Stage 1

Resource assessment and rights

Resource

Using currently available technology and under the current economic conditions, there are 165 billion barrels of remaining established reserves in the oil sands deposits of Northern Alberta. An additional 250 billion barrels could potentially be recovered with more favourable economic conditions or new technology to extract and process.

Approximately 80% of oil sands are recovered through in-situ production.

Assessment of prospects

People interested in beginning oil sands projects have multiple tools at their disposal to determine the best place to acquire rights for exploration. These include:

  • geological appraisals: aerial surveys, field surveys
  • geophysical assessment: seismic, magnetic, gravitational
  • examination of public records, which are often records resulting from previous exploration efforts

Rights

Once a parcel of land is identified as being likely to contain oil sand, mineral rights for that specific area are purchased from either private owners or the Provincial Crown via Alberta Energy. This is the beginning of the oil sands tenure process.

Land is leased via Public Offerings every two weeks, results are also available. Bids can be submitted through the Electronic Transfer System.

Well licence

At any time following the purchase of mineral rights, a well licence can be obtained. A well licence allows you to begin production immediately. All production from Crown rights is subject to payment of royalties.

Exploration

With a well licence secured, detailed exploration can begin. This can include:

  • seismic assessment
  • drilling

The Canadian Association of Oilwell Drilling Contractors produces daily, weekly and monthly rig counts.

Stage 2

Scheme & project approval

Scheme approval process

Many commercial oil sands operations require a project scheme, which allows for larger-scale production on smaller parcels of leased land rights.

  1. The company applies for a scheme approval from the Alberta Energy Regulator (AER).
  2. The AER determines if a public hearing is required to allow citizens to express potential concerns or support.
  3. Environmental impact assessments are submitted to Alberta Environment and Parks detailing the water use request and socio-economic impact studies.
  4. The AER and other regulatory bodies approve an oil sands scheme based on factors affecting lands and wells.

Oil Sands Royalty (OSR) project approval

All produced bitumen from Crown rights is subject to royalty. Once the developer has an AER approval, he is now eligible to apply for project approval for royalty purposes through the Oil Sands division of Alberta Energy. This step is not mandatory, as royalties on bitumen can be paid under the Non-Project Well Royalty. But there are advantages to applying under the Oil Sands Royalty Regulation. Applications are reviewed by engineers and economists for a variety of technical and fiscal factors and considerations.

Construction

Construction of extraction facilities can begin at any time during Stage 2. Extraction facilities include wellpads, mine sites and processing infrastructure. The cost to build mining operation or in situ facilities and an on-site upgrader is in the billions of dollars.

Construction costs can vary depending on labour, steel and other building material prices, and the location of the project. Construction cost can significantly impact the payout* date of a project.

*For a pre-payout project, the first date at which the cumulative revenue of a project first equals the cumulative cost of the project.

Recovery

Mining

Roughly 500 km2 of the 140,000 km2 oil sands deposit in Northern Alberta is currently undergoing surface mining activity. This is about 3% of total oil sands surface area or 20% of oil sands reserves.

Surface mining uses truck and shovel technology to move sand saturated with bitumen from the mining area to an extraction facility. Surface mining is used to recover oil sands deposits less than 75 metres below the surface, while in-situ technologies are used to recover deeper deposits. The electric and hydraulic shovels used have a capacity of 45 m3 and trucks can carry up to 400 tonnes of ore.

Trucks move the oil sand to a cleaning facility where it is mixed with hot water and diluent (naphthanic, parafanic) to separate the bitumen from the sand. Sand, water, fine clays and minerals, or tailings, are separated from the bitumen and diluent and sent to tailings ponds where the sand settles.

The diluted bitumen can be piped to an upgrader on site, if one has been built in conjunction with the mine. Currently 5 Alberta upgraders process about 54 % of Alberta's crude bitumen production. The remainder is sent to upgraders and refineries throughout North America.

About 2  tonnes of oil sands must be dug up, moved and processed with 2 to 4 barrels of water to produce 1  barrel of synthetic crude oil (SCO).

Extraction – In situ

In situ recovery is used for bitumen deposits buried too deeply ─ more than 75 m ─ for mining to be practical. Most in situ bitumen and heavy oil production comes from deposits buried more than 350 to 600 m below the surface.

Steam, solvents or thermal energy make the bitumen flow to the point that it can be pumped by a well to the surface.

No tailings ponds are required for in situ methods of recovery. Sand remains in the ground. Only bitumen is removed. An average of 0.5 barrels of water is used to produce 1 barrel of SCO.

Methods of in situ recovery:

Cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) (PDF, 248 KB) are effective in situ recovery methods.

  • CSS is a thermal production technology in which 1well is used to both inject steam and produce oil. Steam is injected at pressures high enough that the hydraulic fractures are induced in the reservoir, allowing steam to access and heat new areas of the reservoir. After weeks or even months, the injection cycle is completed. A few days are allowed for the steam to condense and then the production of oil and water begins. Production initially occurs due to increased reservoir pressures. But later, cycles require artificial lift technologies to produce the remaining oil during the production cycle. This cycle is then repeated after the production rates become too small (as determined by the producer). CSS is a viable option for deeper reservoirs that have a thick, capping shale to manage the high steam injection pressure. The high injection pressure and multiple recovery mechanisms enable CSS to work effectively with a broader range of reservoirs, especially with heterogeneous characteristics.
  • Steam-assisted gravity drainage (PDF, 248KB) is a thermal production technology which utilizes 2 parallel horizontal wells, known as a well pair. One injects steam and the other produces water and oil. Initially, steam is circulated in both wells to establish communication between the wells. The top horizontal well then continuously injects steam to heat the reservoir, creating a steam chamber. The oil from the chamber drains to the production well below. This allows for production initially through pressure drive and then by artificial lift or gas lift. The steam injection and oil production happen continuously and simultaneously once production starts. This technology has a high ultimate recovery of oil from the reservoir relative to other in situ production technologies. Canada's largest SAGD project is at Cold Lake, Alberta.
  • Cold Heavy Oil Production with Sand (CHOPS) allows the deliberate flow of sand into a bitumen well in order to increase the rate of bitumen recovery. Heavy oil is more viscous than conventional oil but less viscous than bitumen. By introducing sand into the well and producing oil and sand together, the higher viscosity is mitigated by the increased permeability of the deposits. The sand essentially creates wormholes through which the bitumen can flow more easily. Currently, CHOPS is only employed in the Cold Lake oil sands area. The 2002 Cold Heavy Oil Production with Sand in the Canadian Heavy Oil Industry provides more information.
  • Vapour recovery extraction and pulse technologies have been tested.

The Innovative Energy Technologies Program supports innovation, research and technology development. A number of pilot and demonstration projects use innovative technologies (SAGD, polymer flood or others) to increase recoveries from existing reserves. They also encourage responsible development of oil, natural gas and in situ oil sands reserves.

Upgrading

Bitumen from the oil sands has been degraded by millions of years of organic processes, resulting in a thick, viscous substance with a deficiency of hydrogen. Upgrading either adds hydrogen or removes carbon in order to achieve a balanced, lighter hydrocarbon that is more valuable and easier to refine.

The upgrading process also removes contaminants such as heavy metals, salt, oxygen, nitrogen and sulphur to turn bitumen or heavy oil into SCO.

The upgrading process involves:

  1. Distillation: Separates various compounds by physical properties
  2. Coking, hydro-conversion, solvent deasphalting: Improves hydrogen to carbon ratio
  3. Hydrotreating: Removes contaminants such as sulphur

Upgrading benefits include:

  • a bridge to other energy processing opportunities (upgrader “off-gases” such as ethane for petrochemical feedstock, see Energy processing in Alberta
  • more market access for higher-value products
  • improved facilities and transportation infrastructure
  • experience with environmental technologies (carbon sequestration)
  • skilled workforce and jobs in Alberta

More information can be found in Upgrading and Refining: Stats and Facts (PDF, 289 KB).

 

Alberta Upgrader Projects

Stage 3

Royalties, refining and sale

Royalties

Companies recovering resources from Alberta Crown rights must pay royalties to the Province. Royalties are determined by either the Non-Project Well Royalty Regime (production-based royalty) or, if OSR project approvals have been completed, under the Oil Sands Royalty Regime (share of profit royalty). Royalties can be paid with product under the Bitumen Royalty-in-Kind program.

Transport

Oil and oil products are most efficiently transported by pipeline throughout North America where they can connect to ports for international markets. Pipelines in Canada are regulated based on jurisdiction. If a pipeline crosses a provincial or international border, it is regulated by the National Energy Board. Pipelines that operate entirely within a province are regulated by the regulator in that province. Multiple products can be transported by a single pipeline simultaneously, resulting in an extremely efficient system.

Refining

Most North American refineries receive either diluted bitumen or SCO via pipeline from Alberta. Refineries transform upgraded diluted bitumen or SCO into usable petroleum products such as gasoline, diesel, jet fuel, kerosene, butane and other hydrocarbons.

Sale

In 2017, about 42% of crude bitumen production was sent for upgrading into synthetic crude oil to 4 Alberta upgraders. Most of blended bitumen, upgraded bitumen and crude oil is sold to refineries in the US Midwest, Rocky Mountains and Gulf Coast, British Columbia, Ontario and Quebec.

Stage 4

Shutdown and reclamation

Shutdown

After wells or mining pits have been exhausted, facilities must be dismantled and removed from the site. Much of this equipment is mobile or reusable and can be applied to future operations. Metal parts can be recycled. Pits at mine sites are refilled with sand, overburden and the original top layer to restore the land. Infrastructure such as roads and power transmission lines must also be removed.

Reclamation

Reclamation is the process by which lands formerly involved in industry, in this case bitumen production, are returned to the state of natural productivity that existed previous to the start of industrial activity. The process of reclaiming the land differs depending on what types of activity took place there. Mine operators are required to supply reclamation security bonds to ensure requirements are met.

If mining took place, processed sand and sediment from tailings ponds (sand, clay, etc.) must be returned to the pit to fill the hole. Overburden (soil and organic material) that was stored at the beginning of the operation is placed over the sand and sediment layer. Special care is taken to ensure that overburden is not contaminated during the storage period. That way it can be replaced as soon as the mining operation concludes. In 2008, Syncrude was the first company to successfully reclaim a site near Fort McMurray. The area is reforested or replanted with species native to the area to support a sustainable ecosystem. Extensive research is done in conjunction with local Aboriginal people to determine which types of plants should be reintroduced during reclamation.

In situ operational footprints are typically much smaller than mine sites so reclamation activities are often faster and easier. Wellpads and roads must be removed and replaced with appropriate soil conditions for regrowing native plants. Well bores are filled with an inert liquid, capped below the surface with concrete plugs and buried. Disturbed areas are replanted with native species.

Once reclamation is complete, projects undergo a strict regulatory and environmental review. This can take a significant amount of time in order to ensure that the land has been returned to its original state. When all the criteria is met, the AER issues a reclamation certificate.

Contact

Connect with Oil Sands Operations:

Hours: 8:15 am to 4:30 pm (open Monday to Friday, closed statutory holidays)

Email:
Oil Sands Royalty Project Applications and Compliance osrapplications.energy@gov.ab.ca
Oil Sands Royalty Administration osreport@gov.ab.ca
Oil Sands Royalty Information Management osrim@gov.ab.ca
Oil Sands Tenure ostenure@gov.ab.ca

Mailing Address:
Alberta Energy
Oil Sands Operations
6th floor, Petroleum Plaza, North Tower
9945 108 Street
Edmonton Alberta  T5K 2G6