Oil sands are naturally occurring deposits of sand, clay, water, and a thick, heavy form of petroleum called bitumen. Unlike conventional crude oil, which flows freely underground and can be pumped to the surface, bitumen is so dense and viscous at room temperature that it has the consistency of cold molasses. Extracting and processing it into usable fuel requires significantly more energy, water, and infrastructure than traditional oil drilling.
The world’s two largest oil sands deposits sit in Canada and Venezuela. Canada’s Athabasca deposit in northern Alberta is the most extensively developed, and Alberta alone accounted for 83.6% of Canada’s total crude oil production in 2024. Venezuela’s Orinoco Belt holds comparable reserves but has seen far less commercial development due to political and economic instability. Together, these two countries hold the vast majority of the planet’s oil sands resources.
What Bitumen Actually Is
Bitumen is petroleum that never completed the geological journey to becoming light crude. Over millions of years, crude oil migrates through rock formations, and the lighter, more fluid varieties tend to move closer to the surface. Bitumen stayed trapped in shallow sandy deposits, where bacteria broke down its lighter components, leaving behind a heavy, carbon-rich residue mixed with sand and clay. It contains more sulfur, nitrogen, and heavy metals than conventional oil, which is why it requires extensive processing before it can be refined into gasoline, diesel, or jet fuel.
In its raw state, bitumen is essentially unusable by a standard refinery. It needs to be either diluted with lighter hydrocarbons for pipeline transport or upgraded into what the industry calls synthetic crude oil, a product that refineries can handle just like conventional crude.
How Oil Sands Are Extracted
There are two fundamentally different ways to get bitumen out of the ground, and the choice depends entirely on how deep the deposit sits.
Surface Mining
When oil sands lie within about 70 meters of the surface, companies use open-pit mining. Massive truck-and-shovel operations strip away the overlying soil and rock (called overburden), then scoop out the bitumen-laden sand. The material is mixed with hot water to separate the bitumen from the sand and clay. This method is visually dramatic, leaving behind vast open pits and large tailings ponds that hold the wastewater and leftover sediment.
In-Situ Extraction
Most of Alberta’s oil sands sit too deep for mining. For deposits below 70 meters, and some lie 400 meters or more underground, producers drill wells and inject superheated steam into the formation. The heat softens the bitumen enough for it to flow toward a collection well, where it can be pumped to the surface. The most common version of this approach uses paired horizontal wells: one injects steam, and one below it collects the heated bitumen as it drains downward by gravity. In-situ extraction has a smaller surface footprint than mining but requires enormous amounts of natural gas to generate the steam. It has been steadily growing and is now overtaking surface mining as the dominant method in Alberta.
Both methods are water-intensive. Industry figures put freshwater consumption at 0.4 to 3.1 barrels of water per barrel of oil produced, with mining operations generally sitting at the higher end of that range.
Turning Bitumen Into Usable Fuel
Raw bitumen contains large, heavy molecules that won’t evaporate during normal distillation, the process refineries use to separate crude oil into useful products. Upgrading is the series of steps that breaks those heavy molecules into lighter ones a refinery can work with.
The process starts with separation: removing salts, water, and solid particles. Then comes primary upgrading, where the heavy residue is heated to over 400°C. At those temperatures, the carbon-to-carbon bonds in the large molecules crack apart, producing lighter hydrocarbons. This thermal cracking is the backbone of every commercial upgrading operation.
The cracking step, however, produces compounds loaded with sulfur and nitrogen, both of which cause pollution when burned and damage refinery equipment. Secondary upgrading uses hydrogen and metal-based catalysts to strip out more than 90% of the sulfur and over 70% of the nitrogen, with minimal additional cracking. A further step called hydrocracking can convert heavy distillates into lighter feeds suitable for gasoline production. The end product, synthetic crude oil, behaves much like conventional crude and can be shipped to any standard refinery.
Carbon Footprint Compared to Conventional Oil
Producing oil from oil sands generates more greenhouse gas emissions per barrel than pumping conventional crude, primarily because of the energy needed for steam generation, mining, and upgrading. Measurements taken at four major surface mining operations in Alberta found emissions ranging from about 48 to 267 kilograms of CO₂ equivalent per barrel. That wide range reflects differences in facility design, ore quality, and how much upgrading happens on-site.
A study published in Nature Communications found that these measured emissions were higher than estimates calculated using standard international reporting methods, which had placed industry averages at 77 to 122 kilograms of CO₂ per barrel. The gap suggests that official inventories may undercount actual emissions. And even those measured figures don’t include the emissions from transporting synthetic crude to a refinery, which would push the totals higher still.
The Economics of Oil Sands
Oil sands projects have historically been expensive to build and operate, but costs have dropped dramatically. Between 2017 and 2019, oil sands producers needed crude prices around $51.80 per barrel to break even. By 2024, the five largest Canadian oil sands companies had pushed that number down to between $40.85 and $43.10 per barrel, a roughly $10 reduction achieved through standardized maintenance, better water management, and squeezing more production from existing infrastructure. Suncor alone cut its breakeven price by $7 per barrel in a single year.
That shift has changed the competitive picture significantly. U.S. shale oil producers, once considered the lower-cost alternative, now need about $65 per barrel on average to profitably drill new wells, according to a Dallas Federal Reserve survey. That means established oil sands operations are now among the lowest-cost plays in North America, a reversal from just a few years ago. The catch is that new oil sands projects still require massive upfront capital and take years to build, so the low breakeven figures apply mainly to operations already in the ground.
Scale of Production
Canada set new crude oil production records in 2024, driven largely by oil sands growth. Alberta’s output rose by 172,000 barrels per day that year, a 4% increase powered almost entirely by expanding bitumen production. The oil sands are not a niche energy source. They supply a significant share of North America’s crude and are deeply integrated into continental pipeline and refinery networks, particularly after the completion of the Trans Mountain pipeline expansion, which opened a route to Pacific Coast export terminals.
The scale of the resource means oil sands will remain a major part of global energy supply for decades. The deposits contain enough recoverable bitumen to sustain current production levels well into the future, and ongoing cost reductions have made them economically resilient even during periods of lower oil prices.