supply of western canadian sedimentary basin crude oil · enhanced oil recovery to increase %...

Supply of Western Canadian Sedimentary Basin Crude Oil

The Next Ten Years and Beyond

Prepared for Prof. J. Doucet

BUEC 560, Section Z2 February 12, 2002

By

Alex Frei

TABLE OF CONTENTS Is a Crisis Brewing with Canada’s Oil Supply?....................................................................1 Canada’s Oil Supply Today....................................................................................................1 Contributors to Growth in Canadian Crude Supply ...........................................................2

Oil Sands as a Resource................................................................................................ 2 Reality Check: The Economics of Suncor’s Expansion ............................................ 3 Oil Sands Production that is Not Upgraded............................................................... 4 Conventional Heavy Oil ............................................................................................... 4 Conventional Light Oil ................................................................................................. 6 Condensate or ‘Pentanes Plus’ .................................................................................... 6

Factors that will Affect Future Supply ..................................................................................7 Increases in Tar Sands Production ............................................................................. 7 Decreases in Heavy Oil Production ............................................................................. 7 Decreases in Conventional Oil Production ................................................................. 8

Canadian Crude Oil in the World Market............................................................................8 Macroeconomic forces influencing WCSB crude supply.......................................... 8 Geopolitical Influences ................................................................................................. 9

Supply Senarios .....................................................................................................................11 Future World Oil Prices and the Impact on WCSB Oil Supply ............................ 12 National Energy Board (NEB) Supply Scenarios .................................................... 13

Potential Effects of Technological Advancement on Reserves and Recoverable Oil.......15 Seismic Reprocessing .................................................................................................. 16 3D Visualization .......................................................................................................... 16 Short Condensate Supply........................................................................................... 16 Hot Oil Pipelines ......................................................................................................... 16 Light Oil and Synthetic Oil as a Diluent................................................................... 17 Enhanced Oil Recovery to Increase % Recovered of OOIP................................... 17 Other Possible Technologies that may Affect WCSB Oil Supply .......................... 19

Conclusion .....................................................................................................................19 APPENDIX A – Current and Planned Oil Sands Developments......................................20 APPENDIX B – Suncor’s Custom Blends ...........................................................................21 APPENDIX C – In-Situ Oil Sand Recovery Methods ........................................................22 APPENDIX D – Crude Oil Formation, Location and Types.............................................23 APPENDIX E – World Total Oil Supply Costs ..................................................................26 APPENDIX F – Density to °API conversion chart .............................................................27 APPENDIX G – Excerpts from NEB Document Showing Assumptions for Cases.........28 APPENDIX H – Diluent Constraint on Bitumen Supply...................................................29 APPENDIX I – Radar Technology to Improve Reservoir Management, Plant Oils to

Replace Petroleum.....................................................................................30 REFERENCES .....................................................................................................................31

Supply of Western Canadian Sedimentary Basin Crude Oil Page 1 Alex Frei February 2002

Is a Crisis Brewing with Canada’s Oil Supply? Canada’s proven reserves of conventional oil are estimated to last 10 to 15 years at current production levels, yet there are no warning signs that we are going to run out of oil soon or that the price of gasoline is going to skyrocket. This paper examines how Canada will deal with this apparent pending crisis by identifying growth prospects in Canadian crude supply, the impact of world oil geopolitics on Canada and potential effects of technological advancement in the oil patch. Canada’s Oil Supply Today

Canada is currently a net exporter of crude oil and hydrocarbon liquids. Canada is a large country, with a relatively small population distributed across great distances and with the majority of crude production in Western Canada. As a result, there are regions where we export oil from, and regions where we import oil to. With our close trading ties and proximity to major oil consuming markets in the U.S., we export oil from the Prairie Provinces, primarily to refiners in the American mid-west. With Canada’s east coast expensive to serve with Canadian crude by pipeline, we import oil to supply Canadian refineries in the Maritimes and Quebec.

Three areas in Canada currently have significant commercial development of oil and gas. The Western Canadian Sedimentary Basin (WCSB) is the largest with 57% of estimated conventional oil and gas reserves, followed by the Atlantic Margin with 18% and the Arctic Cratonic with 10%.1 To date, the WCSB has supplied 99% of Canada’s crude. However, Canada’s supply of conventional crude from the WCSB has been in a state of decline since the mid-1970s. This decline, coupled with the world oil crisis in 1973/74 has lead to exploration for conventional crude in more difficult areas such as the Rocky Mountain Foothills, the Arctic and the East Coast offshore areas. Small volumes of conventional oil are currently being produced from these areas. In addition, heavy oil and bitumen resources in Alberta have been developed and contribute significantly to Canada’s oil production today. If we were to talk only about Canada’s conventional crude supply, we would be ignoring the most important oil resource developments in Canada. Current activity in the oil resource sector and the business and government climate in Canada assure us of our domestic supply for many years to come, and support the increasing volumes of export production we expect into the distant future.

1 Petroleum Communication Foundation (2000b), Inside Front Cover

Supply of Western Canadian Sedimentary Basin Crude Oil Page 2 Alex Frei February 2002

Contributors to Growth in Canadian Crude Supply Oil Sands as a Resource The Oil Sands are an important and vast Canadian resource. Canada has an ultimate volume of crude bitumen in place estimated to be 2500 billion barrels. With 12% or 300 billion barrels estimated to be recoverable, we have a recoverable volume comparable to the proven reserves of Saudi Arabia.2 All of Canada’s bitumen resources are found in Alberta, in regions defined as Athabasca, Cold Lake and Peace River Oil Sands Areas, shown to the right.3 Currently there are several Oil Sands projects under way with several more planned. Planned and announced investments total over 40 billion dollars for that period, of which about 10 billion have been spent to date. Daily production rates of synthetic crude will increase from approximately 450,000 barrels today to an estimated 900,000 by 2008.4 Additional projects will provide increasing production volumes through 2025, the extent of Canada’s planning horizon. Refer to Appendix A for a pictorial showing the current and planned projects to 2010. Bitumen currently is mined as tar sand in two large operations north of Ft. McMurray, Syncrude and Suncor. A third project, by Shell Canada, is under construction and scheduled to start production by the end of 2002. The existing two plants extract the mined bitumen from the tar sand and upgrade it on site to synthetic crude. Current production from Syncrude is approximately 260,000 bbls/day and from Suncor is approximately 200,000 bbls/day.

2 National Energy Board (2000a), pp. viii 3 Ibid, pp. 4 4 Syncrude (2002a) slide 4, Suncor (2000a) pp. 14

Supply of Western Canadian Sedimentary Basin Crude Oil Page 3 BUEC 560 Term Paper Alex Frei 0165661 February 2002

NOTE: All prices are given in Canadian dollars except as specifically identified.

Syncrude produces one product, Sweet Synthetic Crude (SSB), which is distributed as oil to it’s owners in proportion to their ownership. This is necessitated by the structure of the partnership, whereby profits are not distributed in the usual way for a subsidiary. As all but one owner is an oil company, this is apparently a satisfactory way of providing return on investment to the owners. Suncor’s ownership is more typical of a corporation, with shares traded on Canadian and American stock exchanges. Accordingly, profits are distributed in the traditional way. Therefore Suncor is free to take advantage of opportunities to custom blend synthetic crude. As a result Suncor produces about a dozen custom blends, as well as road diesel sold in the Ft. McMurray and Edmonton markets. Refer to Appendix B for a listing of custom blends that Suncor currently makes. The Oil Sands plants require massive investment in plant and equipment. To date Syncrude has spent approximately $8 billon on its plant, with a $3 billion expansion (UE-1) currently under way. Suncor has spent approximately $9 billion including a just-completed $3.25 billion expansion. In addition, Suncor is undergoing a further expansion (Firebag) and has another expansion in the planning stages (OS3). Building plants of this size requires working on a very long-term planning horizon. Current production costs for Syncrude are in the $16/bbl range, with a target cost of $12/bbl in today’s dollars. Suncor’s production costs are just over $10/bbl. Differences in production costs are due to Syncrude’s sensitivity to natural gas costs, which accounted for about $2 to $4/bbl in 2001, and accounting differences. Syncrude believes their costs, after discounting for the natural gas effect are slightly higher that Suncor’s. With these variable costs of production, the price of oil must remain substantially higher to maintain reasonable returns to shareholders and amortize the huge capital investment. The project returns are calculated over the life of the plant, typically 20 to 30 years. Reality Check: The Economics of Suncor’s Expansion Let us analyze Suncor’s decision to expand based on projected world oil prices, in order to determine if the expansion is indeed viable from a business point-of-view. We shall take the final cost and added production capacity numbers and determine if there is a minimum reasonable return on investment. We can estimate Suncor’s expected crude price by making a number of reasonable assumptions. Suncor spent $3.25 billion to increase production by 110,000 bbls/day.5 Assume that the lifespan of the project is 20 years, the price per barrel remains at $30 (approximately US20/bbl) for Suncor’s synthetic crude, the variable cost per barrel is $10 and that the expected real rate of return on capital is 8%. The expansion produces an additional 40 million barrels per year, at $30/bbl. The sell price of $30/bbl minus variable cost of $10/bbl produces an annual net revenue of $800 million per year ($20 x 110,000 x

5 Suncor (2000a), pp. 15


365). The present value of the production at 8% is 8x108 P20�0.08 or 8x108x9.81815 or approximately $7.855 billion. This is well in excess of the $3.25 billion spent with an 8% return. The project would still be economically viable provided the annual revenues exceeded $331 million. (The present value of $331 million for 20 years at 8% is $3.25 billion, the amount invested). Revenues of $331 million/year correspond to a price of $18.25/bbl for the entire period. Suncor would have to receive less than this price on average over 20 years to make the plant expansion uneconomical. As described below in the sections “Geopolitical Influences” and “Future World Oil Prices” this is very unlikely. A complete analysis would account for other risks and considerations. The economics show that this investment will likely provide excellent return to shareholders, especially if the oil prices remain at or near $30/bbl. Oil Sands Production that is Not Upgraded Currently a negligible volume of bitumen is shipped without upgrading out of the Ft. McMurray area. Developments regarding shipments of bitumen are discussed later in the section on “Factors that will Affect Future Supply”. Oil sands production also occurs in the Cold Lake area. The oil is typically recovered by cyclical steam injection (refer to Appendix C for details) and is not upgraded before shipment to market. Four companies are active in the area, Esso, CNRL, Flint Hills Resources (formerly Koch Petroleum) and Husky Oil. Recently AEC has started a heavy oil play in the Cold Lake Air Weapons range, Foster Creek. Pan Canadian has started a project adjacent to Foster Creek, but outside the weapons range, called Christina Lake. I don’t have exact numbers for total production from this entire area, as the NEB has not summarized them yet. However I estimate that there is approximately 380,000 bbls/day total production in the area (130,000 Esso; 80,000 CNRL; 70,000 Flint Hills; 60,000 Husky, 30,000 AEC Foster Creek and 10,000 Pan Canadian Christina Lake). A smaller deposit to the west of the Ft. McMurray deposit, the Wabasca deposit, is producing 25,000 bbls/day with CNRL and AEC as the producers. Conventional Heavy Oil6 Heavy oil supply has increased in the past decade and will continue up to 2007 and is expected to decline thereafter. Canada has large heavy oil reserves, located in an area approximately within a 150-kilometer radius around Lloydminster, Alberta. Technical advances in drilling (horizontal drilling) and pumps (submersible or progressive cavity) have led to reduced production costs. Use of SAGD technology (refer to Appendix C) has reduced the energy and water consumption per barrel recovered. Both drilling and SAGD technologies have reduced the environmental and lease cost impact by reducing the footprint of the surface production facilities. Even so, current supply costs for heavy

6 Refer to Appendix D for a description of crude oil types such as light, heavy and synthetic


crude are estimated to be in the range $12.80 to $14.80/bbl.7 As long as crude prices remain near US20/bbl, it is economic to produce from these fields. Further development of heavy oil is very dependant on current crude prices. Heavy oil sells at a discount to conventional light crude, referred to as the ‘differential’. There are several reasons for this. Heavy oil requires more refinery processing because of it’s greater proportion of heavy hydrocarbon molecules. Refer to Appendix D for a detailed description of crude oil types. Typically a coker is required in front of the usual refinery equipment to eliminate the heavy hydrocarbons and add hydrogen to capture more of the feedstock as a hydrocarbon liquid (as opposed to a solid - carbon only). There are a limited number of refineries that have cokers that can handle heavy oil. Some refineries can use small quantities mixed with lighter crude oil. As a result the refinery market is limited for heavy oil. Heavy oil prices are seasonal. In addition to heavy oil being rich in commercially valuable carbon molecules, it has a relatively small portion of lighter hydrocarbons than conventional crude. The light hydrocarbons are processed into motor fuels: gasoline and diesel. The net result is that heavy oil demand rises in the summer once paving season starts in the American mid-west. This is because heavy oil is primarily processed into asphalt and diesel, both of which are in great demand in the summer months. Canada’s heavy oil supplies Alberta and Saskatchewan with asphalt, plus the more heavily populated and industrialized states from Chicago west to the Rockies. The seasonality of demand and the differential with respect to conventional light crude makes heavy oil production and field development very price sensitive. If prices remain at US20/bbl, and the differential is below $10/bbl, development of heavy oil resources continues. The finding and completion cost per barrel is in the $2.00 to $3.00 range. (Heavy oil is typically near to the surface – refer to Appendix D for background of oil geology in the WCSB). If heavy oil prices drop below about $16/bbl, exploration immediately ceases. If prices drop further to below the variable cost of production, at $14.00 on average, wells are immediately shut in. Producers are very aware of current heavy oil prices and react almost instantly when prices rise or fall. To minimize the seasonality of heavy oil demand and be able to continue to produce heavy oil regardless of the differential, Husky operates an upgrader in Saskatchewan just outside Lloydminster. Upgrading costs are $3 to$4 per barrel, depending on natural gas prices. If the differential is greater than the cost to upgrade, it is economical to run the upgrader at capacity. Typically this is done in winter months when the asphalt demand is low. The upgrader produces synthetic crude similar to Syncrude’s.

7 National Energy Board (2000a), pp. 57


Production and development of heavy oil is hair trigger sensitive to world oil prices. Therefore it is difficult to accurately predict how quickly existing reserves will be depleted and the pace of reserve replenishment. Nevertheless, the National Energy Board estimates that production will peak in 2007 and start to decline thereafter.8 Therefore, in the longer term, the heavy oil contribution to Canadian oil production will be a significantly decreasing portion. Conventional Light Oil As noted above, conventional crude in the WCSB is in decline, and will essentially be tapped out in the next 10 to 15 years. Canada will still be producing conventional crude, but not from the WCSB in great quantities. Frontier sources such as the Artic and the East Coast offshore will match WCSB production by 20159. It is important to note that the current reserves of non-WCSB conventional crude are small compared to the original WCSB reserves. Technology plays a big factor in the discovery and production of oil. The impact of current leading edge technology and possible future developments are discussed later in this paper, in the section, “Potential Effects of Technological Advancement on Reserves and Recoverable Oil”. Condensate or ‘Pentanes Plus’ Condensate is not strictly speaking crude oil, but because of it’s similarity to light crude oil and its importance in heavy oil transportation, it requires mention here. Condensate is a group of light hydrocarbons produced as a byproduct of natural gas production. Refer to Appendix D for a detailed description of crude oil types. Condensate is typically separated from natural gas at the wellhead and collected for use. Alberta has an extensive pipeline system used exclusively for gathering and distribution of condensate. Heavy oil and bitumen production is limited by the availability of condensate, used to facilitate transportation from the production site to main oil pipe trunk lines. Heavy oil is diluted in approximately the ratio 1:2 condensate to heavy oil. Bitumen is diluted in the ratio 1:1. This means that for every two barrels of heavy oil sent down the pipeline, 1 barrel of condensate is required. For every one barrel of bitumen, one barrel of condensate is required. With natural gas production unrelated to heavy oil or bitumen production, condensate is frequently in short supply. This is exacerbated by current level of oil prices and heavy oil production, and our increasing reliance on heavy crude and bitumen as part of our total crude oil supply. The result is that condensate costs 2 to 3 times as much as heavy oil. It is also not returned to Alberta for re-use, once it has left the province it’s gone for good.

8 National Energy Board (1999a), pp. 68 9 National Energy Board (1999a), Appendix 7: Crude Oil


Short supply and high prices are creating advances in technology for transporting these crude oils. More discussion is given in the “Potential Effects of Technological Advancement on Reserves and Recoverable Oil “ section of this paper. It is therefore important take into account condensate supply when looking at heavy oil and bitumen production. Factors that will Affect Future Supply Increases in Oil Sands Production Current production levels of synthetic crude from the Ft. McMurray area are approximately 450,000 bbls/day. Current production from the Cold Lake oil sands is 380,000 bbls/day. Projects which will be producing by the end of the year are:

� Shell’s Muskeg River project is scheduled to produce 150,000 bbls/day starting the end of 2002

� Petro Canada is schedule to produce 20,000 bbls/day starting July 2002 Including the Wabasca area, the total oil sand production will be 450,000 bbls/day of synthetic crude and 575,000 bbls/day heavy oil/bitumen by the end of 2002. With the oil price levels generally expected to remain above US18/bbl for the next 20 years, many oil sands projects have been announced. Even with the huge capital investment needed, the economics of these projects, examined earlier, prove to be extremely good for synthetic crude oil production. It seems that smaller projects will ship bitumen out of the area, while larger projects will upgrade the crude locally. Shell and Petro Canada will ship bitumen south, to be upgraded at their existing refinery sites. Shell is nearing completion of their upgrader expansion at Scotford, and Petro Canada has started their $1 billion upgrader in Edmonton. Other planned projects include upgrading on site. An estimated additional $38 billion is planned for oil sands by 2010. This will bring the total production of synthetic crude from the Ft. McMurray area to 1.7 million bbls/day, the total heavy oil/bitumen production to 365,000 bbls/day from the Cold Lake area and 100,000/day from the Wabasca area. (Refer to Appendix A for a map detailing these developments). This is 2,165,000 bbls/day total planned oil sands production by 2010, an increase of 211% over the expected 2002 production. Decreases in Heavy Oil Production The WCSB oil production is in a relatively mature state. As of 1997, 52% of established heavy oil reserves have been produced and 82% of the estimated ultimately recoverable


resources have been discovered. The NEB predicts that heavy oil production will peak in 2007 and decline after that.10 Decreases in Conventional Oil Production As of 1997, 77% of established conventional reserves had been produced and 82% of the estimated ultimately recoverable resources having been discovered.11 This means that most of the conventional oil in the WCSB is gone and little is likely to be discovered. There will always be oil in the ground. However, with current technology, the cost of discovering or developing the remaining oil becomes prohibitive at current world oil prices. One would expect oil prices to generally remain around US20/bbl for the next 10 to 20 years. When the price of oil eventually rises, it will become economical to search for the smaller more difficult to find and produce reservoirs. Therefore incremental resources will be found and produced as world oil prices rise.12 This phenomenon will occur worldwide. A more detailed analysis of when prices permanently rise is given later, in the “Supply Scenarios” section of the paper. Canadian Crude Oil in the World Market Macroeconomic forces influencing WCSB crude supply Canada produces significant amounts of oil, but is only a small player in the world market. In 2000 Canada accounted for about 3.5% of the world oil production.13 (The estimated world production is 75 to 80 millon bbls/day, and Canada’s production is 2.7 million bbls/day). The large producers determine the world oil prices, and Canada is a price taker. Canada is very closely aligned with the US both politically and in terms of trade. Canada also exports resources to many other countries. With such economic interconnections, we are very dependent on the state of the global economy in general, and the American economy in particular. Recent estimates place 37% of all Canadian industrial production as being destined for the US, including 53% of our oil being destined for American markets. As oil literally ‘fuels’ the economies of the industrialized nations, demand for oil is very influenced by world macroeconomic forces. A decrease in the world’s major economies GDP decreases oil demand and can easily induce a large decrease in oil prices, unless an attempt is made by producers to balance supply and demand.

10 National Energy Board (1999a), pp. 62 11 ibid. 12 ibid., pp. 65, 66, fig 7.3 13 BP(a)


Let us consider equilibrium pricing of oil. We shall make the reasonable assumption that short-term supply is relatively inelastic. Therefore if there is a shift in the demand curve leftwards, due to an economic slow-down, the price will drop by a large amount. The system has some inertia in it in terms of transportation and information delays, but typically OPEC responds by decreasing production, effectively shifting the supply curve left, in the hope of maintaining the equilibrium price at the same level. In the past 10 years OPEC has had reasonable success in achieving this, through good economic analysis and discipline of its members. One would expect OPEC price controls to continue and world oil prices to remain in the low US20s/bbl. This process appears to have worked with modest success in the past. However this is not the end of the story, as other factors come into play. Geopolitical Influences OPEC has influenced world oil pricing since 1973. Recently the dynamics have changed somewhat, whereby non-OPEC producers have decreased OPEC’s market share from over 40% to as low as 35%. This has decreased OPEC’s market power and has added uncertainty to the world oil market. Saudi Arabia, with the world’s largest conventional oil reserves and very low production costs, has historically been the swing producer who maintains prices by balancing world supply and demand with their own production adjustments. Other OPEC members are also supposed to stick to the oil production quotas they have agreed to. Recently the former Russian Federation has brought large production on stream, bringing their production near the level of Saudi Arabia. Since Russia is non-OPEC, Saudi Arabia and the other OPEC have to contend with Russian production in addition to their own internal games. Americans have exerted political influence throughout the world particularly where oil interests are concerned. The US has a vast appetite for oil, consuming 1 out of every 4 barrels produced in the world, or approximately 20 million bbls/day. American domestic production is approximately 8 million bbls/day, so it must import 60% of its needs. In order to maintain its standard of living and political and economic dominance in the world, the US must ensure that it gets its oil. Needless to say this underlying oil appetite predicated much of modern history. It is in the American’s interest to have reasonably stable world politics and oil prices. The interests of the producing nations have to be balanced with the interests of the US, and these interests are often at odds. Given all of this, Canada in simply in for the ride. We are a small producer, are closely allied with the dominant world economic and political power, and are dependant on the world economy for our standard of living and oil exports. Because of our relatively high cost of production, our oil industry is reasonably sensitive to the world oil price. (Refer to Appendix E for a chart showing cost of production for the major oil producers). There are other geopolitical influences. The majority of conventional oil reserves are located in the Arabian Gulf whilst the consumption is concentrated mainly in a small


number of industrialized countries: notably the US, Japan and Germany. (Britain has been left out because of its current self-sufficiency in oil). Consumption is closely linked to the country’s world ranking by GDP. Perhaps the irony is that there is a certain degree of antipathy between these two groups, yet their destinies are tightly intertwined because of oil. Cultural, religious, ideological, governmental, and standard of living differences create a polarity that must be continually managed to keep the system working. In fact they must be managed to avoid the outbreak of another world war. These differences and the resultant world tensions have arguably often been exacerbated by American foreign policy, and the support the Americans receive from other powerful sympathetic countries. OPEC is not a homogenous, constantly happy cartel. Indeed they have a number of fractious members, and frequently member interests are at odds with the group’s goals. In fact all members of the cartel have an incentive to cheat – that is a fundamental characteristic of a cartel. (The dominant strategy equilibrium, as described by John Nash, is to cheat on their agreement and cause the group to achieve a non-optimal outcome.) Members such as Venezuela, Nigeria, and Indonesia are extremely dependant on oil revenues to fund their economy and are particularly motivated to overproduce. It is also unfortunate that these countries tend to have unstable, corrupt governments that are shortsighted and tend to squander the oil money in ways that benefit the people in power at the expense of the hoi polloi. Unfortunately economic benefits of oil revenues tend not to trickle down to the average person. Other OPEC members have political/religious agendas that make them very antagonistic to the West, creating an environment of distrust and overt hostility to the consuming nations. Iraq, Libya and Iran fall into that category. It is to OPEC and Saudi Arabia’s credit that the system works as well as it has in the past 20 years. With the current unrest in the Middle East, the fallout of September 11 and the large non-OPEC production in Russia and Mexico, we may be in an unprecedented difficult period for OPEC. I suspect that they will manage to meet their objectives to “Seek stable oil prices that are fair and reasonable for both producers and consumers of oil”14 This means target world oil prices in the low US20s. Both Russia and Mexico have developing economies that rely to a great extent on oil revenues, and they are not members of OPEC. Although this complicates the world oil situation in the short term, in the long term their influence is relatively minor, given the Middle East’s established reserves and their cost of production. As a result the Russian and Mexican influence and effects are not examined into in this paper.

14 www.opec.org, Mission Statement


Supply Senarios Let us consider the very long range when Saudi Arabia is starting to run out of oil. It is assumed that they are the last to run out of oil. As of 1997 Saudi Arabia had 261 billion barrels of proven crude oil reserves. Iraq, UAE, Kuwait, Iran and Venezuela together had 471 billion barrels of proven crude oil reserves.15 This is an OPEC total of 750 billion barrels (rounded to include smaller producers). To simplify the analysis, we make the following assumptions:

• OPEC supplies 40% of the world oil consumption throughout the analysis period (the underlying assumption is that world oil prices remain fairly constant and the rest of the world continues, business as usual)

• the current world consumption of 80 million bbls/day increases by 5% per year • no oil is found to replace reserves used up

The annual world consumption starts at 29.2 billion bbls/year (80 million bbls/day x 365 days), and therefore the OPEC supply is 40% of that or 11.68 billion bbls/year. We can calculate how long it will take the reserves to be used, including the growth in consumption by using the formula 750=11.68px�0.05 and solving for X. Rearranging the equation and rationalizing, px�0.05=750/11.68=64.21. Looking X up in a time series table, we get a value of 28.6 years. In our model, OPEC will run out of oil in 28.6 years from 1997, or just over 24 years from now. Our simple model ignores future discoveries in OPEC nations and other macroeconomic growth issues, but we certainly get an idea of the time frame of OPEC control of world oil prices. If OPEC is unsuccessful in maintaining oil prices at or above US20/bbl, we would see a large reduction in non OPEC production and non-OPEC development of reserves. This is because most non-OPEC nations have considerably higher production costs than OPEC (refer to Appendix E), and they would not produce oil below the variable cost of production, and not explore below the total projected cost of exploration and production. (The exploration cutoff point is at a higher $/bbl figure that the production cutoff point). The result would be that OPEC would supply a greater portion of world oil, and have their reserves consumed at a faster rate. As an aside, supply and demand analysis suggests that the resulting increase in market share and power would then lead to an increase in prices. Indeed, the price of US20 to US25/bbl is likely the long-run equilibrium price, and market forces would always return the price to that point. Therefore the prediction of OPEC oil lasting for another 24 years is reasonable, regardless of the difficulty of OPEC maintaining that price.

15 Petroleum Communication Foundation (2000b), pp. 56


Future World Oil Prices and the Impact on WCSB Oil Supply It is reasonable to assume that as OPEC’s reserves near the end of their life, world oil prices will start to climb. This will likely be in a reasonably orderly manner, as indicated below:

Projected World Oil Prices

020406080

100120

2000

2005

2010

2015

2020

2025

2030

2035

2040

2045

2050

2055

2060

2065

2070

2075

Year

Pri

ce p

er B

arre

l, U

$

Oil Price, NYMEX

As world oil prices start to climb above the long-term equilibrium price of US20/bbl, in 2020, exploration and production of marginal areas will become economic. This will impact conventional oil, heavy oil and tar sands production. Since tar sands projects are very capital intensive and take years to plan and implement, their expansions are planned on a very long time horizon and these plans are already reasonably factored into Canada’s oil supply to 2050 or so. Tar sands production is projected to climb, and that growth will likely continue to 2050 or 2060. What is of greater interest is the impact of rising world oil prices on conventional oil. Based on the literature, I estimate that newly discovered resources would increase the supply by 10% when the price reaches US30/bbl in 2030, and by another 5% thereafter. Even with better economics, the law of diminishing returns affects the ultimate additions to reserves, all else held equal. These additions would result in total additions of 2.8 billion barrels of conventional crude by 2040. This is 15% of the original recoverable WCSB reserves of 18.9 billion barrels.16 These would all be incremental discoveries, not a new big find, so demand would outstrip supply and this would not materially affect Canada’s crude oil supply. A similar effect would occur in WCSB heavy oil production. The major difference is that heavy oil has higher total supply costs, and therefore is more sensitive to market price.

16 National Energy Board (1999a), pp. 62


Also, as of 1997, only 50% of the WCSB heavy oil reserves have been produced, as compared to 75% of WCSB conventional oil.17 Therefore more is left in place. We can use a similar rationale to above for conventional crude, but with incremental additions of 20% in 2030 and another 20% thereafter (to reflect the relatively low finding costs and high producing costs). Heavy oil additions would total 1.87 billion barrels by 2030. This is 40% of the original recoverable heavy oil WCSB reserves of 4.7 billion barrels. The total conventional crude oil additions would therefore be 4.67 billion barrels. The net result would likely be that the production rates of these crude oils would reverse from their decline to an increase for a period of 10 to 15 years after 2030. After 2040 or 2045, the production rates would again decline. This could be seen as a rising then falling trend line for conventional light and heavy crude oil, if we were to extend the graph shown on the next page.

National Energy Board (NEB) Supply Scenarios To gain some perspective, it is worthwhile to briefly review NEB projections of Canadian crude oil supply. The NEB uses comprehensive data collection and analysis techniques to prepare a series of supply scenarios. The intent here is to have their projections as a backdrop to this paper, not to delve into their analysis in depth. Data has been extracted from their Canadian Oil Supply report18, as I m focusing only on WCSB oil supply, whereas they include data for all Canadian producing areas. A graphical summary of the NEB’s projections for WCSB crude is given below. The most recent data was from 1997, so some of the forecasted results are no longer valid. This is especially true of the oil sands production forecasts, since the major projects now under way and planned were not committed to in 1997. Regardless, the graph shows the trends expected. The ‘Supply Case 1’ is described in Appendix G, excerpt page 9, item 2.4.

17 ibid, pp. 62, table 7.1 18 ibid. Appendix A, Tables 7.3a-d


The main items of note are that conventional light oils continue their decline (dark blue line), conventional heavy oil declines after 2005 in this graph, and oil sands production of synthetic crude and bitumen have a continuing upward trend. These trends are influenced by world oil prices. The following is a graphical representation of different scenarios developed by the NEB, which show the growth or decline of total production based on world oil prices. It is interesting to note that at US14/bbls prices, Canada’s production slowly declines. Conversely, at US22/bbl prices, Canada’s production increases. This paper delves into more detail of the dynamics of reserve discovery and production in later sections, but this graph provides a good indication of what the NEB thought in 1999, based on the data to 1997. (The units are different; however it is important to observe the trends). Case 1 is the same scenario as above. The other cases are described in Appendix G, also.

Western Canadian Sedimentary Basin Crude Supply Case 1

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.019

95

2000

2005

2010

2015

2020

2025

Year

1000

s of

bar

rels

per

day

ConventionalLightPentanes Plus

ConventionalHeavyOil SandsSyntheticOil SandsBitumenTotal


The most notable aspect of this chart is that in most cases, the WCSB oil production declines after 2010. $22 sensitivity increases and plateaus from 2020 to 2025. It is my opinion that these projections are pessimistic. Present and planned projects in Alberta oil; sands, my estimates of future world oil prices, and the potential advances in technology create a potential scenario where Canadian production increases into the foreseeable future. This prediction is based on the analysis discussed below. Potential Effects of Technological Advancement on Reserves and Recoverable Oil Geopolitical influences and world oil prices are two of three determinants affecting actual volumes of recovered oil. The third is technological advances. Several advances have already contributed to increased recovery of oil, and the pace of technological advancement may increase. It is reasonable to assume that as yet undiscovered advances would yield more oil from WCSB reservoirs. Technological advances are not necessarily dependent on world oil prices, but certainly oil prices increase their effect and speed the rate of technological innovation by providing economic incentives. Several current and near-term future advances are discussed briefly below. Estimated impacts on annual production and additions to recoverable oil are made for each technology.

Western Canadian Sedimentary Basin Crude Supply Cases and Sensitivities

0.0

100.0200.0

300.0

400.0500.0

600.019

95

2000

2005

2010

2015

2020

2025

Year

Cub

ic M

(mill

ions

) per

yea

r

Case 1Case 2$14 Sensitivity$22 Sensitivity


Seismic Reprocessing WCSB is thoroughly covered by existing seismic data. In fact data can be purchased from data brokers, reducing the high costs of seismic acquisition. Current technology enables old seismic data to be reprocessed at lower cost, allowing for better ‘focus’ on underground reservoirs. Based on Pan Canadian - Dick Walker’s talk I would estimate that reprocessing of seismic could contribute 3% to WCSB conventional oil reserves, or approximately 567 million barrels. The contribution is less for heavy oil, because deposits are closer to the surface and seismic is less accurate at smaller depths. I estimate the reprocessing contribution to be 1% or 187 million barrels. 3D Visualization 3D seismic replaced 2D seismic in about 1985. 3D seismic eliminates false readings by rejecting echoes from objects outside the plane of interest. Current technology like Pan Canadian’s TerraDeck or the Enterprise’s HoloDeck makes full use of 3D seismic. Six oil companies have 3D visualization rooms in Calgary and the number is likely to grow in the future. The economics of using these devices are extremely attractive, although due to the uncertainty of exact benefits, it hard to quantify the return. Based on information garnered from our Pan Canadian visit, I would estimate that a 5% increase in the declining remaining conventional oil reserves could be added on an annual basis. Assuming a 10% drawdown of reserves annually, we can estimate the total reserve addition as the sum of the series [current reserves] x 5% + [current reserves-10%] x 5%+[current reserves-20%] x 5% and so on. This finite series has a value of [current reserves] x 5% x (1+0.9+0.8+0.7…0.1) = 2126 million x 0.05 x (5.5) = 585 million barrels. Therefore the potential reserve addition of conventional crude is 585 million barrels. Short Condensate Supply Declining condensate supply and growing condensate demand for heavy oil and bitumen transportation has resulted in demand starting to outstrip supply. This will get worse as production of these oils increase dramatically and replace conventional light oil production. Enbridge has predicted that condensate (diluent) supply will limit bitumen production by 2007 (refer to Appendix H). Two approaches have started to be used to overcome this problem, and may gain more widespread use in the future. Hot Oil Pipelines Viscosity can be reduced in bitumen and heavy oil by heating the oil until it flows easily. Typically bitumen or heavy oil is approximately 55ºC once it has been processed. In a hot oil pipeline, it is further heated to approximately 110ºC. The viscosity at this temperature is low enough that the pipeline can operate at capacity using a minimum amount of energy for pumping the oil. Even at these temperatures, a small amount of condensate is


added to reduce viscosity, typically about 10% by volume. The pipeline is insulated to reduce heat loss. Line heaters are spaced approximately every 50 kilometers to replace heat lost to the surrounding ground. Only one hot oil pipeline has been constructed and is operating in Alberta to date. It is CNRL’s ECHO pipeline from the Cold Lake oil sands deposit to Hardisty. As of today some kinks remain to be ironed out in the operation of the pipeline. If this pipeline works well, more hot oil pipelines may be constructed in the future. (Trans Mountain Pipelines has just announced the Bison Pipeline Project, a hot oil pipeline to be constructed from the Ft. McMurray area to Ft. Saskatchewan. It is in the early approval and design stages, so it remains to be seen if they wind up using hot oil technology or revert to the more conventional dilution method for viscosity reduction). Once ECHO oil reaches Hardisty, it still must be diluted with condensate before entering Enbridge’s trunk line to Chicago and Sarnia. Light Oil and Synthetic Oil as a Diluent Some of the major oil producers are looking at alternate supplies of condensate. Light conventional oil and light synthetic oil are starting to be used as a diluent for heavy oil and bitumen. Esso in Cold Lake has started an evaluation program whereby light oil from the Swan Hills area is used instead of condensate to dilute the heavy oil. On a volume basis, more light oil is needed to dilute the heavy oil, but light oil portion can displace a refinery’s direct light oil supply. In essence the two oils can be commingled, resulting in heavy oil ‘piggybacking’ on light oil to get to the refiner. This frees up condensate for other heavy oil shippers. Suncor has contracts with Jacos and Petro-Canada to supply a middle distillate, kero, as a diluent. Both companies produce bitumen in the Ft. McMurray area and transport their hot oil to the Enbridge terminal just south of the Suncor plant site. Suncor kero is added to reduce viscosity and the oil then goes to Hardisty. As with the Esso light oil diluent, this frees up condensate for other heavy oil shippers. With these two developments as examples of condensate replacement, I would estimate that additional condensate alternates will be developed in the near future. This will prevent condensate supply restricting heavy oil and bitumen production. It is interesting to note that free market forces provide incentives that ensure continued oil supply. The high price of condensate and the tight supply has driven oil producers to come up with alternatives. Government intervention has not been required. Enhanced Oil Recovery to Increase % Recovered of OOIP

“In primary recovery – the initial approach to produce oil – natural reservoir pressure or simple mechanical pumps are used to raise oil to the surface. Most oil wells drilled in Canada today have to be pumped. Primary recovery can range from 0.5 % to 60% of the resource in the reservoir, depending on the combination


of oil and rock characteristics. The average primary recovery rate is less than 20 %. This means a lot of oil would usually be left in the reservoir”19

Some of the remaining oil can be recovered by using enhanced oil recovery methods. Currently two methods of enhanced oil recovery are used, secondary and tertiary recovery. Secondary recovery is achieved by injecting water or natural gas into the formation to maintain reservoir pressure. Essentially this works by replacing the produced oil with water or natural gas, and sweeping the oil towards the producing well. This method has been used for decades and the incremental oil recoverable by this method is already factored into our reserve calculations. Tertiary recovery is the final recovery method currently available. The most common tertiary method is miscible flood in light and medium crude oil reservoirs. Natural gas liquids are injected into the formation and dissolve in the oil. This reduces the surface tension and viscosity, allowing the oil to be released from the rock and flow more freely in the formation to the production wells. Carbon dioxide flood is another less common method of tertiary recovery and works in the same way. These techniques bring the total recoverable oil in light and medium oil fields to just over 30% of the original oil in place (OOIP). The remaining oil cannot be accessed with current production techniques. Most heavy oil production uses enhanced recovery methods such as cyclical steam injection or SAGD. Some heavy oil production uses fireflood. Refer to Appendix C for details on these recovery methods. According to the estimates for new oil additions due to seismic reprocessing and 3D visualization, we would gain 1,339 million barrels of reserves. These would be incremental gains and their impact on WCSB oil production would be dependant on world oil prices. The faster and sooner world oil prices permanently rise, the more likely these production additions will increase the net production rates of conventional oil. As world oil prices rise according to the scenario above, starting in 2030, we will likely see new more expensive recovery technologies develop. These will likely be termed ‘Quaternary’20 recovery methods. As these develop, likely only marginal resources will be recovered. These have already been accounted for by the price effect. We will always have oil in the ground, because the very best we can achieve now is 60% recovery, with an average of 30%. It is conceivable that a quantum advance in technology will give rise to much higher recovery rates. If some method is discovered that increases the average recovery rate from 30% to 55%, this would allow for the production of an

19 Petroleum Communication Foundation (2000b), pp. 49 20 Quaternary, the possible name for methods which come after tertiary methods.


additional 25/30 x 18.9 billion barrels, or 15.75 billion barrels of conventional crude and 25/30 x 4.7 billion barrels, or 3.9 billion barrels of heavy oil. This total of 19.67 billon barrels would be a substantial increase in Canadian reserves, almost doubling (25/30 = an increase of 83.3%) the current reserves. In my estimation the likelihood of a quantum advance in recovery technology is small, while the potential effect on WCSB reserves is very large. Therefore their effects are not included in my WCSB crude oil supply forecast. Other Possible Technologies that may Affect WCSB Oil Supply As a sidebar, there are other technological developments that may impact WCSB oil supply. These are included for sake of completeness, in order to show the diversity of possible technological innovation that could impact on oil production. Refer to Appendix I for articles on use of radar to help manage oil reservoirs, and vegetable oil as a sustainable source of gasoline and diesel fuel. Conclusion With the current world oil prices, Canada’s WCSB conventional reserves will run out in 10 to 15 years. Technological advances and eventual increases in world oil prices will increase the future recoverable conventional reserves, albeit at a slower rate than demand. Oil sands production is replacing conventional oil production at an increasing rate, allowing Canada to increase its net oil exports, while providing for 100% of Canada’s domestic needs (overall, when regional transportation issues are factored in). Current planned projects will provide for growth in Canadian oil production to 2025, the limit of the NEB’s planning horizon. After that, world oil prices are expected to rise, creating an incentive to further develop oil sands resources and develop and recover additional marginal conventional and heavy oil reserves. On the surface Canada may be seen to be running out of oil, but this is only conventional oil, and it is fast being replaced with non-conventional oil production. With the vast reserves trapped in oil sands, Canada is likely to be a net oil exporter for the next 50 to 100 years.


APPENDIX A – Current and Planned Oil Sands Developments21

21 Enbridge (2001a)


APPENDIX B – Suncor’s Custom Blends


APPENDIX C – In-Situ Oil Sand Recovery Methods22

22 Petroleum Communication Foundation (2000a), pp. 16, 17, 18


APPENDIX D – Crude Oil Formation, Location and Types What is Oil? Crude oil is a naturally occurring mixture of hundreds of different hydrocarbon compounds.

“It is believed that these hydrocarbons were created millions of years ago when ancient marine life or vegetation died and settled on the bottoms of streams, lakes, seas and oceans, forming a thick layer of organic material. Sediment later covered this layer, applying heat and pressure that 'cooked' the organic material and changed it into the petroleum we extract from the ground today.”23

Often the hydrocarbon mix changed from its original chemical make-up as it migrated to where the deposits are located today.24 These processes created the different forms of crude oils we know today. There are several types of crude oil. Oil is classified by 1) density or gravity, which is the proportion of large carbon-rich molecules that are present in the oil; 2) the source of the oil (oils sands or other) and; 3) whether it has been upgraded or diluted. The density or gravity is expressed in kg/m3, or as a number of degrees on the American Petroleum Institute (°API) scale, with higher numbers indicating lighter oil. The gravity of crude oil can range from less than 0° API to 47° API, or from 1,076 kilogram per cubic metre to 793 kg/m3. (Density in kg/m3 =1/[141.5-°API] – 131.5)25. The names for these different crude oils are defined as follows:

1. The term 'crude oil' usually refers to light crude oils (gravity of 28°API or higher, density of 793 to 885 kg/m3) and heavy crude oils (gravity between 28°API and 12°API, density of 885 to 985kg/m3) and is the traditional source for most Canadian oil production. 26 These crude oils are referred to as ‘conventional’ crude.

2. Heavy oil found in oil sands deposits are considered non-conventional regardless of the oil production processes involved.

3. Bitumen (gravity below 12°API to less than 0°API) is like heavy crude oil, but is in either a semi-solid or solid state found in bituminous sands. It is so viscous that it will not flow unless heated or diluted.

4. Dilbit (diluted bitumen) is bitumen that has been diluted by light oil or condensate to enable pipeline transportation.

5. Synthetic crude oil is heavy oil or bitumen that has been upgraded into light crude by removing the heavy carbon molecules and other impurities.

23 Energy(a) 24 Petroleum Communication Foundation (2000a), pp. 5 25 See Appendix F for Density to °API conversion chart 26 Natural Resources Canada (2000b) pp. 38


6. Condensate or Pentanes Plus is sometimes classified as oil. Condensate is a hydrocarbon liquid often produced with natural gas. It consists of the lightest hydrocarbons, which are a liquid at room temperature and pressure, C5 (pentane), C6 (hexane), C7 (heptane), and C8 (octane). Its primary use is as diluent for reducing the density and viscosity of heavy oil and bitumen to enable pipeline transportation.

Crude oil has many different properties. Its colour can be pale yellow or black, sometimes with red, green or brown shades. Synthetic crude oil is usually fluorescent and glows when viewed under black light. Crude oil may smell like gasoline or have sour or fruity odours; it may or may not be waxy. These characteristics are determined by the oil’s chemical composition. In general, the denser the crude oil, the darker it is and the more asphalt it contains. Denser crude also generally contains a greater proportion of the complex and enormous hydrocarbon molecules that constitute paraffin wax and asphalt and a smaller portion of the simple molecules like methane in natural gas. Synthetic crude is fluorescent because of the high content of naturally occurring aromatic hydrocarbons or those created in the process of upgrading. If the oil contains more than one per cent sulphur by weight it will usually have a foul smell, like rotten eggs; less than one per cent sulphur by weight gives sweet crude the smell of gasoline. The more paraffin the oil contains, the waxier it is. Where is Oil Found? Canada has seven large regions of sedimentary rocks, the kind which may contain hydrocarbons. These are the:

1. Western Canadian Sedimentary Basin 2. Atlantic Margin 3. Arctic Cratonic 4. Arctic Margin 5. Pacific Margin 6. Intermontaine 7. Eastern Cratonic

Three areas currently have significant commercial development of oil and gas. The Western Canadian Sedimentary Basin is the largest with 57% of estimated conventional oil and gas reserves, followed by the Atlantic Margin with 18% and the Arctic Cratonic with 10%.27 These do not include oil sands bitumen, which is estimated to be the largest hydrocarbon deposit in the world, exceeding even the conventional oil reserves of Saudi Arabia. The Western Canadian Sedimentary Basin accounted for 99% of Canada’s crude oil and gas production in 1997.28 The focus of this paper is the Western Canadian Sedimentary Basin. This geologic formation is shown below.29

27 Petroleum Communication Foundation (2000b), Inside Front Cover 28 Ibid, pp. 1 29 Alberta Geological Survey (a)


APPENDIX E – World Total Oil Supply Costs30

30 International Energy Agency Web Site


APPENDIX F – Density to °API conversion chart 1/25/2002 Density to °API conversion chart

Density kg/m3 Degrees API formula API=141.5/[SG@60 degF]-131.5

700 70.642857

710 67.795775

720 65.027778

730 62.335616

740 59.716216

750 57.166667

760 54.684211

770 52.266234

780 49.910256

790 47.613924

800 45.375

810 43.191358

820 41.060976

830 38.981928

840 36.952381

850 34.970588

860 33.034884

870 31.143678

880 29.295455

885 28.387006

890 27.488764

900 25.722222

910 23.994505

920 22.304348

930 20.650538

940 19.031915

950 17.447368

960 15.895833

970 14.376289

980 12.887755

985 12.154822

990 11.429293

1000 10

1010 8.5990099

1020 7.2254902

1030 5.8786408

1040 4.5576923

1050 3.2619048

1060 1.990566

1070 0.7429907

1080 -0.4814815

1090 -1.6834862


APPENDIX G – Excerpts from NEB Document Showing Assumptions for Cases31

31 National Energy Board (1999a), pp. 4-9, 61-77, 95


APPENDIX H – Diluent Constraint on Bitumen Supply32

32 Enbridge (2001a), slide 11


APPENDIX I – Radar Technology to Improve Reservoir Management33, Plant Oils to Replace Petroleum34

33 Intech (2001) 34 Intech (2000)


REFERENCES Alberta Geological Survey (a), www.ags.gov.ab.ca, The Geological Atlas of the Western Canada Sedimentary Basin, Chapter 1, Figure 1.1 BP(a), BP World Web Site, www.bp.com, Statistical Review of World Energy 2001, production statistics spreadsheet Enbridge (2001a), 2001 Transportation North Presentation, Investment Community Conference October 11, 2001 Toronto, Ontario Energy (a), www.energy.gov.ab.ca, Introduction to Oil Intech (2000), an ISA Publication, pp. 24, 26 Intech (2001), an ISA Publication, pp. 24 International Energy Agency Web Site, www.iea.org National Energy Board (1999a), “Canadian Energy, Supply and Demand to 2025, 1999” National Energy Board (2000a), “Canada’s Oil Sands, A Supply and Market Outlook to 2015”, An Energy Market Assessment October 2000 Natural Resources Canada (2000a), “Canada’s Emissions Outlook: An Update”, Appendix Table C-6, Series 13.01: Recent and Forecast Crude Oil Production Petroleum Communication Foundation (2000a), Canada’s Oilsands and Heavy Oil, 2000 Petroleum Communication Foundation (2000b), Our Petroleum Challenge, Exploring Canada’s Oils and Gas Industry, 2000 Suncor (2000a), Suncor 2000 Annual Report Syncrude (2002a), Paul Sutherland MBA Presentation, January 18, 2002

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