With more than 179 billion barrels of proven oil reserves, Canada ranks second only to Saudi Arabia in terms of total oil resources. But there’s a big difference between the two countries: Saudi Arabia’s reserves are mainly conventional deposits, while more than 90 percent of Canada’s oil reserves are in the form of oil sands.

And those estimates may actually prove conservative. Some estimates peg Canada’s total oil sands resource at more than 1 trillion barrels, with more than 300 billion barrels of recoverable resource.

Even more important, production of oil from Canada’s conventional oil deposits is in decline. In fact, oil sands represent one of the only growing production sources in North America. As the chart “Unconventional Resource” shows, by 2015, oil sands are projected to account for 70 percent of Canada’s total oil output, up from just 28 percent in 2000. 

As the name implies, oil sands are nothing more than a mixture of sand, clay and bitumen. Bitumen is a very thick, semi-solid type of crude oil, roughly the same consistency as molasses.

This form of crude is way too thick to flow naturally into a well or through a pipeline network. But once upgraded and refined, it can be used to produce exactly the same sorts of products as conventional crude oil: gasoline, kerosene, jet fuel and diesel, for example.

Oil sands can be found both near the surface and at a considerable distance underground. The former deposits are actually mined in a process that’s similar to strip mining coal. The surface rocks and vegetation are stripped away and removed on large trucks. The sands just under the surface can then be hauled away for processing.

Over the past 30 years, considerable effort has been expended on technologies for mining the deeper subsurface deposits of oil sands. The reason is that approximately 80 percent of Canada’s bitumen deposits are too far underground to be exploited with surface mining techniques.

Underground deposits are produced using in-situ techniques. This involves pumping hot steam underground to heat the bitumen. Once the bitumen is heated sufficiently, it will flow to a wellbore in a manner similar to more conventional crudes.

One of the more widely used in-situ mining techniques is what’s known as steam-assisted gravity drainage (SAGD). This technique involves drilling two horizontal wells spaced about 15 feet apart underground.

Steam is injected into the upper horizontal well, heating the bitumen. The bitumen then flows into the lower wellbore and can be pumped to the surface. On average, between 40 and 60 percent of the bitumen located in in-situ deposits can be produced using SAGD techniques.

Producing steam to inject underground is one major cost for in-situ miners. Typically, producing that steam means burning natural gas.

When natural gas prices spike, the cost of producing the underground bitumen deposits also rises. In fact, whether oil sands are mined in situ or using surface techniques, separating the bitumen from the sand requires large amounts of heat energy.

There are also developing technologies involving vaporizing the bitumen and using solvents to supplement or replace the steam. And cold production is employed in reservoirs where oil sands will flow to the surface without being heated up first.

Once bitumen is produced, it’s separated from the sands by heating them and putting them through giant separator units. Raw bitumen must be processed so that it can flow through a pipeline; this involves either diluting the bitumen with other liquids or further processing the bitumen into synthetic crudes that are suitable for use in a refinery. It takes about 2 tons of sands to produce one barrel (42 gallons) of crude.

Processing bitumen is quite complex. Raw bitumen is deficient in hydrogen, so hydrogen atoms must be added during processing.

But in order for a refinery or processing unit to produce the light products the market demands–gasoline and diesel fuel–that refinery must be capable of refining heavy crude oils. This requires special, complex refining equipment.

US refiners have spent billions upgrading their facilities to handle these more-complex grades of crude. Therefore, rapidly rising oil sands production will benefit not only the firms that own vast reserves there but also the refiners in the US and elsewhere that can handle the bitumen that’s produced.

Oil Sands Issues

The oil sands are no panacea for the world’s energy issues. But they do promise to make a lot of money for producers.

The most obvious factor affecting oil sands development is cost. There are several major costs involved with a particular project, and those costs vary depending on whether it’s an in-situ project or a surface mining operation.

For surface mining operations, the largest costs are upfront. Most surface mining operations underway or planned in Canada also call for building and running an upgrader.

Because mining operations tend to be of a larger scale and produce more daily output, it makes economic sense to also pay for an upgrader to process the bitumen into synthetic crude oil. The synthetic oil can be sold to refiners just like light sweet crude, the highest value product in the marketplace.

In-situ projects tend to be smaller. Although some larger projects do have upgraders, that’s not often the case. This presents two problems.

First, the producer has to find a source of natural gas liquids or synthetic crude oil to use as a diluent; basically, the producer has to mix the bitumen with other products so it will flow through a pipeline. Second, the final product is bitumen, which is priced more like heavy oil than light sweet crude.

Not all refineries have upgraders and facilities designed to handle heavy crude. As a result, the spread between the price of heavy oil and light sweet crude is near record levels.

That means that bitumen is trading at a large discount to light sweet crude oil or synthetic crude. The advantage of an in-situ operation is that the upfront costs of developing are lower because you don’t need to pay for an expensive upgrader.

Operational costs are another big issue for the sands. In in-situ operations, steam is used to heat the bitumen so it can flow into a well. The problem is that most steam is produced using natural gas and producing steam is an energy-intensive process; producing in-situ oil sands requires a large amount of natural gas.

Although surface mining operations don’t use steam to heat the bitumen for mining purposes, it’s often used to separate bitumen from sand. And natural gas is an important commodity for many upgraders.

Hydrogen produced from natural gas, for example, is used to turn bitumen into synthetic crude. Producing a barrel of crude can require moving 2 tons of sands. The fuel to power the giant Earth-moving equipment used in such operations is diesel. Obviously, diesel and natural gas prices are an operational cost.

According to the Canadian Association of Petroleum Producers (CAPP), the oil sands industry consumed some 500 cubic feet of natural gas per barrel of oil sands production in 2005. Given that current production is around 1.1 million barrels per day, that equates to some 550 million cubic feet of natural gas use per day, or 6.5 percent of Canadian natural gas demand. But if production expands to 2.7 million barrels per day as forecast, gas use would jump to more than 1.3 billion cubic feet per day.

Natural gas production in Canada has actually been dropping in recent years, and pipeline capacity into the oil sands region isn’t totally sufficient to meet that much usage. This is also an issue for the US: Most of the gas imported into the US right now comes from Canada. An expansion of oil sands development, coupled with declining or, at best, flat Canadian production, spells less gas available for export to the US.

And experienced labor is in short supply. Years of low energy prices spell fewer engineers and petroleum experts graduating from North American universities. And there have been widespread reports of truck tire shortages for Earth-moving equipment, trucks and spare parts in the region.

And then there’s water. When oil sands are surface mined, the sand is mixed directly into a vat of hot water to separate the bitumen. Using current technologies, several barrels of water are required for each barrel of oil produced; water is in short supply in some areas.

Last is the issue of pipeline capacity. The region where oil sands are most plentiful is relatively unpopulated. If all the production pans out, there will need to be massive pipeline expansions to move all the bitumen and synthetic crude either to ports for export or south into the US market. There are several major planned pipeline expansions in the works.

The bottom line: Despite these costs, shortages and drawbacks, the sands are a competitive resource capable of generating high returns for producers even if oil prices fall from current levels.

Specifically, a 2006 survey by the National Energy Board of Canada suggests that the all-in cost for supplying a barrel of light, sweet synthetic crude oil from a surface mining operation is $36 to $40 per barrel; $18 to $22 of that is actual operating cost. In-situ projects producing lower-quality, lower-value bitumen product cost around $18 to $22 per barrel.

This estimate complements data from Suncor Energy (NYSE: SU), one of the largest dedicated oil sands producers. That company estimates cash operating costs around $22.50 per barrel.

Therefore, oil sands production is profitable as long as oil remains above $35 to $40 per barrel, a far cry from today’s prices in the $90s. Even if the price of oil halved from current levels, it would make economic sense to produce oil from the sands.

Playing Oil Sands

We’ve all heard the pitches for tiny small cap producers owning large potential reserves of bitumen in Canada. Some of these land holders may be bought out by the big players eventually, but buying these start-ups isn’t much better than a crapshoot.

The truth is that bringing a new oil sands development project on line is extremely expensive. Larger, independent producers with well-known operating histories and international integrated oil majors are better equipped to produce Canada’s oil sands than the small fry. 

In fact, most of the majors are already involved. The largest oil sands producer in the world is Syncrude, a joint venture between Encana, ConocoPhillips, PetroCanada, Nexen, Murchy Oil, Canadian Oil Sands Trust (TSX: COS-U, OTC: COSWF) and Imperial Oil.

In 2006, Syncrude produced some 95 million barrels of syncrude sweet blend, a synthetic crude oil with similar properties to light sweet crude. The company produces exclusively using surface mining techniques. 

Royal Dutch Shell and Chevron Corp also operate a joint venture called the Athabasca Oil Sands Project that should produce 400,000 to 500,000 barrels of oil per day by the middle of the coming decade. This joint venture also uses the mining method and an upgrader to produce syncrude.

The most recent entrant to the oil sands region among the major integrated oils is BP. In early December, the company acquired a half share of the Sunrise field in Alberta that’s operated by Husky Energy. This project is being produced using in-situ SAGD techniques; there’s no upgrader associated with the project.

Instead, the BP/Husky joint venture plans to pipe the bitumen to refineries that are capable of handling heavy crudes. In particular, as part of this deal, Husky is taking a share in BP’s own refinery in Toledo, Ohio, that’s being expanded and upgraded to handle more bitumen and heavy oil throughput. First production of bitumen from Sunrise is expected this year and will ramp up to 200,000 barrels per day by 2012.

For a purer play on oil sands, Suncor Energy looks promising. The company has been producing in the Athabasca oil sands region since 1967; the firm now uses a combination of surface and in-situ techniques.

In 2007, Suncor produced about 245,000 barrels per day from its projects and hopes to boost that output to around 350,000 barrels per day this year. The long-range target is to reach more than 500,000 barrels per day by 2010 to 2012.

In addition, among the trusts, Enerplus Resources (NYSE: ERF, TSX: ERF-U) has significant exposure to oil sands. The trust has 460 million barrels of oil equivalent in potential oil sands resources that could be produced using a combination of SAGD and surface mining techniques. The company estimates that, eventually, it could produce more than 60,000 barrels per day from its properties in the region.

Penn West Energy Trust (NYSE: PWE, TSX: PWI-U) is another promising producer. Pembina Pipeline Income Fund (TSX: PIF-U, OTC: PMBIF) is a leading infrastructure player and the safest way to play oil sands growth.