New Technology Magazine


Oilsands Technology Heads South

Citrus-based solvent extraction process poised to unlock U.S. oilsands

The chief executive officer for a Calgary-based oil and gas junior that believes it has unlocked the secret of developing the oilsands deposits in the western United States by using a citrus-based solvent that leaves the sands smelling more like an orange grove than an oilsands mine says the technology also has potential in the much richer Canadian oilsands.

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And Cameron Todd, formerly an executive with Calgary-based Connacher Oil and Gas Limited, which produces about 13,000 barrels daily of bitumen from steam assisted gravity drainage (SAGD) projects in Alberta and also owns a 9,500-barrel-a-day refinery in Montana, should know about the Canadian oilsands.

Todd, who has been chief executive officer of U.S. Oil Sands Inc. since April 2011, was formerly senior vice-president, operations, refining and marketing for Connacher, which, burdened with a significant debt load, announced this past spring it was putting itself up for sale.

“Connacher is a good company with good assets, but raising capital is a challenge in the oilsands business, especially for the little guys,” says Todd, who was with Connacher for five years and has worked for over 30 years in the oil and gas business. But Connacher, unlike U.S. Oil Sands, is operating in a proven oilsands deposit and has been producing bitumen for years.

However, Todd believes his new company, which raised US$11 million in a stock offering this past spring, can be the first to build a commercial plant in the Utah oilsands, where the U.S. Geological Survey estimates there’s as much as 12 billion barrels of recoverable oil in larger deposits, with as much as 32 billion barrels concentrated in smaller, scattered deposits.

The oilpatch veteran believes it’s all about technology and his company (previously called Earth Energy
Resources) needs to raise much less money than Canadian oilsands operators because of it. It only needs about $30 million to $35 million overall to bring on 2,000 barrels daily of bitumen production by the target date of September 2013.

“That would allow us to order the equipment we need to get to first production,” he says.

But Todd says it is a challenge in today’s financial conditions raising even that kind of money, minuscule by oilsands standards. “We’re now looking for a joint-venture partner,” he says. “It’s tough for juniors to raise money in today’s environment.”

It doesn’t help that, although development of Utah’s oilsands has been a dream now for decades, it’s been just that—a dream, at least on a large scale.

ntm092012oilsands2In fact, some Utah oilsands deposits were tapped starting in the 1930s for road asphalt and Utah is the only U.S. state that produces gilsonite, a pure form of asphalt used in printing inks and paints, oil well drilling muds and cements, asphalt modifierst and some chemical additives.

But oilsands development has been virtually non-existent. That’s despite the fact the U.S. Department of Energy has estimated that up to half of the known resources in the state can be extracted with the kinds of thermal and solvent technologies commonly used in the Canadian oilsands, with much of the heavy oil that would be produced being about 15 API gravity, virtually a light crude.

However, commercial oilsands development has eluded the state, despite serious studies of commercial development there stemming back to the 1850s. Numerous plans for development have faltered because of techno­logical, geological and economic challenges.

But Todd says it’s different this time, mostly because U.S. Oil Sands, which holds 32,000 acres of leases in the state’s Utica basin, is using a solvent-based technology that lowers the economic threshold of development while reducing the environmental impact.

“We have a unique technology,” he says. “We’re using a citrus-based solvent that literally strips the oil off of the sand, which means we won’t need a tailings pond and we will use less energy to produce the oil.”

The solvent has been used for the past decade in the oilfield service sector in Alberta, which means it is not an unproven approach. It was developed by Grande Prairie, Alta.–based Kevin Ophus and is called the “Ophus Process.” He is a member of the U.S. Oil Sands board.

Interviewed last year by the Grande Prairie Daily Herald-­Tribune, he described how he developed the approach. “I was in the oilfield industry before, in the chem-ical business, and I started playing with some chemicals to see if there was something better out there to extract the oil,” he told the newspaper.

The process begins by feeding bitumen into a hopper, which crushes it into three-quarter-inch pieces. The bitumen is then converted to a water/oil slurry that is mixed with what Ophus describes as a “food-based chemical.”

The mix is then run through a unit, which separates the water and oil “and the sand goes over the shaker and comes out dry at the other end,” Ophus says.

The result is that 98 per cent of the hydrocarbons are removed, leaving behind little or no toxins and no tailings.

Todd says he knows the technology will work in the Utah oilsands—and would also work in Alberta’s oilsands—because it has been tested in oil spill cleanups and as a degreaser. “It’s used to unstick oil from stuff,” he says.

It works in the oilsands of Utah because of the geology of the area.

“The chemistry of the bitumen is a little different than the Canadian oilsands, which were formed by a sea,” he says. “The Utah oilsands were formed in a lake. The Utah oilsands are oil-wet and are much harder to extract than in Canada. You need to strip it off the rock. In Canada, if you mix hot water with the bitumen, most of it can be  recovered. In Utah, you need a solvent to literally strip the oil from the sands.”

The oilsands of Utah and the oil shales of Colorado, Wyoming and Utah, where the U.S. Geological Survey has estimated there are 1.5 trillion barrels of oil, are two entirely different things, despite their geographical proximity. Only a few thousand barrels of shale oil have been recovered since commercial development was first tried in the 1970s.

First of all, there are the technological and economic hurdles challenging development of oil shale. Most experts say the resource can’t be developed at prices lower than $100 a barrel. That’s because, as Todd explains, the shales are really not even developed enough to be called oil.

“The oil hasn’t fully matured,” he says. “It’s an immature form of hydrocarbon called kerogen. It still needs to be cooked at extreme temperatures [of 500 degrees Celsius or so].”

A chemical process called pyrolysis converts the kerogen in the shale into shale oil and oil shale gas at those extreme temperatures in the absence of oxygen.
The other problem with shale is that it is often deeply buried.

Several attempts have been made to commercialize the development of oil shales in the United States, led during the Second World War by the U.S. military, eventually creating the U.S. Synthetic Liquid Fuels Program, which subsidized oil shale development.

That development reached a crescendo with the de­velopment of Exxon Corporation’s $5-billion Colony Shale Oil Project, located in Parachute, Colo. That megaproject was closed in 1982, leading to the layoff of 2,000 workers.

There have been a series of attempts since to develop the resource, but aside from the economic and techno­logical challenges, environmentalists are now strongly opposed to shale development because it requires large volumes of water—a problem in the parched western United States.

Glen Vawter, executive director of the Glenwood Springs, Colo.–based National Oil Shale Association, blames the government of U.S. President Barack Obama as well for hindering oil shale development.

“The federal government continues to get in the way,” he says. “This is an administration that is siding with en-vironmental groups and preventing oil shale development.”

The oil development–friendly administration of George W. Bush had made almost two million acres of oil shale lands available for development, in addition to 431,000 acres for oilsands development in Utah. Under that round, six companies, including such oil majors as Royal Dutch Shell plc and Chevron Corporation, gained access to potential 5,120-acre oil shale leases.

However, the Obama administration has shrunk new leases to 160 acres, with a strict 10-year development time frame. The leases specify that research and development efforts are paramount.

A recent announcement by the government, issued in February, set aside about half a million acres for future development, far less than previously made available.

Oil shale development is competing now not only with the Canadian oilsands, where the technological and economic challenges have largely been overcome, but also with tight oil development in both the United States and Canada.

Tight oil is often called shale oil, creating some confusion. The main difference is that tight oil deposits in North Dakota, Montana and other U.S. states, and in Saskatchewan and Alberta, have a mature, light petroleum resource. Advances in horizontal drilling and fracturing have allowed producers to unlock the crude, which is trapped in rocks.

ntm092012 oilsandsU.S. Oil Sands’ Todd says he believes his company’s technology can compete economically with the Canadian oilsands and even with tight oil.

It also helps that its lease, like most of the leases in Utah, lies on state- or privately-owned land and the Utah government is development friendly. “It’s much easier to work with the state than with the federal government,” he says.

Gary Herbert, the Republican governor of the state, has called the Obama administration’s approach toward unconventional oil development nonsensical and “bass-­ackwards,” accusing it of being overreaching in its approach.

Todd believes the state government understands the promise of the company’s project. “We have a resource in place of 190 million barrels on our lease, so it has a huge potential,” he says.

The company drilled 180 core hole well tests last year on the site and plans to drill 30 this year. It plans to develop a second 6,000-barrel-per-day plant starting in 2014, with plans to move to a new mine site afterwards. It expects to eventually produce 50,000 barrels daily.

If it raises the required funding, it would dig a 62-acre pit from which it would mine the bitumen for the first phase.

“All our equipment is modular and would be moved on skids,” he says. “Field construction would take about 2.5 months.”
It would employ about 100 construction workers and about 75 permanent workers in the first phase.

But the potential of its solvent-based technology should extend beyond Utah, says the Canadian oilsands development veteran. He has tried to interest Canadian developers in the technology, but believes now it will take successful implementation of the technology in Utah to bring that about.

He then wants the company to be involved with a partner in any subsequent project in Canada, since he says the company isn’t interested in licensing its approach. “We have no plans to license the technology,” he says. “We’re not a service company. I’m an oilsands developer, offering up an opportunity for a partnership.”

Todd points to what he says are compelling economics. He points to Imperial Oil Limited’s Kearl Lake mining project, which will cost about $10.9 billion and produce
110,000 barrels daily in its first phase (with a subsequent mine expansion raising that to 145,000 and with an ultimate goal of 345,000 barrels daily by 2020).

“That means it’s costing Imperial $100,000 per barrel to develop that project and we can develop our project for $15,000 a barrel,” he says. “Our process requires mining, but we can recover 96 per cent of the bitumen in place, compared with the 80 per cent to 85 per cent recovered now with mining projects. We expect that when we demonstrate the commerciality of our project, we will have interest [from lease owners in Alberta].”

The solvent, which is relatively costly, can be recycled up to 50 times, he says. “If I lost 10 per cent of my solvent to the reservoir, that would wear on the economics of a project,” he says.

“It leaves behind a clean beach-type sand,” he adds. “I will only store about 1.5 years of bitumen, with reclamation ongoing. After three years, I’ve already reclaimed the land. It represents a major breakthrough in the mining process.”

Todd says the technology can work at mid-range depths in the Athabasca deposit, deeper than current mining pro-jects but shallower than SAGD projects.

“There are 300 [million] to 500 million barrels of stranded resources at those depths,” he says. “Because tailings ponds aren’t needed, the technology works at $50 a barrel. It doesn’t require the same economies of scale as most mining projects and would work on a smaller scale.”

The Utah bitumen has 90 per cent lower sulphur content than Canadian bitumen, which leads to less CO2 emissions. “It is a sweet, heavy crude and is a lot less complex to upgrade,” which leads to fewer CO2 emissions, he says.

There are five refineries in the state, and bitumen that the company produces can be trucked to any of them. Todd says the company is also looking at development opportunities in oilsands deposits in Russia, Africa and elsewhere.

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