Why Oilsands (a.k.a. tarsands) can’t replace oil

Tar sand excavation images:

The problems with oilsands (tarsands) are:

1)   In the tar sands open-pit mines, to produce one barrel of synthetic crude it takes 2 tons of tar sands, 250 gallons of water and 1700 cubic feet of natural gas. Feb 2008 ASPO newsletter.

2) Oilsands take tremendous amounts of energy to process, requiring expensive mining, crushing, high temperatures, centrifuging, and a lot of water to strip the oil from the tar sands to which the oil is clinging. Consider this description of Brendan Koerner’s about how oil sands are mined:

“Alberta’s black gold isn’t the stuff that geysered up from Jed Clampett’s backyard. It’s more like a mix of Silly Putty and coffee grounds – think of the tar patties that stick to the bottom of your sandals at the beach – and it’s trapped beneath hundreds of feet of clay and rock”. Koerner describes the mining process as: First, shovels excavate thousands of tons of soil and clay, creating a 150-foot pit for mining the oil sands below. Then the oil sand is piled into trucks capable of carrying 400 tons. These trucks dump their payload into crushers, which grind it down to fine oil-coated grains. The grains are then transferred via conveyor to a cyclofeeder, where it’s mixed with hot water to produce a slurry. The slurry flows to the extraction facility, where large centrifuges separate out the oil-rich bitumen. The bitumen flows to cokers, where it’s heated to remove impurities such as sulfur and nitrogen, leaving only usable crude oil.

3) In Canada, it’s hard to do this in the six month winter, when temperatures can often drop below -40F.

4) No matter how the extraction is done, the process is slow [the flow rate will hardly make a dent in world oil supplies], and will never replace the amount of oil we’re presently using.

5) It’s not clear whether the EROEI will continue to be positive as the mining pit gets deeper. It takes more energy for a 400 ton truck to get back to the factory from 300 feet down than when it’s initially scraping the surface.

6) Using nuclear power to refine tar sands won’t work, because it wouldn’t be long before the oil sands being mined are too far from the nuclear power plant to transport it there economically.

May 26, 2007. Brian Wang. Nuclear Power for the Oilsands.

7) Massive use of water in an area that is a cold desert with very little rain. Up to 2 barrels of water are used for every barrel of oil produced.

8) They could add substantially to climate change.  To date burning fossil fuels, clearing forests, and so on have rleased 570 billion metric tons of carbon and 250 billion tons of carbon dioxide since 2000.  At this rate we’ll emit the trillionth metric ton of carbon in sthe summer of 2041.  The tar sands represent a lot of unburned carbon, about 170 billion barrels (enough for 6 years of world consumption) that would release 25 billion metric tons of carbon if burned.  Luckily engineers don’t have a clue about how to get at the remaining 1.63 trillion barrels of oil, which sould add 250 billion metric tons of carbon.

9) Destructive in so many ways: Climate change, biodiversity, environment. Destruction of forests, water quality, wildlife, fish

June 4, 2011. James E. Hansen. Silence Is Deadly I’m Speaking Out Against The Canada–U.S. Tar Sands Pipeline.       http://www.commondreams.org/view/2011/06/04-5

The U.S. Department of State seems likely to approve a huge pipeline, known as Keystone XL to carry tar sands oil (about 830,000 barrels per day) to Texas refineries unless sufficient objections are raised. The scientific community needs to get involved in this fray now. If this project gains approval, it will become exceedingly difficult to control the tar sands monster. The environmental impacts of tar sands development include: irreversible effects on biodiversity and the natural environment, reduced water quality, destruction of fragile pristine Boreal Forest and associated wetlands, aquatic and watershed mismanagement, habitat fragmentation, habitat loss, disruption to life cycles of endemic wildlife particularly bird and Caribou migration, fish deformities and negative impacts on the human health in downstream communities. Although there are multiple objections to tar sands development and the pipeline, including destruction of the environment in Canada, and the likelihood of spills along the pipeline’s pathway, such objections, by themselves, are very unlikely to stop the project.

An overwhelming objection is that exploitation of tar sands would make it implausible to stabilize climate and avoid disastrous global climate impacts. The tar sands are estimated (e.g., see IPCC Fourth Assessment Report) to contain at least 400 GtC (equivalent to about 200 ppm CO2). Easily available reserves of conventional oil and gas are enough to take atmospheric CO2 well above 400 ppm, which is unsafe for life on earth. However, if emissions from coal are phased out over the next few decades and if unconventional fossil fuels including tar sands are left in the ground, it is conceivable to stabilize earth’s climate.

Phase out of emissions from coal is itself an enormous challenge. However, if the tar sands are thrown into the mix, it is essentially game over. There is no practical way to capture the CO2 emitted while burning oil, which is used principally in vehicles.

Governments are acting as if they are oblivious to the fact that there is a limit on how much fossil fuel carbon we can put into the air. Fossil fuel carbon injected into the atmosphere will stay in surface reservoirs for millennia. We can extract a fraction of the excess CO2 via improved agricultural and forestry practices, but we cannot get back to a safe CO2 level if all coal is used without carbon capture or if unconventional fossil fuels, like tar sands are exploited.

I am submitting a comment that the analysis is flawed and insufficient, failing to account for important information regarding human–made climate change that is now available. I note that prior government targets for limiting human–made global warming are now known to be inadequate. Specifically, the target to limit global warming to 2oC, rather than being a safe “guardrail,” is actually a recipe for global climate disasters. I will include drafts of the following papers that I recently co–authored:

Paleoclimate Implications for Human–Made Climate Change

Earth’s Energy Imbalance and Implications

The Case for Young People and Nature: A Path to a Healthy, Natural, Prosperous Future

I will also comment that the tar sands pipeline project does not serve the national interest, because it will result in large adverse impacts, on the public and wildlife, by contributing substantially to climate change. These impacts must be evaluated before the project is considered further.

It is my impression and understanding that a large number of objections could have an effect and help achieve a more careful evaluation, possibly averting a huge mistake.

Dr. James E. Hansen is director of NASA Goddard Institute for Space Studies in New York City and adjunct professor in the Department of Earth and Environmental Sciences at Columbia University. Hansen is best known for his research in the field of climatology. In 1988, Hansen’s testimony before the US Senate was featured on the front page of the New York Times and helped raise broad awareness of global warming. Hansen’s work has inspired scientists and activists around the world to fight for climate change solutions. In recent years, Hansen has become an activist for action to mitigate the effects of climate change, which on several occasions has led to his arrest. In 2009 his book, Storms of My Grandchildren: The Truth About the Coming Climate Catastrophe and Our Last Chance to Save Humanity


Energy Forum Posts and Articles

194  Folke Günther
Economists frequently cite Canada’s Athabasca oil sands as a handy replacement for conventional oil.  But oil sands and tar shale are very energy-intensive, environmentally destructive, and not all that large anyway. For example, back-of-the-envelope calculations show that the Athabasca oil sands could supply less than three years’ worth of oil for the global economy. Three hundred billion barrels of oil (AEUB) gushing out of a pipe would only last 12 years at present World consumption of 70 million barrels a day. Oil sands would last just three years if we super-optimistically assume 25 percent net energy for the digging, etc. over the entire resource. “The mining operation involves stripping off the overburden; separating the bitumen with steam, hot water and caustic soda, and then diluting it with naphtha. After centrifuging, liquid bitumen at 80°C is produced, which is then upgraded in a coking process and subjected to other treatments, eventually yielding a light gravity, low sulphur, synthetic oil.” (The Coming Oil Crisis, p. 121, Campbell, 1997)
201 Brian Fleay  Walter Youngquist in his book Geodestinies says for every three barrels of
oil form Canadian tar sands, energy equivalent to two are consumed producing it.

May 28, 2002.  jean laherrere  Nikiforuk /2001 “The next gas crisis” Canadian Business Aug. 20 estimates that 25% of natural gas produced in Alberta in 2010 will be spent to heat the water used to melt the bitumen of the Athabaska tarsands. The lake gathering the wastes has 22 km of diameter and several meters deep.

Mar 19, 2002  16911  Arthur C. Noll       Syncrude
A few more figures from syncrude: Nearly 450,000 tones of materials, equipment, vessels and plant components traveled the highway to the construction site.
Every 24 hours there is enough metal worn off the mining equipment, by abrasive oil sand, to make two full-size pick-up trucks.

How much energy was expended to make all this stuff and transport it to the site, how much to build and maintain the road?  If all this stuff were to be made and moved with the energy gotten from the oil sands, how much would be left over?  Not forgetting the oil used by the 10,000 workers building the plant, likely a similar number making the parts, and the 5,000 running the place, and the people supporting them.

The abrasion rate is pretty high, and that is only for the mining equipment.  I have to think there is also high erosion of equipment dealing with slurry. They admit themselves that the operating conditions for much of the plant is severe.   The life of the system doesn’t look great, very high maintenance, and it took very large amounts of energy to build it. The energy to build it would have come mostly from “conventional” sources, greatly distorting the cost.

The operation has produced about a billion cubic meters of “tailings”, a sludge estimated to take centuries to solidify on its own.  They are adding gypsum to speed up the process, but guess what that takes?  Mining gypsum somewhere else, transporting it, mixing it in.  More energy… Other ways will also cost energy.

I have to think that they chose a site to start, that had the least amount of overburden to remove, and that other places will have more to remove, at greater energy cost.

I have to have serious doubts about the EROEI on this business, and how long it can be maintained if it is positive for the moment.  Looks to me that they have taken “cheap” conventional fuels and used them to build the system, a typical accounting error when using money.  When conventional fuels get scarcer and cost more money,  oil sand extraction costs will likely go up in step with it.  Much the same as with many “renewable” technologies, that are built and largely maintained with fossil fuel.
June 29, 2003. David Olive. Fun with Fossil Fuel Figures. What’s behind estimate Alberta’s oil reserves have skyrocketed 3600% to 180 billion barrels?  Toronto Star.

False claims have a lot of potency in this era of dubious war aims and rampant accounting scandals.

So it was only a matter of time before someone asked a few embarrassing questions about Canada’s sudden new status as the world’s most oil-rich nation after Saudi Arabia, and wondered if it was built on illusion.

“Canada Builds Large Oil Estimate on Sand” was the headline on a recent New York Times examination of what the paper described as “highly questionable” methods used in the Calgary oil patch to determine oil reserves.

Late last year, an authoritative industry publication, Oil And Gas Journal, reported the remarkable fact that Canada’s estimated oil reserves had skyrocketed to 180 billion barrels from 5 billion barrels. The increase was entirely from a new calculation of Alberta’s bountiful oil sands.

Somehow Canada had managed that stupendous feat of boosting its oil wealth by 36 times overnight without benefit of any new Hibernias or other elephants — the industry term for gigantic finds.

What the Times has found, it believes, is an outbreak of “paper reserves” up in northern Alberta. In a mere bookkeeping exercise back in 1999, the provincial energy regulator used a calculation of the province’s oil resources that vastly increased Alberta’s reported oil-sands wealth.

And more recently, the oil patch’s leading trade group, the Canadian Association of Petroleum Producers (CAPP), was successful in encouraging the Oil And Gas Journal to adopt the new figures. To add to the confusion, the CAPP itself hews to a more conservative line, pegging Alberta’s reserves at about 12 billion barrels, saying its methodology differs from others.

This is just what we need, after Canada’s real and perceived equivocation on Iraq, SARS and mad cow disease — another reason for the Americans to distrust us.

And it is the United States that is targeted for Alberta’s boasting. At a time when Washington is newly focused on U.S. energy security, Alberta is pushing hard for consideration as a politically stable alternative to strife-torn oil-producing regions elsewhere.

There’s another factor. Significant cost overruns have plagued many of Alberta’s big oil-sands development projects in recent years. It can’t hurt to obscure the fact of a skilled labour shortage and other contributors to the overruns by touting the staggering immensity of the Athabasca resource — imparting a hoped-for sense of inevitability to its eventual more thorough exploitation.

Actually, the Alberta oil sands is not a story that needs to be oversold. Even after more than $20 billion in oil-sands development since the mid-1990s, another $35 billion-plus worth of oil-sands projects are under way or planned by Imperial Oil Ltd., Shell Canada Ltd., Nexen Inc., Husky Energy Inc., EnCana Corp. and other players.

Oil-sands production now exceeds the output of Alberta’s increasingly depleted conventional oil fields. When it unveiled its completed Athabasca Oil Sands Project earlier this month, Shell Canada projected that at full production, this one project will account for some 10 per cent of Canadian oil consumption.

So why goose the industry reserve numbers, when oil companies themselves, for the sake of credibility with investors, stick to conservative estimates for their own corporate reserves?

The answer has much to do with the continuing ugly duckling status of oil-sands regions in Alberta, Venezuela and elsewhere. The extraction and refining process for bitumen is still gruesomely expensive and temperamental.

Some 30-odd years after Athabasca development began in earnest, operators still struggle with frequent fires and mechanical breakdowns as they learn in fits and starts how to extract oil profitably from the unforgiving muskeg.

Floating a drilling platform off the West African coast, and sipping crude through a straw, is still the preferred, and cheaper, approach of a tradition-bound industry.

Mind you, some day conventional fields will run dry. Large parts of the North Sea are all but played out. Alaska’s fabled Prudhoe Bay is pumping a meagre 440,000 barrels a day, less than a third of its 1987 daily peak of 1.6 million barrels.

As oil giants like ExxonMobil Corp. and ChevronTexaco Corp. venture somewhat fearfully into Chad, the Congo and other civil-war zones to replenish their corporate reserves, the spreadsheet managers in the Calgary oil patch want to hasten the day when the global industry commits itself even more forcefully to a stable region on the doorstep of the world’s most voracious energy consumer.

There’s no shame in that. But fun with figures is not the most seemly tactic.

The Alberta Energy and Utilities Board (EUB) insists that it is, in fact, the soul of sobriety, that it could tout the truly amazing figure of 1.6 trillion barrels of oil-sands resources it believes could be processed with advances in technology.

But the problem even with the EUB’s “conservative” 180 billion figure is that the vast bulk of those reserves will remain out of reach without an extravagant outlay on state-of-the-art extraction machinery, leading-edge refineries capable of transforming the Athabasca muck into crude, and other “infrastructure.”

What the global industry and all who rely on it desperately need is uniform standards for estimating reserves that are readily available, and also for those requiring currently prohibitive spending on infrastructure.

The latter resources are tied, obviously, to a hike in the world oil price. It’s the play of costs, oil prices, and advances in technology that determine the true status of the resource — a term too often confused, in Canada’s case, with readily accessible reserves.

Actually, that’s par for the course in the global industry, where Saudi Arabia and many other oil-producing nations jealously guard production figures on a field-by-field basis. They don’t want to dissuade potential investors by revealing rates of depletion and other potentially dismal data.

There are consequences from that opacity and the resulting misinformation. The laggard reporting and questionable data that characterizes the industry contributed to the oil-price shock of the late-1970s.

And, conversely, a late-1990s world industry consensus based on false data about a supposed hidden oil glut helped slash the world price by more than half. That triggered the demise of some mid-size producers in Canada and the United States, and the consolidation craze that gave rise to ExxonMobil, BP Amoco Arco (now BP PLC), TotalFinaElf (now Total PLC) and other hulking combinations.

There’s a foreign policy dimension to this, as well.

The U.S. occupation of Iraq puts the United States in a better position to cope with the potential fall of a shaky House of Saud. The Riyadh regime is the “swing state” that controls the world oil price by its judicious changes in Saudi output to counter jarring changes in production elsewhere.

The nightmare scenario for the regime-change strategists in Washington has long been anti-Western extremists taking possession of the world’s largest oil producer.

But to an even greater extent than the confused state of Alberta’s reporting, the actual output and lifespan of the Saudi oil fields are a matter of international conjecture, not fact — a risky basis for geopolitical planning.

In Iraq, meanwhile, the United States is finding that some of the country’s oldest and most prodigious oil fields are far more depleted than outside experts had estimated. These are the same oilfields that are supposed to finance Iraq’s reconstruction.

With the credibility of his province on the line, Alberta Premier Ralph Klein could have staked out some high ground by committing the Calgary oil patch to a leadership role in developing international standards for reserve estimates. Such a bold initiative would put his province in the global industry spotlight for all the right reasons.

But Klein has opted instead to shoot the messenger. Not knowing the value of the unexpressed thought, Klein has blurted that “The New York Times hasn’t been noted for its accuracy lately” — a reference to the paper’s firing of a plagiarizing reporter and the resignation of its two top editors.

That ground was covered by Conan O’Brien several weeks ago. Topic A now is whether Alberta has wilfully misled U.S. energy planners. (The U.S. energy department has also adopted the EUB figures.)

A light bulb seems to have switched on over the heads of some Alberta bureaucrats, if not Klein.

In a National Post essay this week, Neil McCrank, chairman of the EUB, defended the integrity of his agency’s oil reserve estimates. “We stand by our numbers,” he declared.

But the EUB also vows to pursue a previously planned “update” of its controversial accounting with what appears to be unanticipated urgency. A climbdown may be in the offing.

More important, the EUB at least acknowledges the superior merit of accountability over name-calling.

“We need rigorous inquiry to stay focused,” McCrank said of the EUB. “We need to be able to stand up to public scrutiny, Albertans expect no less.”

August 2, 2003. James Stevenson. Conoco’s Bitumen recovery at risk in northern Alberta.  The Canadian Press

Alberta Energy and Utilities Board chairman Neil McCrank is the author of a report that suggests “there is an immediate and continued risk to bitumen recovery from the production of natural gas from an area of concern within the Athabasca oilsands area.”

Sue Riddell Rose, president of Paramount Resources, says evidence is inconclusive in showing there is interaction between gas reservoirs and nearby oilsands deposits when they are injected with steam.

Massive oilsands deposits in northern Alberta would be rendered inaccessible with current technology if nearby natural gas reserves are removed, energy giant ConocoPhillips said Friday.

Releasing hundreds of pages of previously confidential documents, ConocoPhillips said years of study at its Surmont oilsands pilot project northeast of Edmonton prove steam pressure is not contained by rock layers underground.

And if the gas is removed, the pressure levels would be too low to extract the oilsands feedstock, or bitumen, with existing technology, the company said.

The ConocoPhillips data echoes the belief of Alberta’s energy regulator, which decided last week to shut in 938 gas wells by September to protect the underlying bitumen.

“We can’t rely on shale layers as a seal to keep steam pressure up in the chamber,” said Tom Trowell, manager of ConocoPhillips Surmont project. “And we now know that steam does get around or through these layers to the gas above.”

The Alberta Energy and Utilities Board “believes there is an immediate and continued risk to bitumen recovery from the production of natural gas from an area of concern within the Athabasca oilsands area,” it said in a written ruling released in late July.

The previously confidential ConocoPhillips report has long been sought after by natural gas producers in the area, led by Paramount Resources, which claims that up to half of its production could be affected by the shut-in.

Paramount said Friday that it was waiting to fully review the ConocoPhillips data before commenting.

President Sue Riddell Rose has previously said scientific evidence to date is inconclusive in showing there is interaction between gas reservoirs and nearby oilsands deposits when they are injected with steam.

ConocoPhillips says that isn’t the case. “Anyone who claims that the steam hasn’t reached the gas is being premature,” said company spokesman Peter Hunt.

By releasing its data, the Texas-based oil and gas company runs the risk of getting dragged back into the heated debate between oilsands producers, gas producers and the province of Alberta, which claims it wants to protect the resource for maximum benefits.

ConocoPhillips joins the ranks of other large oilsands producers, like Petro-Canada, in supporting the shut-in of gas production in the area.

Those fighting the order are a variety of gas producers ranging from Paramount and other smaller companies all the way to global giant BP.

The dispute is so heated that anyone not directly involved is loathe to take sides.

“This is kind of a dogfight that we’re not involved in,” Rick George, president of oilsands giant Suncor Energy, told analysts this week.

“And if you’re not involved in a dogfight there’s no reason to go in one.”

The shut-in affects about 90 billion cubic feet of gas, or about two per cent of Alberta’s remaining reserves. Conversely, the Alberta Energy and Utilities Board says the amount of bitumen in the area is about 600 times larger.

ConocoPhillips says its Surmont lease alone is roughly the size of the city of Calgary, with an estimated average bitumen thickness of a 10-story building.

The company also says that if Alberta hadn’t ordered the shut-in of wells on the Surmont release back in 2000, its pilot plant would not have been as successful as it has been.

As a result, ConocoPhillips, along with partners TotalFinaElf and Devon Energy, are poised to make a go-ahead decision on a Surmont megaproject before the end of this year that would cost about $1 billion and produce around 100,000 barrels per day by 2014.

Following a meeting this week with all affected companies, Alberta’s energy regulator ordered a regional geological study — to be completed by December — in order to closely assess which gas pools in the area are in close contact with bitumen deposits.

Alberta’s energy department has also begun meetings on the issue, looking at possible compensation for affected gas producers. Paramount has warned that this could end up costing the province hundreds of millions of dollars.

Greg Stringham, vice-president of the Canadian Association of Petroleum Producers, says the geological study is crucial in determining the full impacts of the shut-in.

And Stringham said there are a number of other tests continuing from companies like giant EnCana Corp. looking at repressuring reservoirs with waste gas or even putting pumps at the bottom of the well to pump up the bitumen.

“I think that’s where the real answer to this dilemma lies, it’s not in the back and forth between the companies, it’s how do we apply technology so that both of the concerns can be resolved


Dec 7, 2003. Nelson Antosh. Recovering Canada’s oil takes more mining than pumping.  Houston Chronicle

Conocophillips is heading a trio of companies that will spend $1.1 billion developing an oil deposit in Canada on par with the largest fields ever found in Texas.

At 5 billion barrels recoverable, the Surmont project south of Fort McMurray in Alberta can be likened to the giant East Texas field that has produced 5.2 billion barrels since its discovery in 1930.

In today’s thoroughly searched United States, a billion barrels is considered a giant field.

But finding Surmont wasn’t the hard part, because the oil sands in some regions of Alberta are so shallow they can be discovered with one’s shoe.

The challenge involves getting the oil out of what may be the world’s largest deposit of petroleum because it is mixed with sand and as nearly as thick as tar. As companies show oil can be produced there at reasonable prices, the amount of reserves associated with oil sands zoom upward.

The Oil and Gas Journal, for instance, in its last survey gave Canada 180 billion barrels in reserves, up from less than 5 billion barrels the year before. Such recognition of proven reserves “is clearly leading to a fresh wave of interest,” says Peter Hunt, the public affairs manager for ConocoPhillips Canada in Calgary.

The company’s Surmont lease covers a land area about one-fourth the size of the city of Houston, containing an underground oil formation as thick as a 10-story office building is tall. This oil-soaked sand is located below a rolling forest of spruce and fir in northern Alberta.

The Alberta Department of Energy likes to say that the western province has more oil than Saudi Arabia and is important to the United States because Canada is an area of political stability, unlike parts of the Middle East.

But oil sand production got off to a slow start. It is just in recent years that it is moving toward full-tilt development. Billions are being invested, and the big players like Exxon Mobil and Shell are involved.

ConocoPhillips considers Surmont to be a legacy project, which means it costs a lot of money initially but will be around for a long time, in this case 40 to 50 years.

It this works out, there’s plenty more waiting to be produced. The amount of oil considered recoverable from Canada’s oil sands with current technology ranges from 177 billion to a whopping 300 billion barrels, depending upon which definition and figures you use.

Bigger is better

The difficulty with oil sands, ever since mining began in 1967, has been getting it out at a low-enough cost. Suncor Energy of Calgary, the pioneer, said the key was developing technology, which in this case means bigger and bigger equipment. Its trucks are capable of carrying up to 400 tons at a time.

The oil between the grains of sand is almost as thick as tar, putting it in the category of bitumen: naturally occurring solid or liquid hydrocarbons. In the summer it is soft and glistens like asphalt on a hot summer day (also a bitumen), but in the Canadian winter it turns into chunks almost as hard as rock.

Before the bitumen is usable, it must be run through a refinery unit, typically a high-temperature piece of equipment called a delayed coker, to give it the thinner consistency of crude oil. Suncor uses a delayed coker 10 times larger than those typically found along the Gulf Coast to process the finds.

The earliest recovery tactic, and still the biggest, is to mine the sand and extract the oil with hot water, according to Suncor, which has been doing it this way since 1967.

The oily sand is placed in settling tanks of 180 degree water, where the oil is floated off the top and the sand settles to the bottom. Then the extra-heavy oil must be processed through the coker.

It takes about two tons of sand to produce one barrel of oil, the company says. Currently it is handling 450,000 tons per day to produce 225,000 barrels of oil. About 92 percent of the oil in the sands is actually recovered.

Using the open-pit method, Suncor has extracted nearly 1 billion barrels. The company calculates that it is sitting on 13 billion recoverable barrels.

Two-well method

More recently, Suncor and operators like ConocoPhillips are looking to other methods to tap reserves buried too deep to dig out.

This method is to drill wells and inject steam, leaving the sand in place while pumping out the oil in a more conventional fashion. Called in-situ, this tactic promises being able to reach the 85 to 90 percent of sand deemed too deep to mine.

With the help of its in-situ project called Firebag, Suncor expects to more than double its output by 2010 or 2012. It plans to be cranking out 500,000 to 550,000 barrels per day by then.

ConocoPhillips’ project will borrow from the latest oil exploration technology to develop Surmont, by using three-dimensional seismic imaging to precisely map the underground formation and drilling horizontally to get at the oil.

Suncor’s production costs have been going down, to about $8 in operating expenses per barrel, President and Chief Executive Rick George said during a recent visit to Houston.

One reason is that there aren’t finding costs, said George. The company’s vision is to move the cost curve downward to about $6 per barrel, which would make it one of North America’s lowest-cost producers.

Moody’s Investors Service recently changed Suncor’s rating outlook from negative to stable, on the basis that the company’s cash operating costs will continue on a lower trend in the near to medium term.

The oil sands cost compares with the five-year average finding and development cost in the United States, which was $8.19 per barrel from 1998 through 2002, according to Nicholas Caccione, director of research for John S. Herold Inc.

The ConocoPhillips group isn’t disclosing its expected costs per barrel, other than saying it should be roughly comparable to the mining method.

But there are also environmental costs that could be considerable: surface mines, rows of settling ponds, clusters of large refinery equipment and fragmentation of a northern forest.

Some people are wondering how all of this energy-intensive activity will fit with Canada’s ratification of the Kyoto Accord to limit the emission of greenhouse gases.

However, the government has given oil sand companies some assurance they won’t be stymied by costs connected with limits on carbon dioxide emissions, said to cause global warming, which could make the projects uneconomical.

In the short term, the government has placed a cap on the price of the credits in Canada that may have to be purchased to allow them to emit so much carbon dioxide, said Hunt and Suncor’s CEO, Rick George.

Others are more concerned. The chief of Petro-Canada, Ron Brenneman, told Bloomberg News after a Nov. 24 speech in Montreal that the Kyoto deadline was too short and the implementation plan was too prescriptive. “It’s so restrictive that, as we see it, the only alternative is to buy emissions credits from outside the country,” said the CEO of one of Canada’s largest oil companies, which also has an oil sands project.

100 pairs of wells

There were years of study before the mid-November go-ahead announcement by Houston-based ConocoPhillips, the French company Total and Devon Energy of Oklahoma City.

A pilot program has been running since 1997 to make sure everything works before committing serious money. Conoco came into the picture when it acquired a company named Gulf Canada in 2000.

The plan is to drill about 100 pairs of horizontal wells, which will take production to more than 100,000 barrels of oil per day by 2012, said Hunt. The first production will occur in 2006.

The wells are in pairs, with the top well directly above the bottom well. Steam will be pumped into the upper well to melt the bitumen, said Hunt, so it can seep downward through the sand to be collected by the bottom well. The technology is called steam-assisted gravity drainage.

Horizontal drilling allows the drill bit to travel downward in conventional fashion, then steer horizontally for an extended distance with great precision.

The Surmont wells will be drilled to an average depth of about 1,200 feet before turning horizontal, which is considerably below the 100 to 150 feet that is considered suitable for surface mining.

Eventually a steam cavern will form around the upper well.

This is where 3-D seismic comes into play. You wouldn’t want a layer of something like rock stretching across what is supposed to be a cavern, said Hunt. “What really matters is understanding the geology, so you can drill in the best places.”

ConocoPhillips plans to lessen the environmental impact by using water from deep wells, rather than the river, and sharing roads with a company that is actively logging there.

Rather than build a coker for upgrading the bitumen, ConocoPhillips is considering moving it via pipeline to existing refineries in Wood River, Ill., and Billings, Mont. It could be diluted with some lighter products to the point that it will flow, Hunt said.

Negotiations with the pipeline owners are in progress.


July 2004. Brendan I. Koerner. The Trillion-Barrel Tar Pit Who needs “oil independence” – our friendly neighbor to the north is sitting on a black gold mine! Wired issue 12.07


Fort McMurray, Alberta, is an unlikely destination for a congressional boondoggle, especially when cold snaps of 40 below make it dangerous to leave any patch of skin uncovered. But here I am in midwinter, 250 miles north of Edmonton, watching a flock of Washington politicians in subzero parkas cling to tour guides like a trail of oversize ducklings. With gas prices approaching $3 a gallon in some states, the US representatives are braving the frigid air not for adventure but to learn about a filthy sort of alchemy, one that turns sludgy, sticky earth into sweet crude oil.

Alberta sits atop the biggest petroleum deposit outside the Arabian peninsula – as many as 300 billion recoverable barrels and another trillion-plus barrels that could one day be within reach using new retrieval methods. (By contrast, the entire Middle East holds an estimated 685 billion barrels that are recoverable.) But there’s a catch. Alberta‘s black gold isn’t the stuff that geysered up from Jed Clampett’s backyard. It’s more like a mix of Silly Putty and coffee grounds – think of the tar patties that stick to the bottom of your sandals at the beach – and it’s trapped beneath hundreds of feet of clay and rock.

This petroleum dreck is known in these parts as heavy oil, and wildcatters are determined to get it out of the ground and into a pipeline. If they succeed, the stereotypical oil zillionaire may be not an Arabian emir but a folksy Albertan fond of ending sentences in a question, eh? Like Jim Carter, president of Canada’s largest oil company, Syncrude. A coal-mine foreman by trade, Carter talks as if he just got out of a cut-rate business seminar, spewing jargon like “going-forward basis” and “continuous-improvement mindset.” He’s the kind of guy who straps a snowplow on his John Deere mower and clears the streets just for fun. But he clawed his way out of the pits to a corner office, and now he has a plan to make Canada’s oil reserves pay off.

Heavy oil isn’t a new discovery. Native Americans have used it to caulk their canoes for centuries. Until recently, though, it’s been the energy industry’s stepchild – ugly, dirty, and hard to refine. But the political winds are favoring the heavy stuff, as “energy independence” – aka freedom from relying on Middle East oil – has become a war-on-terror buzz-phrase. Even President Bush has waxed optimistic about Alberta’s “tar pits.”

Better yet, recent improvements in mining and extraction techniques have cut heavy oil production costs nearly in half since the 1980s, to about $10 per barrel, with more innovation on the way. The petroleum industry is spending billions on new methods to get at the estimated 6 trillion barrels of heavy oil worldwide – nearly half the earth’s entire oil reserve. Last year, Shell and ChevronTexaco jointly opened the $5.7 billion Athabasca Oil Sands Project in Alberta, which pumps out 155,000 barrels per day. Venezuela’s Orinoco Belt yields 500,000 barrels daily, and that number should spike when a new ChevronTexaco plant goes online this year.

The trailblazer in heavy oil is Syncrude, a joint venture among eight US and Canadian energy companies, which has been harvesting greasy sand since 1978. Last year, the company shipped 77 million barrels of its trademark product, Syncrude Sweet Blend, mostly to US refineries. That’s 14 percent of all Canadian oil sales, company executives boast – enough to produce 1.5 billion gallons of gasoline.

Chalk up the impressive output to Syncrude’s efficiency. Carter and his team like to present themselves as roughnecks, but they run the company like bookish software engineers. Their oil mines – noisy and grimy and often reeking of sulfur – operate with the high tech prowess of a Taiwanese factory churning out LCDs.

The Caterpillar 797 dump truck is a true monster – 48 feet from tip to tail and 22 feet high, it creeps uphill with a 400-ton payload at 1 mile per hour. Syncrude owns 36 of the vehicles, which cost $5 million each. This herd of yellow pachyderms lumbers around the company’s open-pit mines, shuttling oil sands from the digging shovels to a massive processing facility called a crusher. The inside of the crusher resembles the guts of the Nostromo, the doomed ore-hauling ship in Alien. Whale-sized pipes and narrow catwalks crisscross everywhere; steam billows from hoses that snake along the floor. Here the sands are pulverized, then sent to cyclofeeders to be mixed with hot water and pumped to gargantuan centrifuges where the oil-rich component, bitumen, is separated out. The bitumen is sent to giant cokers and roasted with hydrogen into Syncrude Sweet Blend.

It’s a laborious process, to say the least – 2 tons of sand yields just one barrel of oil – but nowhere near as painstaking as it used to be. In the 1920s, Karl Clark, a University of Alberta chemist, discovered that steam could tease pitch out of sand. His breakthrough piqued Big Oil’s interest, but no one could make the process cost-effective. In the 1950s, a few desperate hopefuls suggested detonating a subterranean nuclear bomb to blast the gunk to the surface. When Syncrude started, it relied on draglines, huge cranelike devices weighing more than 15 full 747s. Attached to these $100 million machines were enormous buckets; the draglines would scrape the buckets across the earth to scoop up huge chunks of sand – a tough process to coordinate come winter.

The murderous climate caused untold headaches. The conveyor belts that carried oil sands from dragline to processing plant were prone to cracking. Whenever the cokers got clogged with calcified soot, Syncrude had to shut down for a week and send in cleaners with sledgehammers – “the kind of job that makes you thankful you have an education,” quips Mark Sherman, who now manages the company’s cokers.

When an OPEC glut sent oil prices skidding to $10 a barrel in 1985, Syncrude was losing $5 to $10 on every barrel of synthetic crude it produced. Only savage staff cuts staved off complete ruin. Nearly a decade later, Syncrude began to get creative. In 1994, the executives opened an R&D lab in Edmonton and started spending $30 million a year to devise increasingly efficient extraction methods. They ditched the draglines for more agile trucks and shovels and replaced some of the conveyor belts with hydrotransport, a method in which crushed sand is mixed with hot water into a pipeline-ready slurry.

As new information technologies became available in the ’90s, Syncrude moved to further streamline its operations. Today, miles of fiber-optic cable snake between the company’s ore crushers, shovels, and pipes. Operations are supervised from the heated comfort of computerized control centers, where truck dispatchers use GPS to ensure that the Caterpillars proceed like clockwork. A homegrown computer program keeps tabs on each $35,000 13-foot-tall truck tire, as cold tires are prone to cracks. X-ray sensors on the hydrotransport pipes scan for leaks, and ultrasonic transmitters verify that the crushers are never quite empty, lest their metal teeth mash against each other and cause damage.

Carter doesn’t think Syncrude’s costs are low enough yet. For starters, the company spends more than $100 million a year on natural gas to heat the facilities and fuel the hydrotransport system. Then there’s the cost of maintaining the monster trucks. Carter says replacing the trucks with mobile crushers – currently in development at the Edmonton center – could save $1.50 per barrel.

Cutting expenses is always good, but the real payoff for Syncrude will come if its R&D lab can find a way to get at the trillion barrels of oil that currently lie so far below ground that they are beyond the industry’s grasp. All the heavy oil companies are experimenting with new methods that will allow them to go deeper. One possible solution comes in the form of a process known as steam-assisted gravity drainage. In SAG-D, steam is forced through a well into the subterranean oil sands, melting them and separating the bitumen. The oily parts then seep into a second well and rise to the surface. At least a dozen SAG-D projects are under way, the most successful of which, operated by Imperial Oil, is producing 116,000 barrels per day. The problem is that creating the steam requires a lot of energy. A less energy-intensive alternative: vapor-assisted petroleum extraction, a technology that injects gaseous hydrocarbons into the earth. When the heavy oil surfaces, the hydrocarbons are stripped off and recycled. One company, Canada’s Petrobank, is experimenting with an air injection method that blasts out the bitumen with compressed air. There’s also been some renewed interest in nuclear energy – not in the form of a bomb, but as a way to generate necessary steam.

No one’s suggesting that Alberta’s version of beach tar will wean us off Middle East oil anytime soon. After all, it took Syncrude two decades to bring production costs down to $10 per barrel. And that’s still more than triple the cost of producing Saudi Arabian crude, which is so light that it requires much less refining. “Some of it is so good, you can put it right in your car,” says Michael Economides, a chemical engineer at the University of Houston and a consultant to the Russian oil giant Yukos. By contrast, Economides says the heavy oil that Syncrude mines is “shit.”

On my last day in Fort McMurray, I bum a ride with Eric Newell, who recently retired as Syncrude’s CEO. He’s particularly excited about the congressional visit. He recalls a 1996 trip to Washington, DC; he’d been invited to the Canadian embassy to preach the virtues of heavy oil. The audience of US senators, Goldman Sachs bankers, and assorted other bigwigs seemed more interested in their meals than his speech.

What a difference a war makes. These days, Congress is considering a $3 per-barrel tax credit to companies that import heavy oil from north of the border. So forget those scraps over prescription drug prices and trade policy – Canada has never looked like such a pal. The friendly relationship is a none-too-subtle part of Jim Carter’s Syncrude pitch: “Our American neighbors know what Canada’s like. It’s a good, stable country.”

And chock-full of tar patties.

Tapping the Oil Sands of Alberta

The biggest petroleum reserve outside Arabia lies beneath Canada in the form of heavy oil. Here’s how Syncrude is priming the pump.

1)      Syncrude shovels excavate thousands of tons of soil and clay, creating a 150-foot pit for mining the oil sands below.

2)      Oil sand is piled high into monster Caterpillar trucks, capable of carrying 400 tons at a time.

3)      The trucks dump their payload into crushers, which grind it down to fine oil-coated grains.

4)      The sand is transferred via conveyor to a cyclofeeder, where it’s mixed with hot water to produce a slurry. The slurry flows to the extraction facility, where large centrifuges separate out the oil-rich bitumen.

5)      Bitumen flows to cokers, where it’s heated to remove impurities such as sulfur and nitrogen, leaving only usable crude oil.

6)      The crude is sold to off-site refineries, which produce gasoline.


Feb 09, 2005. Angel Gonzalez.  Indus Exec Says Oil-Sands Output Vulnerable To Bottlenecks. Dow Jones Newswires.CALGARY–Analysts expect Canada’s oil-sands output to double to 2 million barrels of synthetic crude a day by the end of the decade, but an industry executive warned Wednesday that this capital- and labor-intensive production is extremely vulnerable to bottlenecks in the upgrading process.

Synenco Energy Inc. Executive Chairman Michael Supple said that when upgrading relies on a single train of production, “the failure of a $5 or $10 widget would shut the whole thing down.” He was speaking at an oil-sands conference in Calgary.

Synenco owns extensive oil-sands mining permits and coal leases in the Fort McMurray area of northeastern Alberta.

Supple, a former oil-sands manager for Suncor Energy Inc. (SU), alluded to a recent fire at the company’s oil-sands facility in Fort McMurray, which shut in half of the facility’s normal production of 225,000 barrels of synthetic crude a day until the third quarter of 2005.

The neighboring Syncrude Canada Ltd. facility also announced a shut-in of 65,000 barrels of oil a day for the remainder of the first quarter due to a maintenance failure at one of its hydrogen plants Jan. 31.

Supple recommended producers not put all of their eggs in one basket, and instead set up independent and multiple production avenues.

Suncor spokesman Brad Bellows said oil-sands production is vulnerable because the tar-like bitumen must be upgraded into lighter products more attractive to refiners.

“People forget how much we are a manufacturing operation,” Bellows said at the conference.

jan 22, 2006. Comment from: Alberta oil sands on 60 minutes.

The introduction to the piece said that oil sands would provide plenty of oil for us for the next hundred years.  What rubbish!  The truth was hidden later in the piece – it’s all in the numbers:
Current oil use worldwide: 84mbl/day.  Projected for 2015: 105mbl/day.
Current oil sands production: 1mbl/day.  Projected for 2015: 3mbl/day.
This is going to “solve our problem”???
And I don’t recall that they even mentioned that, most of the year, they have to use massive quantities of natural gas to melt the crap enough to be able to scoop it out of the ground.  And natural gas is running down quickly in North America.
By the way, those giant trucks (“toys”) use over 100 gallons of diesel fuel per hour.  Not good for yer EROEI…


Dec 05, 2005. Oil sands. Are oil sands the answer to peak oil? Econbrowser.

They’ll help some, to be sure. But they’re not a reason to ignore the issue.

Green Car Congress provides a nice summary of what this energy source involves:

Oil sands are a mixture of sand, clay, water and deposits of bitumen– a very viscous form of oil that must be rigorously treated in order to convert it into an upgraded crude oil before it can be used in refineries to produce gasoline and other fuels. (Oil sands used to be called tar sands, to give you a sense of it.) The ratio of bitumen to everything else is relatively small: 10%-12%.

The bitumen contained in the oil sands is characterized by high densities, very high viscosities, high metal concentrations, high amounts of sulfur and a high ratio of carbon to hydrogen molecules. With a density range of 970 to 1,015 kilograms per cubic meter (8-14o API), and a viscosity at room temperature typically greater than 50,000 centipose, bitumen is a thick, black, tar-like substance that pours extremely slowly.

One of the reasons for interest in oil sands is the potential magnitudes involved. The Alberta Energy and Utilities Board estimates the ultimate volume of Canadian bitumen in-place at 2.5 trillion barrels, which if it could somehow all be extracted would be enough to satisfy by itself the entire world petroleum demand at current rates for 80 years. Even if only a tiny fraction of this proves ultimately to be developed, this would be a very important resource indeed.

Nor is the exploitation of this resource merely a theoretical possibility. Almost 40% of Canada’s current crude oil production of 2.6 million barrels per day is derived from oil sands. About 1/3 of current production is from in situ methods, in which the oil sands are heated while still underground, and 2/3 from open-pit mining and above-ground processing.
Suncor Energy Inc., Fort McMurray, Alberta syncrude_plant.jpg

So what’s the catch? Huge capital requirements, for one. $34 billion (Canadian) have been invested so far in Canadian oil sands just to get to current levels, and an additional $36 billion (US) might bring Canadian bitumen production up to 2.7 mbd by 2015. To put that number in perspective, significantly more than 2.7 mbd in new capacity has to be added every year in order to replace the production that is lost from each year’s depletion of existing conventional oil fields. Moreover, a large amount of energy input is required in order to produce each barrel of bitumen.

There are also significant capital requirements in order to use this synthetic crude on a larger scale. Green Car Congress had a very interesting summary last week of a report from Natural Resources Canada about Canadian oil sands:

These crude oils, whether shipped as unprocessed bitumen or in upgraded form as synthetic crude have different characteristics from conventional light and heavy crudes, and their introduction as a major proportion of the refinery crude diet will present challenges.

Most conventional refineries are limited to using about 10-15% of synthetic oil sands crude in their diets before fuels quality limitations begin to appear, according to the report.

The challenges to utilizing these crudes include the need for more “severe” processes to refine the heavy synthetic crude to duplicate fuel characteristics to which engines have become accustomed. The technology to overcome these differences is largely known, but requires significant lead-time to install.

Environmental issues are another big concern. Oil sands do not seem to involve as severe disruption as oil shale, though many of the concerns are similar. Green Car Congress summarized some of the issues about oil sands raised by the Pembina Institute, an environmental group based in Alberta, Canada. Perhaps the hardest to avoid is the increased emission of greenhouse gases, the issue that ultimately killed Australia’s demonstration oil shale project.


23 Sep 2006. . Murray Whyte. At what price progress? Toronto Star.

Fort McKay, Alta.-From its source at the ancient glacier that bears
its name, the Athabasca River tumbles down from the Rocky Mountains
in Jasper and into the valley it has carved over the millennia, its
icy waters rushing east and north through the foothills and high
Alberta plains. Then, 400 kilometres into its journey, it curls due
north, where the flatlands give way to the swath of Canadian Shield
that spills east from Ontario and buckles the prairie with rock and
centuries-old boreal forest.

Just past halfway on its journey north to Lake Athabasca, the river
rushes through the most rapidly-industrializing place on Earth: the
oil sands.

It is here where the river, with its bounty of glacial water, bound
for the muskegs and fens of the Athabasca delta, crashes into the
very modern priorities of the new West: the stampede for wealth. And
it is the river’s bounty that makes it all possible.

Along the river’s edge, existing oil-sands operations and approved
developments soon to follow have been granted licences to siphon 349
million cubic metres of the river’s flow each year – roughly the
amount of water used by Calgary and Edmonton annually combined – to
extract heavy crude oil from the black muck that holds it. Including
other projects awaiting approval, that allocation swells to 529
million cubic metres. “I don’t think anybody who thinks about this
realistically can believe it’s sustainable,” says David Schindler,
the pre-eminent scholar on ecological policy and hydrology at the
University of Alberta.

Schindler has participated in several public hearings, preaching
prudence and moderation in the oil sands’ growth to mediate the
impact. His 30-year study on the river’s flow level shows a
disquieting trend: a decline in volume of 30 per cent over that span.
And the river’s banks have receded by nearly two metres over that

But industry’s demand for the water will only grow. To free the crude
oil, as many as 4 1/2 barrels of water are needed to yield a single
barrel of oil. The leftover petrochemical brew, too toxic to be
returned to the river, accumulates in tailing ponds with a combined
surface area of 50 square kilometres, visible from space, that have
been growing for decades.

Operators like Suncor and Syncrude, oil sands pioneers, have learned
to do more with less, recycling water and taking only a portion of
what their licences permit.

But that’s as much a result of necessity as it is conservation: In
1995, the National Oil Sands Task Force laid out a growth plan to
reach 1 million barrels per day by 2020. That target has already been
passed: The oil sands today produces 1.2 million barrels every day.

As new projects come online, according to the task force, that number
will triple in 15 years, and grow fivefold in 25. Estimates put the
known reserves at close to 179 billion barrels – second-largest on
Earth, after Saudi Arabia.

About $20 billion worth of investment in extraction was expected by
2020; it’s already there.

In the next 10 years, oil companies from Europe, India, China and the
U.S., will spend another $70 billion digging up the oily black
ground. An open pit nearly 3,000 square kilometres in size will grow,
swallowing streams, wetlands and boreal forest, razing habitat for
fish, birds and woodland caribou.

That dimension is, literally, only the surface. The proportion of oil sands accessible from ground level is less than 10 per cent. The rest of the bitumen – the term for the oil-saturated muck – is deep underground. Companies have a number of methods to extract it, like injecting superheated oxygen or steam as deep as 300 metres below to boil the oil free.

Meanwhile, on the surface, millions of cubic metres of river water, thick with toxic by-products like naphthenic acid, bubble and build in the ponds, never to be returned. According to the U.S. Department of the Interior, Syncrude’s dam, which holds back nearly three decades of waste water, is the second-largest on Earth after the Three Gorges Dam in China.

“If any one of those were ever to breach and discharge into the river, you’re talking about a world-scale ecological disaster,” Schindler says.

For some, the ecological disaster has already begun.

Two hundred kilometres downriver, where the river empties into Lake Athabasca, sits the hamlet of Fort Chipewyan. It is, at first glance, pristine, the landscape thick with boreal forests and wetlands veined with rivers and creeks that pool into a network of lakes and swampy muskegs that nourish hundreds of species

Here, at the river’s end, the Mikisew Cree have hunted and fished for centuries, living on what the river brought from upstream.

They don’t do that much anymore. Fort Chipewyan has been hit hard in the last 30 years. First, the Bennett dam choked off the Peace River to the west. Water levels in the lake dropped by as much as three metres.

“And you’re talking about a 200-mile-long lake. That’s a lot of water,” says Archie Waquan, a former Mikisew chief. Near sunset, he drives along the community’s single paved road that runs along the shore.

But the water’s edge is further now, a 50-metre stretch of bulrushes and long grass from where he pulls over to look.

“In the ’60s, we’d land our boats right here,” he says, standing on a grassy patch. “Now, it’s just land. How much more water can they take out of that river system before it’s damaged permanently?”

This is not the worst of it.

In 2001, the town’s fly-in doctor, John O’Connor, started noticing a proliferation of a rare cancer of the bile duct found, statistically, in 1 out of 100,000 people. In Fort Chipewyan, with 1,200 people, he found five.

For some, it was further confirmation of what they’d already seen. Fish, a source of food and employment, had started appearing with bizarre mutations – enlarged heads, scrawny bodies. There were reports of jackfish oozing a milky, pus-like substance. After generations of drinking straight from the lake, many here now drink only bottled water, trucked or flown in from hundreds of kilometres away.

The Alberta Cancer Board launched an investigation, and concluded earlier this month that the incidence of cancer was no greater than normal.

Then, another recent scare, when Suncor, as part of its environmental impact assessment for an expansion application earlier this year, investigated the potential for seepage along the river of arsenic, a potent carcinogen, from the plants. The Alberta government is evaluating moose meat and cattails in the Fort Chipewyan region for arsenic content, trying to determine its source.

Waquan doesn’t need to hear the results to draw conclusions. “We never had cancer on this river before,” he says. “It’s got to be coming from somewhere, right? And it’s got to be those oil sands plants.”

The industry flatly denies the implication.

“Those ponds are there to recycle water. And those are engineered dams,” says David Pryce, vice-president, Western Canada operations, for the Canadian Association of Petroleum Producers. “The risk of contaminants leaking into the water table is, frankly, negligible.”

Others, like Schindler, are not so convinced. The industry releases hundreds of compounds, most of them unidentifiable, he says. Of those that are, naphthenic acid and toxic trace metals register high on the hydrocarbon analysis.

“It’s sort of a witches’ brew of things,” he says. “The oil sands have greatly accelerated the release of those things.”

But of paramount concern to Schindler is the uncertainty. For much of the 20th century, the oil sands was deemed too costly to be worth the price of extraction. That changed in recent years, as technology improved and world oil prices shot up to $40, $50 and even $70 a barrel, pushing its development into fast forward.

The relatively short time frame means no real long-term data exists to determine cause and source.

Alberta’s environment minister, Guy Boutilier, says he’s “comfortable with the framework we have for the Athabasca.” But Schindler calls it “an old Alberta trick: If you don’t have data, you can’t say there’s a problem.”

In Fort McMurray, the oil sands frenzy has doubled its population, from 30,000 in 1996 to 64,000. It’s both blessing and curse.

A labour shortage has driven wages to unprecedented heights – $100,000-plus for driving a truck. But housing shortages, an overburdened health system, and increasing social ills – homelessness, drug use, alcoholism – are the costs.

On a bad day, the source of it all hits home: A sour stench from the refineries, spewing sulfur and carbon dioxide, that cloaks the bustling downtown in a throat-burning shroud.

In just a few years, the Fort McMurray area has become the largest source of carbon dioxide emissions in Canada. By 2015, it’s estimated the town – projected population 100,000 – will emit more greenhouse gases than the entire nation of Denmark, population 5.4 million.

The development is creating vast wealth in the province, both for individuals and governments. In 1998, the provincial government, through its oil sands royalty program, collected $197 million. Next year, that figure will be $1.7 billion.

But many have started to wonder at what cost. A government proposal last year to prioritize oil sands development over all other issues in the north – education, health care, environment – was met with such a public backlash that it was scrapped. As a result, the province has been conducting public consultations across the province all month.

The most recent were in Fort McMurray this week. Boutilier, a former Fort McMurray mayor, was there. He provided a sense of the shifting priorities: During the hearings for Suncor’s expansion recently, Boutilier broke rank with his development friendly government by preaching prudence in the oil sands’ rapid expansion.

“I actually talked about a delicate balance,” Boutilier says. “I talked about sustaining the environment for our grandchildren.”

But many wonder if this is just simple public relations, fuelled by the public backlash.

“I think a lot of Albertans are saying, `okay, do we have enough in

place for the development to take place in the public interest?'” says Dan Woynillowicz, a senior policy analyst with the Pembina Institute, an environmental think tank. “And I think a growing number would say no.”

His organization has suggested a moratorium on new approvals until further environmental research can be completed.

`I don’t think anybody who thinks about this realistically can believe it’s sustainable’

David Schindler, University of Alberta

Even former premier Peter Lougheed, an Alberta icon, recently called the oil-sands development “a mess.” And yet, there is no slowing down.

But industry and the government are sensitive to the growing public concerns.

“By no means does a company come to us and walk away with an approval,” says Darin Barter, a spokesperson for the Alberta Energy Utilities Board. “The gold rush mentality you keep hearing about isn’t really occurring.”

Pryce says companies were striving to be “ultra-conservative” in their impacts. “There’s some angst from all parties on this, frankly. But companies are becoming more efficient all the time.”

He warns that a moratorium could stifle the boom. “There are huge investment decisions that hinge on this,” he says. “The Crown is challenged with managing the resource, without scaring off investors.”

That investment is double edged, as the people of Fort McKay know all too well.

Fort McKay, a tiny first nations community of about 500 people dead-centre of all the development, is at the crux of the issue for all aboriginals.

Things have changed here, says Stan Laurent, whose business, Fort McKay Enterprises, supplies support services to the industry. The community has near full employment. All the roads, for the first time, are paved. A new timber-frame complex, which serves as the tribal council’s chambers as well as offices for the Fort McKay group of companies, sits at the river’s edge.

“When you’re smack-dab in the middle of $100 billion worth of development, the community should reflect that,” Laurent says. Fort McKay is a big participant in the development, with plans to start its own mine in partnership with Shell. The natives’ traditional territories are rich in oil. At the roadside, long grasses grow out of the black muck, clearly visible on the surface. As a result, they’ve become one of the wealthiest bands in North America.

Every day, though, the stink of sulfur fills the air. “We’ll be wearing gas masks in a few years,” says Laurent’s wife, Cheryl.

And the lands where the people of Fort McKay have hunted and trapped for millennia are all but gone. “Eight or nine years ago, we would just go out our back doors and be in the bush,” Laurent says. “Now, you sit outside at night, and you can hear it – the heavy haulers, the refineries. That’s just daily life.”

Laurent knows that wealth comes at a cost.

“We can’t just sit here and say, `you can’t do this, you can’t do that,’ and then sit back and expect to benefit from it. If we do that, we’ll be losers as a First Nation,” he says. “We have to move on. There’s not going to be another boat like this one coming through here, and it’s already sailing away. This is our chance to make sure our future is set.”

The lands, most acknowledge, are gone, and for good. Companies have reclaimed abut 5,200 hectares of land by filling in expended pits, creating grasslands and nascent forests; so far, not one hectare has been approved by the province as certified reclamation.

While many companies say they can put the land back exactly as they found it, Schindler calls the claim to rebuild centuries-old muskegs and fens “total nonsense. Wetlands experts from all over the world know there’s no way to put it back, period.”

Cecilia Fitzpatrick, a tribal council member in Fort McKay, acknowledges it’s a steep price to pay. But she also accepts the reality.

“We’ll never go back to a traditional way of life,” she says, seated in an office as slick and modern as any in the corporate canyons of Toronto.

Fitzpatrick grew up in the woods hunting and trapping with her parents. From her office, it’s a short walk to the banks of the river, which she remembers as much higher, much clearer, more blue.

“I wish we could live in a bubble,” she says. “But we can’t. We could sit and watch, and be poor. You can’t fight it, but you can profit from it.


“When all is said and done, and all this is gone, we’ll still be
here,” she says. “We need to make sure we’re looked after.”

Schindler believes that vision to be more dream than reality.

“This will be a visible scar on the planet 1,000 years from now,” he
says. “Really, what we should be doing is slowing down. But we’re not.

“We’re making a mess we may never truly be able to clean up.”


Oct 7, 2006. Steve Hargreaves. Curing oil sands fever Despite wide-eyed predictions, serious constraints remain in developing Alberta’s heavy oil.

EW YORK (CNNMoney.com) — The answer to America’s oil addiction lies in Canada.

Or so goes one line of thinking. As oil supplies got tighter and crude prices soared over the last few years, tens of billions of dollars flowed into an effort to develop the biggest oil reserve outside Saudi Arabia: Alberta’s oil sands.

Along with the development rush have come rosy predictions on how much this secure, close, proven supply of oil might yield. Four million, 6 million, even 10 million barrels a day, which is nearly half America’s total daily consumption and would easily replace all imports from the Middle East.

The only thing is, those numbers may be far too high.

Making a barrel of clean, light crude from the thick, dirty oil sand uses massive amounts of water, massive amounts of electricity and requires a large pool of labor in an otherwise sparsely populated area.

“People jump to the assumption that we can immediately ramp up to 9 million barrels per day and save the world,” said Peter Tertzakian, chief energy economist at ARC Financial, a Calgary-based private equity firm. “But it’s just not going to happen.” Stuck in the sand

This isn’t to say the oil sands won’t be a viable energy source. Two hundred miles north of Edmonton, covering an area roughly the size of Florida, they already produce more than 1 million barrels a day.

U.S. majors ConocoPhillips (Charts) and ExxonMobil (Charts), as well as Royal Dutch Shell (Charts), have interests in the area, although Canadian firm Suncor (Charts) and the consortium Syncrude are the biggest players.

Getting a product similar to light crude usually involves one of two methods.

The first uses a model borrowed from open-pit mining, in which the sands are dug out of the ground with heavy equipment, then mixed with steam, hot water and caustic soda to create a slurry.

The slurry then enters a separation tank where bitumen, the valuable product in this process, rises to the top and is skimmed off. The bitumen is then heated again to remove impurities, resulting in a synthetic light, sweet crude that’s easy to refine.

The other method uses a well to inject steam into a seam of oil sand deep below the earth’s surface. The resulting slurry then drains down into a second well drilled below the first, where it’s pumped to the surface.

This eliminates the need to strip-mine the area, but creating the needed steam uses vast amounts of energy.

And energy is the first limitation people bring up at the mention of the oil sands.

Tertzakian said it takes the equivalent of 0.7 barrels of oil to create one barrel of oil sands product.

What’s more, most of the energy needed to make the stuff currently comes from natural gas, an energy-rich, clean fossil fuel.

“It’s like using caviar to make fake crab meat,” said Marlo Raynolds, executive director of the Pembina Institute, a Canadian environmental group.

Experts say most of the natural gas Canada currently exports to the United States will be eaten up by the oil sands projects. To fuel further expansion, they say, Canada will have to import natural gas from Alaska. Some have even suggested going nuclear, although that idea has gained little traction so far.

Another constraint is water. Both extracting methods use huge amounts, up to two barrels for every barrel of oil produced.

Even with production running at one million barrels a year, concerns are already being raised over the drawdown from the major rivers that flow through the region.

“At some point it’s going to reach a tipping point when people say enough is enough,” said Raynolds.

And then there’s the labor question. If you’re looking to make truckloads of money doing mindless work, head to Fort McMurray, the biggest town close to the oil sands.

A quick read of the classifieds at the town’s newspaper turns up jobs selling concessions at the movie theatre paying the equivalent of U.S. $10 an hour. Janitor positions start at $17.

For more skilled workers, a welder can bring in $80,000 a year, more than double the average in the U.S. And that’s without overtime.

“We now have signing bonuses for people who work in coffee shops,” said Tertzakian. “We just don’t have the labor pool to match $90 billion in investment.”

So how much can they pull from the ground in Alberta?

The Canadian government and many of the companies up there put the number somewhere around 4 million barrels per day by 2015, still a significant amount roughly equal to America’s total crude production.

“The production levels aren’t unrealistic at all, it’s just a question of time,” said Sheraz Mian, a senior oil and natural gas analyst at Zacks Investment Research.

But others are less sanguine.  The U.S. Energy Information Administration, not generally known for issuing bearish reports, puts the number at 2.3 million barrels per day by 2015.

Tertzakian estimates maybe 2.5 to 3 million barrels per day and cautions against too much optimism.

“Nobody should feel comfortable that Canada’s oil sands are going to single-handedly satisfy the world’s energy needs,” he said.

David Biello. July 2013. Greenhouse Goo. The fate of the Alberta’s tar sands mines and the climate may come down to the Keystone XL pipeline. Scientific American

Caterpillar 797Fs are the worlds largest trucks, capabe of carrying a 400-metric-ton load of tar sands.  Women drivers are sought after because they’re easier on the equipment than men, but hard to find since men outnumber women 3 to 1.

Suncor produces a third of the 2 million barrels produced per day.


Alice Friedemann

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