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Partial Credit: Four Alberta companies that are upgrading bitumen differently

Partial upgrading aims to reduce the thickness of bitumen

Apr 21, 2014

by Darren Campbell

$125 million will be spent on pilot plant near Fort Saskatchewan

There has long been a debate in Alberta about the possibility of upgrading the gooey bitumen produced from the oil sands into light synthetic oil in this province, but the economic case has been difficult to make. And it’s only getting more so: Upgraders make money when the price spread between unprocessed bitumen­ and the synthetic crude they produce – known as the differential in the industry – is wide, at least US$30. But growing light oil production in the U.S. is depressing prices for this crude. Meanwhile, more refiners are now able to handle the heavy stuff, driving up the price of this product. This has resulted in a narrowing in the light-heavy differential and has reduced the profits that can be made from upgrading.

In fact, U.S.-based consultancy IHS CERA forecast the light-heavy differential to average US$29 from 2016 to 2030. According to a 2013 report the firm released that looked at the economics of upgrading, that’s not enough to give proponents even a 10 per cent return on their investment. IHS CERA concluded any return on investment below that benchmark likely wouldn’t be large enough to convince companies to build new upgraders.

Enter partial upgrading, which doesn’t aim to process bitumen into synthetic oil. Instead, the goal is to reduce the thickness of the bitumen so it doesn’t need to be blended with diluent – an expensive, super-light oil used to thin the bitumen so it can flow through pipelines. Because partial upgrading does less processing than full upgrading, it doesn’t cost as much – less infrastructure is required to treat the bitumen. That could make partial upgrading attractive to oil sands producers. So does the fact it’s well suited to being used alongside in situ production methods like steam-assisted gravity drainage,­ which is how 80 per cent of Alberta’s remaining 169 billion barrels of remaining oil sands reserves are expected to be extracted.

Here are four companies trying to find a way to make it work.

Fractal Systems

Technology: Jetshear process
Pilot project capacity: 1,000 bpd
Capital cost: Not available

When it comes to partially upgrading bitumen, Fractal Systems likes to keep things simple. “We are not nearly as heavy a touch as the other field upgrading technologies,” says president and CEO Joe Gasca. “Therefore, we are simpler and a lot cheaper. There’s a lot less cost associated with our technology.”

Fractal’s plan is to heat bitumen to temperatures of 350 to 400 Celsius. The fluid is then pushed through small nozzles that create tiny bubbles, which eventually collapse. When they do, they create heat and pressure at the ­molecular level that reduces the thickness of the bitumen, allowing it to be transported through pipelines with substantially less diluent.

“Our target is to get about a 40 to 45 per cent reduction in the diluent requirements for transportation of heavy oil,” Gasca says. “It saves the producer about $4 per barrel in costs associated in transporting it to market.”

In May of 2013, the privately-owned Quebec-based company announced it had signed an agreement with an unnamed “large” Canadian oil sands producer to test the Jetshear process at a demonstration plant located in the Provost area of central Alberta. Gasca expected the plant to be operating by April. He wouldn’t say how much the project will cost, but after six months of testing he hopes the partners will be in a position to make a decision on whether to build a commercial-scale facility or not.

ETX Systems

Technology: IYQ process
Pilot project capacity: 20,000 bpd
Capital cost: $200 million

After several years of scuffling along trying to advance a 1,000 bpd pilot project for its IYQ partial upgrading process, ETX Systems finally got some good news late in 2013. Last November, it struck a partnership with a midstream company and a senior oil sands producer to work on a feasibility study for the pilot. “We really couldn’t progress any further without support from industry, so I’m cautiously optimistic,” says ETX Systems CEO Gerard Monaghan.

The size of the project has increased substantially. Monaghan says he can’t name the two companies ETX is working with, but the plant will have a capacity to process approximately 20,000 bpd of bitumen. “It’s very hard to show any economics with a 1,000 bpd pilot plant, and because it’s hard to show economics, it was very hard to get industry support,” Monaghan says.


Now that the Calgary-based company is armed with that support, a feasibility study is in the works. In layperson’s terms, the IYQ process features a reactor in which coke is heated. As the coke goes through the reactor, bitumen is sprayed on it and turns into vapour. The vapour is recovered as a lighter oil. Meanwhile, the leftover solids are burned off to produce steam.

Monaghan hopes to have the feasibility study completed by June and will then work on designing the pilot plant if his partners like the results. At that point, ETX wants to have the information in hand that will allow them to raise the capital needed to build the project. “This year should be transformative, for sure,” Monaghan says.

Ivanhoe Energy

Technology: HTL process
Pilot project capacity: None
Capital cost: Not available

Ivanhoe Energy’s Joe Kuhach doesn’t lack confidence when asked if the company’s Heavy-to-Light (HTL) partial upgrading process works. “From a technical standpoint we are ready to go,” says Ivanhoe’s senior vice-president, upstream technology and integration. “But I think people have been reluctant to be the first one out of the gate to implement it commercially.”

Kuhach says that reluctance will subside because Ivanhoe’s HTL process promises some big benefits. Under the HTL process, bitumen is injected into the bottom of a reactor tower where it meets a tornado of hot sand. The heavy oil molecules are then subjected to intense heat and pressure (called “cracking” in the industry), turned into vapour form and a thin film of coke – a carbon-heavy solid produced during the cracking – is deposited on the sand grains. The vapors are separated from the sand, drawn off and cooled into a lighter upgraded oil product. As for the coke-covered sand, it is burned off, creating energy that can be used to make steam to extract more bitumen.

If the Calgary-based company can show it can upgrade bitumen economically at commercial scales using HTL, Ivanhoe would not only use it to upgrade bitumen on property it owns in Ecuador and northeast of Fort McMurray, but it would offer to upgrade other producer’s bitumen for a fee. That could provide a valuable revenue stream for a company that reported losses of $33.5 million during the first nine months of 2013.

The company has yet to start a large pilot project using its HTL process. Instead, Ivanhoe continues to upgrade heavy oil using the HTL process at a test facility it owns in San Antonio, Texas. “We’re a big believer in the technology,” Kuhach says. “Typically, heavy oil is the marginal barrel. If you do more things like partial upgrading to eke out more value out of that barrel it puts you in a much better position to monetize that heavy oil.”

MEG Energy

Technology: Hi-Q process
Pilot project capacity: 3,000 bpd
Capital cost: $125 million

The Calgary-based heavy oil company, which produced an average of 35,371 barrels per day in 2013, is arguably the furthest down the ­commercialization path in Alberta. In ­December of 2013, MEG announced it was spending $125 million in 2014 to build a pilot plant near Fort Saskatchewan that will process 1,500 bpd of diluted bitumen using its Hi-Q partial upgrading process. The company plans to have the pilot plant operating in 2015.

Under the Hi-Q process, bitumen is heated at high temperatures, which produces some light oil that is collected and a heavy waste stream that is sent to what’s known as a de-asphalter. Here the waste is processed to produce a solid called asphaltenes (which must be disposed of) and lighter liquids that are combined with oil collected earlier in the process to produce a crude that doesn’t need as much diluent to be transported through pipelines.

Considering MEG’s diluent costs were $601.2 million in 2013 – up from $496.6 million in 2012 – reducing the need for it would save the company gobs of cash. “If you look at the cost of diluent and the long-term view of diluent supplies, to take that out of the per-barrel cost shows some tremendous upside,” says Brad Bellows, MEG’s director of external communications.

Bellows says the company is still working out its project schedule, but expects const­ruction, commissioning and pre-commercial operation will take three years “to really validate and play with the technology, and generate the engineering and economic data to support further development.”


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