In-situ Oil Production in the Oil Sands

In-situ projects lead growth in the Canadian oil sands

In Western Canada, about 80% of oil sands deposits are located more than 75 metres underground. These deposits cannot be developed through open-pit mining as too much rock and soil would need to be removed to access the oil sands. At this depth, extracting oil sands is only workable using what is referred to as in-situ methods, which combines drilling and steam injection. Currently, over half of oil production from oil sands in Canada comes from in-situ projects.

In-situ extraction began in Alberta in the 1980s and has become increasingly popular. It is expected to become even more so in the coming years. The Canada Energy Regulator (CER) expects in-situ oil sands production to grow almost 70% between 2018 and 2040, from 1.6 to 2.7 million barrels per day. The main reason for this growth is that in-situ plants are cheaper than oil sands mining plants because they are smaller and don’t need processing plants and tailings ponds and dams.

Oil sands production from in-situ expected to increase

Source: The Canada Energy Regulator (CER).

Methods for in-situ production

There are two methods used for in-situ oil production. Steam Assisted Gravity Drainage (SAGD) is the most common. A SAGD project injects hot steam through a pipe below ground into the bitumen deposit, which liquefies the bitumen and separates it from the sand. The liquid bitumen is then pumped to the surface.

In-situ SAGD method

Source: Cenovus, adapted by Natural Resources Canada, 2010

The second most common in-situ method is the Cyclic Steam Stimulation (CSS). The difference between SAGD and CSS is the positioning and number of wells. The CSS method uses one single vertical well to extract the bitumen. The process consists of injecting steam into the well for weeks and allowing the bitumen to soak into the reservoir. After cooling for days, the flow into the well is then reversed to pump the bitumen to the surface.

In-situ mining projects are operated at small sites

Overall, the cost of in-situ projects is lower than oil sands mining projects. Generally, in-situ projects require 10 to 15% of the size of an oil sands mining operation, one or two wells, and a separation plant. Also, they are less expensive to maintain and operate. Compared to in-situ projects, mines typically require more labour, equipment and supplies in all stages of the project.

Based on estimates reported by the Alberta Energy Regulator (AER) and the Canadian Energy Research Institute (CERI), in 2019 an in-situ project was profitable when the oil price was around US$60 per barrel, while the break-even oil price for new oil sands mine was US$75 to US$85 per barrel. The oil price required for an oil sands in-situ expansion was even cheaper, around US$52 per barrel.

In-situ projects can be even cheaper and faster with the help of modular construction methods. According to the AER, in-situ operators have reduced the time between the start of construction and the start of oil production from five to three years by using off-site module prefabrication.

In-situ operations are major emitters of greenhouse gases

Greenhouse gas (GHG) emissions from oil sands extraction have increased due to in-situ projects. In-situ projects generate more than twice as much emissions per barrel than oil sands mining: 90 and 35 kg of CO2 equivalent per barrel, respectively.

With the increase of in-situ production, emissions from in-situ operations have grown 280% between 2005 and 2017, from 11 Mt CO2e to 42 Mt CO2e, while oil sands mining increased 77%. By 2030, in-situ operations are expected to be the single largest GHG emitter in Canada’s oil and gas sector, at 64 Mt CO2e per year; almost three times more than bitumen mining (22 Mt CO2e) and equivalent to the province of British Columbia’s emissions.

Canadian oil sands emissions per barrel

Source: Canada’s Fourth Biennial Report to the UN Climate Change (UNFCCC)

The reason emissions are so high for in-situ production is that large quantities of natural gas are burned to make the steam necessary to extract the bitumen from the oil sands. Due primarily to an increase in in-situ development, natural gas consumption for oil developed more than tripled, from 0.73 billion cubic feet a day in 2006 to 2.38 billions of cubic feet a day in 2016. This means that almost 30% of all natural gas consumed in Canada was for oil and gas development.

Declining natural gas prices have helped to support the growth of in-situ production. According to Alberta Energy, the falling price of natural gas has reduced operating costs for in-situ projects by C$2.80 per barrel, or approximately 15%, between 2014 and 2018.

Natural gas use for in-situ production increased more than five times from 2005 to 2016, and it’s expected to continue to grow. CERI estimates that total gas demand for the oil sands will increase from 3.5 billion cubic feet per day (BCFPD) in 2018 to 5.5 BCFPD by 2039, primarily for in-situ projects.

Natural gas demand for oil sands production 2007-2039

Source: AER, CERI

Despite growing production, innovations in in-situ operations might slow the growth in emissions. Technologies, such as the use of waste heat (recovered from other industrial processes) and the injection of a solvent, along with steam, to reduce the volume of steam required in SAGD, have been tested and may reduce natural gas demand and eventually in-situ emissions in the future.

In-situ projects may also help to reduce overall emissions in Alberta due to the increased use of cogeneration plants. These plants, also known as combined heat and power (CHP), allow the use of natural gas for generating both electricity and steam. While producing electricity for powering in-situ facilities, CHP plants use exhaust heat from the turbine to produce the steam needed for bitumen extraction.

Over the next decade, more CHP plants are expected to be built at in-situ projects as they reduce the amount of natural gas needed to produce steam, as well as project electricity costs. Eventually, the excess electricity generated by CHPs can be sold to Alberta’s grid and reduce emissions from other fossil fuel burning power plants, particularly coal.

Cogeneration process

Source: Cenovus

Case study: Cenovus Foster Creek

In 2001, the Cenovus Foster Creek plant became the first commercial oil sands project to use SAGD technology. The project is located on the Cold Lake Air Weapons Range — an active Canadian military base, about 330 kilometres northeast of Edmonton, Alberta. The oil at Foster Creek sits about 450 metres below the surface. Foster Creek’s current capacity is 180,000 barrels of oil per day.

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