An in-depth look at how in situ oil sands development has evolved
The past, present and future of in situ bitumen recovery
Early last century, entrepreneurs started looking for ways to monetize the oil sands, but the deeper lying deposits proved elusive – until recently. Today’s technology has led to a takeoff in in-situ bitumen production and some insiders point out: “You ain’t seen nothing yet”
The oil sands is all about innovation. Without new technologies, Alberta would still be sitting on a gigantic hydrocarbon resource with no economic value. Today this resource counts as the third-largest oil reserve in the world. Innovation may eventually make it the largest.
A hundred years ago, when A.F.A. Coyne formed Northern Production Co. Ltd., he did not know there were two trillion barrels of bitumen-in-place under his feet. He knew, of course, there was a lot of bitumen in the Athabasca basin but he was actually after something else – “free oil.” In 1915 he imported a cable-tool drilling rig all the way from Pennsylvania and with it he wanted to get at the light oil that presumably lay underneath the bitumen. You only had to drill through the bitumen to tap into the real prize below. Or so he thought.
It took years to haul this state-of-the-art rig along the largely roadless route from Edmonton to his site on the Athabasca River and start drilling. His quest ended, unsurprisingly, in disappointment. But thanks in part to Coyne’s failure, people have stopped fantasizing about pools of free oil swimming beneath the oil sands. The bitumen itself is the prize.
The legendary president of Sun Oil, J. Howard Pew was a risk-taker par excellence. When he decided to mine the oil sands, he famously declared: “This is a great challenge to the imagination, skill and technological know-how of our scientists and engineers … I am convinced that this venture will succeed, and that it will be the means of opening up reserves that will meet the needs of the North American continent for generations to come.” Pew’s Great Canadian Oil Sands (GCOS) project began commercial production in 1967 and eventually metamorphosed into Suncor Energy Inc., Canada’s largest energy company.
In a sense, the GCOS went after the low-hanging fruit: it mined the highest quality bitumen at the shallowest depths. Still, the challenges were immense. Almost all the aspects of the project – from recovery and extraction to upgrading and reclamation – required the development of new technologies specially adapted to the unique conditions of producing in this gigantic resource play. With their success, mining projects have become the international face of the oil sands. Pictures of overburden-laden trucks barreling across stripped landscapes are now the coveted oil sands porn of the industry’s critics.
However, those same critics do not stop to consider the technological advancements that have defined the history of the oil sands and allowed in situ production volumes to surpass mining and open up the lion’s share of the resource – 80 per cent of it.
One of the key people in this complex history wanted to kick things off with a bang. Manley Natland of the Richfield Oil Company hatched the stupendous idea of blasting bitumen reservoirs with nuclear radiation. To be precise, in the 1950s Natland tabled a plan that foresaw the detonation of small atomic bombs deep down under Richfield’s oil sands leases. He believed the carefully placed devices and timed explosions would create subterranean cavities into which the heated bitumen would collect and await extraction with conventional drilling techniques. Radiation leakage would be contained underground by a well plug.
At first Ottawa was enthusiastic. Alberta Premier Ernest Manning and his executive council also got behind the idea. And then when Washington gave the critical thumbs up, the U.S. government went ahead with the order and charged Richfield Oil $350,000 for one atomic bomb, shipping costs included. At 34 inches in diameter, the sleek bomb would have no trouble sliding down the 38-inch diameter borehole.
Thermonuclear in situ bitumen production was not to have its day however. In the early 1960s, the Cuban missile crisis, nuclear non-proliferation treaties and the international banning of underground nuclear testing made the Canadian public very anxious about all things nuclear. Government support eventually caved. Natland’s plan was ditched.
In the 1970s, shortly after the thermonuclear project was relegated to the dustbin of history, a brilliant engineer at Imperial Oil, Roger Butler, thought up a thermal oil sands recovery process called steam-assisted gravity drainage (SAGD). Auspiciously, at roughly the same time, the Alberta government established the Alberta Oil Sands Technology and Research Authority (AOSTRA), the precursor of today’s Alberta Innovates – Energy and Environment Solutions. This Crown corporation focused largely on the promotion of the research and development of recovery methods for deep-lying oil sands. SAGD became the province’s moon-shot.
In 1982, Butler was given the role of director of technical programs at AOSTRA and two years later its industry-supported SAGD pilot project – Underground Test Facility (UTF) – was initiated at a site 60 kilometers northwest of Fort McMurray. With the UTF, SAGD was starting to crawl, but it would take another 20 years before it could walk on its own.
The technology behind Butler’s innovation involves drilling two stacked horizontal wells into the bitumen payzone – a feat that was only made possible by contemporary advancements in directional drilling. Steam is then injected into the upper wellbore, thereby mobilizing bitumen in emulsion form toward the lower production well and up to surface processing facilities.
With money and brains behind it, SAGD technology advanced steadily up the development cycle. In 1996 the first commercial SAGD project was built at Foster Creek and, six years later, reached first production. At last, AOSTRA got its man on the moon. Securities regulators took notice and understood that this meant vast swaths of deep-lying bitumen (under 250 feet) could now be economically recoverable. In December 2002, Houston-based Oil & Gas Journal released its authoritative estimates of global petroleum reserves where it raised Canada’s total proved oil reserves (including conventional) nearly fortyfold from 4.9 to 180 billion barrels.
Butler’s SAGD meant a quantum leap forward in boosting the oil sands’ resource-to-reserve ratio. But the oil sands reserve figure of approximately 170 billion barrels still considered 90 per cent of the resource-in-place out of reach. There were many very tricky reservoirs with fruit too high to pick. These ranged from reservoirs with low pressure gas caps (14 billion barrels bitumen-initially-in-place or BIIP); those lying at an intermediate depth, too deep to mine and too shallow to drill (18 billion BIIP); and those lacking sufficient cap rock (36 billion BIIP); or that were too thin (410 billion BIIP). The most alluring of these hard-to-get-at reservoirs aren’t really oil “sands” at all but bitumen deposits in carbonate rocks and limestone. Loosely referred to as “carbonates,” their initial-in-place size is a staggering 477 billion barrels.
SAGD technology continues to branch out into different areas, each customized to solving specific reservoir challenges. According to Reynold Tetzlaff, national energy leader at PwC, today’s oil sands innovation trends show “an alignment of economic and environmental imperatives.” In other words, economic and operational gains are not cannibalizing environmental performance, but deepening it. Innovators in the field of thermal recovery are striving to reduce operating costs largely by bringing down a project’s steam-to-oil ratio (SOR). A lower SOR is achieved by burning less natural gas to gasify water and this, in turn, reduces emissions and water use.
A look at some innovation trends points the way to the more economically viable and less environmentally disruptive future of the oil sands industry.
The co-injection of solvents, usually natural gas liquids, with the steam represents a highly promising development of unconventional SAGD. This process not only increases oil recovery per well but also decreases the SOR. The exact timing and composition of the solvent is critical and must be optimally matched to the unique characteristics of each individual reservoir. Naturally, the supply prices of the solvents and natural gas – and their costs in relation to each other – are key determinants of the economics of this approach.
Many companies are developing their own carefully guarded solvent co-injection technologies, and each one has a catchy name. For instance, Connacher Oil & Gas speaks of SAGD+, MEG Energy of eMSAGP (enhanced modified steam and gas push), Imperial Oil of solvent-assisted SAGD and Laricina Energy of solvent cyclic SAGD.
Calgary-based E-T Energy is applying an electric multiphase heating technique to its oil sands holdings. Though perhaps inspired by SAGD, it involves neither horizontal well pairs nor steam injection. Called Electro-Thermal Dynamic Stripping Process or ET-DSP, E-T Energy’s technology involves inserting electrical elements into vertical wellbores spaced in a grid configuration. A current is passed between the elements in water-saturated reservoirs and, as a result, the bitumen is heated and its viscosity lowered so that it can flow to a separate production well. Since no steam is required, the process requires little water and produces less greenhouse gas. ET-DSP shares similarities with Athabasca Oil Corporation’s thermal-assisted gravity drainage (TAGD), a thermal conduction (read waterless) recovery method that is being applied to the above-mentioned carbonates.
THAI stands for Petrobank Energy and Resource’s toe-to-heel air injection in situ recovery process. Like TAGD, no steam is involved, but THAI relies on pumping air downhole through a vertical well so that the combustion of a portion of the bitumen melts the rest which, in turn, flows to a horizontal production well. And like ET-DSP and TAGD, the process is intended to radically drive down greenhouse gas emissions and water use.
There are many R&D projects in the area of in situ thermal recovery, but there is also much head-shaking from critics who think oil sands innovation is proceeding much too slowly. They look at IT or the pharmaceutical industry and wonder why Suncor and Cenovus Energy Inc. can’t bring out new technological marvels with the same dizzying speed as Apple and Pfizer. Roger Butler dreamt up SAGD back when Steve Jobs and Steve Wozniak brought out the Apple I home computer, but operation managers at oil sands companies claim that SAGD is still “in its infancy.”
Robert Skinner, interim executive director of the Canada School of Energy and Environment, scoffs at the criticism. He points to northern Alberta’s harsh climate that severely restricts the opportunity window when on-site testing can occur. Moreover, the capital requirements are immense, with each test well costing millions. Moreover, with billions of dollars at risk, project developers often prefer to stick with the tried-and-true than with the sleek-and-new.
Then there are the conflicting interests of the many parties involved in innovation. Skinner describes the oil sands as “big skunk work” with lots of experimentation and trial and error hiccups. But when oil prices head south, enthusiasm for expensive experiments drops quickly. “Then the beakers [Skinner’s name for innovators] get shoved aside by the production engineers who are under pressure to show numbers for the next quarterly results. And investors themselves are not out there thinking about the latest twist on some SAGD wellhead configuration. Investors don’t care about that.”
At the end of the day, funding such innovation only makes sense if oil sands projects bring adequate levels of risk-adjusted investment returns. Today this depends largely on how effectively bitumen crude shippers can access prime markets. Thanks in no small measure to SAGD (and its technological cousins like cyclic steam stimulation), cumulative oil sands production is projected to reach 5.2 million barrels per day by 2030. That forecast may prove too optimistic if takeaway infrastructure is not put in place. On the other hand, if producers can get premium prices and thereby smartly boost netbacks, the development pace of in situ recovery innovation is poised to barrel full steam ahead.
* February 12, 2014: An earlier version of this article incorrectly attributed development of thermal-assisted gravity drainage. Athabasca Oil Corporation is the actual developer and patent-holder of this technology. Alberta Oil magazine regrets the error.
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