25 years of oilsands lessons position a powerful industry for the future; this article was first published here
By Peter McKenzie-Brown
Twenty-five years ago the oilsands business was a different kind of cat from the tiger we know today. The pieces were all in place for the global juggernaut the industry has become, but few could have imagined that a quarter-century later this largely overlooked sector of Canadian oil and gas would be the dynamo behind the country’s economy.
In 1987, the oilsands was seen primarily as megaproject mining operations requiring government assistance to proceed. Although Esso Resources had just begun operations at its ground-breaking Cold Lake in situ project, underground production was not seen as too promising. While the Canadian Petroleum Association (the forerunner to today’s Canadian Association of Petroleum Producers) promoted oil as a possible “engine of growth” for the economy, there was little thought that the oilsands would play a serious role. Languishing at around $15 per barrel, oil prices and existing technology did not justify development anywhere approaching the potential scale recognized today. But each of those factors has changed, beginning with the end of government subsidies for mining operations.
The collapse of government subsidies
In 1987, the oilsands operations of Suncor Energy Inc. and Syncrude Canada Ltd. were well underway—Suncor for 20 years and Syncrude for seven. However, both had remained in the planning stages until conventional oil shortages began to be anticipated, and the scale of both had been increased to compensate for the high cost of development. The two mining projects received special inducements from government, which included exemptions from the existing prorationing system. Effective in 1978, both were also exempt from price controls on crude oil, and both received concessions in respect to financing and taxation. In addition, in 1975 Canada, Alberta and Ontario provided cash infusions to keep Syncrude alive.
However, Syncrude was the last of the subsidized megaprojects. When the next round of mine-based projects began to appear more than two decades later, they were part of a new world order.
Several large projects were bandied about in the 1980s. One was Canstar Oil Sands Ltd. A joint venture between Petro-Canada and Nova Corporation, in 1980 the idea made a brief appearance before fading into oblivion. Sandalta—a Gulf-led megaproject for the Wabasca region—inspired fewer headlines before biting the dust.
Shell proposed Alsands in 1978, budgeted at $5.1 billion. The project was designed to produce 137,000 barrels per day of synthetic oil; to have a 30-year project life; and to begin operations in 1986. The Conservation Board gave the project the green light in December 1979 and the participants began site-clearing and other preliminaries for project development the following month. Less than a year later, because of worries about the federal National Energy Program (NEP), the consortium halted construction. By that time the completed project was budgeted at $13 billion.
Despite last-ditch efforts by the Alberta and federal governments, the economic window had closed. According to then-premier Peter Lougheed, “The day Alsands died was a tough day. In fact, one friend of mine said the last day of April 1982 was one of the worst days politically in a rather dismal time, because we’d gone through the downturn of the 1981-82 winter; we’d had a separatist chosen in a by-election in February. Then came the crusher: Alsands collapsed.”
The last gasp of old-style oilsands development began in 1981, when a consortium formed to develop the $4 billion-$5 billion OSLO (Other Six Lease Operators) project. OSLO’s original plan would have used Syncrude-like technology for a 77,000-barrel-per-day facility. The project would have included a mine and extraction plant 80 kilometres north of Fort McMurray and an upgrader at Redwater, 60 kilometres northeast of Edmonton.
The economics seemed feasible at first because world oil prices stood at around $30 per barrel. In 1986, oil prices collapsed to $10, however. This crushed a petroleum industry that was already cash-poor because of high taxes, royalties and price controls from the NEP years.
Political reactions kept Alsands alive. Anxious to help the province recover from a collapse in real estate prices, Alberta’s Don Getty government was willing to help. So were the feds. Heading into an election the following year, the federal government’s 1987 budget earmarked several billion dollars for energy projects, from Newfoundland (Hibernia) to Vancouver Island (a natural gas pipeline.) For OSLO, the government set aside $1.7 billion.
The business climate changed dramatically after the election, however. The 1989 U.S.-Canada Free Trade Agreement included an energy-sharing pact and opened doors for direct investment by U.S. oil corporations in Canada. These provisions were grandfathered into the 1994 North American Free Trade Agreement.
When Getty—never a popular premier—was replaced in 1992 by the market-oriented Ralph Klein, discussion about public grants for private enterprise stopped. This was the death knell for OSLO. Given the tumultuous events of that era, it is astonishing that it had stayed alive for more than a decade. And given the gloom when the project collapsed, it is ironic that prosperity in the sector would come so soon.
The emergence of market-based policy
In 1993, the Alberta Chamber of Resources initiated the Oil Sands Task Force, which helped create energy policy that would work within a market-based economy. It proposed encouraging investment in the oilsands by getting the two levels of government to change their tax and royalty regimes.
Ralph Klein (premier since 1992) and Jean Chretien (prime minister since 1993 and previously a federal energy minister) responded quickly to this report. They agreed to extensive tax breaks for oilsands development. Companies could write off 100 per cent of their capital costs, including overruns, in the year they were incurred. The provincial government’s incentive package included a one per cent royalty on oilsands revenues until capital costs were paid off.
The outcome was a flood of oilsands spending in the province. Once a modestly successful subsidiary of United States-based Sun Oil Company Limited, Suncor—which had become an independent Canadian company in 1992—began a series of mining and eventually in situ expansions that eventually made it Canada’s largest petroleum company. Syncrude also announced large expansions. Notably, both of these oilsands giants replaced their clunky old bucketwheels, draglines and conveyors for more agile truck-and-shovel technology for oilsands mining and hydrotransport to move the bitumen to processing facilities. These steps cut costs and increased efficiency.
In 1999, a Shell-led consortium began its Muskeg River Mine oilsands development—better known as the Athabasca Oil Sands Project (AOSP). The project went on stream in 2003. Construction of Canadian Natural Resources Limited’s Horizon project began in 2005, with the first phase completed in early 2009.
Even the financial crisis of 2008 did not slow growth in the oilsands sector. At the end of last year, 43 large projects were in the works—operating, under construction or with regulatory approval. Costs ranged from $100 million for Value Creation’s TriStar in situ pilot project, to nearly $20 billion for the two phases of the Kearl oilsands mine being developed by Imperial Oil Limited and ExxonMobil Corporation.
In situ hits its stride
By 1987, Esso had developed an extremely valuable production technology for its extensive Cold Lake holdings. The company developed cyclic steam stimulation (CCS) in the 1960s and 1970s, and that technology became the mainstay of its giant project. In the Peace River deposit, by 1985 Shell was also operating a variation on the technique.
After delays and changes because of the NEP, in 1983 Imperial proposed to develop its Cold Lake project in 16 separate phases of development. The first six phases went on stream in 1986, and the company let economic conditions dictate additional development. By 1991 the project’s average daily bitumen production was 90,000 barrels per day.
As the 1990s continued, Imperial began to experience a steady decline in conventional crude oil production. Rather than invest in the additional equipment required to extract more oil from old fields, Imperial sold off a number of these properties and stepped up production at Cold Lake. By 1997, almost half of Imperial’s net crude oil production came from Cold Lake and another 21 per cent came from its 25 per cent interest in Syncrude. Esso’s emphasis on expensive-to-extract bitumen during a period of lower oil prices put the company at risk. Corporate concern was so deep that, when oil prices crashed below $10 per barrel in 1998, the company suspended expansion at Cold Lake.
Rather than upgrade production into synthetic oil, Esso Cold Lake mixes bitumen with diluents and pipelines about 150,000 barrels of the stuff per day to refineries capable of using it. Imperial now operates four plants at Cold Lake, most of them named in the Cree language after local mammals. The plants are Leming, Maskwa, Mahihkan and Mahkeses. An expansion project, Nabiye, is under construction.
But CSS was only the start of in situ oilsands operations—by the early 1990s, the efficiency of these projects was about to change forever. The reason was the engineering genius of Roger Butler, who had been part of Imperial’s oilsands research team.
Imperial had drilled Canada’s first horizontal wells in the late 1970s—one at Norman Wells; the other at Cold Lake, under Butler’s watchful eye. One hundred and fifty metres in horizontal length, the Cold Lake well was paired with a vertical steam-injection well. This was the first field test of what is now known as steam assisted gravity drainage (SAGD). Butler was pleased that the bitumen production corresponded to his calculations. However, Esso felt that it wasn’t ideal for the Clearwater reservoirs at Cold Lake and continued using CSS.
Several years later Butler took early retirement from Imperial. He joined the Alberta Oil Sands Technology and Research Authority (AOSTRA) just as that provincial funding organization was discussing the prospect of constructing an Underground Test Facility (UTF)—a facility for testing in situ production methods. Butler proposed testing SAGD at the facility, which was to be located on the Athabasca deposit. Shortly thereafter he left AOSTRA to take the University of Calgary’s Endowed Chair in Petroleum Engineering. At that time he developed the idea of using two horizontal wells for SAGD production—and upper well for injecting steam and a lower one for drawing bitumen from the steam chamber that would theoretically develop.
AOSTRA took a big risk by funding the UTF, which went into operation in 1987. However, the result was a clear demonstration of Butler’s ideas and a subsequent transformation of the industry’s thinking about underground production.
The magnitude of the UTF is hard to imagine. Sinking the shafts was done with a drill bit almost four metres in diameter, weighing 230 tonnes. The two shafts were 223 metres deep and neither one deviated from the vertical by more than an inch. As a safety measure, AOSTRA constructed two parallel tunnels through the limestone. More than a kilometre in length, the tunnels were five metres wide by four metres high.
Then the tests began. The first tests involved three horizontal well pairs 70 metres in length, each with 40–50 metres of exposure to the McMurray formation. After a year or so, it was obvious the system was working. That was the beginning of a turnaround within the industry’s mindset. With the second set of three horizontal well pairs, the turnaround was complete.
Project engineers had expected production to reach about 1,800 barrels a day, with recovery rates between 30 per cent and 45 per cent of the bitumen in place. In practice, these wells got 65 per cent recovery. Over the 10-year life of the well pairs, Phase B got a steam to oil ratio of 2.3:1. With the advent of horizontal drilling techniques commercially able to deploy SAGD from the surface, there was no turning back.
Taking—and passing—the “barrel test”
The real test in the oil industry, of course, lies in the number of barrels a venture can produce. Using that measure, the success of the last 25 years of experimental and commercial production in the oilsands has been phenomenal.
In 1987 Canada’s total bitumen production (mining and in situ) was about 300,000 barrels per day. Today’s daily volumes are more than five times greater, at 1.6 million barrels. Of that amount, SAGD projects at the pilot or commercial stages collectively produce almost 520,000 barrels of bitumen per day; Esso’s pioneering Cold Lake project uses CSS to add another 160,000 daily barrels to the mix.
The advances in technology have not only opened up new and previously stranded resources, but also significantly brought down the costs of the tried-and-true. As global energy demand continues to grow, this industry is set to maintain its status as Canada’s economic dynamo long into the future—as long as market access keeps pace.