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By Robert Rapier on Dec 2, 2013 with 13 responses

How Alberta’s Oil Sands are Produced


I spent the first week of November in the heart of the Athabasca oil sands around Fort McMurray, Alberta. I was there as a guest of the Canadian government, which hosts annual tours for small groups of journalists and energy analysts. In the previous two articles, I covered some of the environmental issues arising from the development of the oil sands.

In Oil Sands and the Environment – Part I I discussed greenhouse gas emissions, impacts on wildlife, and I touched upon water usage. I also detailed some of the work of Pembina Institute (PI), which is working to improve the environmental conditions as the oil sands are developed. In Oil Sands and the Environment – Part II I covered the tailings ponds, water consumption, impacts to water quality, and impacts to indigenous people.

Today I want to discuss the actual process of converting the oil sands into oil. Some may feel that this should have been the first article I wrote, but because the development of the oil sands is environmentally controversial on many fronts, I thought it was important to go over environmental issues first before discussing the process. I think that if I had covered the process first, most of the comments and questions would have been about the environmental issues.

First, I want to provide readers with a general overview of the situation in Alberta. I will discuss the two major methods of producing the oil sands — surface mining and in situ production — illustrated by the two companies that we visited on this trip: Canadian Natural Resources Limited (NYSE: CNQ, TSE: CNQ) and Cenovus Energy (NYSE: CVE, TSE: CVE). I will devote next week’s column to the energy return on energy invested (EROEI) and the cost of production of oil sands production based on information gathered on my trip, with a focus on data from Cenovus and Canadian Natural Resources.

Overview of Canada and Alberta

Canada produced 3.9 million barrels per day (bpd) in 2012, making it the fifth largest oil producer in the world. Canada is also the fifth largest global natural gas producer at 15 billion cubic feet (Bcf) per day.

Alberta has a population of 4 million people, and is Canada’s primary oil- and gas-producing province. Alberta’s economy is highly dependent on oil and gas. It is situated next to its more liberal neighbor British Columbia, which is a bit like having Texas border California.

Alberta accounted for 2.5 million bpd of Canada’s oil production, and 10 Bcf/day of Canada’s gas production last year. Alberta’s share of Canada’s oil production is expected to grow substantially over time. The province supplied 22 percent of US crude oil imports in 2012, a larger contribution than from any country outside of Canada.

Canada has the third-largest oil reserves in the world — more than Iran or Iraq. Of the 173 billion barrels of Canadian reserves, 169 billion barrels are from oil sands, which are a mixture of sand, clay, water, and bitumen – a very heavy oil.

Of the world’s oil reserves, 80 percent are state-owned or controlled. Only 20 percent of global reserves are accessible to independent oil and gas companies, and half of those are in Canada’s oil sands.

Alberta’s oil production has been growing by about 170,000 bpd each year, and a production increase of about 1.8 million bpd is forecast by 2022. There is some shale gas and tight oil in the central and southern part of the province, away from where oil sands are located. There have not been any forecasts made on future tight oil production in the province, as it is still at a pre-commercial stage.

Alberta’s goal is to be in the top quartile for conditions favorable for investing in the oil and gas industry, and to grow oil sands from its current market share of 2.1 percent of global oil consumption. Canada’s oil sands saw $25 billion (Canadian) of investment in 2012, versus $20 billion for conventional oil and gas. Historically most of the investment has originated from Canada, the US and Europe, but investments from Asia have increased substantially in recent years. Foreign countries with investments in Alberta’s oil sands include China, Japan, Korea, Thailand, Norway, France, UK and the Netherlands.

If Alberta were a US state it would be the third largest by area, just barely behind Texas. The oil sands deposits are spread across an area slightly larger than New York state. Of the nearly 55,000 square miles of oil sands formation, 1,853 square miles have been identified as being close enough to the surface for mining. To date, 276 square miles have been disturbed by surface mining, and 27 square miles are under active reclamation.

Alberta_Map_with_Legend_Nov_2011Source: Government of Alberta

Surface Mining

Most of the oil sands production thus far has come from surface mining, and this is the technique that has attracted the most environmental criticism. Surface mining is feasible when the oil sands are relatively close to the surface. In order to produce oil sands from surface mines, any harvestable timber is sold and the overburden — which consists of 30 to 40 meters of peat, clay, and sand — is removed and set aside for future reclamation. The oil sands are then removed from the open pit and placed in dump trucks capable of carrying loads of 400 short tons. The trucks themselves weigh 250 tons, so a fully-loaded truck weighs 1.3 million pounds.

Horizon - truck at Ore Prep Plant
Truck unloading oil sands at Horizon oil sands site. Source: Canadian Natural Resources

The trucks transport the ore to a processing facility where it is dropped into a crusher, mixed with hot water, and then piped to the plant. The mixture is put into large separation vessels where the bitumen is removed in the top layer, and the bottom layer of sand and some residual bitumen is sent to the infamous tailings ponds where it will eventually be buried, before the land above the tailings pond is eventually reclaimed (after 30-40 years of use). The recovery rate for bitumen from surface mines is over 90 percent.

Horizon Aerial - plant site
Aerial view of the Horizon oil sands facility. Source: Canadian Natural Resources Ltd.

Bitumen recovered from oil sands can be upgraded through various processes to a lighter oil (syncrude), as well as to products such as naphtha, diesel, and gas oil. Alternatively, the bitumen can be mixed with a diluent like naphtha to form dilbit, which can then be transported by pipeline or rail. (Unheated bitumen has a consistency like tar, and has to be upgraded, diluted, or heated to flow).

Companies involved in surface mining of oil sands include Canadian Natural Resources, Suncor Energy (NYSE: SU, TSE: SU), Canadian Oil Sands (TSE: COS), and Imperial Oil (NYSE: IMO, TSE: IMO). The Muskeg River mine is a joint venture between Shell Canada (60 percent), Chevron Canada (20 percent), and Marathon Oil Canada (20 percent).

In Situ Production

But the vast majority of future oil sands growth is expected to come from in situ (Latin for “in position”) production. As of January 2013 there were 127 operating oil sands projects in Alberta, and only 5 were mining projects. Production from both methods is expected to continue to grow, but the vast majority of the oil sands resource is too deep to be mined. Thus, most future production growth will be in situ production.

CERI In Situ Graphic
Expected oil sands production growth. Source: Canadian Energy Research Institute

In situ production involves injecting steam into the ground to enable the oil to flow freely. The oil is then pumped to the processing facility. In situ production has the advantage of a much smaller surface footprint, since it doesn’t require the removal of overburden from the surface above the deposit. Nor does it require extensive tailings ponds.

There are two primary methods of in situ bitumen production. Cyclic Steam Stimulation (CSS), or the “huff-and-puff” method, was first used commercially in Alberta by Imperial Oil at Cold Lake in 1985. This technique involves the injection of steam into the formation for a period of time, followed by an extraction period in which the oil is pumped out. When the oil flow slows to a certain point, steam is once more injected. This cycle continues until the well is no longer economical. (One reader wrote to point out that CSS was behind this environmental mess where oil came bubbling up through the ground in Alberta).

The other in situ method is called steam assisted gravity drainage (SAGD), and it was enabled by the same horizontal drilling improvements that enabled the hydraulic fracturing revolution. SAGD was first commercialized in 2001 by Cenovus at Foster Creek, and its commercial application was the single biggest reason that Canada’s oil reserves more than quadrupled in the past 20 years. Once a technique makes it both technically viable and economical to produce a resource, it can be placed in the reserves category. Again, this is a similar situation to fracking, where resources in places like the Bakken and Eagle Ford became reserves when fracking made them economical to produce.

SAGD involves drilling a pair of horizontal wells, one about 5 meters above the other. Steam is injected into the upper well for months to heat up the bitumen. I learned from Cenovus that its initial projects required the company to inject steam for 18 months before producing oil, but as the engineers progressed up the learning curve the timing has been reduced to three months of steam injection prior to production. Steam injection continues throughout the life of the well, until the well begins to deplete. At that time steam injection ceases, but the wells continue to produce for a little while in this final phase of production. Once the wells start to produce, they have tended to produce almost without depletion for 10 years (a situation very unlike fracking, where wells initially deplete rapidly). The water that condensed when the steam was injected is also returned, separated from the oil, and reused in the process.

The horizontal wells can be drilled for miles in many directions from a single well pad, and as a result a large land area can be accessed without a huge environmental impact on the surface. A well pad such as the one I visited below can produce nearly 20,000 bpd of bitumen for 10 years before depletion begins to curtail production.

Cenovus Well Pad
Cenovus SAGD well pad with nine well pairs. Source: Cenovus.

The advantage of SAGD versus surface mining is that the environmental impact is much smaller. The disadvantage is that the recovery rate from SAGD is much lower than for surface mining, with recovery factors for the oil in the range of 60-70 percent.

There are certainly environmental issues as documented in my previous two articles, but based on what I saw on my trip oil sands production growth is poised to remain high unless oil prices collapse. SAGD will lead the way, but production via surface mining is also expected to remain strong for the next two decades.

In next week’s article I will take a more in-depth look at the two companies that I visited on this trip — Cenovus Energy and Canadian Natural Resources Limited — and delve into their production costs and energy balance of their process. Following that, I will examine the logistical issues of getting the oil sands to market, including the impact of the Keystone XL decision (regardless of which way it goes).

Link to Original Article: How Alberta’s Oil Sands are Produced

By Robert Rapier. You can find me on Twitter, LinkedIn, or Facebook.

  1. By Forrest on December 2, 2013 at 8:55 am

    Are you sure about SAGD process well 5 meters apart? What diameter are these wells? Do they plumb steam to formation or do they dead head pressure the entire well? It must be a process that utilizes pressure. The formation pressurized and the retrieval is vacuum or ambient pressure. Three month heating period is impressive, considering a ten year harvest. The capture/harvest rate is low as compared to open pit mining, wish they could get that up to 90% and double oil recovered per station. I did read that region of Alberta has impressive geothermal energy. One big spot that could produce 200 deg C steam at well dept of 5 km about 200 km straight west of Fort McMurry. That is about as good as it gets. If petro companies could ever utilize that energy for liquifying the oil sands that would be a positive environmental development. Plus a future resource for electric power generation. BTW, the latest environmental global warming pollutants shift natural gas to as damaging as coal. Yeah, the science of global warming infallible per politics, yet within reality just at the cusp of the beginning to understand the myrid complexities of solar, biological, physics, etc. Also, the backup power for wind turbines not that green and negates the “green” advantage of wind. The cost for wind such as tax breaks, grid extension, backup power increase costs 6x more than advertised cost or about $.18/kwh. So, the greenest source from steady producers of power such as hydro and geothermal or the bio-mass that can be located closer to populations.

    • By Robert Rapier on December 2, 2013 at 1:13 pm

      “Are you sure about SAGD process well 5 meters apart?”

      Yes, according to what we were told, the wells in the well pair are 5 meters apart, with the steam well above the production well. Individual well pairs are more than 5 meters apart. My understanding is that the injection wells are perforated to allow the steam to seep into the ground. No idea how large the diameter of the wells is.

      Your questions remind me that I should put the recovery rate in for SAGD do. Going to edit and include that.

  2. By TimC on December 2, 2013 at 9:57 am

    Thanks for this very informative series, RR. What fuel do they burn to generate steam for SAGD at a well pad like the one pictured? I’m also curious about desulfurization of the heavy bitumen. Do they use hydro-desulfurization, and if so, where does the H2 come from? Did you get a look at the giant sulfur pyramids near Ft. McMurray?

    • By Robert Rapier on December 2, 2013 at 1:09 pm

      They burn natural gas for the steam. They have lots of that apparently; they are shutting in production because it isn’t profitable to sell it. The surface mining guys do use desulfurization; again they H2 comes from natural gas reforming. And I did see mountains of sulfur from the air. I took some pics with my phone but they didn’t turn out too well.

  3. By big john on December 2, 2013 at 5:22 pm

    Is there any good data on productivity per acre for the mining operations? To me, when looking at land impacts, it makes most sense to compare oil sands mining with western coal mining (e.g., Powder River Basin), since they are pretty similar operations. Using some general information, a few years ago I calculated that as much as 5-6 mil gal/acre? Does that sound like it is in the ballpark?

  4. By ben on December 3, 2013 at 9:42 am

    Glad to see this piece in Peak Oil News. You are providing a public service here and the decision to cover enviro issues up front was wise. Canada’s energy reserve stats speak for themselves. The country is becoming an economic power and that largely flows out
    of Alberta’s status as a major energy producer. The scope of investment in the province in the past decade to expedite in situ production has propelled growth and this is certain to continue given support among the citizens and politicians of the province.
    Canada is emerging as an integral part of hemispheric leadership and their commitment to growing their naval force projection capabilities is further evidence of convictions to protect their sovereign interests. Defense of artic boundaries and supervision of foreign powers in their waterways, to include the US, is further evidence of their new-found stature. These are developments that we should acknowledge and applaud, as we are blessed to have such freedom-loving neighbors sharing with us the longest contiguous border in the world.
    Thanks for the solid field work, RR.

  5. By Karla Labrecque on December 3, 2013 at 1:06 pm

    From the front lines of the Canadian oil fields . . . What message does it send to the world about Alberta’s oil sands production when Baytex Energy is forcing my family and our neighbours from our homes through open venting its oil sands processing tanks? Penn West and other Alberta companies capture their oil sands gasses and run closed systems: why won’t Baytex take the same responsibility? Help us get back into our homes. Breathable air and a thriving energy sector are not mutually exclusive. Canada can do better. Facebook at

  6. By Igor Udovenko on December 3, 2013 at 5:34 pm

    Great article. I have one question – does mined bitumen necessitate the use of upgrading? Or can the mined bitumen just be heated, diluted and exported like dilbit?

    • By Robert Rapier on December 3, 2013 at 5:41 pm

      Yes to the latter. I think the reason they upgrade it is that they have to put in significant infrastructure to separate the bitumen from the water, and it isn’t that much of a stretch to then just upgrade it. But there is no technical reason that they have to do so.

  7. By on December 7, 2013 at 7:59 pm

    We’ve just opened a new office in Fort McMurray and this is the exact same experience we’ve over the past few months. Cold up here now though!

  8. By Benjamin Cole on December 7, 2013 at 11:48 pm

    Excellent blogging.

    I would like to see RR take a look at American shale oil, and tell is who is right about the medium-term?

    Shale oil production will begin to tail down, or will rise for many years?

    I say medium-term, as I have learned in the long-term all bets are off…stuff happens.

    My guess is that the optimists are right—people just get better and better at extracting fossil furls. But an RR look would be try worthwhile….

  9. By L e s on March 16, 2016 at 6:51 pm

    Actual COST per barrel ??
    Please respond !

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