Forgive me if I call them tar sands, dear readers. I know that the marketing people want to call them “oil” sands, because it is better for the real estate values.
After all, would you rather have oil on your land or tar? And what sounds better when you meet some new people down at the club and want to impress them: “Hello, I’m in the tar business” or, “Hello, I am an oilman”?
I am sure that you can see the difference. One guy drills oil wells, and there is no question about it. The other guy might fix roofs for a living, or seal your driveway.
What are the Canadian tar sands?
So what are we talking about? The Canadian tar sands are an extensive deposit of oil-rich bitumen (another word for tar) located in northern Alberta, Canada, with some extensions into adjacent Saskatchewan.
These sands consist of a mixture of crude bitumen, which is a semisolid form of crude oil (aka tar, because the hydrocarbons are more carbon and less hydrogen) that impregnates rocks that are composed primarily of sand and clay. The bitumen is almost entirely immobile within the rock matrix, and does not flow into a well bore like conventional crude oil.
You have to, as the expression goes, “add energy” to make bitumen flow and to extract the product. Add energy? And a whole lot more, as we shall see. And there’s the rub.
The largest deposit in Alberta is called the Athabasca tar sands, and there are two other smaller bodies known as the Peace River and Cold Lake deposits. Together, these tar sand deposits cover about 140,000 square kilometers (about 54,000 square miles, or an area about the size of Florida).
The terrain in the region is one of sparsely populated boreal forest and peat bogs. It is, in many respects, a part of the far north right out of a Robert Service poem.
The Athabasca sands are named after the Athabasca River, which cuts through the heart of the eponymous deposit. Traces of tar and heavy oil have been found along the riverbanks since ancient times.
Just as with the Seneca Indians of Pennsylvania and New York, who recovered oil from seeps long before Col. Drake ever set foot in the region, the Cree and Dene tribes of the more westerly region waterproofed their canoes using the Alberta bitumen. The first record of the Canadian tar sands being noted by European explorers was in 1788.
How is oil extracted from the tar sands?
One of the most important characteristics of the above-described Athabasca deposit is that it is the only one shallow enough to be suitable for surface mining. That is, about 10% of the Athabasca sands are covered with less than 75 meters (about 250 feet) of overburden.
The area amenable for mining, according to data supplied by the Alberta government, covers about 3,400 square kilometers (about 1,300 square miles) north of the city of Fort McMurray.
The overburden consists of 1-3 meters (3-10 feet or so) of water-logged muskeg on top of up to 75 meters (250 feet) of clay and barren sand. The pay zone, the underlying tar sands, are typically 40-60 meters thick (up to about 200 feet) and are deposited above relatively flat limestone beds. It is a strip miner’s dream.
The first “tar sand strip mine” was started by Great Canadian Oil Sands (now Suncor) in 1967. The Syncrude mine, among the largest mines in the world, followed in 1978. The Albian Sands mine, operated by Shell Canada, opened in 2003.
All three of these strip mines are associated with massive handling and processing systems that mine the rock with giant earthmoving equipment and hauling trucks the size of a McMansion. The mined rock is hauled to a massive facility that upgrades the material and converts the otherwise almost unusable bitumen into synthetic crude oil for shipment to refineries in Canada and the United States.
In addition to the ones named here, there are many more such mines and facilities in the planning stage and coming on line.
Do the facts live up to the hype?
The attendees of the ASPO conference in Boston were privileged to hear the views of one David Hughes, whose employer is an agency named the Geological Survey of Canada (GSC). I should note at the outset that Mr. Hughes was speaking from his “personal perspective,” based on his more than 30 years of work as a geologist, and “not as an official spokesperson for the GSC or the government of Canada.”
Of course. Personal or no, within a few seconds of opening his mouth, you just plain knew that Mr. Hughes understands what he is talking about. And he was talking about the Canadian tar sands, except for some reason he called them “oil” sands. Marketing, I suppose.
Mr. Hughes noted at the outset that there have been more and more exuberant forecasts issued over the past several years for the Canadian sands. They are, he said, the “Great White Hope of a panacea to support business as usual” in the world of increasing energy consumption based on depleting conventional oil reserves. But, he says, the “forecasts do not live up to the hype.”
The immense numbers often quoted for reserve and resource calculations, some as high as 300 billion barrels of oil equivalent, are “comforting,” says Mr. Hughes, “but also meaningless when it comes to offsetting declines in conventional oil production.” The difficulty, according to Mr. Hughes, is in “growing deliverability.” What does this mean?
According to Mr. Hughes, the tar sands “are a complex resource, requiring much time, energy, capital, and other inputs to achieve deliverability.” Yes, they are a significant hydrocarbon resource, but the issue is whether or not they are ultimately “deliverable” as a useable end product, at a total price that Canada and its customers can afford. Here is a summary of the well-informed perspective of one expert in the field.
The drawbacks: long lead times, large capital investment
According to Mr. Hughes, the Canadian tar sands cannot significantly offset the impending decline in world oil production, because of the long lead times and massive capital investment required.
Even under the best and most optimistic of scenarios, Canadian tar sands might yield about 3 million barrels per day (bpd) of product by 2025, or about 2.5% of forecast world demand of 120 million bpd by the International Energy Agency (IEA).
This latter number is itself, from the IEA, remarkably rosy. 120 million bpd of total world oil usage by 2025? From what sources will that oil originate? I have addressed this point in many of my previous articles in Whiskey & Gunpowder, and this will continue to be a subject of my writing efforts. But back to ASPO and Mr. Hughes.
Restrictions on natural gas supply
Production of “oil” from the tar sands is a very energy-intensive process. Production estimates for 2025 are that the energy input will require between 1.6-2.3 billion cubic feet (bcf) of natural gas per day, approximately equal to the planned maximum capacity of the proposed Mackenzie Valley gas pipeline (1.9 bcf/d) out of northern Canada, or about one-fifth of anticipated daily Canadian gas production.
Pipelines or no, the energy requirements of the projects planned for tar sands development already exceed the amount of available natural gas from the entire Mackenzie River project. Virtually all estimates for natural gas usage in tar sands operations by 2015, just 10 years hence, exceed the projections for available amounts of natural gas. Something has got to give.
In another respect, using natural gas for Canadian tar sands development creates a political issue for Canada due to its obligations under the North American Free Trade Agreement (NAFTA). The NAFTA issue arises because if Canada uses natural gas for tar sands development, that nation will have that much less gas available for export to the U.S.
But also under the terms of NAFTA, Canada cannot reduce natural gas exports to the U.S. unless it also reduces natural gas consumption within Canada. And because sometimes it gets cold in Canada in the wintertime, there may be a domestic Canadian political issue wrapped up in all of this.
Thus the expansion of Canadian tar sands capacity is limited by natural gas supply, and indirectly by the price of natural gas, which will drive the economics of expansion and continued use of the sands resource.
One possible exception to the natural gas limitation would be to develop nonthermal processing technology or to switch to alternate fuels for the tar sand process heat required. These types of alternate solutions are not even on the drawing boards, and hence are highly speculative.
If any alternatives to using natural gas are going to be adopted, these new energy sources will have to be fast-tracked to get them online in time for the tar sands projects to make use of them.
Some examples of alternate energy sources are burning the bitumen that is extracted from the tar sands, or using coal bed methane. Each technique will require its own rather extensive industrial infrastructure. And each of these energy sources emits relatively higher levels of greenhouse gases that natural gas, so Canada will face international criticism, if not other sanctions, over higher CO2 emissions. (Darn, there’s that “global warming” thing again.)
There are proposals to use nuclear plants in the Alberta area to provide process heat or other required energy input. But nuclear plants create issues of their own. These include the capital costs for the plants, the difficulty of constructing such facilities in the Alberta region, time-to-build issues, safety and nuclear waste issues, and the need to construct energy transmission facilities for electricity or steam.
Plus, there are the same kind of “not in my backyard” (NIMBY) people in Alberta as there are in most other locales of North America. Do you want a nuclear plant near you? A lot of people do not.
Limitations on water supply
Another limitation on tar sands expansion is that processing capacity is limited by water supply. Much water is already being recycled using current technology, but current production techniques require 1-2 barrels of “makeup” water per barrel of product.
It will be imperative to develop technology that uses less water or that recycles even more of the water being used. And doing this is not nearly as easy as you might think.
Surface water flows, principally from the Athabasca River, are simply inadequate to meet forecast needs. And deeper water, from underground aquifers, is saline and must be diluted with fresh water or otherwise desalinated. Whoops. This will require more of that energy input stuff.
Immense amounts of water are currently being discarded into settlement ponds, in which it may take 200 years for the smallest particles to settle down to the bottom. Meanwhile, the water is toxic, and mixed with exceedingly high levels of heavy metals and other exotic elements that you probably do not want to eat. Some of these impoundment ponds are many miles in area, and will pose an environmental problem or hazard for many centuries.
Other limitations: transport and diluent
Assuming that there will be sufficient energy and water to utilize in tar sands operations, any expansion of bitumen export capacity from Alberta may be limited by projected shortfalls of what is called “diluent.” What is diluent?
Begin with the fact that bitumen is thick, heavy, and viscous. It will not flow, and cannot be moved through a pipeline unless it is diluted with a lighter medium, or diluent. The best types of diluents are natural gas condensates, but these are becoming rapidly scarce due to depletion of gas reserves.
Tar sand bitumen needs a one-third blend of condensates or a half blend of synthetic light oil to move it through a pipeline. The alternative is to utilize synthetic crude of light oil as diluent. But from where will the diluent come?
One company named Enbridge (ENB) is looking to import 150,000-200,000 barrels per day of condensate or light oil, just to re-export it as diluent in pipeline operations. The projected cost exceeds $4 billion per year. This is expensive, but without importing diluent to the Alberta region, it will be necessary to upgrade bitumen on site to a “synthetic” grade and use it for that purpose. This will require additional capital investment and cost.
Of interest, the pipeline that Enbridge is proposing to construct will run from the tar sands region to the Pacific coast and supply product for export to overseas markets, in all likelihood to China.
As if the shortage of diluent were not enough, the existing pipeline system in the Alberta region is inadequate to support the anticipated exports of bitumen, let alone the possible imports of significant quantities of diluent. Thus, the region will require new pipeline capacity of about 1 million barrels per day.
The existing Alberta pipeline system will be at maximum capacity by mid-2008. There are, of course, proposed expansions that are intended to accommodate product movement, but these expansions will be fully utilized by between 2009-2011. There are no announced plans for pipeline capacity expansion after 2011 (these might come along later, but they are not being proposed just yet.) But absent even further expansion of the pipeline system, by 2011, there will be an absolute limit of about 3.5 million barrels per day on product movement. This includes diluent coming in and product going out.
Who will meet the capital costs?
All construction and expansion activities in support of Canadian tar sands development in Alberta are competing within a world market for materials, equipment, and labor. This includes everything from steel and cement, to complex industrial equipment, to engineering talent and field labor.
Some firms are flying welders into the region from as far away as Nova Scotia, and there is a serious housing shortage in the tar sands region. It takes us back to that Robert Service line about being “camped there in the cold.”
As with almost all major energy development projects in the world, cost overruns in the tar sands region are epidemic. For the past three years, each year and every major project has seen major, and increasing, overruns.
Petro-Canada, for example, has put its Fort Hills project on hold until 2008 due to cost estimates ballooning to the range of $19 billion, or over $130,000 per barrel per day of capacity. Shell Canada has also scaled back expansion plans due to cost estimates more than doubling.
One alternative to massive build-outs of facilities in high-cost Alberta, proposed by EnCana (ECA) and ConocoPhillips (COP), is to export non-upgraded bitumen to the U.S., but still at a capital cost of $35,000 per barrel per day for infrastructure.
However, there are no U.S. refineries currently capable of processing this bitumen material, hence the capital cost for upgrading will have to be incurred in the U.S. (Overall, this may still be less expensive than constructing refining facilities in Canada.)
Estimates for capital investment over the next 20 years in tar sands production in the Alberta region range from $120-220 billion. At the rate things are going, the trend in cost overruns suggests a maximum production of 2.5 million bpd of bitumen by 2020, unless much of the bitumen is exported and the upgrading facilities are built elsewhere. In the latter case, the estimated maximum bitumen production could be 2.8 million bpd by 2020.
Yet for all of the cost of infrastructure and facilities, the strip mining operations for tar sands will “peak” in about 30 years, and play out quite rapidly thereafter because of the anticipated scale of ongoing operations between now and then. Thereafter, the bulk of oil recovery operations will be via in-situ operations, at far less efficiency of recovery.
Under the best of scenarios, Canada will have 2.5-2.8 million bpd of bitumen production, certainly not all of which will be available for export to the U.S. through pipelines not yet built.
But still, the tar sands hype continues. Public perception in many quarters is that the Canadian tar sands will be fueling the U.S. automobile fleet from I-5 to I-95 for centuries to come. I cannot explain that, but the perception simply does not match the reality of what is going on out in the field.