he carbon comes from sand, and to sand it shall return.
Canada's oilsands are unique because the sand granules are surrounded by a skin of water, making the oil outside that layer that much easier to procure. The oil in those sands was first identified in the late 1700s, when it was used by First Nations natives in a mix with pine pitch on canoes. As Mike Ekelund, deputy minister of the Alberta energy department's strategic initiatives division, explains, wells were drilled as early as 1900, but were not feasible for development. Then in the 1920s, a researcher named Carl Clark found a way to take the oil off the sand. From that time until the 1970s, explains Ekelund, the recognized resource went from 4 billion barrels to 175 billion barrels.
Putting the carbon back into the ground is more challenging. But as claims against the oilsands' carbon footprint swell, one carbon capture project after another springs up to counter them.
Bob Savage, acting director, regulatory and mitigation, of the climate change secretariat of the province's environmental department, points out that Alberta has 10 percent of Canada's population but 40 percent of its GHG emissions. The largest source is coal-fired power plants, followed by upstream oil and gas activity and then oilsands extraction and processing. He says 70 percent of the province's emissions come from 100 very large facilities.
"These are large, but state of the art," he says, then notes the gap between facility investment time frames for refineries or cement plants, and the pace of technological development. "When you build a facility that costs several billion dollars, you're locking yourself into a technology emissions performance window for a significant period of time," he explains. "Typically they depreciate their capital over 20- and 30-year cycles. So the challenge for us is how we shorten those cycles, and get new technology that will address the emissions."
It figures that some of the same companies extracting all that carbon are also pursuing such innovative new technology designed to capture it and put it back.
One of them is Shell, which on Nov. 1 earned the world's first certificate of fitness for safe CO2 storage from Norway-based international risk firm Det Norske Veritas (DNV) for its Quest carbon capture storage (CCS) project. Quest will capture and permanently store underground more than 1 million metric tons of CO2 per year from Shell's recently expanded Scotford Upgrader, located near Fort Saskatchewan, Alberta. (Upgrading is the process of cracking large hydrocarbon molecules to increase the hydrogen-to-carbon ratio.)
The upgrader, which just completed a 100,000 barrel-per-day expansion last summer to reach capacity of 255,000 bpd, processes heavy oil from the Athabasca oilsands. Quest is the first application of CCS technology for an upgrader operation.
"The DNV certification is important because it provides third-party validation that our project meets rigorous storage standards," said Ian Silk, Shell's Quest venture manager. "It also helps to confirm the capability and capacity of the Basal Cambrian Sands storage formation that we will be injecting into. Proving up this saline formation for storage, which underlies a good portion of the province of Alberta, is imperative to enable the future CCS projects that will be required to help the government achieve its targeted CO2 reductions."
In June Shell announced it had signed agreements with the governments of Alberta and Canada to secure $865 million in funding for Quest. "By continuing to move CCS technology forward, Alberta is demonstrating its ongoing leadership in realizing the commercial-scale deployment of this technology and greening our energy production," said Alberta Premier Ed Stelmach.
The Alberta government will invest $745 million in Quest from a $2-billion Carbon Capture and Storage Fund, while the Canadian government is contributing $120 million from its $795-million Clean Energy Fund. Shell signed Letters of Intent for Quest funding with provincial and federal governments in October 2009. The funding is phased over 15 years (including the development, construction and 10 years of operations of the Project) and is tied to Shell achieving established performance targets. It also includes extensive knowledge-sharing commitments with both levels of government to benefit future CO2 storage projects. Alberta aspires to 70 percent emissions reduction by 2050.
Shell will make a final investment decision in 2012, subject to the outcome of the regulatory process and economic feasibility. But all is proceeding smoothly thus far. With CO2 injection planned for 2015, Quest would join a handful of CCS projects around the world that are injecting CO2 at a commercial scale. Quest is being advanced on behalf of the AOSP, a joint venture among Shell Canada (60 percent), Chevron Canada Limited (20 percent) and Marathon Oil Canada Corp. (20 percent).
The Global CCS Institute reported that at the end of 2010, 234 active or planned CCS projects have been identified across a wide range of technologies, project types and sectors. Shell itself has other ongoing projects in partnership with governments and other companies, including an advanced CO2 test center in Mongstad, Norway; a project connected to the Gorgon LNG project off the coast of Australia; a project in partnership with ScottishPower and National Grid for a project at the Longannet power station in Fife, Scotland; and other projects in Algeria and in the Norwegian North Sea. Various other projects are under way in the U.S. and abroad from such companies as Linde Group, RWE, Southern Company and BASF.
Some CCS projects are right next door, owing to the apt geology of western Canada. Since 2000, a Shell-backed project has been operating in the Weyburn oilfield in Saskatchewan, where CO2 captured and piped 204 miles (328 km.) from a coal gasification plant near Beulah, N.D., is injected for enhanced oil recovery. And the government of Saskatchewan in April 2011 approved construction of the $1.24-billion Boundary Dam Integrated Carbon Capture and Storage Demonstration Project at SaskPower's Boundary Dam Power Station near Estevan, Sask. The project, which is receiving $240 million from the Canadian government, is expected to reduce greenhouse gas (GHG) emissions by 1 million metric tons per year, while also using the captured CO2 for enhanced oil recovery.
In Alberta overall, there are 58 sites leased for acid gas disposal, for storage of CO2 and hydrogen sulfide.
Best Way Forward
According to the International Energy Agency (IEA), CCS is the only technology available to mitigate GHG emissions from large-scale fossil fuel usage, particularly power generation. The mitigation potential through CCS could account for about one-fifth of the total mitigation effort needed by 2050 if projects are started quickly. "The IEA has also said that without CCS the cost of reducing emissions will be 70 percent higher," says a Shell document.
In a briefing on the project delivered in early November at the Scotford upgrader, Ian Silk said the funds from the provincial and national governments will cover 60 percent of the project costs. And while the funding applies to just 10 years of operating costs, the project is being designed to handle 1.2 million metric tons per year for 25 years.
"We're looking to store something like 27 million [metric] tons," he said. "We believe CCS is the most appropriate mitigation … This technology is our abatement strategy for maybe 50 percent of our emissions around the world."
The CO2 will travel through a 50-mile (80-km.) pipeline to land just north of Thorhild, Alberta. Silk said the routing's public consultation phase resulted in more than 30 reroutes due to landowner requests. But a bigger challenge was where to drill under the Fort Saskatchewan River: "We struggled to find an area that had competent bedrock, which took us to the east," he said.
As for the final resting place of that CO2, Silk said no other wells are drilled within 10 km. (6.2 miles) of the site. Quest will drill between three and eight of its own wells, going down 2 km. (nearly a mile and a quarter) to the Basal Cambrian Sands, known for their high permeability and porosity, and now filled with saline. Dense CO2 will be placed in the formation, moving the water outwards. Formation stability was the crucial attribute.
"We need to be able to assure it stays there," said Silk. "It's really seismically quiet. It's been that way for at least 500 million years. It's topped by a shale mudstone, and backed by two further salt seals. We've drilled our first well — almost one well alone is enough. But to be prudent we'll drill at least three, with two more by next summer. We're going through the final regulatory approval process, and we expect timing of approvals to be March 2012."
Among the items still being worked out are the precise terms of the site's eventual closure. Silk said the company is liable, and that even though the risk of a leak decreases dramatically once injection ceases, Shell will pay into a fund that would cover the expense of that unlikely event.
"We're regulated to inject at a
The formation is approximately 1,000 m. deeper than the hydrocarbon deposits in the area, and some 1,800 m. (more than a mile) below groundwater. As Shell puts it, "The trapping mechanisms involved in the deep geological formations are the same ones that have stored oil and gas for millions of years."
Silk said the company leases the land from the Crown, which still owns the space between those particles and mineral rights, said Alberta government spokesman David Sands.
'Important to Start'
While life-cycle GHGs from the oilsands are slightly higher than those from oil production in Venezuela and Nigeria, the province's Bob Savage says, "Canada represents 2 percent of global GHG emissions. Oilsands are 0.15 percent of global emissions." Moreover, "the oilsands' carbon intensity is decreasing, while the carbon intensity of conventional oil is increasing."
That said, business as usual means growing emissions, Savage explains. "The sheer magnitude of production and economic growth is driving that top line. It's important to start: The longer we wait, the more challenging and expensive the mitigation strategies will be. It's important to send a price signal to companies to make long-term investments."
Successive provincial regulations over the past decade included mandatory GHG reporting in 2004, followed by the establishment of targets in 2007 that require all industrial facilities to improve their emissions by 12 percent.
"The regulation provides incentives to go beyond the target," says Savage. "If they can't get to the target, then they owe us something." That can come in the form of an offset, or a purchase of reductions achieved by another party.
And CCS literally offers the way forward, and the way out from under the metaphorical dome of GHGs hovering over the province.
"The very reason Alberta has all these hydrocarbons under it offers storage opportunities," Savage says, saying the storage capacity is in the realm of 4,000 to 6,000 gigatons, or "enough to take all Canada emissions for 300 to 500 years. The challenge is the cost."
But he reiterates: You have to start somewhere.
"Climate change policy is littered with aspirational targets without a roadmap," he says. "Our approach is very much learning by doing. You need to start, get the systems up and running, and be prepared to adjust your targets and policies."
Alberta charges $15 per ton for carbon, making it the first jurisdiction to have a broad-spectrum regulatory system with carbon pricing, says Savage. Over time, that charge will be higher. "That's how we're going to drive down growth in emissions over time."
Through 2010 and four regulatory cycles, the program has helped avoid 23.8 million metric tons of emissions, and has seen $257 million go into the climate change and emissions management fund and $120 million invested in clean energy projects.
Savage says the not-for-profit managing the climate change fund welcomed 240 applicants from around the world vying for 50-percent funding for their clean energy projects. In exchange, the province only asks that the project's solution be applicable to Alberta industry and made available at market rates. The province takes no IP stake.
As of March 2011, nearly $133 million in funding had been made available for clean tech initiatives in the previous 16 months, he says, and the program is leveraging about $4 for every $1 invested in the fund.
"We expect more than $1 billion worth of projects by the end of next year," he says. "This is job creation. It adds to GDP. It advances technology, and enhances our competitiveness."