Oil sands are petroleum deposits found predominantly in the Athabasca region of Alberta, Canada. This resource consists of a mixture of sand, clay, water, and a heavy, thick form of petroleum known as bitumen. Bitumen is a hydrocarbon so viscous it resembles cold molasses at room temperature, making it too thick to flow naturally or be pumped directly from the earth. Overcoming this extreme viscosity defines the two primary recovery methods: surface mining for shallow deposits and in situ techniques for deeper ones.
Surface Mining and Hot Water Separation
Surface mining is used for oil sands deposits lying less than 75 meters below the surface, accounting for approximately 20% of the total recoverable reserves. The process begins with the removal of overburden, including layers of muskeg, topsoil, clay, and sand, to expose the bitumen-saturated layer. Massive shovels load the ore into haul trucks that can carry up to 400 tonnes.
The mined ore is transported to a crushing facility where large clumps are broken down. The material is then mixed with warm water and a small amount of caustic soda, forming a slurry. This mixture is moved through long pipelines, a process called hydrotransport, which provides the mechanical agitation needed to begin separating the bitumen from the sand grains.
The slurry is delivered to large separation vessels where the hot water extraction process takes place. The heat significantly reduces the bitumen’s viscosity, liberating it from the sand and clay particles. Air is introduced into the mixture, causing the bitumen to adhere to air bubbles and float to the surface.
This buoyancy-assisted separation forms a layer of bitumen froth at the top of the vessel, which is continuously skimmed off. This froth is an emulsion containing contaminants, including water and fine solids, and typically consists of 50-60% bitumen. The sand and clay sink to the bottom of the vessel, and the resulting process water is recycled or sent to tailings ponds.
Deep Deposit Extraction: In Situ Methods
The majority of oil sands reserves, approximately 80%, are buried too deeply for surface mining and must be recovered using in situ methods. These techniques rely on injecting heat or solvents into the reservoir to mobilize the bitumen underground. Steam-Assisted Gravity Drainage (SAGD) is the most widely adopted and efficient of these thermal in situ methods.
Steam-Assisted Gravity Drainage (SAGD)
SAGD involves drilling a pair of parallel horizontal wells, with one stacked directly above the other near the base of the deposit. High-pressure steam is continuously injected into the upper wellbore, which acts as the injector. The steam rises and forms an expanding zone of high temperature called a steam chamber.
The heat from the steam chamber transfers to the surrounding bitumen, drastically reducing its viscosity. This now-mobile, heated bitumen and condensed steam then flow downward along the edges of the steam chamber due to gravity. This process, known as gravity drainage, allows the fluids to collect in the lower wellbore, the producer well, from where they are continuously pumped to the surface.
Cyclic Steam Stimulation (CSS)
An alternative method is Cyclic Steam Stimulation (CSS), also called the “huff-and-puff” method. CSS uses a single well that alternates between three phases: injection, soaking, and production. High-pressure steam is injected into the well for a period of days or weeks to heat the surrounding formation.
The well is then shut in for a soak period, allowing the heat to conduct further into the bitumen. Finally, the same well is opened to produce the heated, less viscous oil and condensed water. This cyclical process is repeated until the oil production rate declines below a profitable level.
Preparing Extracted Bitumen for Transport
Whether separated via hot water extraction or recovered via in situ methods, the raw bitumen remains too heavy and thick to be transported long distances through conventional pipelines. Pipeline systems impose strict specifications on the viscosity and density of the fluid to ensure efficient flow and pump operation.
The raw bitumen’s viscosity must be reduced before it can enter the mainline system. This is achieved by blending the heavy bitumen with lighter, less viscous hydrocarbons, known as diluents. Common diluents include natural gas condensate (a very light crude oil) or naphtha.
The resulting blend is known as “dilbit,” or diluted bitumen, which typically contains 70-80% bitumen and 20-30% diluent by volume. The blending ratio is engineered so that the final product meets pipeline standards, such as maximum viscosity and density limits. Bitumen can also be blended with synthetic crude oil, a partially upgraded product, to create a similar product called “synbit.”