A Tale of Two Canadas
When it comes to refinery markets, Eastern and Western Canada might as well be different countries
When it comes to markets for refined products, Western and Eastern Canada might as well be different countries. Both connect more closely to their U.S. counterparts than to each other. Geography, climate, market size and location, and the physical properties of refined products all play a role. When it comes to refinery feedstocks, transport infrastructure and upgrading capacity are key factors.
From proposed ultra-low carbon refineries in British Columbia, to a gas-to-liquids project in Alberta and Canada’s biggest refinery on the Atlantic coast, Canadian refineries and their related facilities are as diverse as the terrain and time zones their pipelines cross.
Planned BC Refineries
Pacific Future Energy
It’s a long shot, but this proposed $10 billion near-net zero emissions refinery would be located between Terrace and Kitimat on the coast of Northern B.C. The site is on the rail route from Edmonton that would bring 200,000 b/d of bitumen as near-solid neatbit—which has diluent removed making it safer than liquid dilbit.
The proposed $18 billion, 400,000 b/d, low-carbon refinery, located at Kitimat on the coast of Northern B.C. is the vision of Black Press newspaper magnate David Black. It would be one of the world’s ten largest refineries, processing Albertan bitumen shipped by rail as neatbit.
Alberta Industrial Heartland Plants
Field Upgrading aims to get a miniscule 2,500 b/d of processed Albertan bitumen from its demonstration plant to the high seas in mid-2019—but not in the usual “crude to tidewater” sense. Its CEO Neil Camarta is turning it into “CleanSeas” ultra-low-sulfur bunker fuel to power ships.
South African petrochemical giant Sasol plans a gas-to-liquids plant to process one billion cf/d of natural gas into 96,000 b/d of ultra-clean diesel, naphtha and LPG. It would cost about $5 billion and start up after 2020. The economics depend on the price differential between crude and natural gas.
North West Redwater Partnership
The $8.5 billion, 80,000 b/d Sturgeon refinery and upgrader—Canada’s first new refinery in three decades—is a partnership between NW and CNRL. It captures CO2 to send via the Alberta Carbon Trunk Line for injection into oil fields.
The Scotford 225,000 b/d upgrader takes bitumen from Shell Albian Sands north of Fort McMurray. Shell sells 100,000 b/d of synthetic crude to its adjacent Scotford refinery, and the rest goes a refinery in Sarnia, Ontario. The upgrader feeds the $1.35 billion Quest carbon capture and storage project.
Eastern refineries considering upgrade to handle Alberta bitumen
Suncor may add a 30,000 b/d coker, at a cost of more than $1 billion, to its 137,000 b/d refinery in Montreal to handle Albertan bitumen delivered via the planned Energy East pipeline. When Enbridge reversed its 300,000 b/d Line 9 crude pipeline between Sarnia and Montreal it allowed Suncor to switch feedstock from 90 percent imports from the Middle East and Africa to 100 percent North American crudes.
This 300,000 b/d Saint John Refinery is one of the ten largest refineries in North America and the largest in Canada. Lacking pipeline access, it imports most of its feedstock from African and Middle Eastern countries by tanker, or by rail from the U.S. It exports more than half its refined products to the U.S. Northeast. Irving Oil is exploring adding a coker for Albertan crude once the proposed Energy East pipeline connects to it.