Editorial Comment

	Vol. 227 No. 5
PERRY A. FISCHER, EDITOR

It depends on what you call oil, Part 2. In the unfortunate argument about peak oil supply, what constitutes “oil” is usually poorly defined. Canada’s vast bitumen deposits, mostly located in northern Alberta, offer insight into the difficulty of determining what oil is, defining proved reserves, and peak production. There is little agreement on how this bitumen should be classified. Many folks do it the way World Oil does: with explanations and footnotes.

One of our reasons for not classifying bitumen the same as conventional proved reserves is the fact that it presently relies on large amounts of natural gas and water for extraction and processing, as well as future solutions to growing environmental problems. Should gas or environmental problems become too costly, the 174 billion barrels of Canadian bitumen would become much more expensive to recover using present technology. It would take 476 years at today’s production rate of 1 million barrels a day to produce the claimed reserves.

About 20% of the claimed bitumen reserves are in surface mineable sand deposits, with the remaining 80% requiring heat-extraction methods through boreholes, such as the proven Steam Assisted Gravity Drainage (SAGD), which uses injected steam to get the tar-like substance to flow. To date, these two sources have been used about equally for production, but the future lies with SAGD. Natural gas and water are used for creating steam, both in extracting and in processing the bitumen.

The 40 or 50 oil sands developments now being planned or contemplated through 2020 would mean 4.2 million barrels per day of bitumen and synthetic crude (syncrude) production.

Environmental challenges are many. The bitumen contains high metal concentrations and 4.8% sulfur on average. By 2030, sulfur recovery from the expanded oil sands region could generate 10 million tons of sulfur per year, according to a 2004 report by Canada’s National Energy Board. Getting rid of this byproduct is a major problem facing producers.

Surface mining creates huge volumes of fluid waste called fine tailings. Solutions are being researched, but there are no demonstrated means to reclaim these tailings. So, ponds must be constructed to be leakproof and last indefinitely. The volume of these is daunting, with current trends indicating tailings in ponds will range between 6 and 10 billion barrels by the year 2020.

Air emissions is yet another complex and challenging problem. The full complement of pollutants, including SO₂, NO_X, CO, H₂S, volatiles (VOCs), ozone and particulate matter are released in the extraction and upgrading process. And then there’s the greenhouse gases of methane and CO₂. Since Canada is a Kyoto Protocol signatory, the country is supposed to cut CO₂ emissions to 20% less than 1990 levels by 2010. The latest data show emissions are running 24.4% above 1990 levels. So, achieving Kyoto targets is not likely. Canada is simply too resource intensive, with its economy sitting near the top of the OECD list in energy and carbon intensity. A new goal for bitumen production might be CO₂ reduction on a per-barrel basis, which is already making good progress.

In addition to the environmental burden, there are huge demands made on water and natural gas. The production process uses 2.5 to 5 barrels of water for each barrel produced. However, this has been an improving number and, in any case, the area has good water resources, so, this does not appear to be a major impediment to future growth.

Average gas use is between 1.2 Mcf per bitumen barrel for thermal in situ projects, and 0.5 Mcf for mining and upgrading projects. While not all of this must be purchased, this still means that, at current rates, just 3 million bpd of bitumen production would require more than all of the gas that could be delivered via the as-yet-to-be-built, $7.5 billion MacKenzie pipeline from the Canadian arctic.

Considering the environmental and resource requirements, it seems obvious that the only way the bitumen resource will get produced is through future technologies, not the existing ones that the SEC insists on. But those technologies are indeed being developed.

PetroBank began its experimental Toe-to-Heel Air Injection (THAI) project last month at Whitesands. It began steam injection in vertical wells, which will be followed by air injection for combustion and then production via horizontal wells.

The Vapor Extraction Process (VAPEX) is an in-situ process similar to SAGD, only it uses solvent vapor (typically propane, butane, or CO₂) along with a carrier gas (typically methane or CO₂), to dissolve and dilute the bitumen. It requires less water and natural gas than steam. It is in testing by an industry research consortium.

Perhaps the most interesting project is the Nexen/ OPTI Canada joint venture, whose Long Lake Project should see first steam in late-2006 and upgrader start-up in mid-2007. Proprietary technology, using distillation, solvent de-asphalting and thermal cracking, separates the produced bitumen into partially upgraded sour crude oil and liquid asphaltenes. Commercially available hydrocracking and bitumen gasification technologies allow upgrading of sour crude into light (39°API), synthetic sweet crude oil, and the asphaltenes are converted to a low-energy, synthetic fuel gas. This gas is a low-cost fuel source and a hydrogen source required in the hydrocracker. The gas will also be burned in a co-generation plant to produce steam for the SAGD operations and for electricity to be used on-site and sold to the grid.

Co-generation of steam and electricity could also benefit bitumen production. However, while there’s no doubt in the efficiency increase, there are questions about the market, transmission and infrastructure needed for long-distance electricity transport.

Finally, there is a study by the Canadian Nuclear Society that calls nuclear energy a “viable option from an economic viewpoint,” for heat and hydrogen generation for bitumen production and upgrading. While technically feasible, realistically, it’s a long way off from garnering public and governmental support.

Of course, if these new technologies become proven, these tar sands will also become proved reserves, by any definition. Truth be told, these bitumen deposits are in a class all their own, and do not fit well into our present ideas of proven and probable oil reserves. And the effect on the public? I doubt that anyone will care whether the stuff that fuels their cars comes from a tar-like substance, or from oil.