Canada’s oilsands resource has become the world’s hottest hydrocarbon play

June 12, 2006
Spurred by record high oil prices and diminishing chances for discovering giant oil fields elsewhere in the world, companies are flocking to Canada for what is now deemed one of the best low-risk opportunities to add big oil reserves volumes.

Spurred by record high oil prices and diminishing chances for discovering giant oil fields elsewhere in the world, companies are flocking to Canada for what is now deemed one of the best low-risk opportunities to add big oil reserves volumes.

While hugely capital-intensive, Canadian oilsands development entails no exploration risk and negligible political risk. Those are key incentives in an oil industry climate in which elephant-class exploration opportunities are fewer in number and often foreclosed by environmental or geopolitical concerns.

Oilsands development economics, having survived periods of oil price collapses and having expanded during long stretches of low-to-moderate oil price expectations, are bolstered by many forecasts that posit a world oil price averaging $40-50/bbl for the foreseeable future.

Expectations are exceptionally high for the future of Canadian oilsands expansion. In April of this year, the Conference Board of Canada projected that industry will spend over $100 billion (Canadian) on new oilsands development and upgrading projects in the coming decade.

Some analysts estimate that production of bitumen and synthetic crude from Canadian oilsands will almost triple in the coming decade (Fig. 1) and could jump more than fourfold by 2025.

Click here to enlarge image

That optimistic outlook is tempered somewhat by concerns over availability of natural gas, water, and personnel to support the oilsands boom, as well as the prospect of tightening environmental strictures related to carbon emissions reduction.

Still, enthusiasm remains undiminished for a resource that has evolved from lowly origins to its current role as the best chance for stemming the relentless decline of oil production in North America.


Alberta’s oilsands resource has come a long way from 1883, when the Geological Survey of Canada’s G.C. Hoffman first tried to separate Canadian bitumen from oilsand with water.

In 1915, subsequent experimentation with oilsands separation techniques by Canada’s Federal Mines Branch led to paving 600 ft of road in Edmonton, Alta., with bitumen that withstood 50 years of traffic.

In 1928, the Alberta Research Council’s Karl Clark was granted a patent for a hot water extraction process not too far removed from that used today for mined bitumen.

Using Clark’s process, the International Bitumen Co. Ltd., founded by Robert C. Fitzsimmons, started mining oilsands and producing bitumen commercially in 1930 at a site Fitzsimmons dubbed Bitumount. Through various changes in ownership, Bitumount continued to operate until it was shut down in 1958. Canada’s first commercial oilsands operation is now a Provincial Historic Site.

The first large-scale oilsands mine development started up in 1967 when Great Canadian Oil Sands (now Suncor Energy Inc.) introduced massive bucketwheels from the coal mining industry. Syncrude Canada Ltd. followed in 1978, installing the first giant draglines to deliver the mined oilsands to the processing plant. The first commercial in situ oilsands project started up in 1985 when Imperial Oil Ltd. began operating its Cold Lake project and BP Canada and Petro-Canada commenced operations at Wolf Lake in the Cold Lake region. The most recent major oilsands mining operation got under way in 2003, when the Athabasca Oil Sands Project (AOSP), operated by a consortium led by Shell Canada Ltd. and Chevron Canada Ltd., started up.

There are four major oilsands projects in operation today, all in Alberta:

  • Suncor, which currently produces 269,000 b/d of synthetic crude (syncrude) and bitumen.
  • Syncrude, which is expected to achieve production of 350,000 b/d this year, up from about 230,000 b/d in 2005.
  • AOSP, which produces about 155,000 b/d of syncrude.
  • Cold Lake, which produces about 150,000 b/d of bitumen from an in situ project.

However, a host of smaller projects have come on stream in recent years that have helped Canada’s oilsands production pass the 1 million b/d mark for the first time in 2004.

Oilsands potential

These projects and other new projects and expansions announced (see table, pp. 7-8) will only scratch the surface of an enormous potential resource.

The provincial government of Alberta estimates the oilsands original oil in place at 1.7-2.5 trillion bbl in three main areas: Athabasca, Peace River, and Cold Lake, together covering almost 140,000 sq km. The Athabasca deposit is the biggest and nearest the surface, making it more amenable to mining. About 20% of the entire Alberta oil sands deposit can be mined. The deeper deposits at Peace River and Cold Lake require in situ recovery. About 80% of Alberta’s oilsands deposits are too deep to use open pit mining, so future oilsands development will shift increasingly to deeper deposits and in situ processes.

The percentage of bitumen in Canadian oilsands can be 1-20%. It takes about 1.16 bbl of bitumen to make 1 bbl of syncrude.

Provincial and industry sources estimate Alberta’s oilsands reserves-specifically, those deemed economically recoverable with today’s technology-at 175 billion bbl. That would put Canada second worldwide behind Saudi Arabia in a ranking of proved oil reserves.

The new boom

The Canadian Association of Petroleum Producers (CAPP) forecast that oilsands production will more than double by 2015 to reach 2.7 million b/d. If that happens, Canada would jump to fifth place among the world’s top oil producers projected for that year from its current No. 8 ranking.

“Today, oilsands production accounts for 1 out of every 2 bbl of supply in Western Canada,” CAPP says. “By 2015, the oilsands share of production will rise to 3 out of every 4 bbl.”

A multiclient study by the Canadian Energy Research Institute (CERI) in 2005 estimated Canadian oilsands investment would total $100 billion (Canadian) during 2000-2020. That projection jibes with CAPP’s own forecasts, as the association notes that from 1996 to 2004 oilsands investment totaled $36 billion (Canadian), while CAPP forecasts a further $45 billion invested by 2015.

Alberta Economic Development (AED) estimates that industry will invest $30-50 billion (Canadian) in commercial oilsands projects over the next decade.

According to Alberta’s provincial government, about half of the $50 billion (Canadian) in announced oilsands projects have been approved.

In addition to CAPP, most other Canadian industry and government forecasts put oilsands output at about 2.7 million b/d by 2015. Further out, the U.S. Energy Information Administration predicts Canadian oilsands production will add 3.5 million b/d by 2025. CERI projects that oilsands output will climb to 4 million b/d by 2020 and 6 million b/d by 2030.

Despite all of the enthusiasm, there are serious hurdles ahead for the Canadian oilsands industry that could deflate some of these expectations.

Click here to enlarge image

“There are several critical issues currently facing oilsands development,” says James Bates, vice-president and general manager, asset development, Chevron Canada Ltd:

  • “Minimization of environmental impact.
  • Competing megaprojects and the resulting pressures on labor supply, resources, and overall project economics.
  • Finding means to have positive impacts on communities (public infrastructure, health and social impacts, aboriginal communities, etc.)
  • Natural gas and diluent price and supply.
  • Developing appropriate strategies to ensure access to markets, pipelines, refineries.”

Click here to download a .pdf of “Canada"s major oilsands projects”

Infrastructure concerns

Constraints on personnel and infrastructure are the most immediate concern.

According to the Conference Board of Canada, the oilsands boom could leave Alberta facing a worker shortfall totaling 350,000 by 2025.

Alberta’s government is working with industry and the federal government on extensive measures to increase workforce availability by training and recruitment programs to maximize the number of Albertans entering the key trades and professions, as well as attracting qualified people from the rest of Canada and other countries.

A spokesman for AED says, “There is a high level of infrastructure construction activity happening in Alberta to support the expanding oilsands sector, as well as for other projects such as coalbed methane development and potential northern gas pipelines. This has impacted the availability of required skilled workers and materials for the construction of large, capital-intensive projects required for oil sands extraction and upgrading.”

Soaring material and labor costs are spurring big cost overruns in some of the new oilsands projects and expansions, as well as hikes in operating costs. Canada’s National Energy Board (NEB) in 2004 estimated oilsands operating costs at $8-14 (Canadian)/bbl for steam-assisted projects and $12-18 (Canadian)/bbl for mining/upgrading projects. Industry officials generally put the breakeven oil price threshold for an integrated (mining and upgrading) oilsands project at about $25 (US)/bbl.

Ironically, even though the oilsands boom has been driven by high oil prices, those same high prices are contributing to the new projects’ escalating costs.

“Oil sands development is highly dependent on price,” Chevron Canada’s Bates notes. “Below some threshold, it isn’t viable. However, conventional SAGD [steam-assisted gravity drainage] processes are fuel-intensive. As the price of oil rises, so does the cost of fuel and other commodities like steel, which in turn increases our project costs.”

Expansion of materials and fabrication shop capacity for oilsands development also is being encouraged across Canada and abroad.

Increasing oilsands development is placing a high demand on large capital items, resulting in many Alberta fabricators being close to-or at-capacity and having to turn down work and push out lead times to manage the demand. To address the issue, AED recently collaborated with the Metal Working Association of New Brunswick. The idea is to forge partnerships with New Brunswick companies to ensure that Alberta fabricators maintain their client base by outsourcing jobs to Eastern Canadian fabricators to assist with the overflow. Supply chain partnering is another viable alternative to companies that otherwise are not able to take on new work. Similar initiatives are being looked at with other provinces in Canada.

“While critical skill and material shortages are a concern for oilsands development, it should be noted that high energy prices have prompted high levels of energy investment in many countries, so the shortages are a global problem, not confined to Alberta alone,” AED says.

Adequate transportation infrastructure capacity to develop these energy products and reach export markets is required, AED says: “Putting the necessary pipeline, road, rail, and port capacity in place requires some lead time after the specific marketplaces for these products have been identified and has to be an element of every new bitumen extraction project’s development program. The province has also announced additional land for development in Fort McMurray and the twinning of Highway 63 in terms of land and infrastructure concerns.”

Pipeline capacity shortfall

The lack of pipeline transportation capacity is a significant but probably short-term infrastructure concern, say industry officials.

CAPP contends that decisions are needed now for pipelines that will accommodate the industry’s ambitious production expansions in the next 4-5 years.

A number of pipeline projects have been built and proposed for oilsands development areas, including additional export pipelines to the US that are expected to alleviate some of the transportation capacity shortfall.

Enbridge Inc., Calgary, in 1999 started up its 920-mile, 570,000 b/d Athabasca pipeline that links Suncor’s oilsands operations to Enbridge’s terminal at Hardisty, Alta. Kinder Morgan Canada Inc., Calgary, operates the 280-mile, 220,000 b/d pipeline from oilsands projects near the Muskeg River to Shell’s upgrader at Scotford, Alta. Both pipeline operators are planning additional pipeline capacity to accommodate projects slated to come on stream in the near term, such as those under development by ConocoPhillips, Nexen Inc., and Imperial Oil Ltd.

Another possibility is the consideration of building pipelines to link the oil sands deposit with Canada’s Pacific coast, with an eye to foreign markets, notably China. Enbridge is seeking regulatory approval to build a 720-mile, 400,000 b/d pipeline from Edmonton to a British Columbia port in order to facilitate exports to Asia and California. Kinder Morgan also is planning a similar pipeline and considering expanding its Trans Mountain pipeline between Edmonton, Alta., and Burnaby, BC, to 260,000 b/d from 225,000 b/d.

Natural gas hurdle

Natural gas price and availability could prove the thorniest near-term concern for oilsands expansion.

The recent spike in North American gas prices has affected oilsands operations, which depend on the fuel for steam generation, upgrading (hydrogen production), heat, and power. Canadian oilsands operations consume about 5% of Canada’s natural gas supply. Natural gas costs can account for as much as half of the cost of steam-assisted bitumen production.

Alberta’s Energy Ministry predicts that, absent a fuel substitute for gas, growth in oilsands production will push that sector’s gas consumption to 1 bcfd over the next 10 years, up from about 600 MMcfd in 2004. That projected volume is equivalent to a majority of the gas that would be marketed from Canada’s Arctic, should the Mackenzie Valley gas pipeline project come to fruition. And yet NEB forecasts that Canadian gas production will remain relatively flat at 16-17.5 bcfd through 2011, even as gas demand increases across North America.

Shell Canada notes that gas prices are a huge factor in oilsands economics, contending that each $1/MMbtu increase in the price of gas adds 60¢/bbl to the cost of oilsands supply, currently averaging $10-12 (US)/bbl. CAPP recently estimated that higher natural gas costs have added about $3 (US)/bbl to oilsands supply costs

One possible solution is a new bitumen gasification process that would back out natural gas. Nexen and OPTI Canada Ltd. have included plans for a bitumen gasification unit for their proposed $3 billion oilsands project in the Athabasca deposit.

Other fuel alternatives under consideration are coal and coke gasification, asphaltenes atomization and combustion, steam generation, and renewable sources such as biomass and geothermal energy.

Environmental concerns

A number of environmental concerns also threaten to hobble oilsands expansion.

Bates contends that “…water usage, CO2 emissions, and Canada’s Kyoto reduction targets [Canada is a recent signatory to the Kyoto Protocol on climate change] are key environmental concerns, although there are several other issues that need to be addressed, such as caribou migration.”

Water supply is a growing concern for oilsands operators, which depend heavily on water used for thermal cooling in oilsands power plants. Although most of the water is recycled, the industry still needs about 20% of potable make-up water.

Some environmental groups in Canada have questioned the viability of Alberta’s water supply if oilsands development isn’t slowed. However, oilsands industry officials contend that Alberta’s underground aquifers and surface supplies are more than up to the task. The industry is targeting efficiency improvements in water use that would bring recycling up to more than 90%.

Oilsands operators also are developing consolidated tailings processes and other tailings management technologies that are expected to reduce the need for large tailings ponds and allow for progressive reclamation practices.

Greenhouse gas concerns loom large. The amount of energy needed to produce a barrel of syncrude is roughly a third of the energy in a barrel of bitumen. Because bitumen recovery requires more energy, it generates more CO2 than does conventional oil recovery.

Consequently, how Canada accommodates a massive expansion of its oilsands sector could bring it into conflict with its efforts to reduce greenhouse gas emissions. Despite $3 billion (Canadian) spent to date on greenhouse gas reduction initiatives, Canada’s CO2 emissions grew to 740 million tonnes in 2003 from 596 million tonnes in 1990. Meeting the Kyoto target would entail slashing emissions by 240 million tonnes.

CAPP has estimated that accommodating Kyoto would add 25-30¢/bbl to oilsands development costs. That’s a major reason Ottawa prefers a “made in Canada” approach to cutting greenhouse gas omissions.

One novel approach the oilsands industry is contemplating is to develop a network of pipelines, dubbed the CO2 Hub, that would transport CO2 from oilsands operations in northern Alberta to use in enhanced oil recovery (EOR) operations in the declining oil fields of central and southern Alberta.

In the meantime, the emphasis is on abatement technologies to reduce CO2 emissions.

New technology

Oilsands operators continue to press research that would yield incremental improvements in efficiency and cost reduction, as well as the next game-changing technology.

According to the Alberta Chamber of Resources (ACR), “Continued research into less energy-intensive processes and better upgrading technology will ensure growth and commercial production from these resources is sustained for the long term.”

ACR notes that the recovery rate of bitumen from mined sand today is about 90% with good quality ore.

“While there is room for new technology at the mine face, most continuous improvement opportunities might be available in areas such as material handling and better designed equipment,” ACR says. Key technical challenges include the development of “at face” continuous mining; low-temperature, energy-efficient extraction processes; decreased freshwater use; and improved tailings disposal processes.

One technology enjoying rapid deployment in the field is the SAGD process, which entails injecting steam into the producing zone, creating a high-temperature chamber in the formation. The oilsands viscosity is reduced, and the bitumen flows by gravity to a horizontal production well below.

ACR contends that the SAGD process can still benefit from further technology development: “Continuous improvement opportunities for SAGD include reducing the steam-to-oil ratios, introducing new solvent processes, developing more reliable downhole pumps, and enhancing water recycling and reuse.”

A recent addition to the oilsands sector’s technology arsenal is the vapor extraction (Vapex) process. With Vapex, vaporized hydrocarbon solvents are injected into oilsands (or heavy oil) deposits to increase recovery by oil viscosity reduction, in situ upgrading, and pressure control. A field pilot project is under way by Nexen. The technology is promising for its applicability in thin reservoirs where thermal methods aren’t prospective and for its potential to reduce CO2 emissions.

“The game-changing recovery technologies of tomorrow will likely be variations of SAGD and Vapex; such technologies are being developed at the Alberta Research Council,” AERI notes.

Another new technology garnering attention is the toe-to-heel air injection (THAI) process developed by Petrobank Energy & Resources Ltd., Calgary. THAI entails combining a vertical air injection well with a horizontal production well. A combustion front is created where part of the oil in the reservoir is burned, generating heat that reduces the viscosity of the oil allowing it to flow by gravity to the horizontal production well. The combustion front sweeps the oil from the toe to the heel of the horizontal producing well, recovering an estimated 80% of the original oil in place while partially upgrading the crude oil in situ. Petrobank claims its proprietary process works in reservoirs that SAGD isn’t suited for: lower in quality and pressure, thinner, and deeper. Other cited advantages are 30% lower capital and operating costs, 50% less greenhouse gas emissions, and negligible fresh water use.

Bates emphasizes the level of effort needed to make significant progress in oilsands technology.

“It takes a great deal of time, technical people, resources, and investment to understand and model oil sands reservoirs, and to test enhanced oil recovery technologies,” he said. “Current technology such as…SAGD for in situ recovery is relatively immature and untested. There are considerable oilsands resources currently considered uneconomic because the industry does not have proven technologies to recover the bitumen.

“Maturation of these technologies will take time. Unfortunately, the commercial pressures to recover the resource is not conducive to that timeline, so Chevron will be looking to its global expertise in heavy oil to help manage these issues.”

Bates also notes that EOR technologies that can net even small improvements in recoveries could have significant impacts on the viability of oilsands projects.

“Finding and optimizing the appropriate EOR technology to improve the net cost (in dollars, emissions, resource utilization, etc.) per barrel of bitumen produced will be a critical factor in making current and future projects economic,” he says.

Other examples of advanced technologies being eyed include in situ combustion or gasification to warm up and mobilize the bitumen and introducing catalysts in production strings to help reduce energy consumption.

In situ steam-assisted gravity drainage targets Alberta’s deeper-pay oilsands resource. Shown are Petro-Canada’s Mackay River in situ SAGD oilsands operations. Photo courtesy of Petro-Canada.
Click here to enlarge image



Given the many factors that can impede oilsands development, operators are grappling with ways to minimize business risk.

Bates offers several avenues his company is taking to reduce business risk and costs:

  • Working with competitors to manage labor requirements for competing megaprojects.
  • Diversification-involvement in mining and in situ projects as well as upstream and downstream integration opportunities.
  • Realistic forecasting of project performance, project costs, and schedules.
  • Developing alternatives to natural gas for fuel (such as gasification) and/or alternatives to conventional SAGD processes.
  • Development of more-efficient technologies for in situ recovery.
  • Strict adherence to project management processes.
  • Effective utilization of lessons provided by existing projects.

“These are early days for Chevron in Canada’s oilsands development,” Bates added. “However, Chevron Corp. operates more than half the heavy oil production in the world recovered through thermal processes. We think there are significant opportunities to use this worldwide expertise and the integrated nature of our company (upstream and downstream proficiency) to further build upon the successes that the Alberta heavy oil industry has enjoyed in recent years.”

Some of the major business risks in oil sands development today are related to the high investment cost and long lead times for bitumen extraction and upgrading projects, according to AED.

“Research efforts are focused on reducing the cost and hence the financial exposure of developers,” AED says. “Both the Alberta and federal governments are working with industry to increase the construction workforce to avoid project delays.”

AED contends that, with the current outlook for strong oil demand, it is unlikely that oil prices can fall to the point where oilsands development becomes uneconomic: “Technology is improving to reduce investment and operating costs per unit of output, and a large component of the operating cost is for energy consumption, which would tend to decrease with lower oil prices.”

Oilsands development will remain attractive if oil prices remain above $25/bbl, says AED. But at the same time, developers must mitigate their light/heavy crude differential risk through integrated projects, it contends.

Even with the hurdles the oilsands industry faces, AED still points to the attractiveness of the sector for future investment.

“Alberta’s other advantages with its oilsands have not been neutralized: proven reserves, recoverable with existing technology, supported by an extensive infrastructure of human and physical capital, transparent regulatory system, location adjacent the world’s largest energy consuming country (US), and a stable political and fiscal climate.”