This article explores diverse ways adopted by companies to find ways to make extracting oil from the sands of northern Alberta a little easier. At Petrobank’s Whitesands site, heat from in situ combustion both melts and upgrades the bitumen in the underground deposit. Horizontal production wells carry the oil to the surface. However, even with the new processes in place, copious quantities of energy and water are needed to produce oil from sands. In situ production processes exploit bitumen deposits that are inaccessible through surface mining. The facility at EnCana’s Foster Creek site processes some of the water used to extract bitumen in situ. That recycled water is then boiled and reinjected below the surface. Environmental arguments aside, many observers contend that the only argument against exploiting the Alberta oil sands that might have any success is economic—that it might cost more than alternatives. The paper concludes that barring some unforeseen calamity, oil demand is expected to outstrip the capacity of conventional petroleum production. Even if wringing oil from the Alberta sands is expensive and energy-intensive, it is probably a cost most consumers will be willing to pay for access to the next easiest oil.


Finding Oil has Always Been Hard Work



The contentious arguments over drilling on the continental shelf and in an Alaskan wildlife refuge highlight just how strapped the United States is today for conventional oil. But geologists estimate that beneath the boreal forests of Alberta, a Canadian province due north of Montana, he nearly 179 billion barrels of oil, the second largest proven petroleum reserve in the world, after that of Saudi Arabia.

Unfortunately, unlike Saudi light, sweet crude, which has set the world standard for petroleum, Alberta’s oil is a low-grade, tarry hydrocarbon known as bitumen. This heavy stuff is inextricably bound up with water and clay, making it no oilman’s dream.

But when oil prices skyrocketed over the past few years—and with some geologists contending that conventional oil production levels may have reached their limit—oil sands have begun to seem like a viable resource.

This prospect has alarmed some environmentalists, who fear that ramped-up oil sands mining would lay waste to millions of acres of wilderness. Extracting bitumen and upgrading it to usable oil demands expensive water- and energy-intensive techniques. And the large open-pit mines are unquestionably ugly. But monitoring by Alberta Environment, the government agency responsible for enforcing the province’s air and water standards, indicates that some of these fears may be overblown. And newer in situ or underground extraction techniques that reach hundreds of meters beneath the surface promise to address many of these objections.

Extracting crude from oil sands will never be as easy as drilling a well in East Texas. But it’s likely that the effort will be preferable to living without oil altogether.

MINING BITUMEN HAS NO NEED FOR MEN DESCENDING INTO DEEP, DARK SHAFTS. “Mining oil sand is just scraping the stuff on the surface,” says Dan Boyd, a petroleum geologist with the Oklahoma Geological Survey. This is literally true: Before operations start, existing forest must be logged and the rich topsoil salvaged and stored away from the mine for future reclamation projects. Next, the overburden—the material that lies atop the oil sands—must be removed. In the Athabasca region, the largest of Alberta’s three main oil sands deposits, the sands are generally less than 70 meters below the surface, although Syncrude Canada Ltd. mines bitumen from as far down as 90 meters.

Syncrude, which is Canada’s largest oil sands producer, started surface mining operations in the Athabasca region in 1978. At that time, draglines and bucket-wheels—equipment the size of multistory buildings—dug up and scooped oil sands mixed with clay onto miles-long conveyor belts that went to the extraction facility. There, they were dumped into drums known as tumblers, mixed with a witch’s brew of steam, hot water, and caustic soda, and heated to 80°C (175°F). That process lifted bitumen to the top, sent sand and clay to the bottom, and left water in between.



The entire process was very energy-intensive, and thus expensive. According to Mark Kruger, a spokesperson for Syncrude, “We wanted to reduce operating temperatures and energy use.”

As part of this effort, in the 1990s, Syncrude began replacing draglines and bucket-wheels with equally gigantic trucks and shovels that used hydraulics and electricity for better performance. Two new separation processes were also introduced at mines for energy reduction. Instead of sending raw oil sands directly to extraction, a toothy crusher known as a feeder-breaker chews them up into smaller pieces. These smaller chunks travel by conveyor to a cycle-feeder, which, Kruger explained, is a tub of swirling water that looks like a flushing toilet. Adding the oil sands to the swirling water yields a slurry that is piped to the extraction facility.

Bitumen starts splitting off in the pipeline. The tumblers, which still use the same witch’s brew for separation as in the 1970s, but at lower temperatures because of the new processes, finish the job. At one of Syncrude’s extraction units, tumblers can do the job at 25°C—room temperature—although older units still rise nearly to 80°C.

After separation, water, sand, and clay are piped to tailing facilities. The bitumen goes to an upgrader, essentially a refinery for bitumen. At the upgrader, Syncrude removes sulfur and adds hydrogen to convert the bitumen to high-quality, light, sweet crude oil.

“Other operators may choose to produce lower-quality crude or bitumen,” Kruger said. “Syncrude is a one-stop shop in producing very high-quality, light, sweet crude oil.”

EVEN WITH THESE NEW PROCESSES IN PLACE, LARGE QUANTITIES OF ENERGY AND WATER ARE NEEDED TO PRODUCE OIL SANDS. For instance, it takes Syncrude 1.3 million Btu to produce a barrel of oil, which yields 5.8 million Btu. That means the ratio of energy output to energy invested is only about 4.5. (For a conventional oil well, that ratio is estimated to be between 11 and 17.) And Syncrude took 36 million cubic meters of water from the Athabasca River for its operations in 2007, or about two cubic meters per cubic meter of produced oil.

But those raw figures may be misleading out of context. “If you look at the energy Syncrude consumes, most of it is self-generated,” Kruger said. “In upgrading the bitumen, we create fuel gas that we use in production. Coke is also produced as a byproduct, and we use as it in production and upgrading.” Syncrude does import natural gas, but most of that is to provide the hydrogen for upgrading heavy crude to the company’s light, sweet product.

Syncrude also reuses 88 percent of all the water required for extraction. So although the company pulled 36 million cubic meters from the river last year, it used another 256 million cubic meters of water that had been drawn from the river over the years and has been continuously cycled through the extraction process. The company is also increasing its per-barrel water-use efficiency. “This makes perfect economic and environmental sense,” Kruger said.

The provincial environmental agency keeps a constant watch on the industry, always pushing it to do better. “We have put into place a water management plan for the Athabasca River that limits the water oil companies can take out of it,” said Cheryl Robb, a spokesperson for Alberta Environment. “In 2006, total consumption of water from the river by all oil sands was four-tenths of a percent of the average annual flow,” Robb said, far less than the three percent allowed by the agency. According to Robb, every year so far, the oil companies have used less than their allotted maximum.

Water quality has not suffered, either. Because of its underlying geology, bitumen naturally seeps into the Athabasca River. “It comes from the sand, which feels oily to the touch,” Robb said. The agency monitors major waterways and lakes in the province and has detected no changes in water quality since oil sands production began.

Finally, there’s the land. “When you see oil sands development, there’s a large impact on the land,” Robb said. “ But we have a lot of boreal forest, and less than one percent of it is impacted by the oil sands.” The total surface area disturbed by oil sands mining, according to Alberta Environment, is 205 square miles, an area about the size of the built-up part of Edmonton.

Before receiving approval to operate, every oil company must put up a cash bond equal to the amount needed to reclaim any land it disturbs in production. “Even if the company goes bankrupt, there is still money to pay for reclamation,” Robb said. “They can’t just put clean soil back, they must have trees and vegetation growing.”


However, thanks to new techniques and technology, these areas may now be developed. If production from these regions lives up to its promise, Canada could well become the major oil exporter in this hemisphere.

One technique that has been in development since the mid-1990s is steam-assisted gravity drainage, or SAGD. Like all in situ techniques, SAGD can go hundreds of meters beneath the surface, well past the limit of open pit mining, which may be about 200 meters deep. It’s based on a simple idea: If you heat up bitumen, it begins to flow.

In practice, SAGD is anything but simple. It starts by drilling two wells, which initially bore straight down, but gradually turn 90 degrees to horizontal. The two wells will end up vertically separated by five meters (just over 16 feet).

“We inject steam through the injection well,” said Mark Bilozir, EnCana Energy’s integrated oil division team lead. “As it cools, it heats up the surroundings, making the bitumen less viscous. At a sufficient temperature, the bitumen starts to move fairly freely.” Condensed water from the steam and the bitumen flow down via gravity to the production well waiting below.

The steam is under pressure, enabling it to reach about 450°F, but even at that temperature, the flow of bitumen is by no means instantaneous. “We inject and circulate steam for about six months before we start to see production,” Bilozir said. “Then it’s about 18 months to peak production, and we can stay at peak production for three or four years in a good reservoir.”

Another way to heat the bitumen is through fire. Although fire in an oil reservoir is usually considered a worst-case disaster, for one of the newest in situ oil sands techniques it is the key element.

“Fundamentally, the idea of injecting air into a heavy hydrocarbon reservoir and creating combustion—or oxidation—of the oil has been around since the 1920s,” said Chris Bloomer, vice president and director of heavy oil for Petrobank Energy.

In previous combustion attempts, air was injected via vertical wells, and at high pressures in the presence of hydrocarbons, it automatically ignites, resulting in a vertical wall of flame. This combustion front feeds on the heaviest fractions of the hydrocarbons in the reservoir, literally upgrading the oil in place. It would be collected by vertical production wells.

In practice, using vertical injection and production wells didn’t work out. “In a vertical injection well, you don’t produce combustion air,” Bloomer said. “You have to keep injecting more and more air to keep up a steady flow.” Under these conditions, the combustion heat dropped, failing to completely consume all the oxygen. “That led to oxygenated hydrocarbon compounds— emulsions—that were difficult to process.”

“Combustion has always been seen as the Holy Grail because it’s more efficient,” Bloomer added. “But it’s hard to manage.”



In the early 1990s, however, research and experimentation by Malcolm Greaves, a professor of chemical engineering at the University of Bath in England, suggested that the Grail might be within reach. His breakthrough came by investigating a change in the configuration of the injection and production wells. “He found that a vertical injection well at the toe of a horizontal production well at the bottom of the reservoir could control the combustion air and use it as a lift mechanism for the oil,” Bloomer said. “You’re always having fresh air, so you cansustain high temperatures and can manage the combustion front more efficiently.”

That vertical injection well at the toe of a horizontal production well is the toe-to-heel air injection, or THAI, process. Petrobank now owns the THAI process and has piloted it successfully in two reservoirs in Alberta.


But they also change the equation on return for energy investment and on environmental impact. For instance, with EnCana’s SAGD operations, the big energy consumption issue is generating injection steam. Because EnCana’s two reservoirs are nice and thick, they require a lower steam-to-oil ratio than thinner, lower-quality reservoirs would. “It works out to 1,000 cubic feet of natural gas to one barrel of bitumen,” Bilozin said. That works out to an energy output-to-input ratio of about 4.8. EnCana uses natural gas purchased within the province to produce its steam.

EnCana uses no surface water for its oil operations, although SAGD is a water-intensive process. The water that the company uses comes from the same source as the oil: the deep underground reservoirs.

“We separate water from the bitumen, treat it, and boil it again,” Bilozir said. “We recycle 90 percent of our water in a continuous steam loop.” The make-up water also comes from underground.

For Petrobank’s pilot THAI wells, the company has been using electricity off the grid to power its air compressors. THAI upgrades hydrocarbons in the reservoir by burning through the lowest-grade fractions. It also releases gases that can be used as fuel for the air compressors. “In a larger, commercial project, we will be self-sustaining. We’ll produce upgraded oil and our own power,” Bloomer said.

THAI doesn’t use water for production at all.

All in situ processes, by their nature, use just a fraction of the land dedicated to open pit mining. Alberta Environment estimates that the footprint for an in situ extraction operation is about 15 percent of that needed for a conventional surface mine.

Environmental arguments aside, many observers contend that the only argument against exploiting the Alberta oil sands that might have any success is economic— that it might cost more than alternatives. When prices were at record levels in recent years, various companies announced plans to increase production in the tar sands to some five million barrels a day, almost seven times the 2007 level. It remains to be seen whether the recent fall in oil prices might delay some of those projects.

But it’s unlikely to derail them. Barring some unforeseen calamity, oil demand is expected to outstrip the capacity of conventional petroleum production. Even if wringing oil from the Alberta sands is expensive and energy-intensive, it’s probably a cost most consumers will be willing to pay for access to the next easiest oil.