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Feature: Here’s Where the Next Barrels of Alberta Oil Sands Production Will Come From

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Within the next two to five years, oil sands production will ramp up significantly considering the lack of capital expenditures in recent years


The next five years will be a crucial period for oil sands producers. According to the International Energy Agency, oil sands production will grow by 800,000 b/d over the next five years as existing projects are expanded and new projects are brought online. Most of this production is a sure thing, as oil sands producers try to look past the ugliness of oil markets in the near term and consider expansion of their future production profiles.

Beyond 2021, though, there is uncertainty about where oil sands expansion will happen—or rather if it will happen at all in a significant way. In its latest production forecast, the Canadian Association of Petroleum Producers predicts the oil sands will exceed 3.6 million b/d by 2030, up from 2.3 million b/d in 2015. That 1.3 million b/d of production growth is significantly below its 2015 forecast of 2.4 million b/d, and underscores the huge amounts of capital expenditures that have been pulled out of international oil markets in recent years. CAPP says in the report “an average annual growth of 128,000 b/d is forecast for oil sands production from 2016 through to 2021, after which the rate of growth slows to less than half this rate, or 59,000 b/d.” While the projection is anything but bullish, there is still a fairly significant volume of new production expected to come online in the next five years. The following is an overview of where those new barrels will come from, and when.

Medium-term build-out

Within the next two to five years, oil sands production will ramp up significantly considering the lack of capital expenditures in recent years

Kearl • Imperial Oil



Imperial completed the expansion of its Kearl mine in June 2015, which is doubling near-term production to 220,000 b/d. In the first quarter of 2016, the company posted an average production at Kearl of 165,000 b/d. The latest expansion of the mine involves using a froth treatment process that thins bitumen and allows it to flow, effectively eliminating the need for an upgrader.

Fort Hills • Suncor Energy



After many delays, Suncor Energy, Total and Teck Resources announced in 2013 the $13 billion project would finally go ahead as planned. In September 2015, as oil prices continued to languish, Total announced it was selling its 10 percent stake to Suncor Energy. Analysts and industry observers have openly speculated whether Fort Hills could be Alberta’s last mega mine oil sands project.

Foster Creek • Cenovus Energy



What began as Cenovus’s first oil sands pilot project at Cold Lake, Alberta, in 1996, has gone through several stages of additional development since. Foster Creek is a multi-phase SAGD project—the first commercial SAGD project in the oil sands—with a very low steam-to-oil ratio (SOR). A timeline for the completion of Foster Creek’s 30,000-b/d Phase H expansion, which was slated for 2017, is currently unknown, while Phase G is expected to start producing oil in the third quarter of 2016.

Christina Lake • Cenovus Energy



Before oil prices began to plummet, Cenovus Energy was one of the industry’s best-positioned oil sands producers. And while it is still in a position of relative strength, the company was forced to put its steam-driven Narrows Lake development aside in favor of its flagship projects Christina Lake and Foster Creek. The Phase F expansion at Christina Lake is expected to be completed later this year, while the 50,000 b/d Phase G expansion is on hold.

Horizon Oil Sands • Canadian Natural Resources



Canadian Natural Resources devoted $2 billion toward completing the construction of its Horizon project in 2016. Construction consists of the 45,000 b/d Phase 2B expansion, slated for completion in 2016, and the final 80,000 b/d Phase 3 expansion, completed in the fourth quarter of 2017. The project was originally scheduled to be nearly double the capacity of its current completion in 2017, but was scaled back amid lower oil prices. Horizon suffered severe cost overruns during past expansion phases, but the company says its current construction is on time and on budget.

Sunrise • Husky Energy



Husky was forced to shut down its steam-driven Sunrise development following the Fort McMurray wildfires. The company still hasn’t set a timeline for the next two phases of expansion at the project.

A tool for every job

Most new production following 2021 is expected to come from in situ developments, which are using a suite of new technologies to develop oil more cheaply and efficiently

Solvent-assisted steam-assisted gravity drainage (SA-SAGD)

Aspen • Imperial Oil

Imperial Oil has long experimented with solvent production at Cold Lake, and it has recently come close to commercializing a solvent-assisted (SA-SAGD) process that the company says could materially boost efficiency. Imperial applied to the AER to move the SA-SAGD production to the commercialization stage, and expects to make a final investment decision in 2017.

Solvent-Aided Process

Christina Lake • Cenovus Energy

The solvent technology, similar to a number of other solvent-based in situ technologies, injects natural solvent such as butane along with steam to improve reservoir recovery. Cenovus is currently piloting the technology at Christina Lake, and had plans to commercialize the technology at its Narrows Lake development before the project was put on hold.


MacKay River • Suncor Energy

The SAGD LITE technology involves adding “surfactants,” or what it describes as soap-like additives, to its steam before injection, improving reservoir yields. The company began testing on three well pairs at its MacKay River project in 2013, and has continued tests on various other pilot wells at its Firebag and MacKay River developments.

Enhanced Solvent Extraction

Dover • Suncor Energy; Harris; Devon Energy; Nexen Energy

The technology basically replaces the need for water with electromagnetic heating (it also goes under the acronym ESEIEH). It essentially distributes radio waves through a reservoir using a patented antenna technology, which melts the bitumen in place. After the bitumen is heated, a solvent is added to allow it to flow up a production well. The consortium started working on the technology in 2011, and the first field test ran in 2012 at Suncor’s Steepbank mine facility. Its most recent pilot at Dover is expected to last two years.

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