at its Foster Creek lease. Although commercial SAGDprojects have been in operation since 2001, it is still relatively early in the development of thisrecovery method, and there is considerable scope for modification and improvement, in terms ofenergy efficiency and recovery rates. The required purchase of natural gas for SAGD is about 1 Mcfper barrel of production and companies are adopting innovative strategies to reduce their exposure tonatural gas prices.

The total estimated cost of SAGD projects is between 10 and 16 $/b.

Cyclic Steam Stimulation (CSS)CSS is a three-stage process: first, high-pressure steam is injected through a vertical well bore for aperiod of time; second, the reservoir is shut in to soak; and third, the well is put into production. Inaddition to heating the bitumen, the high pressure steam creates fractures in the formation, thereby

improving fluid flow. Production declines until the cycle needs to be repeated. Imperial Oil hasemployed CSS technology since 1985 to recover oil sand bitumen on a commercial scale in the ColdLake region.

A key focus in a CSS operation is to increase the total recovered bitumen by increasing the quantityrecovered in each cycle and/or increasing the number of cycles for which recovery is economical. Thesteam-oil ratio (SOR) - and therefore the gas costs for steam generation - is typically at its lowest pointduring early cycles, after which it begins to rise until the point at which bitumen production is nolonger economic and the well is abandoned.

The required purchase of natural gas for CSS is comparable with that of SAGD at approximately 1 to1.2 Mcf per barrel of production. The total estimated cost of CSS projects is between 9 and 13 $/b.

Injector well

Producer well

Legend :

SAGD: Steam Assisted Gravity drainage

Steam chamber

Mobile oil

Overbunden

Underbunden

7/30/2019 Eur 22168 En

23/81

19

VAPEXTMVapour Extraction Process or VAPEXTM is similar in operation to SAGD, except that a solvent such asethane or butane instead of steam is injected into the reservoir along with a displacement gas, tomobilise the hydrocarbons and move them toward the production well. This offers the cost advantageof not having to install steam-generation facilities or purchase natural gas to produce steam. Themethod requires no water processing or recycling, offers lower CO2 emissions and can be operated atreservoir temperature with almost no heat loss. According to EnCana, the capital costs are anestimated 75% of those for SAGD and the operating costs an estimated 50% of SAGD. On thenegative side, more wells are needed to achieve similar production and recovery rates. The drawbackwith this process is that the solvent is a high-value product and must be fully recovered followingproduction if the projects are to be economical.

Devon Canada Corporation is leading a $30 million consortium (funded 25% by the Alberta ResearchInstitute, 25% by the Canadian federal government and the rest by industry partners) conducting fieldtrials to develop and test VAPEX recovery technology. The pilot is located at the Dover UndergroundTest facility site in the Athabasca oil sands area near Fort McMurray. The research project,commissioned toward end 2003, is scheduled to last 5 to 10 years.

In addition, hybrid steam/solvent processes are currently under development for reservoirs in whichsteam or solvent processes alone are not suitable.

In-situ combustion - THAITM /CAPRI processIn-situ combustion recovery methods were tried in heavy-oil and oil-sand settings in the 1970s and1980s, using vertical wells, but met with little success, primarily because of an inability to control thedirection of the fire-front in the reservoir. This generally resulted in a poor production performanceand often caused damage to down-hole equipment. New methods include enhancing existing systems,using different types of wells combining horizontals and verticals and different schemes combiningproduction and injection wells.

One of these is the Toe to Heel Air injection (THAI) process, a proprietory technology ofCanadian Petrobank Energy and Resources Ltd. Petrobank has set up a subsidiary, Whitesands InsituLtd., to commercialise THAITM technology. Its first step is to undertake a pilot project to test theprocess. A field-scale pilot plant is scheduled for Q4 2005 on the Whitesands lease in Alberta. TheTHAITM process is patented in Canada, the US and Venezuela.

THAITM combines a vertical air injection well with a horizontal production well. During the process acombustion front is created, burning part of the oil in the reservoir, which generates heat, reducing theviscosity of the oil and enabling gravity to drain it to the horizontal production well. The combustionfront sweeps the oil from the toe to the heel of the horizontal production well, recovering an estimated80% of the original oil in place and partially upgrading the crude oil in situ. Proponents of the THAI

method believe that using a horizontal production well offers better control of the fire-front.

The purported advantages of THAITM over SAGD are lower unit-production costs, minimal use ofnatural gas and fresh water, upgraded in-situ oil quality from 10 to 20API, reduced metal and sulphurcontent and high recovery rates. These now have to be proven in the field.

7/30/2019 Eur 22168 En

24/81

20

A THAITM variant, CAPRI, uses a standard refinery hydrodesulfurisation (HDS) catalyst in thehorizontal well to promote the precipitation of asphaltens and thus upgrade the bitumen in-situ. Thepatents for this method also belong to Petrobank. The method has not yet been tested in the field.

Summary of extraction technologies

Table 7. Summary of extraction technologiesExtraction technology Capital exp.

$/bOperating exp.

$/bRecovery rate

%Technology maturity

Mining (extraction toupgrading)

3 5 13 - 17 90 Commercial

Cold production 2 4 5 7 5 - 10 CommercialCSS 2 4 7- 9 20-25 CommercialSAGD 2.5 - 5 7.5 - 11 >60 CommercialVAPEXTM 75% of SAGD 50% of SAGD >60 Field testingTHAITM

Petrobanknd nd 80 Field testing -start in

2005CAPRIPetrobank

nd nd nd Laboratory testing

1.3.2 Transportation technologies

Due to their very high viscosity, extra-heavy crude and bitumen generate extremely high friction inpipes and cause great loss of pressure. Most current and planned solutions for transporting theseproducts consist either in reducing their viscosity by diluting them with a lighter crude, creating an oilemulsion in water, or upgrading on-site before transporting. Other solutions focus on reducing thefriction in the pipe instead of modifying the viscosity of the crude. The most common methods aredilution and on-site upgrading.

THAI process (Toe-to-Heel Air injection)

Air and water

Overbunden

Underbunden

Mobileoil zone

cold heavy oil

Combustion frontInjector

wellProducer

well

7/30/2019 Eur 22168 En

25/81

21

Dilution consists in diluting the heavy crude with a solvent such as condensate, natural gasoline ornaphtha. This is the most common transportation technology for extra-heavy oil or bitumen because itis very easy to implement. The drawback is that dilution increases the volume for transport and thusrequires larger pipeline capacities - in some case, diluent can represent some 35% of the heavy oilvolume. Potential problems are the availability of the diluent and the need to recycle it. In-situ projectsin Canada use this method for transportation. In Venezuela, the four strategic associations also use it,and recycle the diluent.

On-site conversion is commonly used for heavy crude extracted by mining in Canada. The idea is topartially upgrade the crude to produce good quality (i.e. API degree 20 and above), transportablesynthetic crude oil, which can be sold to refineries for further processing into finished products.

Another method is to create an emulsion, i.e. the extra-heavy crude or bitumen is suspended in waterin the form of droplets stabilized by chemical additives. Production of emulsions as fuel for electricpower plants is well known, e.g. by the Bitor company in Venezuela. However, this practice is underpressure on account of the associated flue-gas emission levels and CO2 issues. One solution would beto break the emulsion, but no such process is available, and this would anyway require additional

investment in treating and cleaning the used water.

Recently research work has appeared on a new method calledcore-annular flow. The idea is that thewater acts as a lubricating layer to absorb the shear stress existing between the walls of the pipe andthe viscous oil, reducing the flow resistance to just 1.5 times that of water. This drastically reduces thepressure drop caused by the viscous fluid. The main problem with this technology is that the oil tendsto adhere to the wall of the pipeline on contact, restricting and eventually blocking the flow. Theseproblems are exacerbated when the flow in the pipeline has to be stopped for any time.

One very new idea for transporting non-conventional oil is the use of a friction-reducing agent incombination with dilution, to optimize the effect. This method is already used for conventional oil buthas to be adapted for non-conventional types.

In terms of cost and environmental impact, core-annular flow is potentially the cheapest and leastpolluting transportation method. The other methods all have a fundamental problem: high investmentcosts for dilution and on-site upgrading, and the extra cost of water separation and treatment foremulsions.

1.3.3 Upgrading technologies

Heavy and light crude oil processing gives the same range of refined products but in very differentproportions and qualities. Heavy oils produce much greater vacuum residues than lighter ones. Theseresidues have an API degree of between 1 and 5 and very high sulphur and metal content, which donot facilitate their treatment. Several processes exist for converting vacuum residues, either thermal,catalytic or both.

Thermal conversion methods are mature technologies but the products obtained are generally of lowerquality than those obtained with catalytic processes, e.g. visbreaking and coking.

Solvent deasphalting (SDA) is a well-proven process which separates vacuum residues into a lowmetal/carbon deasphalted oil and a heavy pitch containing most of the contaminants, especiallymetals. SDA is very attractive to refiners because it enables them to recover a substantial quantity ofincremental light feedstock, especially when producing lubricant base oil from vacuum residue, thusincreasing refinery yields. Moreover, the pitch can be gasified to meet zero fuel-oil production.

7/30/2019 Eur 22168 En

26/81

22

Most recent work has therefore concentrated on various types of hydrotreating. This involvesreducing the products carbon-to-hydrogen ratio by adding significant amounts of hydrogen, as well asdesulphurising and removing nitrogen and heavy metals. These processes usually require specificcatalyst combinations and are performed at high pressure. There are three types of reactor technologyfor hydrotreating: fixed bed, ebullated bed and slurry reactor.

-fixed-bed processes were the first to be developed but their application is limited to feeds withhigh metal contents.

-ebullated-bed reactors were first introduced in the 1960s. In this design, hydrogen and oil enter atthe bottom of the reactor, expanding the catalyst bed. The catalyst performance can be keptconstant because fresh catalyst can be added and part of the aged catalyst withdrawn while thereactor is operating. Recent R&D has led to substantial improvements in the ebullating process.However, all these processes require large amounts of hydrogen, which would have to bespecially produced from natural gas, thus causing CO2 emissions.

-slurry reactors use a high concentration of finely divided catalyst. This type of technology mightallow high conversion rates. No commercial process is currently available.

Recent research has focussed on combining different processes to optimise heavy crude conversion.Combinations of hydrotreating and solvent deasphalting are receiving particular attention. Suchcombinations can be used either in refineries or for on-site partial upgrading. It allows the refiner toobtain a good-quality syncrude which could be used as a feed by a standard refinery, and a dirty heavyasphalt phase which can be recovered as a solid or liquid fuel for IGCC purposes or just forcombustion, to generate steam for upstream applications.

Another route for upgrading heavy oil is gasification, which involves the conversion by partialoxidation of the feed, liquid or solid, into a synthesis gas in which the major components are H2 andCO. Gasification is a clean, flexible technology already proven on coke and heavy crude. It is nowreceiving global interest as a result of IGCC, in which gasification can process low-value refinerystreams and generate power with the lowest SOx and NOx of any liquid/solid feed technology. Onemajor concern will, in future, be the substantial CO2 emissions produced by such processes. Thecapital cost of IGCC has fallen by 50% in ten years. However, the oxygen-production stage is stillcostly and much research is being done to improve air separation and integrate this stage of theprocess with the partial oxidation in a single-step reactor.

7/30/2019 Eur 22168 En

27/81

23

The following table lists the technologies described above and their licensors.

Table 8. Residual upgrading technologies and licensors

Process Licensors

Hydrogen addition

Catalytic hydroprocessing using HDS catalystsChevron, UOP, Exxon, Axens, Chiyoda, Shell, ShowaShell Sekiyu KK, Idemitsu Kosan, Cosmo Oil,University of Tokyo

Ebullating bed catalyst HRI/Texaco, ABB Lummus, Crest/Oxy, R&D/BP

Thermal Slurry hydroprocessing

PetroCanada/SNC-Lavalin, VEBA, UOP, Imperial,Alberta Research Council, CANMET, NRCan,PDVSA/INTEVEP, NRIPR and Niigata Engineering,Idemitsu & M.W. Kellogg, Asahi Chemical Industry,Nippon Mining, and Chiyoda, Nikko Consulting &Engineering

Non-catalytic hydrovisbreaking Axens, University of Utah, Gulf (Chevron), Allied

Carbon rejection

Visbreaking ABB Lummus Crest, Axens

Steamcracking

Toyo Engineering & Mitsui Chemical, Kurehc, Fuji Oiland Chiyoda, Stone & Webster Engineering/Total,Shell, Exxon, Texaco/ABB Lummus Crest, UOP,Kellogg, Axens, Engelhard, BARCO

Coking

Exxon, ABB Lummus Crest, Kellogg, UOP, Koo Oil,Conoco, Foster Wheeler, Lurgi, Lurgi and Exxon, HRI,Osaka Gas, Fuji Oil/Fuji Standard Research, KobeSteel, Koa Oil, Idemitsu, Nippon Mining, Hitachi,Kashima Oil, and RAROP

Gasification Shell, Texaco, NoellFlash pyrolysis NRCan

Separation

Solvent deasphaltingKellogg (formerly Kerr-McGee), Axens, FosterWheeler, UOP, Cosmo Oil

1.4 CO2 emissions and other environmental issues

With oil sand development in Alberta poised to enter a period of unprecedented growth and expansion,operators face a number of environmental issues and challenges. Recent hearings on oil sanddevelopment saw climate change and greenhouse gas emissions top the list of environmental concerns,

along with other significant issues such as other emissions, boreal forest disturbance and waterconservation.

1.4.1 Atmospheric emissions

Oil-sand operations emit large amounts of carbon dioxide (CO2) and some methane (CH4). Thesebelong to the heat-trapping "greenhouse" gases (GHG) that effect the global climate. Otheratmospheric emissions from oil sands include: SO2, NOx, H2S, CO, volatile organic compounds(VOCs), O3, polycyclic aromatic hydrocarbons (PAH), particulate matter (PM), reduced sulphurcompounds (SCc) and other trace air contaminants.

7/30/2019 Eur 22168 En

28/81

24

The government of Canada released the Climate Change Plan for Canada in November 2002. Itincludes oil-sand producers in the category of Large Industrial Emitters (companies emitting 8 000tonnes of CO2 equivalent or more per year). This category includes both the upstream and downstreamoil and gas sectors, electricity generation, mining and manufacturing, e.g. cement plants and iron andsteel mills. Collectively, the Large Industrial Emitters are expected to produce about half of Canada'stotal GHG emissions by 2010.

In Alberta, the Provincial Government has developed its own GHG-reduction program. Its goal is toreduce by 2020 GHGs relative to the province's GDP by 50% from 1990 levels.

According to a recent IFP study1, CO2 emissions from the bitumen-production process areestimated to be 26 g/MJ , i.e. twice as much as for conventional oils. Emissions from cold productionof extra-heavy oil in Venezuela are put at about 21 g/MJ. Considerable efforts have been made by theCanadian oil-sand industry in the last few years to reduce energy consumption and thereby GHGemissions. For example:

- Shell successfully redesigned its original 1997 plans for the Athabasca Oil Sandsproject, reducingemissions by 64% when it commenced operation in 2002. It also estimated, in a 1999 feasibility

study, that it could half emissions from this project by 2010 through a mix of reduced energyconsumption, improved energy efficiency and offset measures, such as reafforestation projects.

- between 1988 and 1999, Syncrude, the world largest producer of crude from oil sands, cut CO2emissions per barrel of oil produced by 26% and claims it can improve that to 42% by 2008.

Furthermore, the oil-sand industry has been actively dealing with emissions by using low NOxburners, sour water treaters and flue gas desulphurisation.

Alternative fuels are also being considered. A switch from natural gas to other fuel sources couldinclude low sulphur coal. That would be likely to lead to the deployment of technologies for thecapture, transport and storage of CO2. Coal gasification technology is being developed but has yet tobe made economic. Coal-bed methane and the combustion of the heavier bitumen products are also

being considered as alternatives, although these fuels also have high emissions. Nuclear power hasalso been discussed.

1.4.2 Water use and conservation

While both mining and in-situ bitumen operations use large volumes of water, most of it can berecycled. Process water is the lifeblood of an oil-sand operation; its quality can have a significantimpact on extraction performance, tailings management, reclamation performance and plant integrity.The primary challenge as regards process water is that no large-scale water treatment facilities existnear the oil sands. As a result, process water is recycled, which ultimately reduces process efficiency.

Water requirements for oil-sands projects range from 2.5 units to 4 units of water for each unitof bitumen produced. Moreover, the in-situ process has the detrimental effect of removing waterpermanently from the hydro-geological cycle. The net permanent loss for SAGD and in-situoperations is estimated at 1 barrel of water for every barrel of oil recovered (water is used to fillthe space left when oil is removed). For mining operations, the main water-related issues are muskegdrainage, overburden and formation dewatering and diversion of water flow. Water that remains withthe oil and sand slurry after the bitumen extraction is disposed of as mine tailings, which are usuallystored in large ponds until they can be used to begin filling the mined-out pits.

1* "valuation des missions de CO2 des filires nergtiques conventionnelles et non-conventionnelles de production de

carburants partir des ressources fossiles" (Evaluation of CO2 emissions from conventional and non-conventional fossilfuel production sectors), Georgia Plouchard, ref 55 949 - April 2001.

7/30/2019 Eur 22168 En

29/81

25

Water use and conservation are important issues in oil sand development and there have been severalinitiatives to develop new technologies and integrated approaches to water conservation. For example:

- oil-sand mine operators in the Fort MacMurray region are looking at ways to coordinate waterwithdrawals and jointly manage water, to minimise impacts on the Athabasca River.

- Suncor is conducting a company-wide assessment of water use in all regions in which itoperates, to evaluate opportunities for reducing the amount of water used by its operations.

Other methods include:

- developing a non-thermal, in-situ recovery method, using solvents to assist in the extraction ofbitumen, which could reduce the need for water;

- treating water from basal aquifers for use in the extraction process;- re-injecting used water into basal water sands;- recapturing and recycling water from mine tailings.

Regulatory and policy initiatives are being implemented to improve the efficient industrial use ofwater. With this may come plans to implement a fee for water use, which would be likely toencourage water conservation and improved efficiency in water allocations. Charging could putadditional financial pressures on the oil-sand industry.

1.4.3 Tailings and by-products

Tailings managementThe current method for recovering bitumen from oil sands - surface mining -generates large volumesof fluid waste called fine tailings. These are a complex system of clays, minerals and organics.Because of their extremely slow rate of consolidation, settling basins or tailings ponds must be

constructed to last indefinitely and must be protected against erosion, breaching and foundation creep.After about six years, the consolidated tailings, consisting of a mixture of coarse tailings, thickenedtailings and gypsum, are deposited in mined-out pits. The principal environmental threats from tailingsponds are the migration of pollutants through the groundwater system and the risk of leaks to thesurrounding soil and surface water.

Despite technological advances, the scale of the problem is daunting and current production trendsindicate that the volume of fine-tailings ponds produced by Suncor and Syncrude alone will exceedone billion cubic metres by 2020.

Numerous collaborative studies between industry and researchers have been undertaken to increaseknowledge of tailings disposal and reclamation. The research focuses on accelerating the consolidationof fine tailings, detoxifying tailings pond water and reprocessing fine tailings.

There have been some technological advances in the clean-up and reclamation of fine tailings. Twomethods being developed are bioremediation, in which bacteria and nutrients are used to treat thetailings ponds, and electrocoagulation, in which electrical current is used to separate the amorphoussolids from fine tailings.

A process has been developed by the National Research Council of Canada (NRC) to treat fine tailingsand recover potentially valuable by-products such as residual bitumen, heavy metal minerals andamorphous solids that may be suitable as fertiliser. This process also improves the dewatering andconsolidation behaviour of fine tailings and has succeeded in recovering over 60% of the originalwater for recycling.

Another avenue being investigated is the co-production of minerals and metals (aluminium, titaniumand others) from fine tailings.

7/30/2019 Eur 22168 En

30/81

26

By-productsBy-products currently produced from oil-sand and/or extra-heavy oil operations include: elementalsulphur, coke, gypsum and ammonium sulphate from flue gas desulphurisation units and brineconcentrate from water-treatment facilities. There are options for the commercial sale, disposal andmanaged release of these by-products into the environment, all of which have various risks andbenefits.

For example, the Sincor project in Venezuela produces 6 000 t/d of coke which is exported and used incement plants.

Considerable research effort is being focused on these by-products, particularly the management ofsulphur.

SulphurBitumen contains on average 4.8% sulphur. By 2030, sulphur recovery during the bitumen-productionprocess in the expanded oil sands region could generate as much as 10 Mt of sulphur per year. Today,

the Sincor project in Venezuela produces 900 t/d of sulphur.

Currently, producers either stockpile the converted elemental sulphur or ship the by-product for use inmanufacturing fertilisers or road asphalt. A study to determine if sulphur can be safely buriedunderground is currently under way on behalf of Alberta Sulphur Research Ltd. The use of caverns insalt deposits is also being considered for both waste sulphur and produced sand.

1.5 Main inputs for the database and model

The quantitative model provided for tar-sand and extra-heavy oils will include a database of theresources and a technical and economic analysis of the technologies used for the production of

syncrude or bitumen blend.

The database will include lists of the following:

- countries with in-place resources, including recovery rates and recoverable volumes;- known production projects, either already producing or to be developed, including production

data up to 2015, operator name, investment needed, production type and saleable productspecifications in terms of API and percentage sulphur content;

- production technologies, including recovery rates, capital expenditure, operating expenses andgas volumes required to produce steam, where relevant.

1.6 Main References

The economics of oil definitions: the case of Canada's oil sands - Douglas B. Reynolds, OPECReview, Volume 29, Issue 1, March 2005.

Pipeline Transportation of Heavy Oils: a Strategic, Economic and Technological Challenge - A.Saniere, I. Hnaut and J.F. Argillier - Oil & Gas Science and Technology - Rev. IFP, Vol. 59 (2004),Issue 5, pp 455-466.

Canada's Oil Sands: Opportunities and Challenges to 2015 Canadian National Energy Board, May2004

7/30/2019 Eur 22168 En

31/81

27

U