The odds are good, and growing better, that your next tank of gas is mixed up in the sticky black sand of a monster truck pounding along the banks of the Athabasca River.
As Len Hale points out, the truck is so massive — it carries 360 tonnes — you can see a wave forming in the soft dirt in front of each tire as the truck rolls across the ground, deforming the earth as it goes.
Hale is general manager of Suncor Energy Inc.’s Millennium Mine in the Athabasca oil sands of northern Alberta.
The sands lie at the junction of Canada’s energy future.
They’re a huge source of energy in their own right.
The flow of synthetic crude out of the oil sands today now exceeds that of conventional crude from Alberta’s conventional southern oil fields. In theory, their capacity is second only to the oil fields of Saudi Arabia.
This year, the tar sands are projected to produce just over one million barrels a day on average — nearly equal to the 1.1 million barrels produced by conventional means.
The reason there’s such a push to develop the oil sands is that easy-to-produce conventional oil is becoming scarcer.
By 2015, conventional production is projected to drop more than 40 per cent, to 600,000 barrels a day, while production from the sands will more than double to 2.6 million barrels.
(Atlantic Canada production is currently 420,000 barrels a day, climbing by 100,000 barrels next year when the White Rose field off Newfoundland comes into production.)
But the tar sands are a more complex energy proposition than a conventional field, in which oil trapped in porous rock is simply pumped to the surface.
The sands are not just a source of energy; they’re also a voracious consumer of energy in the form of natural gas — and in that capacity are competing with homeowners and industrial gas users who use natural gas both for heat and as a source of chemicals for products ranging from fertilizer to plastics.
As both a source and a consumer of fossil fuels, the sands also are a big source of greenhouse gases, pushing Canada away from its goals of cutting emissions.
Ontario electricity users have a reason to keep an eye on the oil sands, too. As the province moves to shut down its coal-fired electricity generators, much of the power formerly generated by coal is likely to come from natural gas, tying the electricity sector more closely to the complex energy equation of the tar sands.
No one has a conclusive theory about how the oil got into the sands, which stretch in a band across northern Alberta.
And for years, no one knew how to make money getting it out. At some levels, it’s not that difficult. Pour some hot water onto some oil sand in a jar, shake it up and the oily water will float to the top while the sand settles to the bottom.
Doing it on a commercial scale — and then upgrading the heavy, black oil known in the trade as bitumen into the usable products you can pour into your car’s gas tank or crankcase — is more of a trick.
Assembling the billions of dollars needed to build the massive mining and refining facilities that have now sprouted around Fort McMurray is another. Oil sands mega-projects have had a nasty habit of going over budget.
But here they are, now scarring huge swaths of the forest and muskeg around Fort McMurray.
The three biggest integrated operations, combining large-scale mining with on-site upgrading operations:
Syncrude, currently pumping 230,000 barrels of crude a day.
Suncor, producing 233,000 barrels of crude a day.
And the newest kid on the block, the Athabasca Oil Sands Project a partnership of Shell Canada, Chevron Canada and Western Sands L.P.
But a host of smaller operations are also busy sucking oil from the sands and sending it to other companies for upgrading into usable products.
And south of Fort McMurray, a joint effort of OPTI Canada Inc. and Nexen Petroleum Canada, is on the verge of starting a project that will use the oil sands’ own energy to power the extraction and upgrading processes.
Why the stampede to the oil sands? It’s not just in Canada that cheap, conventional oil is becoming scarcer.
The markets’ recent flirtation with oil at $40 (U.S.) a barrel has raised questions about over-all worldwide supplies.
Serious oil analysts are questioning the state of world oil supplies for the longer term.
One of the most prominent has been Matthew Simmons, who heads U.S. investment banking firm Simmons & Co. International, which specializes in the oil industry.
Simmons warns that the days of easy oil have come to an end.
The world floats for the most part on a pool of Saudi Arabian oil, Simmons argues in a presentation he has made widely to oil industry audiences. It is the Middle East, and especially the Saudis, who have the capacity to increase or decrease production to match world demand.
Saudi production rests on five huge oil fields, but one — the Ghawar field — is responsible for up to 60 per cent of Saudi production. It alone produces 5 million barrels a day — about double Canada’s total production from all sources.
But Simmons questions the reliability of Saudi reserve estimates, which he says have not been sufficiently scrutinized by third parties. And he wonders whether the Arabian super-giant fields are nearing the down-slope of their productivity.
Moreover, no new super-giants have been found — in Saudi Arabia or anywhere else in the world — since the 1950s, he points out.
Half a dozen OPEC nations, including Saudi Arabia, mysteriously boosted their “proven reserves” in the late 1980s by 50 per cent or more, Simmons notes. Skeptical observers at the time labelled them “paper barrels.” More recently, he says, they have been regarded as “possibly conservative” numbers. Simmons now labels the estimates of Saudi reserves as “fuzzy,” because in his view there hasn’t been a rigorous third-party review of the estimates. That’s dangerous in a world where demand for oil continues to grow.
“Can oil output double?” he queries. “Can it safely stay flat? Might all five key (Saudi) fields soon enter rapid decline?
“Without any data, nobody really knows.”
Simmons pleads for a “new era of energy transparency” so at least the world knows where it stands. And in case the outlook is grimmer than we’ve been led to believe: “We need to begin creating a new form of energy to replace some portion of oil and gas use.”
Not everyone agrees, of course.
Energy economist G.C. Watkins of the University of Aberdeen argues in a recent paper that the world’s ultimate reserves are unknowable, because new science and technology can open up new supplies.
Reserves fall when companies believe the return they’ll get on exploring for new supplies doesn’t justify the expense. Reserves are dictated by economics, not geology.
Since the OPEC oil embargo of 1973 brought the idea of an energy shortage into public consciousness, Watkins notes, world oil reserves have doubled while production continues to increase.
But Simmons is not alone in his darker outlook.
`If we ever get serious
about carbon emission control the oil sands are
in deep trouble.’
Tom Adams
Energy Probe
Phillip Chan, senior manager of petroleum engineering in North America for Talisman Energy Inc., also said in a recent interview that world oil production has probably peaked.
“I think the major field have been found worldwide, the super-majors,” he said in an interview.
Closer to home: “In the last 30 years, we haven’t made a major oil discovery in Canada.”
The supply side of the equation is also difficult, Chan said.
China seems to be buying heavily on world oil markets, and may be building a strategic oil reserve, he said.
“They must foresee a (supply) crunch,” he said. “Otherwise, why would they stockpile oil at $40 a barrel?”
Chinese consumption is rising as well. “I don’t think any energy agency has factored Chinese demand into their equations,” he said. To some extent, the same goes for the world’s other giant nation, India.
Meanwhile, some major non-OPEC oil fields are in decline, including the North Sea and Alaska’s North Slope.
However, other experts predict oil fields in West Africa and Central Asia will pick up the slack of declining fields elsewhere.
Canada is not immune against the decline of easily accessible conventional fields, which explains the rush to the oil sands.
The economics of an oil sands mining operation differ from the classic oil industry.
The gamble of conventional oil is running expensive exploration and development programs that often turn up dry holes.
But there is no such problem finding the oil in the tar sands, says Suncor’s executive vice-president Steve Williams.
“We know where it is. It’s much more akin to a manufacturing industry than conventional oil and gas.”
Oil sands plants make or lose money on labour costs and the cost of the energy they need to drive the plants — both of which are only marginally important to conventional oil.
Their success also depends on their success in bringing massive, complex projects in on schedule and on budget — a problem that has plagued all of the major projects in Canada’s oil sands to date.
Despite the difficulties in controlling costs, Suncor’s Williams says the economics make sense as long as oil stays above $20 a barrel: “Our plans are to grow as fast as we can.”
But the growth will require massive amounts of capital — $1.5 billion a year or more over the next seven or eight years to get Suncor from its production rate of 225,000 barrels a day to its target of 500,000 barrels a day by 2016.
The National Energy Board estimates there are 1.6 trillion barrels of oil in the sands — of which 178 billion barrels are recoverable. At Canada’s current rate of consumption — about 2 million barrels a day — that’s a 250-year supply.
Not everyone can mine the oil sands. If it’s buried too deep below the surface soil — and more than 90 per cent of the oil sands are — surface mining doesn’t work. In those cases, companies separate the oil from the sand deep underground and pump it to the surface, what’s called “in situ” production in the trade.
The most common method, which uses steam to force the heavy, black bitumen to the surface, requires copious quantities of natural gas.
It takes 1,000 cubic feet of gas to convert a barrel of bitumen into light crude, according to George Crookshank, chief financial officer of OPTI Canada Inc. (A typical Canadian home with natural gas heat uses about 9,000 cubic feet of gas a month, on average.)
It’s a use of natural gas that some critics question. Gas is not only a clean fuel, it’s a rich source of raw material for the petrochemical industry.
Using a high quality fuel — natural gas — to produce a low quality fuel — bitumen — is, in the words of Tom Adams of Energy Probe, “crazy.”
Adams and others also note that current oil sands technology, which burns natural gas to make oil that will in turn be burned, releases vast quantities of carbon dioxide.
“If we ever get serious about carbon emission control the oil sands are in deep trouble,” says Adams.
It also raises the question: How much gas do we have? If we’re using increasing amounts to produce our oil, how does it affect other uses, such as home heating and petrochemicals?
Industry experts talk about gas supplies with varying degrees of urgency, but it’s no heresy to suggest gas will become scarcer.
Peter Tertzakian, chief energy economist for ARC Financial Corp., was blunt in his assessment in an interview at the recent Canadian International Petroleum Conference in Calgary.
“It’s getting increasingly difficult to find and produce natural gas on the (North American) continent,” he said. “It’s important to emphasize we’re not running out of natural gas. But we’re running out of natural gas at prices people were historically accustomed to … If you want it, fine. It can be delivered. But you have to pay for it.”
Kurt Abraham, managing editor of World Oil magazine, noted at the same conference that a decade ago, Canada drilled 12,000 gas wells a year — enough to modestly increase reserves.
“Now we’re up to 20,000, 21,000 wells a year, and if you’re lucky, you’re going to keep it level,” he said in an interview. “You’re not going to increase supply. That tells you the easy to drill resources are gone, or mostly gone … It’s showing you it’s going to require a heck of a lot more investment to get the same amount of gas than it used to with a certain number of wells.”
There are a couple of alternative ways for North America to grow its natural gas supply — but none of them are easy.
One is to extract natural gas from the continent’s huge coal reserves. A second is to import liquefied natural gas from offshore. But production of coal bed methane, as it is called, currently makes up only a tiny fraction of current North American gas production.
“The next couple of years are really important to see how commercial it becomes,” says Greg Stringham of the Canadian Association of Petroleum Producers.
Coal bed methane also carries environmental baggage in the U.S., because large quantities of underground water must be pumped to the surface to release the methane trapped in the coal. The water, often full of salt and other minerals, can contaminate surface soil and water if allowed to run off.
Canadian law requires coal bed methane operations to re-inject the water underground.
As for liquefied natural gas (LNG), North America will need to build more specialized terminals — not to mention several hundred specialized tanker ships — to boost gas imports to a serious level. Some communities are hostile to hosting LNG storage and regasification terminals.
What of coal itself? It has traditionally been regarded as the dirtiest option, although the supply of North American coal is vast: In North America, more than 90 per cent of the hydrocarbon energy is stored in coal, with less than 5 per cent each for oil and natural gas.
The problem with coal is its emissions: Depending on the type of coal and the way it’s burned, coal facilities spew carbon dioxide that contributes to global warming; sulphur and nitrogen compounds that create smog; and mercury and other pollutants that are dangerous to human health.
In the short run, coal is unlikely to shake its bad reputation in Ontario. In the longer term, a group of coal companies and electric utilities are researching whether it’s possible to “burn” coal without emissions.
ZECA Corp., a consortium including coal interests and utilities, is working on a process that claims to be able to produce either electricity or hydrogen, emits no poisonous heavy metals, and produces a stream of pure carbon dioxide that can be used for industrial processes or bound into solids so it doesn’t add to global warming. But getting a full-scale production up and running is several decades away, even if research and test modelling goes smoothly.
