Is the U.S. a Friend or Foe?
The United States is often
portrayed in Canadian media as the bad boy on the block, Canada’s former client turned cutthroat competitor, forcing us to sell our landlocked crude for far less than it’s worth. In reality, for those big oil sands producers that operate refineries south of the border, the U.S. is the gift that keeps on giving. The shale boom has provided plenty of cheap pipeline condensate from the U.S., which is sold in Canada at far higher rates and recycled in dilbit. Furthermore, the decline in Alaskan and Californian heavy crude output has created more capacity for Canadian exports at U.S. refineries. Still there are some who argue for more oil refining right here in Canada, especially given the difficulties that oil sands pipeline companies are having in winning public support for their projects. Bruce Peachey is an instructor of petroleum engineering at the University of Alberta, and he’s been thinking a lot about those very things lately.
How many new upgraders have been planned and cancelled in Alberta recently, and why?
At the peak there were around 13 planned expansions and new upgraders. Only one, North West Redwater Partnership’s at Sturgeon, is going ahead. The economics of upgrading are driven by the high differential between heavy crude and synthetic crude; people get excited when the differential is $40 per barrel but cool off when it’s $5 per barrel. In the case of Husky and Syncrude’s upgraders, the government had to buy in to support them. In the case of the North West upgrader, the government guaranteed both a supply of bitumen and a price, so it couldn’t be taken elsewhere.
Companies like Paramount Resources that don’t have refineries in the U.S. are very interested in upgraders so they don’t have to buy diluent from their competitors. U.S. refineries that can handle Alberta’s bitumen recycle diluent, buying it at a discount when it arrives as diluted bitumen and sending it back to Canada at a premium to the oil sands operators.
The Kearl project didn’t build an upgrader because Exxon has its own supply of diluent and refineries in Illinois. Shell’s Carmon Creek needed the Northern Gateway pipeline to the B.C. coast to be viable. Northern Gateway would ship dilbit to the coast for Shell’s Californian refineries that can refine heavy crudes, and have a return pipeline bringing back diluent to Alberta. Right now, Shell’s Scotford upgrader in Alberta’s Industrial Heartland is processing Shell’s own mined bitumen from the Albian Sands project. It has a nice steady supply, so it won’t likely expand to take Carmon Creek crude until the Albian mining production winds down. The Trans Mountain expansion is a one-way pipeline, so there’s no recycling of diluent.
Diluent costs only $3 to $5 per barrel to recycle. Companies without U.S. refineries might buy diluent at 10 percent over WTI in the U.S. and sells it as part of the dilbit volume at 30 percent below WTI in Alberta. That’s why companies like Paramount want to send it by rail where only seven percent is diluent rather than 30 percent in a pipeline. From a Canadian macroeconomic perspective, as diluent is worth more than the oil we’re selling, the balance of trade takes a hit. Partial upgrading means the producer doesn’t have to buy diluent. But this depends on upgrading process. Imperial has looked at visbreaking. This upgrades bitumen enough to go by pipeline, but it still doesn`t look like natural crude. Even Syncrude is sold at a discount to WTI and the further you get away from natural crude the heavier the penalty you pay.
Do you see any more carbon-capture upgraders popping up in Alberta, seeing as the government has been non-committal about the technology?
Jurisdictions want the jobs from upgrading but not the emissions. CNRL has conventional maturing oil fields south of Edmonton along the Alberta Carbon Trunk Line, which have wells that were abandoned after primary production finished. CNRL is probably lobbying the government to support carbon capture in future upgraders for CO2 injection—if someone buys an oil pool after its abandoned someone knows something. ACTL has to get its CO2 from somewhere and Agrium’s fertilizer plant and North West Partnership’s refinery won’t provide enough for many projects at a time.
If KXL goes ahead, how does the decision impact the Trans Mountain expansion and Energy East projects?
It could impact Energy East, as both can get crude to the same Atlantic markets— KXL will supply the U.S. Gulf Coast, which can get it to other Atlantic markets by tanker. KXL doesn’t affect California as much. It will get it closer to a rail line to get it to PADD 5 in California, but it doesn`t go directly. Mexico might increase output in five to 10 years, if they can bring in foreign investment, but meanwhile it’s dropping like a rock. However, California is still the main market we’re trying to get to as there are upgraders there already. Ten percent of U.S. oil production used to come from heavy oil from California but this feedstock has declined by about 500,000 b/d since 1985—they’ve been injecting steam into those fields since 1940. Alaska production, including some heavy oil, has also declined by about 1.3 million b/d so this loss of U.S. West Coast supplies has created surplus capacity in California that is now open to other heavy oil supplies. Venezuela is building pipelines through Ecuador to get to the Pacific, even though their total production has declined, and Colombia has also built pipelines to get heavy oil to Pacific markets, with California being the closest. Trans Mountain would also likely be used to supply any remaining California demand, in competition with Venezuela, Colombia, Mexico and Peru, before it would supply much to more distant Asian markets.
Is the Canadian Oil Sands Innvoation Alliance’s goal of taking carbon out of the barrel by 2040 realistic?
CO2 is very stable. It’s hard to turn it into something useful without using a lot of energy and there’s a limited market for graphite etc., which has to compete on cost against natural sources. Technically processes can be developed but they are extremely unlikely to be economically viable by 2040.
Bruce Peachey, Instructor of petroleum engineering, University of Alberta