Ian MacGregor is passionate about the potential to capture Alberta’s abundant man-made CO2 bounty and use it to extract millions of barrels of oil that would otherwise remain trapped in aging central Alberta oilfields.
But that passion comes with dollar signs attached to it, as the veteran oil and gas executive argues that the companies he heads, which are building an $8.5-billion refinery northeast of Edmonton and a $1.3-billion CO2 pipeline, are helping to pave the way for an economic future in Alberta built around transforming a negative into many positives.
MacGregor, chairman and chief executive officer of NW Refining and chair of the board of Enhance Energy, is no recent convert to the CO2 capture and storage (CCS) and enhanced oil recovery (EOR) processes. An engineer by training, MacGregor has long been a disciple of CCS and EOR with the use of injected CO2.
“I first became interested in the potential of man-made CO2 when a partner and I owned 11 per cent of the Weyburn [CO2 injection] project in Saskatchewan starting in 2001,” he says. “I could see the potential of CO2 and EOR then.”
He and his partner subsequently sold their company’s interest in that project, which has become part of the world’s most successful CO2 storage and EOR project.
The Weyburn-Midale project, which covers two legacy oil-producing fields in southeastern Saskatchewan, has been in existence since 2000. It has since been widely studied and continues to be monitored by international experts who have determined that CO2 can safely be stored in the reservoirs for hundreds of years.
About 8,500 tonnes/d of CO2 are captured from a coal gasification plant in North Dakota and moved via a 320-kilometre pipeline to the Weyburn and Midale oilfields, owned by Cenovus Energy and Apache Canada, respectively. This is the first time man-made sourced CO2 has been used for EOR.
At Weyburn and Midale, CO2 and water are injected deep underground with the aim of permanently burying the CO2 and increasing reservoir pressure and oil fluidity.
Meanwhile, the depleted Weyburn and Midale fields have become reliable oil producers, with production at Weyburn having increased by 16,000–28,000 bbls/d and Midale increasing by 2,300–5,800 bbls/d. Use of EOR is expected to enable the production of an additional 130 million barrels of oil from the fields, extending their life about 25 years. About 20 million tonnes of CO2 are expected to ultimately be stored.
It was the success of the Weyburn-Midale project that convinced MacGregor the approach could be duplicated in Alberta, especially if CO2 costs could be contained. (CO2 from North Dakota costs about $20 a tonne.)
MacGregor has no reservations about the technology his companies are deploying at the Sturgeon Refinery nor the CO2 pipeline and EOR technologies that will be used by Enhance. But the veteran entrepreneur also argues that in energy-intensive economies like Alberta and Saskatchewan there is no alternative but to find ways to capture CO2 and use it for EOR.
“We have all the tools in Alberta to manage our own destiny,” he says.
Alberta’s NDP government has chosen to shift away from coal-fired power and reliance on the CO2-capture technology Saskatchewan has chosen, relying instead on more renewables and gas-fired power (and a climate tax to help fund the transformation).
However, MacGregor argues that if the province’s oilsands, refining and petrochemical sectors are to continue growing and driving the economy—the NDP government has pledged its support for all three areas—it must rely on CO2 capture and EOR.
MacGregor and others spent 12 years developing a viable plan for creating a network that would upgrade and refine oilsands bitumen, capture CO2 while doing so, and build a pipeline that would transport that CO2 to otherwise-exhausted central Alberta oilfields, which would lead to the production of crude that would otherwise remain in the ground. Meanwhile, the CO2 would be sequestered for centuries.
He points to several recent studies from the International Energy Agency and others that have confirmed that CO2 can be safely sequestered. One of those studies confirmed that CO2 is being safely stored underground in the Weyburn-Midale area.
A study by the U.S. Department of Energy shows that the CO2 intensity of upgrading bitumen, rather than light crude, is 20 per cent greater.
“But if you do what we’re doing at the Sturgeon Refinery, you get a seven per cent improvement over the refining of light crude,” he says. “With that benefit, you can compete from an environmental standpoint with any refinery in the world.”
Construction on the refinery began in September 2013. NW Refining Inc. (NWR), the corporate entity that owns the refinery, is an equal partnership between Canadian Natural Resources Limited and Northwest Upgrading. The refinery, the first one in the world designed to capture CO2 as part of the refining process, is slated to go into operation in late 2017.
The Sturgeon Refinery was first planned at a time when Alberta was booming, with dozens of new oilsands projects proposed. Since oil prices collapsed most of those new oilsands plants are either on the back-burner or have been shelved.
However, MacGregor says he’s determined to build all three planned phases of the project, which would create needed economic activity.
“We could start [building the next phase] right now,” he says.
Most of the engineering for the next phase has been completed and storage tanks, access roads, electrical substations and other needed infrastructure are already in place.
The hard hit Alberta construction sector would welcome the thousands of jobs ongoing construction would lead to, he says.
NWR wants to eventually develop three phases of the refinery, with each phase refining 80,000 bbls/d of diluted bitumen and producing 81,500 bbls/d of product. Each phase would process the same volume of diluted bitumen and produce about 40,000 bbls/d of light diesel as well as heavy diesel, for which there is a ready market in western Canada. In addition, production would include diluent, which is used in the oilsands industry, and naphtha, which is used in the petrochemical industry.
He estimates there is a demand in Western Canada for 260,000 bbls/d of diesel while production is at about 150,000–175,000 bbls/d.
The bulk of the diesel from subsequent phases would be exported. Diesel demand from Asian, South American and other developing nations is at about 25 million bbls/d, with that forecast to grow to about 31 million bbls/d by 2030.
And, unlike oilsands bitumen, which is likely to have problems reaching markets in the future if no new pipelines are built from western Canada, “there are tankers moving diesel every day” from Canada’s West Coast.
He estimates that that would give the Sturgeon Refinery a $5/bbl cost advantage over transporting bitumen to the U.S. or the West Coast.
In addition, there’s the “clean fuel refinery” cost advantage, he says.
MacGregor assumes the Alberta government will eventually impose a carbon tax of $50/tonne. On that basis, he says that will give the refinery “another $5 a barrel advantage” over unrefined bitumen.
That $10/bbl advantage would allow the Sturgeon Refinery to compete favourably with unprocessed bitumen.
The key to the success of the Sturgeon Refinery is its unique design, he says. It will rely on gasification technology rather than the more conventional hydrocracking process. The gasification process converts organics or fossil fuel into hydrogen and CO2 using a controlled amount of oxygen and/or steam. Gasification technology is used widely in the industrial sector to generate electricity.
The advantage of the gasification approach is that the refinery won’t need to rely on natural gas as a source of hydrogen for the process. Instead of producing dry coke as a byproduct, which needs to be disposed of, Sturgeon will transform hot liquid bottom ends into hydrogen, oxygen and pure CO2.
“It produces 99.5 per cent pure CO2,” says MacGregor.
Most CO2 from conventional upgraders and refineries is mixed with nitrogen and other elements, rendering it unsuitable for EOR. But the CO2 from the Sturgeon Refinery can be used for EOR in central Alberta, unlocking millions of barrels of oil while allowing CO2 to be sequestered in the process.
That’s where Enhance Energy, the related company chaired by MacGregor, comes into the picture.
Enhance plans to build the 240-kilometre, 16-inch-diameter Alberta Carbon Trunk Line. The line will transport CO2 from the Redwater Refinery, from an Agrium fertilizer plant located near Redwater, Alta., to be used for EOR in central Alberta oil reservoirs.
Enhance has received a commitment of $495 million from the former Conservative Alberta government’s $2-billion carbon capture and sequestration fund towards the $1.3-billion cost of the project, as well as $63 million from Natural Resources Canada from the Clean Energy Fund and the EcoEnergy Technology Initiative.
MacGregor says work has already begun on the pipeline, with Enhance having purchased needed rights-of-way and legacy oilfields near Innisfail and Clive, Alta. Work on the first phase of the pipeline project (over time Enhance would build a larger-diameter pipeline) will start soon. Given that about half of the funding is in place, he is confident raising capital will not be a problem.
Enhance would access about 4,000 tonnes/d of CO2 from the Sturgeon Refinery and another 1,000 tonnes/d from Agrium. MacGregor sees the capacity eventually rising to beyond 10,000 tonnes/d of CO2.
“We’ve tried to route it through ‘Refinery Row’ near Edmonton,” he says. “There’s probably at least another 10,000 tonnes daily available from there. The plan is to have a CO2 distribution system in place [that other oil producers can utilize].”
In total, Enhance calculates there is about 150 million bbls/d of oil in place in the fields it has purchased, much of which it could recover by injecting CO2. It would inject about 15 million tonnes a year into the reservoirs.
“That’s equivalent to taking every car off of the road in Alberta,” he says. “We think [the refinery and CO2 pipeline combined] will be the world’s largest man-made CO2 project.”
Ultimately, Enhance thinks it can recover 70,000–80,000 bbls/d from the fields it has purchased, starting at about 22,000 bbls/d.
MacGregor says the concept can be expanded and lead to the capture and use of CO2 for EOR in much of Alberta.
“It’s like finding a new Leduc,” he says. “I think there is one billion barrels of oil recoverable using CO2, with the potential to sequester two billion tonnes of CO2. That’s equal to all of Alberta’s oilsands emissions for 25 years.”
He says the NDP government, which in the past has sounded somewhat lukewarm about CO2 capture, appears to have warmed to the entire concept, which was developed under the previous government in Alberta.
“I think they see the benefits of it,” he says, adding that Alberta “must solve its CO2 problem” to earn support for future pipeline projects and other energy industry expansion.
Provincial government support is critical if future phases of the refinery are to proceed. That’s because under the former Conservative government’s bitumen royalty-in-kind program, in which the government collects bitumen in lieu of royalties then sells it to encourage domestic upgrading-refining, the government will contribute up to 75 per cent of the diluted bitumen for the project.
Critics such as Ted Morton, a former finance minister under the Conservatives, who is now with the School of Public Policy at the University of Calgary, argue that the government could be on the hook for as much as $19 billion under that 30-year commitment with the partners in the refinery. (Canadian Natural Resources would provide the remaining 25 per cent of the bitumen.)
Morton says the government could lose as much as $26 billion in processing payments during the life of the contract through a “take or pay” agreement.
MacGregor challenges Morton’s calculations, arguing he miscalculated the processing fee, basing it on 50,000 bbls/d. In fact, he points out the refinery will refine over 80,000 bbls/d, which he says led to Morton miscalculating processing fees by 50 per cent.
He says the government would have actually earned a profit on the refinery if it was now in operation, even at today’s low oil prices.
After the refinery is in operation, MacGregor says debt payments will decline and profits will steadily rise.
Morton says his concern is that the Alberta Petroleum Marketing Commission, the government agency that markets Alberta crude, would be ultimately responsible for the debt payments.
“The risk isn’t to the bondholders but ultimately to the Alberta taxpayers,” he says.
He’s also concerned that there will be additional risk if cost overruns go beyond what is already being forecast. (The project has already ended up costing almost $3 billion more than first budgeted for.)
That additional exposure would likely be picked up by the taxpayers.
He says the concept of the Sturgeon Refinery and the linked CO2 pipeline is a good one.
“My concern is with the economics of the project and the fact that the risks are transferred to the Government of Alberta,” he says.
Morton says he’s also concerned that newer technologies may render the refinery somewhat old-fashioned, since partial bitumen upgrading technologies proposed by Imperial Oil Ltd., MEG Energy and others may mean full upgrading and refining isn’t necessary to get Alberta bitumen to market.
However, the Sturgeon Refinery and the related CO2 pipeline definitely have their fans, including the environmental group the Alberta-based Pembina Institute, not usually a strong supporter of fossil fuels.
Duncan Kenyon, director of unconventional oil and gas for Pembina, says MacGregor is right in arguing that CO2 capture and storage is a key to tackle the world’s climate change challenge.
“To get to the goal [of preventing the average global temperatures from rising by more than two degrees by 2050] we need to use CCS,” he says. “There’s no way we can save this planet without CCS.”
Kenyon says “it’s too bad” that CCS is not a preferred option of the NDP government, since a shift to the use of more renewables for power generation will not deal with the legacy CO2 production in an energy-intensive economy like Alberta’s (or like Saskatchewan’s).
Kenyon says certain industrial processes, such as cement production, will always be carbon-intensive, which is why finding ways to capture and sequester carbon is so vital.
Like this? Check out the latest issue of Oilweek.
An earlier version of this article (and its print edition) incorrectly stated that the Sturgeon Refinery project had received funding from Sustainable Technology Development Canada. We apologize for the error.