About 60 kilometres northwest of Fort McMurray, there used to be a 109-foot-tall steel headframe that housed the hoist system for Alberta’s only deep hard rock mine. A three-metre-diameter shaft used to plunge an elevator 200 metres through the earth, landing in a set of tunnels in a limestone layer just below the bitumen-rich McMurray Formation.
It used to be the Underground Test Facility (UTF), where the oilsands game-changing technology SAGD was born.
In the 1980s, the Alberta Oil Sands Technology and Research Authority (AOSTRA) laid out $35 million to take on its doubters and build the UTF to test the merits of horizontal drilling and gravity drainage in the oilsands using the concept of SAGD. The technology was developed by Roger Butler, a chemical engineer with Imperial Oil.
They had to go underground because there wasn’t yet the technology to drill from the surface.
Thirty years later, horizontal drilling is the least of SAGD’s challenges, and the majority of the oilsands industry’s future growth profile hinges on how this now-standard extraction method can be improved.
For its part, the UTF is now closed. Literally. Almost 5,000 metres of concrete seals the access shafts, forever entombing this historic place.
In the 1970s, the oilsands was a surface mining game, but keen observers in government and industry knew that the massive potential of Canada’s bitumen resources went far beyond moving dirt.
In 1975 the Alberta government established AOSTRA, with a key part of its mandate to find and coordinate development of in situ oilsands technologies. Clement Bowman, who had been working in a senior research position with Imperial Oil for more than a decade, became the founding chair.
In 1978 Bowman, his vice-chair, Maurice Carrigy, and the AOSTRA board received a paper from Norwest Corporation’s founder, Gerry Stephenson, detailing how SAGD—not yet extensively tested—could be successfully applied. It was Stephenson’s contention that SAGD would work best with pairs of horizontal wells drilled from shafts and tunnels beneath the bitumen-bearing formation. Bowman and Carrigy liked the idea and invited industry to join the project but were met with deafening silence.
Under Bowman’s leadership, AOSTRA took a bold step—for the only time in its history, the government agency paid the full price for Phase 1 of a pilot project. The resulting UTF, considered by Bowman to be the “jewel in AOSTRA’s crown,” proved that SAGD would work. Although it may not have been apparent at the time, the venture provided the most important technology development in the oilsands industry since the commercialization of Karl Clark’s hot water bitumen separation process.
The first SAGD project was commercialized in 2001 at Foster Creek by a Cenovus Energy predecessor, the Alberta Energy Company.
SAGD and the future
SAGD currently accounts for about 80 per cent of Alberta’s in situ oilsands production, with the remainder of volumes produced via cyclic steam stimulation. Overall, SAGD technology is responsible for about 40 per cent of total oilsands production of about 2.7 million bbls/d, while mining operations produce about 52 per cent.
There are currently five SAGD projects that produce in excess of 100,000 bbls/d.
The technology has had incredible benefits, but industry recognizes it has to be improved and adapted in order for the oilsands to continue growing as oil remains stuck near $50/bbl and greenhouse-gas reduction becomes increasingly important.
Producers and suppliers are developing technologies to make new SAGD projects competitive with other oil plays, including U.S. shale development, in terms of both the cost and the environmental footprint as the price of oil remains low.
This will be enabled by a combination of incremental new technologies, game changers and systems that fit somewhere in between, CIBC Equity Research noted in early 2017.
“The goal for oilsands producers today is to lower supply costs and improve environmental stewardship while supporting oilsands development,” CIBC analysts wrote.
“These goals will be achieved by a spectrum of applications, ranging from simply better ways of doing things with less steel and fewer energy inputs to radically new recovery schemes.”
In particular, systems that either co-inject solvents with steam or inject solvent alone, offering dramatic reductions in water use, greenhouse gas emissions, capital and operating costs have potential.
While the UTF was decommissioned and sealed with concrete in 2013, the Dover site continues to be used for collaborative in situ technology testing, including Nsolv’s pure solvent technique and enhanced solvent extraction incorporating electromagnetic heating.