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Water works are on in Canada’s oil sands

Interesting developments in water technologies essential to in-situ extraction methods continue despite a generally negative outlook for the exploitation of the Canada’s oil sands resources

The sanctioning of new oil sands projects has almost come to a standstill as producers suffer from falling oil prices and increased regulatory and public scrutiny, as well as dwindling interest from investors in recent years. However, innovation continues in a few key areas, such as water treatment and steam generation for in-situ recovery, particularly because of the need to maintain or improve the economics of existing projects and comply with government-imposed sustainability targets.


As a heavier, lower-grade product, Western Canada Select has always sold at a discount to the US’ West Texas Intermediate, but in November 2018, the differential reached an all-time high of more than $45. Alberta’s provincial government responded by implementing production curtailments to boost oil prices.



Adjustments to evaporators and steam generators, as well as new approaches in injection chemistries and membrane technologies, are just some of the areas where progress is being made on the water side of oil sands activities. This is especially true for the most common of in-situ extraction methods, steam-assisted gravity drainage (SAGD), of which there are more than 20 active projects in Canada.


Output from the oil sands consistently outpaces the production of any of Canada’s other hydrocarbons resources.


Despite the challenges of low oil prices and political friction leading to a lack of export capacity, in 2018 the oil sands accounted for 64% of total hydrocarbons output in Canada, the world’s fourth-largest oil producer (see charts 1 and 2). Bitumen extraction relies heavily on water, so the technology behind treatment and steam generation is vital to production. Advances in these areas offer producers a way of combatting high cost structures resulting from complex energy- and resource-intensive processes.


For many of the players still operating in Canada’s oil sands, there is no question as to whether activity will endure. It is more a matter of when oil prices and the regulatory environment will improve and what can be done in the meantime to maintain project viability and move the dial on cost competitiveness.


Water recycle rates are high for in-situ projects and make-up water use is consistently lower than surface water and groundwater allocations set by the government. Alberta Energy Regulator


Especially for in-situ projects, which had an average 86% water recycle rate in 2018, produced water management is mission critical (see chart 3). The water treatment package is the largest for those types of projects. Producers can sink about $1 billion into large-capacity plants, including for infrastructure and equipment packages, Mark Nicholson, a senior project developer for HPD Evaporation and Crystallization at Veolia, told Water in Oil.

Evaporators have become a widespread technology to treat boiler feedwater over the past 20 years and are typically designed with a recycle rate of 95% or more (see chart 4). As SAGD usually requires 3 bbl of water to produce 1 bbl of oil and evaporators at large plants can each process about 45,000 bbl/d of water, projects require two to three units to meet water demand, Nicholson explained.


Water used in SAGD projects typically follows this train. Tweaks to technologies over the years have only slightly adjusted the water cycle, but technological R&D could lead to new ways of handling water. GWI


Evaporators represent a significant cost in the water treatment train due to the energy required to operate them and the logistical challenges associated with installation in remote locations that experience freezing temperatures. Modularization has helped bring expenses down, and other technological tweaks have increased the reliability of the equipment.

For example, Veolia, which has been involved in nine oil sands projects at various stages, has been able to make its evaporators more resistant to scaling through the development of a seeded type of technology specifically for produced water from SAGD projects in Alberta. “It involves precipitation of the scaling species on the ‘seed’ instead of the heating surface. It is also resistant to organic/oil fouling,” Nicholson explained. Veolia has commercialized the technology within the past 15 years.


To reduce steam-to-oil ratios and increase production, many producers have already begun piloting a variety of SAGD processes wherein a share of the steam injected into the reservoir is replaced with solvents or noncondensable gases.

In November 2018, Imperial Oil made a final investment decision for its CAN $2.6-billion Aspen SAGD project, which was to use this new solvent injection process to produce 75,000 bbl/d of oil. The company had initially planned to begin operating in 2022, but announced in March 2019 that the project was on hold due to unfavorable economic circumstances. Though Imperial’s project has been shelved, other producers are testing similar technologies.

Suncor Energy began a pad-scale expanding solvent SAGD (ES-SAGD) pilot at its Firebag facility in February 2019, and Canadian Natural Resources (CNRL) is implementing solvent-steam coinjection at its Kirby project which it predicts could reduce the steam-to-oil ratio by 50%. Depending on the results, the company hopes to expand the program to its Primrose/Wolf Lake site. CNRL has also tested coinjecting steam and noncondensable gas at Kirby South.

Additionally, Cenovus has advanced pilots for both solvent-driven and solvent-aided processes, the latter of which are expected to reduce steam-to-oil ratios by as much as 30%. MEG Energy has also developed its own similar processes, enhanced modified steam and gas push (eMSAGP) and enhanced modified vapor extraction (eMVAPEX).


Other water technologies hold promise for reducing costs and raising efficiency in oil sands operations; however, various technical issues prevent them from being applied at a larger scale.

One such technology is reverse osmosis (RO), which has the potential to produce clean boiler feedwater in a more energy efficient way. The challenge in successfully applying RO in the oil sands is threefold:

• membrane-fouling oil and organics

• high concentrations of salt and silica

• high temperatures

Produced water flows to the treatment plant at about 85-90 °C (185-195 °F). The development of temperature-resistant membranes would enable producers to skip having to cool down the water stream to less than 40 °C (104 °F) before it can be treated, and then heating it back up during steam generation. The results would be a treatment process with lower energy intensity and greenhouse gas (GHG) emissions as well as a smaller surface footprint, all of which would lead to cost savings.

Alan Daza, Aquatech’s vice-president of sales and business development in the Americas and Europe regions, told Water in Oil that “membrane technologies will be the next wave” in the development of technologies that have the potential to make oil sands activities more appealing.

Several companies are working on high-temperature RO for oil sands applications, namely Suez in partnership with Suncor and CNRL. Kinga Uto, a senior environmental, social, and governance analyst for investor relations at Suncor said that this technology will be piloted within the next two years. Based on those results, the company could potentially roll out RO in four to six years.

Aquatech has also done work in this area, for both high-temperature RO and high-efficiency RO, the latter of which entails fouling-resistant membranes, making it suitable for treating water with high silica content.

“We have completed in-house pilot testing with high-temperature RO elements and have found that the application has its benefits and potential savings, especially from a total installed cost and opex [perspective],” Daza said. He went on to explain that membrane construction integrity remains a challenge, as does finding an end-user willing to be an early technology adopter.

Oleophobic membranes are being tested by some companies to address fouling by oil and organics, though none have been commercially applied.


As existing steam generators require produced water to be extensively treated to a high quality, several companies are pushing boundaries on technologies in this area to simplify SAGD operations.

“The innovative technologies are generally directed toward steam generation technologies which reduce or eliminate the water treatment [process], which has the benefit of reducing costs and GHG generation,” Keith Minnich, principal at Third Bay, told Water in Oil.

One alternative steam generation technology is the indirect fired steam generator, which uses a closed loop heat source and is under evaluation by producers for commercial testing. Another technology is direct contact steam generation, in which produced water directly contacts the combustion gases, allowing both steam and carbon dioxide to be injected into the reservoir for improved recovery. Working with Canadian energy technology research laboratory CanmetENERGY, Suncor is among the producers looking into this technology.

Discussing producers’ interest in alternative steam generation technologies, Nicholson said demonstration units have already been deployed. He also pointed out that, “There is risk here, since the boiler would be essentially both your water treatment and steam generator.”


The oil sands will likely see even more innovation in water technologies following the startup of the long-awaited Water Technology Development Centre (WTDC) in 2019 (see chart 5). The $145 million facility is a collaboration between Canada’s Oil Sands Innovation Alliance (COSIA), Suncor, CNRL, CNOOC, and Husky Energy. The WTDC is attached to Suncor’s Firebag project and will allow operators to jointly test technologies in real-life conditions. During the first year of operations, several pilots will be run for technologies related to inlet separation and deoiling, water treatment, and steam generation.


Suncor’s water recycle rate at Firebag continues to be greater than projects belonging to its peers. The start up of the WTDC will undoubtedly help push recycling to higher levels for all operators involved. Alberta Energy Regulator

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