N. American unconventional oil a potential energy bridge

April 11, 2005
The US and Canada together can claim enormous volumes of oil in place, but most of it is locked in unconventional resources, primarily oil shale in the US and oil sands in Canada.

The US and Canada together can claim enormous volumes of oil in place, but most of it is locked in unconventional resources, primarily oil shale in the US and oil sands in Canada. Nonetheless, US Department of Energy officials claim, “These resources can serve as North America’s energy bridge to the future until other energy resources and technologies can be developed and commercialized.”

Of the two resources, Can-ada’s oil sands deposits are the more productive. Alberta has massive deposits of oil sands-a mix of sand, clay, water, and bitumen, a black, asphalt-like hydrocarbon as thick as molasses-that account for most of the province’s crude reserves.

Analysts at Lehman Bros. Inc. said in a recent report that rising oil prices and lower operating costs have created a “huge opportunity” for Canadian oil sands operators.

“High prices not only improve economics at existing operations but dramatically improve returns on future investments,” the analysts said.

Canada’s National Energy Board (NEB) called the bitumen in Alberta’s oil sands “one of the world’s largest known deposits of liquid hydrocarbons.” Its estimate for initial established reserves, 178 billion bbl, is 35 times as large as the estimate of conventional Canadian oil reserves and puts Canadian total reserves second in the world to Saudi Arabia’s conventional oil reserves. The resource could satisfy Canada’s domestic demand for crude at current rates for 250 years, said NEB officials. In Alberta, production of raw bitumen surpassed conventional crude production in 2001 and has been increasing since.

By comparison, Venezuela’s Orinoco Belt also contains vast hydrocarbon resources generally referred to as heavy and extra-heavy crude oil. Those deposits are estimated to contain 1.9 trillion bbl of oil in place, ultimate recoverable reserves of 272 billion bbl, and proven reserves of 77.8 billion bbl.

Production rising

In 2004, Canada’s oil sands production exceeded 1 million b/d. “And it’s expected to rise even further in coming years,” said Charles Rulgrok, CEO of Syncrude Canada Ltd., in a recent speech to New York business executives. “We’ve only seen the tip of the iceberg in terms of oil sands production, with only about 3 billion bbl produced to date and that over a span of almost 40 years.”

Three current open mine projects in the Athbasca area produce roughtly 615,000 b/d, or 55% of Canada's total oil sands production. Photo courtesy of Suncor Energy Inc.
Click here to enlarge image

He said, “With the decline in more conventional supplies of crude oil and continued strength in world demand for oil, the oil sands opportunity is coming to the forefront. It’s expected that oil sands-related production will double in the next 10 years and that it will continue to grow. Some projections suggest that oil sands-related production could reach as much as 5 million b/d.”

Rulgrok said, “By 2015, we anticipate that [North American] crude oil demand will be over 25 million b/d. Of this, about 10 million b/d would come from conventional [North American] sources, about 3 million b/d from Canada’s oil sands, and the balance from imported oil sources. Canadian oil sands-related production under this forecast would represent 25% of all North American production.”

Canada’s three known oil sand deposits-Peace River, Cold Lake north of Lloydminster, and Athabasca, the biggest, in the Fort McMurray region-are all in Alberta.

Roughly half of oil sands production growth is expected to come from mining projects. The three current mining projects-Athabasca Oil Sands Project, Suncor’s Steepbank, and Syncrude-produce about 615,000 b/d, or about 55% of total oil sands production. All three projects are located in the Atahbasca area, the only area where deposits are shallow enough to be mined. The remaining 45% comes from in situ projects that lie along the whole oil sands region.

Oil sands initially were discovered in shallow deposit areas where bitumen can be found at the surface. The deposits vary in depth below the surface, necessitating two primary means of production. “Where the deposits are shallow, the oil sand can be mined” in an open-pit process, said Rulgrok. “This is the case in the northern portion of the Athabasca deposit where Syncrude operates.”

At Syncrude, Rulgrok said, “We start by mining the oil sand using large shovels and trucks. The heavy black bitumen is then separated from the sand using heat (hot water and steam) in an extraction plant. Finally, the bitumen is sent to our central upgrader for processing into a light, sweet crude oil blend before it is shipped by pipeline to refineries across North America. A similar process is used by the other active producers in the region, Suncor and Albian Sands, which is largely owned by Shell.”

Syncrude’s upgrading operation is much like a typical high conversion refinery, with two cokers, a hydrocracker, several hydrogen and hydrotreating units, sulfur plants, and a large utility infrastructure. “We’re investing over $5 billion in the expansion of our upgrader,” Rulgrok said. “Through the course of this year, this new facility will be tied in to our existing upgrader.”

Last year, Syncrude, the largest of three surface mining operations, produced 238,000 b/d of crude. “We’re in the midst of a major expansion that will see our capacity grow to 350,000 b/d in mid-2006 and perhaps as much as 500,000 b/d at some point in the future,” said Rulgrok.

Record production

An industry update report prepared in September for Alberta Economic Development (AED), the marketing arm of the Alberta government, noted two companies set oil sands production records last year. Syncrude produced a record-breaking average of 241,000 b/d during the first half of 2004, up from 212,000 b/d in 2003, the report said, while the Athabasca Oil Sands project produced a record monthly average of 182,000 b/d in August. Its production averaged 142,000 b/d in the second quarter of 2004. The design capacity for the project is 155,000 b/d.

Suncor produced an average 228,000 b/d during the first half of last year, including 10,000 b/d from its Firebag in situ operations, which started production in January 2004. Suncor’s average production in 2003 was 212,000 b/d.

Among other production figures cited in the report:

  • Petro-Canada produced an average 13,000 b/d at its MacKay River in situ project in the second quarter of 2004, down from 17,000 b/d during the first quarter. That project has a design capacity of 30,000 b/d.

  • EnCana Energy was maintaining production of 5,000 b/d from the first phase of its Christina Lake thermal project, with a design capacity of 10,000 b/d. During the second quarter of 2004, the company also produced an average 29,000 b/d from its in situ Foster Creek thermal project.

  • Canadian Natural Resources Ltd. (CNRL) was producing 53,000 b/d from its Primrose-Wolf Lake in situ project. In September, the company announced plans to expand operations through the development of Primrose East on leases located entirely within the Cold Lake Air Weapons Range. Plans include modifications of its Wolf Lake central facility to increase processing capacity to 120,000 b/d and water-treating capacity to 60,000 cu m/day. Primrose East is expected to be fully integrated with CNRL’s existing operations by 2009.

  • Imperial Oil Ltd. produced 119,000 b/d from its Cold Lake project during the first half of 2004, down from 129,000 b/d during the same period in 2003.

    The report said Deer Creek Energy had commenced steaming operations in the first phase of its Joslyn oil sands project, with full production of 600 b/d expected by mid-2005. It also reported start of construction on steam-assisted gravity drainage (SAGD) in situ facilities including ConocoPhillips’s Surmont project with a design production capacity of 100,000 b/d and Opti Canada-Nexen’s Long Lake project with an integrated upgrader and a first-phase design capacity of 70,000 b/d.

    In situ operations

    About 80% of the estimated 300 billion bbl of recoverable bitumen in Canada will require in situ production because of depth, Rulgrok said.

    With the in situ process, bitumen is removed from the sand underground, usually by using heat to separate the bitumen from the sand and making it liquid enough to be pumped to the surface.

    There are two commercial methods for in situ production. One process known as cyclic steam stimulation (CSS) “is typical of what Imperial Oil uses at its Cold Lake operation, which is the largest in situ facility in Canada today,” Rulgrok said. “In this process, a single well is used to both inject high pressure steam into the oil sands deposits to heat the oil and then to pump the oil to the surface.”

    The other approach, SAGD, uses conventional horizontal drilling technology to drill two closely spaced horizontal wells near the base of an oil sands deposit. Steam is injected through the upper well, causing the bitumen to flow into the lower well where it can be pumped to the surface.

    Another form of in situ production is the vapor recovery extraction method, which involves the use of solvents as a supplement or alternative to steam. Another approach is primary or cold production, which can be employed in reservoirs where the oil sands will flow to the well bore without the use of heat.

    Much of the oil produced from in situ operations is blended with a lighter crude oil or condensate stream for transportation to refineries in Canada or the US.

    “Lower steam injection pressure generally means that SAGD can be applied to thinner reservoirs than CSS, although good vertical permeability is essential,” said NEB in a recent report. “A major advantage of SAGD is that an estimated 40-60% of original bitumen in place can be recovered, compared with CSS, where an estimated 20-25% of the initial oil in place is estimated to be recoverable.”

    NEB reported, “Current supply costs for Athabasca SAGD are estimated to be $11-17/bbl of bitumen.” It said, “SAGD supply cost is less sensitive to capital cost than mining projects since the capital investment required is far less. Historically, in situ projects have also had a better track record of staying on budget.”

    Typically, steam for SAGD production is produced by natural gas-fueled generators. An industry rule of thumb is that it takes 1 Mcf of natural gas to produce 1 bbl of bitumen.

    “Steam-to-oil ratio (SOR) is a measure of the quantity of steam required to produce 1 bbl of oil,” said the NEB report. “Therefore, a lower SOR translates into lower fuel costs. A change of 0.5 in the SOR results in approximately a 60¢/bbl change in the supply cost.”

    At a US price of $24/bbl for West Texas Intermediate, NEB said, “a large- scale Athabasca SAGD project with a high-quality reservoir is estimated to provide a rate of return in the low to mid-teens, which for most companies is considered adequate to compensate for cost of capital and project risk.”

    NEB reported, “CSS is a three-stage process: first, high-pressure steam is injected through a vertical wellbore for a period of time; second, the reservoir is shut in to soak; and third, the well is put into production. In addition to heating the bitumen, the high pressure steam creates fractures in the formation, thereby improving fluid flow.”

    It said, “Although CSS is characterized by higher SORs than SAGD, the quality of the steam used is lower and requires less energy to produce. In CSS operations in the Cold Lake area, some 15% of natural gas requirements are typically met through produced solution gas, whereas in a SAGD operation in the Athabasca area, these amounts are comparatively minimal.”

    The report further stated, “Current operating costs for CSS are estimated to be in the range of $8-14/bbl, with supply costs estimated to be in the range of $13-19/bbl. It is not anticipated that the CSS method will be widely applied outside of the Cold Lake region.”

    According to Lehman Bros. analysts, oil sands projects generally need a WTI market price of $22-27/bbl in order to generate a pretax 10% internal rate of return (IRR). Mining projects need an estimated $25/bbl, while SAGD projects need at least $22/bbl owing to their sensitivity to natural gas prices. “For a typical SAGD project, we estimate that every 15-20% change in natural gas prices would increase the break-even oil price requirement by about $2-3/bbl,” the analysts said.

    Bitumen amenable to cold production methods “is heavier than conventional heavy oil but lighter than the oil sands bitumen that is recovered through mining and thermal stimulation methods,” NEB said. There are several thousand cold production wells in Alberta’s oil sands region with production rates of 19-284 b/d.

    “Typically, cold bitumen recovery wells have productive lives of 4-10 years with 60-70% of total recovered bitumen being produced in the first 3-4 years,” the report said. “A significant level of ongoing drilling is required to maintain production. Low capital investment and lower operating costs, because steam generation is not required, generally mean that cold production is more profitable than thermal methods.”

    Supply costs for cold production in the Wabasca and Seal areas are estimated at $10-14/bbl.

    However, the cold production process used in the Cold Lake region “involves the intentional coproduction of sand with oil, as it has become apparent that the exclusion of sand results in uneconomical production rates.” Management of the large volumes of sand and fluid waste produced through that process is a major component of operating costs, said NEB. Well workovers are more frequent and account for a greater proportion of supply costs than in conventional production, the report said. Operating costs are estimated at $6-9/bbl, with supply costs estimated at $12-16/bbl. NEB doesn’t expect substantial growth in cold production or significant changes in operating costs.

    Upgrading necessary

    The bitumen contained in oil sands is heavy at 8-14º gravity; high in viscosity at greater than 50,000 cp at room temperatures; high in metal concentrations; and high in carbon content relative to hydrogen in comparison with conventional crudes.

    Compared with typical crude oils that contain 14% hydrogen, bitumen is deficient in hydrogen. To make it an acceptable feedstock for conventional refineries, it has to be upgraded through the addition of hydrogen or the rejection of carbon. To be transported to refineries equipped to process it, bitumen must be blended with a diluent, usually condensate, to meet pipeline specifications for density and viscosity.

    Bitumen obtained through either mining or in situ production can be used directly for asphalt; diluted and transported by pipeline to refineries for processing; or upgraded into synthetic crude oil for input into refineries to be processed into gasoline, aviation fuel, or other products, said the AED report.

    “Syncrude and Suncor have upgraders on site north of Fort McMurray, and the Albian Sands mine is integrated with the Shell upgrader in Scotford to the northeast of Edmonton in Strathcona County. Stand-alone upgraders are located in Lloydminster and Regina,” it said.

    Oil sands costs

    Current supply costs for integrated mining and upgrading projects are estimated at $22-28/bbl for SCO, while supply costs for mining-extraction without upgrading are estimated at $12-16/bbl of bitumen. Those costs are expected to continue to decline as technologies improve and operators gain experience, said NEB.

    “Even though our industry is profitable, reducing our cost structure is one of the larger challenges faced by oil sands developers,” said Rulgrok. “Syncrude and others face a lot of pressures associated with the management of large capital projects. In fact, Syncrude recently announced a 35% cost increase for its Stage 3 expansion, bringing the total from $5.7 billion to $7.8 billion (Can.)”

    One challenge facing the industry is “the unpredictable price” of natural gas, which is used to make heat and hydrogen. “There’s also a challenge in making sure skilled trades are available when needed,” Rulgrok said. “Then there are regulatory issues such as process, timing, and duplication of effort between the federal and provincial governments. Access to new markets is the final uncertainty, but as long as pipeline expansion plans continue, market access should not be an issue.”

    New technology and better processes are crucial to reducing industry costs. “One example lies in the new technologies that will result in a 30% reduction in CO2/bbl of product by 2010 vs. the technology that was used in 1990,” Rulgrok said. “The trucks, shovels, low-energy extraction, and hydrotransport invented in Syncrude’s R&D labs...have resulted in 40% less energy being used to extract a barrel of bitumen. Both environmental and economic benefits are substantial.” Rulgrok also cited competitiveness benefits resulting from the North American Free Trade Agreement “and deregulation in general.”

    The oil sands industry is researching several methods for reducing supply costs for in situ operations by:

  • Reducing dependence on natural gas through improved efficiency of steam generation and implementation of new, less expensive sources of energy that may include nuclear, bitumen combustion, and gasification. “Nuclear energy appears to be a viable option from an economic viewpoint; however, major hurdles exist in terms of public and industry acceptance,” said NEB officials.

  • Increasing electricity transmission capacity out of the Fort McMurray area to permit wider incorporation of cogeneration plants.

  • Injection of solvents, with or without steam, to increase production rates.

  • Advancement of drilling technology to reduce costs and improve the accuracy of well placements in the reservoir.

  • Development of advanced computer simulations to better predict reservoir performance.

  • Steam-tracking technology for more efficient steam injection.

    “Natural gas use in oil sands operations is extensive. Gas costs can comprise up to 50% or more of total operating costs in a thermal in situ project,” NEB noted. Meanwhile, natural gas production from the Western Canada Sedimentary Basin appears to be flattening as North American demand for gas escalates. With continuous volatility in gas prices, NEB noted, “The economics of using natural gas as the primary source of fuel will become less attractive.”

    Challenges to oil sands

    Lehman Bros. analysts said, “Oil sands projects typically offer modest returns but very high asset values (the long project lives account for this). As a result, these projects are very sensitive to oil prices and capital and operating costs. Oil sands operators will face very substantial technical and environmental challenges.”

    The analysts cite these potential risks:

  • Oil sand projects have historically experienced cost overruns of 50%-plus. “Causes of these overruns have been attributed to labor shortages, engineering-related changes made during the construction phase, and the industry’s inability to effectively manage large- scale megaprojects, particularly ones that incorporate an upgrader.”

  • “Mechanical problems, especially ones associated with the upgrader, can temporarily result in lower production rates and reduction in product quality due to a necessary shutdown of an upgrader.”

  • Diluent supply might not be sufficient. According to the Alberta Chamber of Resource, gas condensate is expected to increase by 126,000 b/d, or almost 135%, from 2001 levels to 220,000 b/d by 2012.

  • A large surge in crude production or a fall in demand could reduce prices.

  • The dependency of oil sands projects on natural gas creates supply and price uncertainty. “We estimate that the oil sands industry is currently consuming about 800 MMcfd, or about 5% of total Canadian natural gas production,” said the analysts. “We estimate that natural gas usage could more than triple to 2.4-3.5 bcfd by 2015 if all projects are completed on time. This could cost the industry an estimated $5-8 billion (Can.)/year, assuming a flat $5/MMbtu Henry Hub, La., natural gas price and [an exchange rate of] 80¢ (US)/$1 (Can.).”

  • Oil sands producers face large environmental costs. They are required to protect and restore the environment through costly land reclamation as well as conduct constant water and air monitoring. The Kyoto protocol adds 20-35¢ (Can.)/bbl to costs of fully integrated oil sands projects.