New numbers show Canada’s oil and gas sector remains far ahead of other industries when it comes to environmental protection spending.

Statistics Canada reports that oil and gas producers and pipeline operators spent $4.3 billion on environmental protection in 2023 — the highest total among the 20 industries surveyed.

The figures capture spending on staff, services, machinery and equipment used to prevent pollution and restore damaged environments.

The investment by oil and gas producers and pipeline operators represents more than one third of total environmental protection spending in Canada. 

It’s more than triple the spend of the next-highest industry on the list, mining and quarrying, at $1.3 billion. Coming in third is primary metal manufacturing at $1.1 billion in 2023.  

From 2019 to 2023, oil and gas producers and pipeline operators spent $17.9 billion on environmental protection, more than primary metal manufacturers, miners and food manufacturers combined.

In 2023, across sectors businesses spent the most on wastewater management ($3.6 billion), followed by solid waste management ($2.6 billion) and air pollution management ($2.3 billion).  

In 2023, Alberta businesses accounted for the largest share of environmental protection spending at 39 per cent, followed by Ontario at 20 per cent.

The unaltered reproduction of this content is free of charge with attribution to Canadian Energy Centre Ltd.

Growing up in a small town in central Alberta, Blake Wickland saw what oil and gas companies contributed to the community.

“They did so much in Drayton Valley – my minor hockey teams always had an energy or energy services company sponsor us — and I’m sure people who grew up in any small town in Alberta could say the same thing,” Wickland said.

He wound up working in the industry, building and maintaining facilities around the province and the globe in scorching summer heat and freezing January darkness for almost three decades.

“I’ve seen a lot of change in the industry in that time. Some developments are very exciting and what we are seeing with methane emissions is one of them,” Wickland said.

“We are doing important work by making a stronger oil and gas industry through emissions reduction. Doing that helps future proof our industry and all the benefits it brings.”

These days, Wickland serves as executive director of the Calgary-based Methane Emissions Leadership Alliance, but remains focused on work at the wellhead.

Emissions targets surpassed

In Alberta, producers met the target of reducing methane emissions in the province by 45 per cent below 2014 levels three years ahead of schedule in 2022 — and have since surpassed it, with a 51 per cent reduction in 2024.

Oil and gas producers in B.C. are also ahead of schedule, reducing methane emissions by 51 per cent as of 2023, beating the province’s 2025 target of 45 per cent two years early.

New technology funding

Late last year, the Alberta government announced nearly $30 million in technology funding to help further reduce methane emissions in the oil and gas sector.

Emissions Reduction Alberta (ERA) will receive $22.4 million for its new Methane Reduction Deployment Program, while $7 million was earmarked for the NGIF Accelerator’s new Methane Reduction Demonstration Program.

The funding comes from Alberta’s Technology Innovation and Emissions Reduction (TIER) program, financed by levies paid by oil and gas producers under the province’s carbon pricing system.

“Our goal is to reduce emissions intensity by 20 per cent per project on average,” said Luca Jungen, ERA’s efficiency program delivery lead.

“There’s a much greater warming potential with methane than CO2 so the more we do with methane, the easier it is for Alberta and the energy industry to hit their GHG targets.”

Deploying methane-cutting technologies

Calgary-based Spartan Controls is one of the companies whose technologies have helped slash methane emissions in Alberta.

Spartan manager of environmental solutions Brian Van Vliet said previous incentives have helped companies adopt technologies that cut methane emissions.

“Producers trying to run a business face challenges being competitive globally with variable commodity prices, constraints in access to market and differing regulatory requirements. Implementing technologies to cut methane emissions is an added capital cost,” Van Vliet said.

“Providing funding through TIER, which industry pays into, makes sense because industry can get some of those dollars back when they continue to invest in eligible measures  that reduce their GHG footprint. And that benefits industry and the province because Alberta is producing hydrocarbon products with lower carbon intensities.”

Exporting Alberta innovation

Van Vliet said the benefits could reach beyond Alberta, with companies able to export methane reduction technologies to other regions.

“If something works in Alberta with its wide range of ambient temperatures and process conditions, it will be robust enough to work anywhere in the world,” he said.

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.

A steady stream of more than 450 oil tankers calls at ports in Eastern and Atlantic Canada every year, drawing little public attention.

That’s in part due to the industry’s safety record in the region, where accidents involving tankers are rare. 

The most recent serious pollution incident from an oil tanker took place in Nova Scotia more than 45 years ago, and the last recorded minor spill from a tanker occurred 25 years ago, following a grounding incident in Labrador.

“Marine shipping as a whole is extraordinarily safe when you look at nautical miles travelled versus incidents,” said Meghan Mathieson, director of strategy and engagement for Clear Seas, an independent not-for-profit that studies marine shipping issues. 

“In Canada, shipping is much safer than your morning commute driving in a vehicle. Of the spills that do occur, most come from fuel from pleasure boats or fishing vessels,” she said. 

“People should not conflate debates about the pros and cons of fossil fuel production with marine safety. Is it safe to ship oil and gas in Canada? Yes, it is.”

Where tanker traffic occurs

Prior to the 2024 completion of the Trans Mountain expansion, about 85 per cent of oil tanker traffic in Canadian waters took place in Atlantic Canada, according to Clear Seas.

The increase in tanker traffic off the B.C. coast has shifted the overall balance to 58 per cent of movements on the West Coast and 42 per cent on the East Coast.

Map courtesy Clear Seas

In Atlantic Canada, this is divided between Saint John, NB, which sees about 115 tankers annually importing crude oil, and the Whiffen Head facility in Newfoundland, where 90 tankers are loaded for export every year.

There are also an estimated 240 shuttle tanker transits annually along the St. Lawrence Seaway in Quebec, moving oil between a storage facility in Montreal and a refining facility in Lévis.

Mathieson says there is greater familiarity with oil tankers in Atlantic Canada than in other areas. 

“They have been used to seeing tankers carry oil for a lot longer in that region. But there’s a cultural component as well. Wherever you are in Atlantic Canada, you are not that far from the ocean,” she said. 

“A lot more people work in the marine sector, such as fishing and offshore oil, than other parts of the country, or they know people who do. They are on the water more, so they may be more familiar with the advancements made by the industry to make it safer.”

How tanker safety has evolved

Many of those improvements came in the wake of the 1989 Exxon Valdez oil spill in Alaska’s Prince William Sound. 

Graph courtesy International Tanker Owners Pollution Federation

“Catastrophic incidents tend to stay in people’s minds when discussing marine safety, but so much has changed in the industry in terms of standards and procedures since then,” Mathieson said. 

“Today’s tankers are designed to be safer—they have double hulls and reinforced attachment points for towing equipment. And the procedures and protocols have advanced just as much, from having local pilots guide them into port to inspections by Transport Canada and certified response organizations for spill clean-up.” 

Spill response organizations on both coasts

Eastern Canada Response Corporation (ECRC) is responsible for responding to spills throughout Atlantic Canada as well as the Great Lakes, Quebec, and St. Lawrence Seaway. 

ECRC is the eastern counterpart to the Western Canada Marine Response Corporation (WCMRC), which is responsible for protecting all 27,000 kilometres of Canada’s western coastline. 

In anticipation of increased tanker traffic from the Trans Mountain expansion, WCMRC completed Canada’s largest-ever expansion of marine oil spill response capacity, doubling its capabilities with new vessels and response bases.

ECMRC’s area of response runs from the Alberta/B.C. border to offshore Newfoundland and from the U.S. border to the 60th parallel.  

Part of the marine community

“We have six response centres located throughout the area that face different challenges based on climate and other factors,” said Michael Kean, manager for the ECRC’s Dartmouth Response Centre, which covers parts of New Brunswick, Prince Edward Island and Nova Scotia as well as the Northumberland Strait and Cabot Strait shipping areas. 

“Some of those areas will ice over for parts of the year, as an example, while our region remains ice free. But regardless of the different challenges, we are training around the year so we are ready.”

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.

In the heart of Alberta’s oil sands region, a lake sits next to Suncor Energy’s Mildred Lake operation. 

On the surface, it looks like one of the countless natural lakes dotting the boreal forest north of Fort McMurray. But several metres below, it tells a different story. 

Base Mine Lake is not a natural lake—it’s a demonstration pit lake at one of the industry’s oldest mines. 

Once a tailings pond, Base Mine Lake was capped with water in 2012 and is now undergoing reclamation, drawing on decades of innovation to restore the land and water affected by development. 

Base Mine Lake. Photo courtesy Suncor Energy

“Tailings ponds aren’t meant to be a permanent part of our closure landscapes,” said Rodney Guest, Suncor’s senior development advisor, mine water closure. 

“We’re investing significant resources to advance tailings treatment technologies in support of land and aquatic reclamation to meet our commitments.”

Those commitments include fully reclaiming mine sites, including tailings facilities, and returning the land to Albertans and local communities, he said. 

Pit lakes: widely used around the world

Pit lakes are a common mine reclamation and closure practice used worldwide. 

According to the Canadian Association of Petroleum Producers (CAPP), a pit lake is basically any lake formed within a former mine pit. 

Over time, as the site stabilizes, these lakes generally come to look and function much like natural lakes. 

Thousands of examples exist globally, particularly in coal and hard-rock mining operations such as gold and copper, CAPP says.

Helping address oil sands tailings

Even as the oil sands sector has reduced its freshwater use per barrel by nearly one-third since 2013, the total volume of fluid tailings has reached about 1.4 billion cubic metres, reflecting continued production growth. 

Aquatic reclamation techniques like pit lakes are helping address the tailings challenge. 

This is evident in the reduction of “legacy tailings,” or tailings placed in storage before 2015. 

Since 2015, the volume of legacy tailings across Alberta’s oil sands has fallen by 40 per cent, according to Alberta Energy Regulator data. 

Base Mine Lake has contributed to this reduction, which overall is helped by water-capped tailings and permanent aquatic storage structure (PASS) technology.

How water-capped tailings technology works

Oil sands tailings are a mixture of fine clay, water, sand, and residual bitumen left over from the bitumen extraction process. 

Traditionally stored in large ponds, these liquid tailings settle very slowly—a process that can take decades. Water-capped tailings technology provides a more controlled solution.

In this approach, a layer of water is placed over tailings within a mined-out pit, forming a pit lake. 

The water cap isolates the tailings from the surface environment while promoting the development of a natural aquatic ecosystem.

Supported by long-term research

Numerous pit lakes, with and without tailings, are proposed or planned for the oil sands region. 

Each is designed to integrate into the final reclaimed landscape, supporting sustainable water management and creating new habitats for aquatic and terrestrial life.

Long-term research and monitoring at several sites—some dating back to the 1980s—has shown that water-capped tailings can be effective. 

Bacteria quickly break down many compounds within the tailings, while the solids settle naturally within weeks. The water layer above largely prevents tailings sediments from migrating back to the surface.

Base Mine Lake. Photo courtesy Pathways Alliance

Base Mine Lake performance

At Base Mine Lake, for example, a water cap currently between 10 and 13 metres covers the tailings. Ongoing research and monitoring show it’s performing as expected, Guest said.

“The tailings remain contained at the bottom and don’t mix with the water,” he said. 

“Water quality continues to improve, diverse habitats are forming, and typical boreal lake life including insects, invertebrates, plants and mammals are present in and around the demonstration watershed.”

While the lake doesn’t currently discharge to the environment, the long-term plan is for its water to eventually integrate into the regional watershed. 

Prior to release, water will be monitored and tested to ensure it meets regulated water quality guidelines, Guest said. 

In the meantime, Suncor adds fresh water and withdraws water for use in its mine operations. 

PASS technology demonstration

Suncor is implementing permanent aquatic storage structure (PASS) technology at a demonstration site that includes Lake Miwasin, a 10-metre-deep lake with a five-metre water cap. 

PASS uses common treatment agents to help tailings settle and release water more quickly. The process speeds up consolidation and helps improve overall water quality.

The company says early results are promising, showing expected improvements in water quality and the re-establishment of vegetation.

Insights from local Indigenous communities have helped refine techniques, including influencing landform design and identifying culturally important plants and trees.  

Confidence in pit lakes

“Results from Base Mine Lake and Lake Miwasin give us the confidence that pit lakes are a safe and integral component of our planned closure landscape,” Guest said.

The transition to a fully reclaimed boreal landscape in Alberta’s oil sands will take time. 

Most of the reclaimed area will consist of forests and wetlands, with pit lakes expected to account for less than 10 per cent. 

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.

*References to land that is reclaimed, permanently reclaimed and surface reclaimed meet the definition of “permanently reclaimed” as defined in the Alberta Energy Regulator Direction for Conservation and Reclamation Submissions (December 2018).

In Alberta’s oil patch, some companies are going beyond their obligations to clean up inactive wells. 

Aspenleaf Energy operates in the historic Leduc oil field, where drilling and production peaked in the 1950s. 

In the last seven years, the privately-held company has spent more than $40 million on abandonment and reclamation, which it reports is significantly more than the minimum required by the Alberta Energy Regulator (AER). 

CEO Bryan Gould sees reclaiming the legacy assets as like paying down a debt. 

“To me, it’s not a giant bill for us to pay to accelerate the closure and it builds our reputation with the community, which then paves the way for investment and community support for the things we need to do,” he said. 

“It just makes business sense to us.”

Aspenleaf, which says it has decommissioned two-thirds of its inactive wells in the Leduc area, isn’t alone in going beyond the requirements.

Producers in Alberta exceeded the AER’s minimum closure spend in both years of available data since the program was introduced in 2022.

That year, the industry-wide closure spend requirement was set at $422 million, but producers spent more than $696 million, according to the AER.

In 2023, companies spent nearly $770 million against a requirement of $700 million.

Alberta’s number of inactive wells is trending downward. The AER’s most recent report shows about 76,000 inactive wells in the province, down from roughly 92,000 in 2021.

In the Leduc field, new development techniques will make future cleanup easier and less costly, Gould said.

That’s because horizontal drilling allows several wells, each up to seven kilometres long, to originate from the same surface site.

“Historically, Leduc would have been developed with many, many sites with single vertical wells,” Gould said.  

“This is why the remediation going back is so cumbersome. If you looked at it today, all that would have been centralized in one pad. 

“Going forward, the environmental footprint is dramatically reduced compared to what it was.”

During and immediately after a well abandonment for Aspenleaf Energy near Edmonton. Photos for the Canadian Energy Centre

Gould said horizontal drilling and hydraulic fracturing give the field better economics, extending the life of a mature asset.  

“We can drill more wells, we can recover more oil and we can pay higher royalties and higher taxes to the province,” he said. 

Aspenleaf has also drilled about 3,700 test holes to assess how much soil needs cleanup. The company plans a pilot project to demonstrate a method that would reduce the amount of digging and landfilling of old underground materials while ensuring the land is productive and viable for use.

Crew at work on a well abandonment for Aspenleaf Energy near Edmonton. Photo for the Canadian Energy Centre

“We did a lot of sampling, and for the most part what we can show is what was buried in the ground by previous operators historically has not moved anywhere over 70 years and has had no impact to waterways and topography with lush forestry and productive agriculture thriving directly above and adjacent to those sampled areas,” he said. 

At current rates of about 15,000 barrels per day, Aspenleaf sees a long runway of future production for the next decade or longer.  

Revitalizing the historic field while cleaning up legacy assets is key to the company’s strategy. 

“We believe we can extract more of the resource, which belongs to the people of Alberta,” Gould said. 

“We make money for our investors, and the people of the province are much further ahead.”

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.

Tailings are a byproduct of mining operations around the world. 

In Alberta’s oil sands, tailings are a fluid mixture of water, sand, silt, clay and residual bitumen generated during the extraction process.

Engineered basins or “tailings ponds” store the material and help oil sands mining projects recycle water, reducing the amount withdrawn from the Athabasca River.

In 2023, 79 per cent of the water used for oil sands mining was recycled, according to the latest data from the Alberta Energy Regulator (AER). 

Decades of operations, rising production and federal regulations prohibiting the release of process-affected water have contributed to a significant accumulation of oil sands fluid tailings.

The Mining Association of Canada describes that: 

“Like many other industrial processes, the oil sands mining process requires water. 

However, while many other types of mines in Canada like copper, nickel, gold, iron ore and diamond mines are allowed to release water (effluent) to an aquatic environment provided that it meets stringent regulatory requirements, there are no such regulations for oil sands mines. 

Instead, these mines have had to retain most of the water used in their processes, and significant amounts of accumulated precipitation, since the mines began operating.”

Despite this ongoing challenge, oil sands mining operators have made significant strides in reducing fluid tailings through technological innovation.

This is demonstrated by reductions in “legacy fluid tailings” since 2015. 

Legacy Fluid Tailings vs. New Fluid Tailings

As part of implementing the Tailings Management Framework introduced in March 2015, the AER released Directive 085: Fluid Tailings Management for Oil Sands Mining Projects in July 2016.

Directive 085 introduced new criteria for the measurement and closure of “legacy fluid tailings” separate from those applied to “new fluid tailings.” 

Legacy fluid tailings are defined as those deposited in storage before January 1, 2015, while new fluid tailings are those deposited in storage after January 1, 2015. 

The new rules specified that new fluid tailings must be ready to reclaim ten years after the end of a mine’s life, while legacy fluid tailings must be ready to reclaim by the end of a mine’s life.

Total Oil Sands Legacy Fluid Tailings

Alberta’s oil sands mining sector decreased total legacy fluid tailings by approximately 40 per cent between 2015 and 2024, according to the latest company reporting to the AER. 

Total legacy fluid tailings in 2024 were approximately 623 million cubic metres, down from about one billion cubic metres in 2015. 

The reductions are led by the sector’s longest-running projects: Suncor Energy’s Base Mine (opened in 1967), Syncrude’s Mildred Lake Mine (opened in 1978), and Syncrude’s Aurora North Mine (opened in 2001). All are now operated by Suncor Energy. 

The Horizon Mine, operated by Canadian Natural Resources (opened in 2009) also reports a significant reduction in legacy fluid tailings. 

The Muskeg River Mine (opened in 2002) and Jackpine Mine (opened in 2010) had modest changes in legacy fluid tailings over the period. Both are now operated by Canadian Natural Resources. 

Imperial Oil’s Kearl Mine (opened in 2013) and Suncor Energy’s Fort Hills Mine (opened in 2018) have no reported legacy fluid tailings. 

Suncor Energy Base Mine

Between 2015 and 2024, Suncor Energy’s Base Mine reduced legacy fluid tailings by approximately 98 per cent, from 293 million cubic metres to 6 million cubic metres. 

Syncrude Mildred Lake Mine

Between 2015 and 2024, Syncrude’s Mildred Lake Mine reduced legacy fluid tailings by approximately 15 per cent, from 457 million cubic metres to 389 million cubic metres. 

Syncrude Aurora North Mine

Between 2015 and 2024, Syncrude’s Aurora North Mine reduced legacy fluid tailings by approximately 25 per cent, from 102 million cubic metres to 77 million cubic metres. 

Canadian Natural Resources Horizon Mine

Between 2015 and 2024, Canadian Natural Resources’ Horizon Mine reduced legacy fluid tailings by approximately 36 per cent, from 66 million cubic metres to 42 million cubic metres.

Total Oil Sands Fluid Tailings 

Reducing legacy fluid tailings has helped slow the overall growth of fluid tailings across the oil sands sector.

Without efforts to reduce legacy fluid tailings, the total oil sands fluid tailings footprint today would be approximately 1.6 billion cubic metres.

The current fluid tailings volume stands at approximately 1.2 billion cubic metres, up from roughly 1.1 billion in 2015.

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.

As a business owner, Ryan Smith values few things more than predictability when it comes to the oil and gas market and the demand for his company’s services.

That’s why knowing that next year in Alberta, the regulator requires at least $750 million worth of work cleaning up inactive oil and gas wells and other legacy energy infrastructure is tremendously helpful for the CEO of Calgary-based 360 Engineering & Environmental Consulting.

“Having a minimum spend in place for the province makes the market more predictable and consistent, which in turn helps our clients and our business plan for the future, which is a good thing,” says Smith, whose company has completed more than 5,000 site closure activities in Canada and internationally since 2015.

“Site closure has really emerged as a growth market over the last decade, especially in Western Canada where the regulatory systems for oil and gas are more advanced than anywhere else we are exposed to. It is an integral part of the energy lifecycle, and if it is done well it adds a lot of value to the industry.”

The Alberta Energy Regulator (AER) introduced an industry-wide minimum “closure” spending requirement in 2022, part of Alberta’s Inventory Reduction Program to accelerate the remediation of inactive oil and gas wells, facilities and pipelines across the province.

The mandatory quota determines the minimum level of work a company must conduct primarily to decommission and reclaim a proportion of its inactive inventory.

Inactive wells are defined as those that have not been used for six months or a year, depending on what they are being used for. When a company decides that they will not reactivate an inactive well they decommission it through a process called abandonment.

A well is considered successfully abandoned after it is cleaned, plugged with cement, cut to a minimum of one meter below the surface and covered with a vented cap. After abandonment comes remediation and reclamation, where the land around the well is returned to the equivalent of its original state.

The first two years under the new rules saw Alberta’s energy industry significantly exceed the minimum closure requirements.

In 2022, companies spent more than $696 million, about 65 per cent more than the initial threshold of $422 million. The AER increased the minimum spend to $700 million in 2023, which producers surpassed by 22 per cent with total expenditures of $923 million.

The 2024 minimum remains at $700 million, while in July the regulator announced that the minimum spend for 2025 was raised to $750 million.

This closure work does not include remediation of oil sands mining sites, which is handled under the Mine Financial Security Program, nor does it include the closure of orphan wells (wells without a legal owner) managed by the industry-funded Orphan Well Association.

Gurpreet Lail, CEO of Enserva, an industry association representing energy service companies, suppliers and manufacturers, says there was an initial rush of closure work when the quotas were first put in place, but activity has since become more even as companies develop long-term closure plans.

“A lot of the low-lying fruit has been taken care of, so now companies are working on more complex closure files that take more time and more money,” Lail says.

Facility owners say that Alberta’s rules provide direction for planning closure and remediation work, which in the past may have been put on hold due to the ups and downs of the oil and gas market.

“When commodity prices are up, everyone is focused on drilling more wells and when prices are down, budgets are strained for doing work that doesn’t bring in revenue. Having a minimum spend makes sure closure work happens every year and ensures there is longer-term progress,” says Deborah Borthwick, asset retirement coordinator for Birchcliff Energy, an oil and natural gas producer focused in Alberta.

Over the last few years, Birchcliff has budgeted more than $3 million for annual facility closure work, far above its required minimum spend.

The company completed 11 well abandonments and decommissioned 23 facilities and pipelines in 2022, according to its latest environmental, social and governance report.

Borthwick says having the closure quota for 2025 already set has allowed it to plan ahead and line up the necessary service companies well in advance for next year’s remediation work.

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.