The oil sands sector’s average emissions per barrel is coming down thanks to new technology and improved processes – in some cases, today’s oil sands crude has lower emissions intensity than the average oil consumed in the U.S.

About 12 per cent of oil sands production – or about 350,000 barrels per day – comes from a mining project process known as paraffinic froth treatment (PFT). In 2018 the greenhouse gas emissions per barrel of PFT crude averaged 1.6 per cent below the U.S. average, according to analysts with IHS Markit.

Suncor Energy CEO Mark Little has called PFT “accelerated carbon sequestration,” where the parts of the oil sands barrel that are most energy intensive to treat are removed prior to further processing, reducing CO2 emissions.

Suncor opened Canada’s newest PFT oil sands mine, Fort Hills, in January 2018. The project’s successful ramp-up contributed to a 10 per cent drop in the overall emissions intensity of oil sands mining between 2017 to 2018, IHS Markit says.

This was the second greatest year-on-year drop in the estimated history of oil sands mining operations; the largest was a 12 per cent decrease between 2014 and 2015.

Imperial Oil vice-president Sherri Evers says that with PFT, “Really what you end up left behind with is a very clean bitumen product that you can actually ship without having to be further processed or upgraded.”

Imperial Oil has been using PFT at its Kearl oil sands mine since startup in 2013.

Evers explained to a virtual energy symposium hosted by the Canadian Association of Petroleum Producers and Scotiabank this week that the process occurs after bitumen froth is extracted from mined oil sands.

“Bitumen froth produced in extraction is a mix of bitumen, fine solids and water, and it requires further cleaning essentially before it can be upgraded into crude or sold into the market. Paraffinic froth treatment is a process where the water, the fine solids and some asphaltenes are removed from the bitumen froth, and that is done using extraction with hydrocarbon solvents.”

In addition to Fort Hills, analysts report that four out of five legacy oil sands mining operations realized reductions in emissions intensity in 2018 thanks to energy efficiency improvements and reductions in the use of petroleum coke.

IHS Markit estimates that average oil sands emissions per barrel range from 1.6 per cent below to 8.6 per cent above the U.S. average, depending on production process.

Overall oil sands emissions intensity declined by over 23 per cent between 2012 and 2019, according to Government of Alberta data. The province forecasts that leading producers are on track for a further 16-23 per cent reduction over the coming decade.

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Oil sands producer Suncor Energy is restarting construction of a major project that is expected to significantly decrease its greenhouse gas emissions per barrel.

That the company is already getting back to work on the project, which was put on hold in 2020 in the wake of COVID-19, shows its commitment to reducing its footprint, says Kevin Birn, vice-president with business information provider IHS Markit.

“It’s an indication as one of the first things they restart of how important this project is and [its] multiple benefits,” Birn says.

Suncor is investing $1.4 billion to replace boilers at its oil sands mining base plant that currently run on petroleum coke – a fuel similar to coal for its carbon content – with natural-gas fired cogeneration units. This is expected to reduce the plant’s GHG emissions from steam production by approximately 25 per cent, or the equivalent of taking 550,000 vehicles off the road each year.

As part of its overall strategy, Suncor is also restarting construction of the $300-million Forty Mile Wind Project in southeast Alberta, which was also put on hold in 2020. Together, the two projects are expected to reduce Suncor’s GHG intensity by 10 per cent, which the company says will take it two-thirds of the way to its goal of a 30 per cent reduction from 2014 levels by 2030.

The cogeneration project is large enough to have an impact on the footprint of the oil sands mining sector broadly. Once operational, the new units will reduce average GHG emissions intensity from oil sands mining and upgrading by two per cent, according to IHS Markit modelling.

Oil sands mining and upgrading projects have been on a steady trend of emission intensity reduction thanks to new technology and improved efficiency, decreasing by 24 per cent from 2009 to 2018, IHS Markit reports.

“Every individual little bit chips away at the intensity, and this kind of project and their prioritization of it gives us the indication that those intensity improvements will continue,” Birn says.

In 2020, analysts found that more efficient and newer forms of oil sands production have life cycle GHG emissions that are below the US average.

Cogeneration is a highly efficient process that creates both electricity and heat from the same stream of natural gas. Suncor will use the heat to create steam for its plant processes, while selling approximately 800 megawatts of electricity to the Alberta grid, or about 8 per cent of current demand.

Meanwhile, the Forty Mile Wind Farm will increase Suncor’s interest in wind power capacity to approximately 300 megawatts, from about 100 megawatts.

Both projects are expected to be operational by 2025.

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Global oil demand is rebounding quickly off COVID-19 pandemic lows and Canada is positioned to benefit more quickly than its biggest competitor, according to new analyst reports.

IHS Markit says that world oil demand has bounced back by a “meteoric” 13 million barrels per day in the last four months and is now at 89 per cent of pre-COVID levels. Analysts expect demand to return to up to 95 per cent of pre-COVID levels through the first quarter of 2021.

Like oil producers around the world, Canadian producers responded quickly to shut in production as prices tanked in March and April amid stay-home orders and social distancing measures. IHS Markit estimates that at its worst, over 700,000 barrels per day of oil sands production may have been temporarily curtailed in the second quarter of 2020.

According to the U.S. Energy Information Administration, U.S. oil producers ramped down from approximately 13 million barrels per day in March to 11.2 million barrels per day at the end of May. Production has continued to decline, to 10.8 million barrels per day as of mid-August.

Meanwhile in Canada, oil sands or heavy oil production is already well into coming back online as producers capitalize on their unique ability to swiftly respond to stabilizing oil prices.

“Canadian oil sands has virtually no base decline, so as production is returned online it can ramp up back to previous levels more quickly,” says Elisabeth Murphy, analyst with ESAI Energy.

“The steep decline rates for [U.S.] shale require constant drilling and completion activity, and it will take a while to get production back to pre-pandemic levels.”

The rebound in Canada is already being seen on the Enbridge Mainline, the country’s largest transporter of crude oil.

“With stabilized prices, we’ve seen heavy [oil] volumes come back. Actually, if you look at July, heavy capacity is being fully utilized again,” Enbridge CEO Al Monaco told analysts in late July.

“Barring another shutdown of the economy, we expect Mainline throughput closer to where we were in Q1 by year-end.”

Monaco said that in April, deliveries on the Enbridge Mainline to refineries in the U.S. Midwest dropped by 12 per cent compared to pre-COVID levels. By July, this was back up to 98 per cent. Meanwhile, Mainline deliveries to the massive U.S. Gulf Coast refining cluster in July increased to 120 per cent of levels pre-pandemic.

“Overall, the pace of recovery was a little bit better than we thought in Q2, but with the rise in infection rates that we’re seeing today, we’re cautious on the timing of a full return,” Monaco said.

IHS Markit says a full return to pre-COVID oil demand depends on the timing of travel activities getting back to normal, especially air travel and commuting to work. “And that won’t happen until there is containment of the virus and effective vaccines,” says head of oil markets Jim Burkhard.

Canada’s oil producers are already better positioned than competitors in the United States to capitalize on demand recovery. According to RBN Energy analyst Martin King, the industry is actually on its way to growth, with small oil sands expansions underway by companies like Canadian Natural Resources and Suncor Energy.

“Canadian production could actually be higher after all this,” he says. “Maybe slightly delayed in terms of getting to that point but still higher next year than where it was pre-COVID, whereas the US could be down by 1.5 million, maybe 2.5 million barrels a day, and it’s all because of the oil sands.”

Progress is being made to solve one of the oil sands industry’s highest profile environmental challenges. Thanks to years of companies working together and more than $10 billion of combined sector investment, the future outlook for reduction of oil sands tailings is looking brighter.

A “notable acceleration” in the application of new technologies to treat tailings from oil sands mining is starting to pay off, BMO Capital Markets analyst Jared Dziuba wrote in an investment report earlier this year.

It’s a critical step forward for what he described as an issue “at the centre of the global scrutiny and tainted image of [the] oil sands.”

Major strides have been made by the two largest mining producers, with one reducing new project tailings by half and the other reducing its total operated tailings footprint altogether. Meanwhile, producers on the whole since 2015 have been able to keep tailings inventories lower than expectations, despite increasing oil production.

Dziuba said that based on performance trends and R&D momentum, BMO believes that tailings management will be an important and exciting area to keep an eye on.

“It could act as a catalyst for the sector to vastly improve its image on the global stage,” he said.

Oil sands tailings

Tailings are a consideration in mining operations around the world, created during the extraction process that separates the target valuable product from other material.

The extraction process that unlocked Alberta’s vast oil sands resources to commercial development in the late 1960s is based on hot water. The hot water is used to separate sand and clay from bitumen, which is then treated and sold as oil. This leaves behind a mix of water, sand, clay and residual bitumen that is stored in engineered basins known as “tailings ponds.” These facilities enable the water to be fed back into the system. In 2018, for example, 75 per cent of the water used by oil sands mining producers was recycled using this process.

But decades of operations, increasing oil sands production, technological challenges and the regulatory requirement to store untreated process-affected water have contributed to a large accumulation of tailings in Alberta. Since the introduction of new tailings regulations in 2009 and their continued evolution, producers have heavily ramped up their R&D efforts.

The Alberta Energy Regulator’s current rules for oil sands tailings include a mandate that all fluid tailings must reach “ready to reclaim” status 10 years after the end of a mine’s life.

Investment and collaboration

Tailings are one of four priority areas for Canada’s Oil Sands Innovation Alliance (COSIA), a collaboration of the largest producers that exists to accelerate environmental performance improvement. In fact, collaboration on tailings existed before the launch of COSIA in 2012, through the Oil Sands Tailings Consortium.

COSIA chief executive Wes Jickling says operators “are aggressively working on innovative, sustainable approaches to reducing tailings volumes, accelerating tailings reclamation time, increasing water recycling and reducing GHG emissions.”

“Collaboration is driving significant progress through COSIA; oil sands producers, universities, government agencies and research institutes are bringing together shared experience, expertise and best practices to drive innovation,” he said, adding that more than 189 tailings technology and research projects have been or are being advanced through collaboration.

“Industry has invested more than $10 billion into tailings management and the implementation of innovative tailings treatment technology.”

According to BMO’s analysis, the volume of fluid tailings being treated by the various approved technologies has grown substantially, from approximately 60 million cubic metres in 2016 to over 160 million cubic metres in 2018.

“We believe that this trend has been at least partly influenced by regulatory pressures, but also motivated by a drive to revive the sector’s image and lower costs,” Dziuba said.

Work paying off

Suncor Energy hit the first major milestone for oil sands tailings in 2010 when it became the first operator to reclaim a tailings pond to a solid surface. Tailings Pond One, which operated from 1967 to 1997, became Wapisiw Lookout, a 220-hectare area that is being developed into a mixed wood forest and small wetland.

Suncor achieved the milestone using a portfolio of technologies it calls tailings reduction operations (TRO), which BMO said is also responsible for the trend of success it is currently on.

“The company has managed to actually decrease net fluid tailings at its Base Mine despite considerable expansion in production directly as a result of TRO innovations,” Dziuba wrote.

According to AER data, between 2015 and 2019 Suncor reduced the fluid tailings inventory at its Base Mine by almost 17 per cent, from 316 million cubic metres to 263 million cubic metres. This has been achieved in part by reducing its “legacy” tailings, or volumes that were in storage before 2015. Suncor reduced its legacy tailings by approximately 45 per cent between 2015 and 2019, from 293 million cubic metres to 162 million cubic metres.

In its new sustainability report the company says it is able to achieve the reductions by building on its TRO approach with a process called called permanent aquatic storage structure (PASS). Suncor says that using PASS, in 2019 it was able to treat more than double the amount of tailings that it produced at the project.

“This has been a key reason why Base Plant’s untreated fluid tailings inventory is shrinking,” the company says.

BMO also singled out the successful efforts of Canadian Natural Resources, which “has proven its ability to reduce fluid tailings by approximately 50 per cent in its latest expansion at Horizon, along with approximately 14 per cent decrease in GHG emissions, using its non-segregating tailings treatment process,” Dziuba wrote.

Canadian Natural is also “on the cusp of commercializing” a technology called its In-Pit Extraction Process, which would create dry, stackable tailings and completely eliminate the need for fluid tailings, he said.

For now, industry-wide tailings volumes continue to grow, but at a slower pace than expected. As of 2019, oil sands producers had regulatory approval to have 1.4 billion cubic metres of tailings inventory, but actually had approximately 1.27 billion cubic metres of tailings inventory, or about 10 per cent less than expected.

The future

COSIA’s Jickling says that industry is working both on enhancing and optimizing existing technologies and developing new approaches to reduce or even eliminate the production of tailings.

This includes water capping, which is expected to play a key role in the post-reclamation oil sands landscape. The approach has been used successfully in various sectors of the mining industry globally but is not yet considered commercial in the oil sands. There are currently two oil sands demonstration pit lakes: Syncrude’s Base Mine Lake, which was commissioned in 2012, and Suncor’s Lake Miwasin, which was commissioned in 2018 and is being used to validate the company’s PASS process.

The AER’s current tailings rules include a commitment for the Alberta government to develop direction for water-capping; once this direction is received, a regulatory approach specific to water-capped tailings will be developed. This has not yet occurred.

Another major future advancement for dealing with oil sands tailings would be the ability for producers to release treated process-affected water back into the Athabasca River.

There is currently zero release of treated process-affected water allowed back into the river. Based in part on analysis of a new Syncrude technology pilot as it goes forward, the governments of Alberta and Canada are developing regulations to allow for process water release, with 2023 previously set as the deadline for those rules.

It’s fair to say Toronto’s Didi Horn has a sky high view of the future.

The former fighter pilot and drone operator has always had a keen eye for the horizon, which helped crystalize his vision for SkyX, a proprietary unmanned aircraft system purpose-built for monitoring over long distances, making it a natural fit for inspecting sprawling arrays of pipeline infrastructure.

The founder and CEO of the Toronto-based tech company couldn’t have known four years ago when he launched SkyX that it could become a critical cog for oil and gas companies emerging from the COVID-19 pandemic and looking for ways of minimizing risk to personnel while streamlining operations.

But it’s a challenge he says SkyX is ready for.

“I think SkyX is built, to be honest, for what we’re seeing right now and that’s the movement or transition of manned forces to unmanned systems,” Horn says.

“In January, 2019 we basically launched the product as a full solution to customers. It was fascinating to see that despite the fact we are considered small or tiny on the scale of oil and gas companies, we’ve been approached by the big whales. And six months into the year, we’ve already signed our first contract, seven figures, with our first customer.”

In April, SkyX announced a partnership with TC Energy to monitor a pipeline and its right-of-way in the Greater Toronto Area, scanning for debris discarded along the line, nearby construction activity and excavation that could damage the infrastructure, a level of vigilance made even more critical by its proximity to densely populated communities.

The company’s first VTOL (vertical take-off and landing) aircraft, SkyOne, has a range of over 100 kilometres, but its ability to extend its monitoring missions is boosted by remote x-Stations, which recharge the aerial units while running diagnostics, allowing it to continue its mission over hundreds or even thousands of kilometres.

The COVID crisis has prompted oil and gas companies to examine all aspects of their operations, while doubling down on technological innovations that were already in the works.

TC Energy was one of the first industry giants to begin the technological transition, announcing in 2017 that it was working with Amazon Web Services to host its information infrastructure. Last month, the company said it would migrate 100 per cent of its data to the online cloud, positioning it to continue operations as normal during the COVID-19 crisis, with employees able to worth remotely while maintaining security.

Other industry leaders have also recognized the value of digital transition, with companies like Cenovus and Suncor also striking deals with tech giants like Amazon, Microsoft  and IBM to transition their information infrastructure to the cloud. Imperial Oil also recently entered into a two-year agreement with the Alberta Machine Intelligence Institute to develop capabilities for a range of artificial intelligence projects.

“Our early steps have been encouraging. We’ve recently begun work in a variety of areas using robotics, artificial intelligence, and remote sensing technology. In fact, last year, we invested $635 million in technology development and deployment, including digital transformation,” Suncor president and CEO Mark Little said at the company’s AGM in May.

“Our journey into the digital world will only accelerate.  As we step further into this space, we’re cognizant that it’s not just about shiny new technology. It’s really about our people, our culture and our leadership. And how we can get our organization to work together to fully leverage technology to improve our performance. Let me be clear. Technology and innovation are part of our DNA. I have no doubt that with the ingenuity, creativity, and energy of our people, we will continue to lead.”

Geoffrey Cann, a consultant and speaker specializing in digital transformation for the oil and gas industry says there is a challenge facing some companies that may not have the corporate will to make a seismic technological shift.

But the sweeping impact of the COVID-19 pandemic across all operations has the potential to serve as a catalyst to force energy companies to modernize, or possibly be left behind.

“What they need to do is step back and say ‘let’s reimagine this industry,’” Cann says.

“There seems to be a rising awareness that a business model that’s pushing people into close contact with one another is not optimal. COVID has also taught the industry that people don’t need to work in an office in downtown Calgary.

“The pandemic, in my view, absolutely showed executives that some of their long-standing views no longer hold.”

Cann says while the list of potential technological innovations that could improve oil and gas companies are myriad, some of the key areas for them to consider are robotics, automation, virtual team collaboration tools, virtual training, online shopping and procurement, and, of course, remote monitoring.

And it’s in that ecosystem of remote monitoring and digital transformation where SkyX’s Horn sees significant growth potential as more companies realize the benefit not only to their bottom lines, but to their operations as well.

Beyond just having eyes in the skies to replace humans who have to physically walk the line to detect any issues, SkyX software will be able to interpret and analyze the data it collects, reducing the need for an employee to dig through reems of aerial photographs in search of anomalies.

“We are taking this information and turning it into actionable pieces of data,” Horn says.

“Now the big asset of SkyX is after a while that we’re deployed, we’d be able to provide what we call predictive analytics, meaning not only can I tell you right now what’s going on with your pipeline, but after a couple of months I’ll be able to tell you ‘look, this section is more prone to problems, or this section is prone to have more leaks over the springtime.”

In 2018, SkyX unveiled its next generation UAV, SkyTwo, at the Farnborough International Airshow in the United Kingdom, which will be able to carry heavier payloads and fly up to 170 kilometres on a charge, before fully recharging in just 2.5 hours at an xStation. It’s expected to be market-ready later this year.