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Alberta

The Alberta energy transition you haven’t heard about

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11 minute read

From the Canadian Energy Centre

By Deborah Jaremko

Horizontal drilling technology and more investment in oil production have fundamentally changed the industry

There’s extensive discussion today about energy transition and transformation. Its primary focus is a transition from fossil fuels to lower-carbon energy sources.

But in Alberta, a fundamental but different energy transition has already taken place, and its ripple effects stretch into businesses and communities across the province.

The shift has affected the full spectrum of oil and gas activity: where production happens, how it’s done, who does it and what type of energy is produced.

Oil and gas development in Alberta today largely happens in different places and uses different technologies than 20 years ago. As a result, the companies that support activity and the communities where operations happen have had to change.

Regional Shift

For the first decade of this century, in terms of numbers of wells, most drilling activity happened in central and southeast Alberta, with companies primarily using vertical wells to target conventional shallow natural gas deposits.

In 2005, producers drilled more than 8,000 natural gas wells in these areas, according to Alberta Energy Regulator (AER) records.

But then, three things happened. The price of natural gas declined, the price of oil went up and new horizontal drilling technology unlocked vast energy resources that were previously uneconomic to produce.

By 2015, the amount of natural gas wells companies drilled in central and southeast Alberta was just 256. In 2023, the number dropped to only 50. Over approximately 20 years, activity dropped by 99 per cent.

Where did the investment capital go? The oil sands and heavy oil reserves of Alberta’s northeast and shale plays, including the Montney and Duvernay, in the province’s foothills and northwest.

Nearly 60 per cent of activity outside of the oil-rich northeast occurred in central and southeast Alberta in 2005. By 2023, overall oil and gas drilling in those regions had dropped by 30 per cent, while at the same time increasing by 159 per cent in the foothills and northwest.

“The migration of activity from central and southern Alberta to other regions of the province has been significant,” says David Yager, a longtime oil and gas service company executive who now works as a special advisor to Alberta Premier Danielle Smith.

“For decades there were vibrant oil service communities in places like Medicine Hat, Taber, Brooks, Drumheller and Red Deer,” he says.

“These [oil service communities] have contracted materially with the new service centres growing in places like Lloydminster, Bonnyville, Rocky Mountain House, Edson, Whitecourt, Fox Creek and Grande Prairie.”

Fewer Wells and Fewer Rigs

Extended-reach horizontal drilling compared to shallow, vertical drilling enables more oil and gas production from fewer wells.

Outside the oil sands, in 2005, producers in Alberta drilled 17,300 wells. In 2023, that dropped to just 3,700 wells, according to AER data.

Despite that massive nearly 80 per cent decrease in wells drilled, total production of oil, natural gas and natural gas liquids outside of the oil sands is essentially the same today as it was in 2005.

Last year, non-oil sands production was 3.1 million barrels of oil equivalent (boe) per day, compared to 3.4 million boe per day in 2005–but from about 13,600 fewer new wells.

Innovation from drilling and energy services companies has been a major factor in achieving these impressive results, says Mark Scholz, CEO of the Canadian Association of Energy Contractors. But there’s been a downside.

Yager notes that much of the drilling and service equipment employed on conventional oil and gas development is not suited for unconventional resource exploitation.

Scholz says the productivity improvements resulted in an oversupply of rigs, especially rigs with limited depth ratings and limited capability for “pad” drilling, where multiple wells are drilled the same area on the surface.

Rigs have been required to drill significantly deeper wellbores than in the traditional shallow gas market, he says.

“This has resulted in rig decommissioning or relocations and a tactical effort to upgrade engines, mud pumps, walking systems and pipe-handling technology to meet evolving customer demands,” he says.

“You need not go beyond the reductions in Canada’s drilling rig fleet to understand the impact of these operational innovations. Twenty years ago, there were 950 drilling rigs; today, we have 350, a 65 per cent reduction. [And] further contractions are likely in the near term.”

Scholz says, “collaboration and partnerships between producers and contractors were necessary to make this transition successful, but the rig fleet has evolved into a much deeper, technologically advanced fleet.”

A Higher Cost of Entry

Yager says that along with growth in the oil sands, replacing thousands of new vertical shallow gas wells with fewer, high-volume extended-reach horizontal wells has made it more challenging for smaller companies to participate.

“The barriers to entry in terms of capital required have changed tremendously. At one time a new shallow gas well could be drilled and put on stream for $150,000. Today’s wells in unconventional plays cost from $3 million to $8 million each,” he says.

“This has materially changed the exploration and production companies developing the resource, and the type of oilfield services equipment employed. An industry that was once dominated by multiple smaller players is increasingly consolidating into fewer, larger entities. This has unintended consequences that are not well understood by the public.”

More Oil (Sands), Less Gas

Higher oil prices and horizontal drilling helped change Alberta from a natural gas hotbed to a global oil powerhouse.

In the oil sands, horizontal wells enabled a key technology called steam assisted gravity drainage (SAGD), which went into commercial service in 2001 to allow for a massive expansion of what is referred to as in situ oil sands production.

In 2005, mining dominated oil sands production, at about 625,000 barrels per day compared to 440,000 barrels per day from in situ projects. In situ oil sands production exceeded mining for the first time in 2013, at 1.1 million barrels per day compared to 975,000 barrels per day from mining.

Today the oil sands production split is nearly half and half. Last year, in situ projects–primarily SAGD–produced approximately 1.8 million barrels per day, compared to about 1.7 million barrels per day from mining.

Natural gas used to exceed oil production in Alberta. In 2005, natural gas provided 54 per cent of the province’s total oil and gas supply. Nearly two decades later, oil accounts for 60 per cent compared to 29 per cent from natural gas. The remaining approximately 11 per cent of production is natural gas liquids like propane, butane and ethane.

Alberta’s non-renewable resource revenue reflects the shift in activity to more oil sands and less natural gas.

In 2005, Alberta received $8.4 billion in natural gas royalties and $950 million from the oil sands. In 2023, the oil sands led by a wide margin, providing $16.9 billion in royalties compared to $3.6 billion from natural gas.

Innovation and Emerging Resources

As Alberta’s oil and gas industry continues to evolve, another shift is happening as investments increase into emissions reduction technologies like carbon capture and storage (CCS) and emerging resources.

Since 2015, CCS projects in Alberta have safely stored more than 14 million tonnes of CO2 that would have otherwise been emitted to the atmosphere. And more CCS capacity is being developed.

Construction is underway on an $8.9-billion new net-zero plant producing polyethylene, the world’s most widely used plastic, that will capture and store CO2 emissions using the Alberta Carbon Trunk Line hub. Two additional CCS projects got the green light to proceed this summer.

Meanwhile, in 2023, producers spent $700 million on emerging resources including hydrogen, geothermal energy, helium and lithium. That’s more than double the $230 million invested in 2020, the first year the AER collected the data.

“Energy service contractors are on the frontlines of Canada’s energy evolution, helping develop new subsurface commodities such as lithium, heat from geothermal and helium,” Scholz says.

“The next level of innovation will be on the emission reduction front, and we see breakthroughs in electrification, batteries, bi-fuel engines and fuel-switching,” he says.

“The same level of collaboration between service providers and operators that we saw in our productivity improvement is required to achieve similar results with emission reduction technologies.”

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Alberta

Calls for a new pipeline to the coast are only getting louder

Published on

From Resource Works

Alberta wants a new oil pipeline to Prince Rupert in British Columbia.

Calls on the federal government to fast-track new pipelines in Canada have grown. But there’s some confusion that needs to be cleared up about what Ottawa’s intentions are for any new oil and gas pipelines.

Prime Minister Carney appeared to open the door for them when he said, on June 2, that he sees opportunity for Canada to build a new pipeline to ship more oil to foreign markets, if it’s tied to billions of dollars in green investments to reduce the industry’s environmental footprint.

But then he confused that picture by declaring, on June 6, that new pipelines will be built only with “a consensus of all the provinces and the Indigenous people.” And he added: “If a province doesn’t want it, it’s impossible.”

And BC Premier David Eby made it clear on June 2 that BC doesn’t want a new oil pipeline, nor does it want Ottawa to cancel the related ban on oil tankers steaming through northwest BC waters. These also face opposition from some, but not all, First Nations in BC.

Eby’s energy minister, Adrian Dix, also gave thumbs-down to a new oil pipeline, but did say BC supports expanding the capacity of the existing Trans Mountain TMX oil pipeline, and the dredging of Burrard Inlet to allow bigger oil tankers to load Alberta oil from TMX at the port of Vancouver.

While the feds sort out what their position is on fast-tracking new pipelines, Alberta Premier Danielle Smith leaped on Carney’s talk of a new oil pipeline if it’s tied to lowering the carbon impact of the Alberta oilsands and their oil.

She saw “a grand bargain,” with, in her eyes, a new oil pipeline from Alberta to Prince Rupert, BC, producing $20 billion a year in revenue, some of which could then be used to develop and install carbon-capture mechanisms for the oil.

She noted that the Pathways Alliance, six of Canada’s largest oilsands producers, proposed in 2021 a carbon-capture network and pipeline that would transport captured CO₂ from some 20 oilsands facilities, by a new 400-km pipeline, to a hub in the Cold Lake area of Alberta for permanent underground storage.

Preliminary estimates of the cost of that project run up to $20 billion.

The calls for a new oil pipeline from Bruderheim, AB, to Prince Rupert recall the old Northern Gateway pipeline project that was proposed to run from Alberta to Kitimat, BC.

That was first proposed by Enbridge in 2008, and there were estimates that it would mean billions in government revenues and thousands of jobs.

In 2014, Conservative prime minister Stephen Harper approved Northern Gateway. But in 2015, the Federal Court of Appeal overruled the Harper government, ruling that it had “breached the honour of the Crown by failing to consult” with eight affected First Nations.

Then the Liberal government of Prime Minister Justin Trudeau, who succeeded Harper in 2015, effectively killed the project by instituting a ban on oil tanker traffic on BC’s north coast shortly after taking office.

Now Danielle Smith is working to present Carney with a proponent and route for a potential new crude pipeline from Alberta to Prince Rupert.

She said her government is in talks with Canada’s major pipeline companies in the hope that a private-sector proponent will take the lead on a pipeline to move a million barrels a day of crude to the BC coast.

She said she hopes Carney, who won a minority government in April, will make good on his pledge to speed permitting times for major infrastructure projects. Companies will not commit to building a pipeline, Smith said, without confidence in the federal government’s intent to bring about regulatory reform.

Smith also underlined her support for suggested new pipelines north to Grays Bay in Nunavut, east to Churchill, Manitoba, and potentially a new version of Energy East, a proposed, but shelved, oil pipeline to move oil from Alberta and Saskatchewan to refineries and a marine terminal in the Maritimes.

The Energy East oil pipeline was proposed in 2013 by TC Energy, to move Western Canadian crude to an export terminal at St. John, NB, and to refineries in eastern Canada. It was mothballed in 2017 over regulatory hurdles and political opposition in Quebec.

A separate proposal known as GNL Quebec to build a liquefied natural gas pipeline and export terminal in the Saguenay region was rejected by both federal and provincial authorities on environmental grounds. It would have diverted 19.4 per cent of Canadian gas exports to Europe, instead of going to the US.

Now Quebec’s environment minister Benoit Charette says his government would be prepared to take another look at both projects.

The Grays Bay idea is to include an oil pipeline in a corridor that would run from northern BC to Grays Bay in Nunavut. Prime Minister Carney has suggested there could be opportunities for such a pipeline that would carry “decarbonized” oil to new markets.

There have also been several proposals that Canada should build an oil pipeline, and/or a natural gas pipeline, to the port of Churchill. One is from a group of seven senior oil and gas executives who in 2017 suggested the Western Energy Corridor to Churchill.

Now a group of First Nations has proposed a terminal at Port Nelson, on Hudson Bay near Churchill, to ship LNG to Europe and potash to Brazil. And the Manitoba government is looking at the idea.

“There is absolutely a business case for sending our LNG directly to European markets rather than sending our natural gas down to the Gulf Coast and having them liquefy it and ship it over,” says Robyn Lore of project backer NeeStaNan. “It’s in Canada’s interest to do this.”

And, he adds: “The port and corridor will be 100 per cent Indigenous owned.”

Manitoba Premier Wab Kinew has suggested that the potential trade corridor to Hudson Bay could handle oil, LNG, hydrogen, and potash slurry. (One obvious drawback, though, winter ice limits the Hudson Bay shipping season to four months of the year, July to October.)

All this talk of new pipelines comes as Canada begins to look for new markets to reduce reliance on the US, following tariff measures from President Donald Trump.

Alberta Premier Smith says: “I think the world has changed dramatically since Donald Trump got elected in November. I think that’s changed the national conversation.”

And she says that if Carney wants a true nation-building project to fast-track, she can’t think of a better one than a new West Coast oil pipeline.

“I can’t imagine that there will be another project on the national list that will generate as much revenue, as much GDP, as many high paying jobs as a bitumen pipeline to the coast.”

Now we need to know what Mark Carney’s stance on pipelines really is: Is it fast-tracking them to reduce our reliance on the US? Or is it insisting that, for a pipeline, “If a province doesn’t want it, it’s impossible.”

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Alberta

Central Alberta MP resigns to give Conservative leader Pierre Poilievre a chance to regain a seat in Parliament

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From LifeSiteNews

By Anthony Murdoch

Conservative MP Damien Kurek stepped aside in the Battle River-Crowfoot riding to allow Pierre Poilievre to enter a by-election in his native Alberta.

Conservative MP Damien Kurek officially resigned as an MP in the Alberta federal riding of Battle River-Crowfoot in a move that will allow Conservative Party of Canada leader Pierre Poilievre to run in a by-election in that riding to reclaim his seat in Parliament.

June 17 was Kurek’s last day as an MP after he notified the House Speaker of his resignation.

“I will continue to work with our incredible local team to do everything I can to remain the strong voice for you as I support Pierre in this process and then run again here in Battle River-Crowfoot in the next general election,” he said in a statement to media.

“Pierre Poilievre is a man of principle, character, and is the hardest working MP I have ever met,” he added. “His energy, passion, and drive will have a huge benefit in East Central Alberta.”

Kurek won his riding in the April 28 election, defeating the Liberals by 46,020 votes with 81.8 percent of the votes, a huge number.

Poilievre had lost his Ottawa seat to his Liberal rival, a seat that he held for decades, that many saw as putting his role as leader of the party in jeopardy. He stayed on as leader of the Conservative Party.

Poilievre is originally from Calgary, Alberta, so should he win the by-election, it would be a homecoming of sorts.

It is now up to Prime Minister of Canada Mark Carney to call a by-election in the riding.

Despite Kurek’s old seat being considered a “safe” seat, a group called the “Longest Ballot Committee” is looking to run hundreds of protest candidates against Poilievre in the by-election in the Alberta Battle River–Crowfoot riding, just like they did in his former Ottawa-area Carleton riding in April’s election.

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