Perhaps lost in the tsunami of shale oil production from the U.S., Canadian hydrocarbon resources are as important to the global energy supply as any other region. Canada is the fourth largest producer and third largest exporter of oil in the world, with just about all of its exports ending up in the U.S., according to Natural Resources Canada (NRC).

However, product delivery challenges resulting from pipeline capacities have driven down the price of oil in Canada to as much as $28/bbl below West Texas Intermediate. Help might be on the way though in the form of Kinder Morgan’s Trans Mountain pipeline project and the TransCanada Keystone XL pipeline, as each project works through development delays and opposition. Enbridge’s Line 3 is also expected to come online in the second half of 2019 with an initial capacity of 760,000 bbl/d, according to Enbridge.

Market challenges

Once infrastructure and cost challenges are overcome, resources developed in Western Canada’s Montney and Duvernay basins could have a substantial impact on the global energy market, said Paul MacKay, president of Shale Petroleum Ltd., speaking at the American Association of Petroleum Geologists’ Global Super Basins Leadership Conference in March in Houston.

MacKay explained that the Western Canadian Basin is classified as one of the world’s super basins, producing 4.2 Bcm/d [15 Bcf/d] of natural gas and 34 MMbbl/d of oil, most of which is heavy oil or bitumen. But difficulties in getting the product to market have resulted in sharp discounts in hydrocarbon pricing.

“People have always viewed this as a basin of extremes,” MacKay said. “Either you get gas out of it or you get this heavy oil. Both products are discounted severely.”

He said there was a period last fall when producers had to pay to put natural gas into the region’s distribution pipelines.

“Our point-forward value on gas in Alberta is about $1.50/Bcf Canadian and $1.10/Bcf U.S.,” MacKay said.

Production from the Alberta region of Canada dominates the basin, he said. The region produces 2.9 MMbbl/d and 2.8 Bcm/d [10 Bcf/d], most of which is exported to the U.S., MacKay said. Meanwhile, British Columbia is producing about 23,000 bbl/d and 13 Bcm/d [4.6 Bcf/d], and Saskatchewan produces just under 500,000 bbl/d and “a little bit of gas,” he said.

“One of the things that is very good about the Western Canadian Basin is the access to data,” MacKay said. “We have unparalleled access to data. All data that come out of a well belong to the provincial governments, and the provincial governments make those free.”

Of the 171.4 Bbbl of total reserves in Canada, 165.3 Bbbl come in the form of the country’s oil sands, according to NRC. The agency reported that oil sands account for about 62% of the country’s oil production, or about 2.4 MMbbl/d.

MacKay said the OPEC oil embargo in 1973 made Canada’s vast oil sands economic. By 2002 production from oil sands began to dominate the Western Canadian Basin, he said.

“In 2014, 2015 with the price collapse, the conventional production fell, but the oil sands did not,” he said. “They continued to accelerate their production. This production was mostly going down to the Gulf Coast and was displacing Venezuelan and Mexican heavy crude.”

Canada’s energy market was aided by the emergence of the U.S. as one of the world’s preeminent oil refiners, MacKay said.

“Even though there was an imbalance of trade, what the U.S. was doing was accepting the Canadian bitumen and refining it as diesel and gasoline and selling to Europe and South America,” he said.

Addressing completions in Canada’s unconventional plays, MacKay said fracturing designs typically feature smaller proppant tonnages, smaller angles and more stages, which result in higher liquid recovery.

“I’m not saying put less tonnage into the reservoir, but you do it in smaller stages,” he said. “That seems to work out better.”

Analysts on Canada

Speaking during a recent analysis of the Canadian unconventional market, Michael Hebert, Wood Mackenzie Canadian research analyst, explained how the Montney Formation is the most prolific play in Western Canada, with well economics that rival almost any in North America.

“Breakevens in the core areas can get as low as $1.55/ Mcf, and because of this we anticipate production from the Montney to reach about 8.3 Bcf/d [23 Bcm/d],” Hebert said.

Investment firm Peters & Co. Ltd. reported that Montney natural gas production in October 2017 was about 178.3 MMcm/d (6.3 Bcf/d). Hebert said improving economics in the Montney have been seen in the region’s core areas of development.

“We’ve seen year-to-year increase in IP-30 rates, cumulative production and improvements in drilling efficiencies [and] completion designs,” he said. “Refinements in proppant loading and frack stages help continue to drive activity in the play.”

Canadian producers

Among the top operators in Western Canada are Seven Generations Energy, Kelt Exploration, ARC Resources, Tourmaline Oil Corp. and ConocoPhillips. However, ConocoPhillips divested 50% of its nonoperated interests in the FCCL Partnership in May 2017. The company also sold the majority of its Western Canada gas assets to Cenovus Energy. According to ConocoPhillips, production from the assets sold was 103,000 boe/d.

ConocoPhillips has maintained 2 Bboe of resources in the Montney Formation, according to its 2017 annual report, an amount that quadrupled from 2016 to 2017.

Meanwhile, according to the company’s first-quarter 2018 investor report, ARC Resources achieved average production of 131,016 boe/d for the first quarter of the year, 36,874 bbl of which was oil and 16 MMcm/d [565 MMcf/d] was natural gas. ARC Resources full-year average production for 2018 is expected to be between 130,000 boe/d and 134,000 boe/d.

Through the first quarter of the year, ARC Resources produced more than 43,000 boe/d at its Dawson project. (Source: ARC Resources)


In its 2017 annual report, Cenovus Energy said that a technology drive has led to improved field operations, include longer reach horizontal well pairs, drilling improvements and improve startup techniques.

The company reported that redesigned well pads, specifically at its Christina Lake project, features improved modular design and scalable designs for well pairs and pads. Initial pad designs featured 19 pads of 213 wells at a cost of $1.6 billion with 310 MMbbl of recoverable reserves. Later pad designs featured 13 pads with 105 wells at a cost of about $800 million and 310 MMbbl of recoverable reserves.

At Foster Creek Cenovus’ previous pad designs featured 18 pads with 120 wells at cost of about $1.1 billion, which led to 200 MMbbl of recoverable reserves. Enhanced pad designs feature eight pads of 66 wells at a cost of about $600 million, but with identical 200 MMbbl recoverable.

Cenovus’ 2018 production at Christina Lake is forecast at 200 MMbbl/d, while at Foster Creek the company is forecasting about 160 MMbbl/d for the year.

ARC Resources, which stated in its 2017 annual report that it was among the early entrants into the Montney play, said it was a pioneer in the use of multistage fracturing for horizontal completions.

Through March, ARC Resources produced 43,740 boe/d at its Dawson project, 29,533 boe/d at its Parkland/Tower Field, 21,963 boe/d at its Sunrise Field and 15,467 boe/d at Ante Creek.