This article is part of the Spring 2018 edition of the Journal of the Canadian Heavy Oil Association.

In the highly competitive world of oil production, oilsands projects face headwinds on multiple fronts.

Investment in new major growth projects has been all but halted amid the drop in oil prices, challenges in market access and regulatory uncertainty.

However, companies continue to advance new technologies and approaches to make the industry more competitive and beneficial — economically, environmentally and socially.

Here are seven current examples.

1. Advanced data analysis and machine learning: Smart steam

Out of Baker Hughes GE’s customer innovation centre (CIC) in Calgary has emerged a sophisticated computer program that helps oilsands companies improve efficiency by optimizing their steam-to-oil ratios and reducing greenhouse gas emissions.

A sort of adaptive intelligence app for steam optimization, Steam IQ leverages machine learning, a branch of artificial intelligence that evolved from pattern recognition and cognitive learning. Algorithms can quickly adapt to new scenarios, learning from data to predict and optimize outcomes, according to GE.

“Customers may have several constraints across the whole field—it may be steam, it may be on the production side, or not having enough capacity to process produced water, or enough shipping capacity,” said Warren Gieck, production optimization leader at the CIC.

“In the case of steam [constraint], you may want to know how to best allocate your steam for the most optimal operation.”

In that case, all the inputs into the field operations are used to create a highly accurate model, up to 98 per cent accurate, which can then be manipulated to gain actionable insights.

What machine learning can do that people struggle with is to simulate and optimize across an entire field, Gieck said. An engineer uses experience and knowledge to iterate to the best solution on a well pair, and it could take one person days or even weeks to get to the optimized state.

“People use rule of thumb or negotiate right now because they know how to operate their wells very accurately, but to operate a whole field and optimize is a whole different thing.”

Machines are much better at iterating and the technology has advanced to the point where massive quantities of structured and unstructured data can be ingested and synthesized, millions of hypotheses can be tested, and insights and outcomes can be derived in seconds.

Steam IQ can answer questions around well completions and well operations, such as which wells are most productive under certain conditions and what allocation of resources offer the best outcomes. It can also address equipment optimization, facilities efficiency and marketing and blending optimization, determining the best mix of production targets, for example.

The company has been able to show that it can increase production on average about a per cent on steady state operations, which can add up to millions of dollars in added value annually. In unsteady state, where for example there is a boiler outage or forest fire disruption, GE has shown improvements closer to eight per cent, Gieck said.

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2. Digital twin modelling cutting costs for SAGD producers

Last summer, every evening after building activity stopped and all was quiet at a SAGD module manufacturing facility in Alberta, a robot named Franchesca wheeled out of storage and began automatically scanning the partially built units and the parts and tools scattered around them.

It then created an exact digital replica of the modules’ physical reality down to the millimetre scale in a format that allowed comparison of the physical objects against digital renditions like computer-aided design (CAD) models—to make sure everything lines up as intended.

This “model of truth” is designed to ensure that when the various components are assembled in the field, at remote wellsites in the oilsands region of northern Alberta, companies can avoid the most common cause of capital project cost overruns—rework.

“What we are tackling is the big pain point in capital projects. On a global scale the average capital project overruns its budget by about 30 per cent,” said Steve Fisher, co-founder and chief executive officer of Veerum Inc., developer of Franchesca.

“On the global scale, it comes in to about $1.6 trillion in unbudgeted wasted capital on an annual basis. We are going after that opportunity—that’s our focus.”

Veerum has verified all the technologies that go into Franchesca in pilot projects with various oilsands producers, including Husky Energy, Cenovus Energy and Suncor Energy.

Fisher said that by bridging the physical and digital worlds in project development, tremendous savings are available. Pilot projects have indicated savings of 20-50 per cent, accomplished by virtually eradicating rework.

3. New technology could virtually eliminate SAGD steam generation emissions

New technology being developed by SAGD operators could effectively eliminate CO2 emissions from the steam generation process, the largest source of greenhouse gas releases from in situ bitumen production.

Known as direct contact steam generation (DCSG), the technology, thought to be about five years from commercial deployment, could provide additional benefits, including reduced water requirements and production of pure CO2 that could be used for enhanced oil recovery elsewhere.

Suncor Energy Inc. is leading the multi-year development project, backed by Canada’s Oil Sands Innovation Alliance (COSIA).

“It is a potential game changer,” Suncor’s Todd Pugsley said at the 2017 Oil Sands Innovation Summit sponsored by COSIA, Alberta Innovates and Natural Resources Canada.

Today, huge quantities of steam are produced with once-through steam generators, which create heat on one side of a surface, in this case tubes, to heat water on the other side. To preserve the tubes, the water requires some degree of treatment.

DCSG does away with the heat transfer surface altogether, to “directly contact the water with the flame, kind of the way you put out your campfire, except in this case, you don’t want to put your fire out,” Pugsley explained. “When you are directly contacting your feed water with the flame, this allows you to take your produced water and send it directly to the direct contact steam generator without any water treatment.”

Suncor says it is progressing two areas of DCSG technology development.

Results are upcoming from a pilot project at the company’s MacKay River SAGD project where CO2 was co-injected with steam into one well pair to assess the potential impacts to reservoir performance, determine if production is maintained, achieve a lower SOR and confirm CO2 sequestration potential. Start-up of the field pilot began in the fourth quarter of 2016 and was scheduled to last until the middle of 2017.

A second project in collaboration with CanmetEnergy involves pilot testing in Ottawa. This focuses on potential corrosion and its mitigation, fuel efficiency, and optimization of burner design.

Suncor says it is also working with CanmetEnergy and other vendors to design the field demonstration of DCSG scheduled to begin at its Firebag SAGD project in late 2019 or early 2020.

4. Achieving milestones with Aboriginal businesses

Aboriginal businesses are an important part of the oilsands supply chain, receiving significant levels of investment from some of Canada’s largest oilsands producers.

After spending a record $342 million with these business in 2017, Syncrude achieved the major milestone of surpassing the $3 billion mark in total spending since 1992, when the number first began to be tracked.

Syncrude reached the $1-billion mark in business in 2006, while the $2-billion mark was passed in March 2014.

“We’ve reached $3 billion in half that time it took for us to go from $1 billion to $2 billion in spending,” says Doug Webb, Syncrude’s Aboriginal Business Liaison.

“Syncrude works together with more than 50 Aboriginal-owned companies based in Wood Buffalo and are continuing to explore further opportunities based on the shared successes we’ve enjoyed.”

While Cenovus Energy's total spending with Aboriginal businesses dropped in 2016 as major projects were completed and delays in new growth continued, these firms got a bigger share of the company's overall spend.

In 2016, 19 percent of Cenovus’s capital spend was with Aboriginal companies. The figure is an increase from 17.3 percent of total capital spend in 2015, 12.4 percent in 2014 and 9.7 percent in 2012.

Cenovus had total capital spending of $1,026 million in 2016, a decrease from $1,714 million in 2015 and $3,051 million in 2014. In 2016, $198 million of this spend was with Aboriginal companies, down from $297 million in 2015 and $384 million in 2014.

“We expect that our industry will continue to face economic challenges associated with oil price volatility. While this impacts our planned capital expenditure overall, working with local Aboriginal businesses will continue to be a priority for Cenovus,” the company said.

“Our Aboriginal business spend as a percentage of total capital spend in 2016 was 19 percent, a reflection of our effort to engage Aboriginal suppliers as well as the growing number of qualified Aboriginal-run businesses. From 2009 to early 2017, we surpassed $2 billion in cumulative spend doing business with local and Aboriginal companies in our operating areas.”

Meanwhile, in 2017 Suncor Energy was certified at gold-level in the Progressive Aboriginal Relations (PAR) program from the Canadian Council for Aboriginal Business (CCAB).

Since receiving silver-level accreditation in 2014, Suncor has worked to address CCAB's recommendations and has imbedded Aboriginal relations programs across the organization. Examples of this progress include:

  • Development of a long-term social goal that seeks to strengthen relationships with Aboriginal Peoples.
  • Maturity of integrated Aboriginal relations governance.
  • Establishment of the Aboriginal Employee Network (AEN), which is comprised of more than 400 employees with four focus areas: Community circle, Outreach circle, Aboriginal Awareness circle, and Advisory circle which support broader diversity and inclusion within Suncor and in community activities.
  • In 2016, Suncor spent $445 million with Aboriginal businesses, bringing the total spend to almost $3.9 billion since 1999.
  • The Suncor Energy Foundation's support for reconciliation, and investment in cultural initiatives, learning and youth.

"The PAR program encourages companies to evolve and participate in the Aboriginal business economy across Canada," said JP Gladu, president and CEO, CCAB. "Suncor has demonstrated that they are willing to put in the effort to continue learning and growing in this area. They are a role model for positive and progressive Aboriginal relations and more importantly, they have a continuous improvement philosophy and focus."

5. New technologies to improve market access

The Government of Alberta is putting up to $1 billion behind commercialization of technologies to partially upgrade bitumen to a medium or heavy crude.

This could “dramatically increase” the number of refineries that could take Alberta crude, according to the province’s Energy Diversification Advisory Committee (EDAC).

The government funding is expected to drive construction of two to five partial upgraders, representing up to $5 billion in private investment.

While well over a dozen partial upgrading technologies exist, no commercial-scale partial upgrader has ever been built in Canada. At least one system has had recent advancements, with Cenovus Energy recently purchasing a field pilot owned by Fractal Systems, and requesting an extension to operations in order to move the technology closer to commercialization.

At present, more than 75 per cent of Alberta bitumen is sold to about 16 refineries, mostly in the U.S. Midwest. These facilities are equipped with coking capacity to convert bitumen to refinery-ready crude.

According to the EDAC report, the United States’ total refining capacity is 18 million bbls/d, but it only has coking capacity of 2.8 million bbls/d. China’s total refining capacity is 15.4 million bbls/d, but it only has coking capacity of 2.5 million bbls/d.

“Initial analysis shows that there is potential for an additional two million [bbls/d] of partially upgraded medium crude absorption in the U.S. market,” the report says.

The EDAC report noted a 2017 study by the University of Calgary School of Public Policy estimated partial upgrading could boost netbacks by as much as $10-$15/bbl, depending on oil prices.

Partial upgrading could also free up as much as 30 per cent of the capacity on existing pipelines by freeing up the space now taken by diluent, the EDAC report says. This would allow more oilsands crude to be exported to the U.S. and, when the Trans Mountain pipeline expansion is built, to Asia.

The committee believes “aggressive adoption of partial upgrading technologies could have the same effect over a number of years as building another major pipeline.”

6. A pathway to to GHGs equivalent to the world average

One of Canada’s largest oilsands producers says it is on a pathway to produce oil with GHG emissions intensity that rivals that of light crude oil in North America and around the world.

Achieving this would be a big win for a sector that is facing delays building new pipelines for its growing production, in large part because of higher GHGs compared to other sources and concerns over the GHG reduction commitments that have been made by Canadian governments.

A 2014 study by IHS Markit found that oilsands crudes consumed in the U.S. had GHG emissions that ranged from 1 percent higher to 19 percent higher than the average. IHS Markit also found that in 2012, 45 percent of U.S. oil supply was within the same GHG intensity range as oilsands, such as imports from Latin America, Africa, the Middle East and parts of the U.S. itself.

Canadian Natural Resources, which produces from the Primrose, Kirby, Horizon and AOSP oilsands projects, doesn’t just want to be equivalent to the average crude on GHGs, says executive vice-chairman Steve Laut – it plans to do better.

“If you look at where we are today at Horizon itself, taking our carbon capture and storage activities, we’re about five percent off the global average GHG emissions intensity for all crude oil,” Laut told JWN.

“We see many improvements in the use of technology to leverage that. We’re running pilots, [and] depending on the success of those pilots and the iterations we take we see a pathway where we could actually be below the global average oil greenhouse gas emissions intensity.”

The company’s 2016 Report to Stakeholders describes a decrease in company-wide GHG emissions intensity of 16 percent over the previous five years, although this does not include intensity reductions at the Horizon mine and upgrader.

Carbon capture and storage (CCS) operations are a key piece of Canadian Natural’s GHG reduction strategy. With its $12.74-billion buy into the AOSP in 2017, the company became majority owner of the Quest CCS project located at the Scotford Upgrader. Added to its own CCS activities at Horizon, Canadian Natural estimates it has approximately 1.5 million tonnes of CCS capacity, which will jump to 2.7 million tonnes of CO2 annually once the CCS-equipped Sturgeon Refinery is fully operational this year.

Laut said that Horizon CCS activities also have benefits around water use and physical facility footprint.

While Canadian Natural is optimistic about the technology “pathway” to lower-than-average GHG intensity, Laut was cautious not to call it a “line of sight.”

“When you use technology, you never know how it’s going to go. Sometimes things happen a lot faster than you think and sometimes take more iterations,” he said.

“The timing is hard to say, but I think that’s one thing that has been underestimated is the Canadian industry’s ability to innovate and leverage technology to reduce our environmental footprint, and that’s all players in the Canadian oil and gas industry.”

7. Oilsands production growing without increasing use of new water

New data from the Alberta Energy Regulator (AER) shows that while oilsands production is increasing, the industry’s introduction of new water into its processes is not – indicating that the industry has found ways to get more from less.

The key driver has been increased water recycling, according to the AER, which launched more detailed water use reporting in 2017 in order to enhance transparency and encourage improved performance.

In 2012, in situ oilsands operators used about 30 million cubic meters of new or “make-up” water (both saline and non-saline) to produce about 307 million cubic meters of oil equivalent. In 2016, while oil production increased approximately 55 percent to 476 million cubic meters, make-up water use stayed essentially flat at 31 million cubic meters.

Overall in situ water use increased over the period to about 217 million cubic meters, which the AER says was almost entirely enabled by increased recycling (79 percent in 2012 to 86 percent in 2016).

Make-up water requirements have remained steady for in situ projects in part due to new rules introduced in 2012, the regulator notes.

A similar trend is seen on the oilsands mining side, with the total volume of recycled water increasing by 33 percent from 2012 to 2016, the AER says. At the same time, mined oilsands production increased to 466 million cubic meters from 378 million cubic meters.

Total mined oilsands water use increased to 813 million cubic meters from 648 million cubic meters, with make-up water – primarily non-saline water from the Athabasca River – increasing by 10 million cubic meters, from 171 million to 181 million cubic meters.

Some of the improvements in non-saline water use intensity can be attributed to improvements in technologies and operational processes which require less water, the AER says, adding that operators also use recycled water from tailings ponds or storage ponds.

Image: Cenovus Energy

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