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Can technology enable Alberta to reach its climate-change targets?
Unless the technology to produce Alberta’s oilsands goes through a transformative change, and quickly, the carbon-intensive sector is on a direct collision course with provincial and national greenhouse gas (GHG) emissions reductions goals. With oilsands production set to double in a decade and triple a decade after that, the nation can expect the sector’s CO2 emissions to follow a similar trajectory if current extraction technologies continue to be put in the ground, all but guaranteeing emissions will exceed Alberta’s target to peak in 2020 and begin a steady decline thereafter, and Canada’s international commitment to trim them 17 per cent from 2005 levels by the same year.
Even if previous greenhouse gas intensity gains per barrel of production—which have stabilized or even declined in recent years—were to improve to previous levels, booming production increases will more than wipe out those gains. The roughly 15 per cent per decade emission intensity improvements seen in the past two decades would do little to slow soaring emissions increases if production grows 100 and 200 per cent in the next two decades as predicted.
And Alberta’s big hope, that carbon capture and storage (CCS) would carry most of the load in stabilizing and eventually reducing emissions (accounting for 70 per cent of reduction by 2050), has stalled since its emissions targets were put in place in 2008. One of four projects slated to jumpstart CCS development, to have captured CO2 from a coal-powered power plant for use in enhanced oil recovery, was cancelled earlier this year despite hundreds of millions offered in government subsidies.
With two of the other three projects—Royal Dutch Shell plc’s Quest project at its Edmonton-area upgrader (with $865 million in subsidies), and Northwest Upgrading and Progress Energy’s carbon capture and enhanced oil recovery plan ($558 million in subsidies)—having only recently been given the go-ahead after years of study, and with no other major projects on the horizon, there is little chance the province will meet its goal to limit emissions growth to 50 megatonnes below business-as-usual by 2020.
“Unfortunately, Alberta’s climate plan states that 30 megatonnes of annual reductions will be derived by CCS by 2020—the equivalent of 25 Quest-type projects in the next eight years. Clearly, this is a fiction,” Simon Dyer, policy director at the Pembina Institute, told members of the U.S. Congress in hearings of the Subcommittee on Energy and Power last March.
Or, as he put it to New Technology Magazine, “It’s fashionable to talk about projects being CCS-ready, but that’s like saying my garage is Porsche-ready.” On its present course, he says the province will fall short of its 2020 target by over two-thirds. In its report, Responsible Action? An assessment of Alberta’s greenhouse gas policies, the Pembina Institute estimates current provincial policies will see reductions of “no more than 14 megatonnes relative to business- as-usual, and possibly by less than 10 megatonnes.”
Moreover, on its present course, growth in the oilsands GHG emissions will likely prevent Canada from meeting its stated international obligation to trim emissions by 2020, short of all other provinces making “implausible efforts to compensate” for Alberta’s growing emissions, says the Pembina.
Other studies point to similar trends. In its study, Oil Sands Technology; Past, Present, and Future, IHS CERA found that even in its rapid technical innovation scenario with “relatively moderate oilsands growth,” that a 30 per cent improvement in emissions intensity to 2030 would still see a doubling of absolute GHG emissions in that period, far in excess of the Alberta targets. Given the lag time between a successful pilot and broad commercial deployment, it says, potentially revolutionary technologies—such as electric heating, solvents, in situ combustion and underground tunnels—are not likely to start having an impact before 2025-30.
Ongoing efficiency improvements and new hybrid steam- solvent technologies have the potential to trim in situ production well-to-retail pump emissions five to 20 per cent, while the more mature mining operations could see GHG intensity improvements of five per cent, it found.
The study, released in 2011, said CCS applied at upgraders, the cheapest point of CO2 capture available in the oilsands (estimated to cost $75–$155 per tonne, compared to $175–$230 per tonne from in situ operations), would result in only an 11–14 per cent GHG intensity improvement (well-to-retail pump) in part due to increased energy use. In a forecast that assumes aggressive oilsands technology improvements, combined with strong government policies to limit emissions, such as a $100-per-tonne carbon tax by 2020 and a North America–wide cap-and-trade system, it said industry-wide GHG reductions of 10 per cent from business-as-usual would result by 2035.
“I would agree that the province was very optimistic that [CCS] would take off, but in fairness they had expected much higher natural gas prices and that carbon prices would be higher,” says Eddy Isaacs, chief executive officer of Alberta Innovates–Energy and Environment Solutions, who is responsible for Alberta’s strategic directions and investments in energy technologies, renewable and emerging resources, environmental management and water resources.
“And also, the cost of the technology is such that you really need to reduce the cost before it will take off,” Isaacs says. “So my organization, actually, we are spending a fair bit of time and effort on looking at next generation capture technologies for that very reason.” The organization has also shifted its focus to using CO2 for enhanced oil recovery (EOR) in hopes of providing a revenue stream to go along with sequestration.
Despite the seemingly long odds, the province still stands firm on its target to see absolute emissions begin a long and steady decline from 2020 to 2050, says Ogho Ikhalo, spokeswoman for Alberta Environment and Sustainable Resource Development. “The goals we have under our 2008 strategy are still very much in place,” she says. “We remain firmly committed to doing our fair share to reduce emissions by working with the federal government to meet their targets and to meet our targets.”
Ikhalo does concede that the province has already missed its 2010 emissions target, to reduce annual emissions by 20 megatonnes below business-as-usual, and is now in the midst of re-evaluating its options, though “there is no timeline on that” review, she says. “We are in the early stages of revisiting our strategy.”
Without CCS to backstop its 2020 target, and in the absence of a mechanism to purchase carbon credits from elsewhere, Alberta appears to be left with only three viable options: to rapidly develop and deploy significantly lower-emissions production technologies; to restrict future oilsands production or coal-fired power supply; or to abandon its stated GHG targets and risk incurring the international criticism and erosion of its social licence to operate that that could bring.
The Pembina Institute contends both Alberta and Canada could meet not only their own targets, but more stringent “science-based targets” without damaging the economy, though that may require restriction on production growth. For example, “A modelling study conducted by the same consultants as used by Alberta Environment has shown that Alberta could continue to have Canada’s fastest-growing provincial economy with a carbon price reaching $200 per tonne by 2020 and mandatory CCS for all new natural gas processors, coal-fired power plants and oilsands operations.”
While the technology option may be the most palatable, how realistic is it? Various studies examining future technology advancements, such as the IHS CERA study, generally point to only 20–30 per cent energy and emissions reductions potential in the short to medium term (evolutionary technology improvements), with much larger gains possible further out if some of the over-the-horizon advances are proven out (revolutionary technologies).
Part of the challenge in reducing emissions is the need to overcome declining reserves quality. As producers move from the best, easiest-to-reach deposits that were the first to be developed to more marginal reservoirs, more energy is required to produce them, resulting in higher emissions. Another major challenge is the increasing proportion of extraction using in situ methods such as steam assisted gravity drainage (SAGD), which are about 2.5 times as GHG-intensive compared to mining. Some 80 per cent of the oilsands is only accessible using in situ production, which is poised to overtake mining as the dominant technique.
As of 2010, the most recent year statistics are available from the province, oilsands operations had overtaken power generation—predominantly from coal combustion—at 38 per cent of Alberta’s GHG emissions (conventional oil and gas extraction was another seven per cent and pipeline transportation a further two per cent). While oilsands mining and upgrading accounted for 23 per cent of the province’s emissions compared to 15 per cent for in situ extraction, the latter is growing much more rapidly, more than doubling from 2004 to 2010, compared to a jump of about 33 per cent in mining and upgrading emissions over the six-year period.
Not only is in situ production more emissions-intensive, but it presents fewer opportunities for the capture and reuse or sequestration of CO2, since its emissions are more dilute (typically eight to 10 per cent CO2 concentration in steam generator flue gas streams) and originate at operations in a region lacking geological storage opportunities. On the other hand, as a less mature technology than mining, most experts say it offers more opportunity for technological advances to improve efficiencies.
For in situ production, “the big gains are in reducing steam use—that really reduces greenhouse gas emissions,” says Isaacs, who notes the use of solvents with the steam used in both cyclic steam stimulation (CSS) and SAGD recovery methods has recently moved beyond the pilot stage. Both Imperial Oil Limited at Cold Lake (where liquid addition to steam for enhanced recovery, or LASER, is applied in later life cycles of CSS) and Cenovus Energy Inc. at its proposed Narrows Lake field consider the technology commercial. Many other companies are piloting a variety of hybrid steam and solvent techniques, which Isaacs says can increase efficiencies up to 30 per cent per barrel of bitumen produced.
By adding solvents, “you need less steam, but you are also working at a slightly lower temperature,” and often bolstering overall recovery, says Isaacs, himself the co-inventor of one variation of solvent-assist—expanded-solvent SAGD.
While solvents work well to mobilize the semi-solid bitumen in situ, they can present a challenge to recover, an important factor considering the high cost of solvents. Widespread use of solvents would only drive the cost up further.
Still, Isaacs says “they are the best near-term options. Longer term, potentially, we are looking at electrical heating.” Both E-T Energy Ltd. and the ESEIEH (Effective Solvent Extraction Incorporating Electromagnetic Heating) consortium are advancing in this area, he says, and have received funding from the Climate Change and Emissions Management Corporation (CCEMC) of almost $7 million and $16 million respectively. (CCEMC supports projects to reduce GHG emissions using funds the province collects from facilities that emit more than 100,000 tonnes of GHG per year.)
“But those technologies I would say are much further away from commercialization—they are still in the early stage of piloting,” says Isaacs. “They are probably 10 years off.”
Even further out, Isaacs points to in situ combustion, which is being piloted by a couple of companies, borehole mining and in situ upgrading, a concept under study at the University of Calgary. “Those are quite a ways off,” he says, noting that in a climate of cheap natural gas, there is less incentive to quickly get such technologies into the field.
Steve Larter, professor in the department of geoscience, University of Calgary, and Canada Research Chair in Petroleum Geology, says there are many avenues to significantly reducing oilsands emissions, and is a proponent of setting much higher goals and providing the funding to back them up. He looks at the oilsands as an industry in its very early stages that has done little thus far to investigate more radical technologies that could transform extraction.
“We need a much bigger sustained level of investment in developing new technologies. Our basic problem has been long-term lack of investment in alternatives to things like SAGD and CSS. If you look at the in situ [production], you have only got two technologies that date from the early 1980s, that have been refined and have produced a commercial oil industry, but there aren’t a lot of good alternates.”
In the near term, he says simply having a better understanding of the resource can be of tremendous advantage. “The first quick win I think is much better use of reservoir characterization data and customization of well placements and operating strategies to the geological realities of the reservoirs. If you look at [regulatory] applications, for example, they all have almost identical well configurations, well spacings and operating strategies.
`“But the realities are, these are extremely complex reservoirs geologically, extremely complex in terms of viscosity, profiles and fluid properties and so on, and so it is extremely unlikely that cookie-cutter SAGD operations are going to operate uniformly across the very wide range of reservoirs in the oilsands. Just as we all have different shoe sizes, each reservoir needs a different well placement and operating strategy, even between well pairs.
“So I think that is where a quick win in emissions reductions could come, just from more sensible application of all the brilliant reservoir characterization work that goes on in downtown Calgary. We have got some of the top reservoir characterization groups in the world, but the final engineered recovery processes seem to be very uniform, which is surprising.”
Longer term, in order to make real progress Larter says the industry needs to throw the door open to a wide range of technology innovations and get them in the field for trials. Even though most will likely fail, some disruptive technologies are likely to rise to the top.
“In terms of longer-term game-changing technologies, part of our problem is there have been woefully few pilots of alternate technologies. For example, in situ combustion; there has only really been one major pilot of that in the time I have been in Calgary, about nine years. There are a few electrical heating types of technologies being tested but again, relatively small and very few pilots. We need dozens of these to pick the ones that are actually going to change the game.”
One over-the-horizon technology Larter is researching is biological gasification of heavy oil and bitumen. “The natural process that makes heavy oil and bitumen is a biological one that produces natural gas as a by-product, and we looked extensively at trying to accelerate that to commercial rates so you don’t recover energy as bitumen, you recover energy as methane. That’s at the stage where we could run pilots, but there is no business interest whatsoever in that because the current market is high-priced liquid hydrocarbons, low-priced natural gas.”
Taking the idea one step further, Larter says biological conversion could be used to transform the natural gas to more valuable liquid fuels. Organisms called methanotrophs that consume methane “can potentially be tweaked to produce liquid transportation fuels, either hydrocarbons or methanol. Both those types of research are going on at the University of Calgary—we’ve been mainly concentrating on looking at turning oil into natural gas at commercial rates and another group, in biology, is looking at converting natural gas into liquids, either hydrocarbons or methanol. So that could be another route.”
In fact, Larter says the industry needs nothing short of “a revolution in innovation and R&D [research and development] investment, if we are going to maintain Canada’s hydrocarbon-based economy and cut emissions. For me, at the moment, the Canadian energy industry has got its one egg in one basket, and what we need, I think, is Manhattan Project–levels of investment.
“I think there are many possible game- changing technologies that maintain a business case and cut emissions. And the target for emissions should be zero. We shouldn’t just be trying to get our emissions to other conventional fuel levels, we should be going for zero—that’s what superpowers do, they aim for the moon and they get there.”
Petroleum Technology Alliance Canada (PTAC), which launched a Clean Bitumen Technology Action Plan in 2009, is also actively encouraging low-emission technologies.
“We have a number of projects under that initiative,” says PTAC president Soheil Asgarpour. They range from innovative application of electricity for the oilsands to creating an artificial reservoir to investigating the use of nuclear power.
While not specifically aimed at reducing emissions, Asgarpour says a project to create value from asphaltenes—the fraction of the bitumen that is currently converted to low-value petroleum coke or syngas—could lead indirectly to energy efficiencies. New technologies are being sought that could transform asphaltenes into high economic–value products, such as transportation fuels or petrochemicals, while reducing the environmental impact of current approaches.
“If you break the molecular structure of the ashphaltenes, then this business of requiring diluent [to allow bitumen to be pipelined] would go away. There clearly is going to be a reduction related to energy consumption as well, though that’s not the main focus—the main focus is value-added opportunities.”
He says the artificial reservoir under development could allow for the evaluation of heavy oil and bitumen recovery technologies that may offer substantially better performance than existing models, reduce costs and accelerate the pace of technology development. “It provides a way that we could test different concepts, be they SAGD or similar concepts, in a huge, large lab environment, even larger than a room-sized environment, where it is under reservoir pressure and reservoir temperature.”
The project’s scope includes examining the current state-of-the-art, for-laboratory-scale reservoir models and how these models accommodate the mechanisms involved in various in situ recovery processes. The models of interest are those focused on two main geological features: heavy oil and bitumen sandstone reservoirs at depths between 100 and 600 metres (excluding bitumen in carbonates); and the presence of shale barriers and water, gas and thief zones.
Recovery processes and technology options being targeted for study include SAGD, solvent and steam processes, in situ combustion and air injection, heating with devices using electricity, biological processes, and number of wells and well spacing—options for single or multiple well patterns.
Clean-tech fund CCEMC has completed five rounds of funding to a total 43 projects since it was established in 2009. By leveraging its funding, it says the roughly $168 million it has handed out has resulted in about $850 million in R&D. CCEMC chair Eric Newell, former president and chief executive officer of Syncrude Canada Ltd., says funding so-called long-shot technologies is part of its mandate.
Newell says funding is divided roughly as 20 per cent toward energy-efficiency projects, 30 per cent toward reducing the costs of CCS and 50 per cent toward greening the energy mix. “We have defined greening the energy mix as two pots: one is renewables and the second one is what we call a really transformative change in how you produce fossil fuels.
“We know we are going to need transformative technologies, so we need to also have projects coming in at the discovery research level or, I think, the technical term is ‘wild-ass idea.’”
Some of the funding recently handed out will lead to the testing of CO2 capture technology at in situ oilsands operations, while many others look to increasing energy efficiency in the oilsands.
He says CCEMC has already been successful at generating a good flow of ideas, but it’s early to judge its longer-term success, since game-changing technology adaption is a long-term process. “After five years, if we are successful, we will have a very good strategic portfolio of projects, and in there we know we will have a couple of winners at least, and then it’s 10 years when you will actually see the curve bending, actually starting to get significant greenhouse gas reductions—that’s just how long it takes.”
The 2020 targets may already be out of reach, but with the success of some long-shot technology advances yet to be uncovered, and some policy shifts to encourage their development and testing, longer-term goals may still be attainable.
“A lot of what we are trying to do is—especially at that transformative technology part of the spectrum—is really aiming out at the 2050 target,” Newell says.
GHG Reduction Road map
Efficiency gains, new technologies offer 30 per cent CO2 emissions improvements
Of the various studies to examine future technology advancements, one of the most recent, a report prepared by oilsands giant Suncor Energy Inc. and Jacobs Consultancy released in May and titled A Greenhouse Gas Reduction Roadmap for Oil Sands, suggests that near to mid-term operational and capital improvements could bring about seven to 12 per cent reductions in greenhouse gas (GHG) emissions, while longer term (10-plus years) technology improvements offer 10–30 per cent improvements.
The road map, completed with funding of about $800,000 from the Climate Change and Emissions Management Corporation (CCEMC, which uses CO2 fees collected from high emitters in Alberta to fund low-emission technologies), used Suncor’s mining, steam assisted gravity drainage (SAGD) and upgrading facilities in the Fort McMurray, Alta., area as a basis in analyzing the theoretic best energy efficiency that could be achieved in developing the oilsands.
“Technology developments for improving energy efficiency offer the most significant potential to close the GHG intensity gap between crude oils derived from bitumen and heavy crude oils produced outside of Alberta,” it states.
With no real price incentive on CO2 reductions, the report all but dismisses the possibility of carbon capture and storage (CCS) contributing to reductions in the short to mid-term, despite its potential to lower CO2 intensities, noting that “under the current and anticipated economic and regulatory environment, CCS is not economically viable.”
For in situ recovery, the study found improvements in energy efficiencies that could reduce CO2 emissions 12 per cent. And based on new technologies identified, a further 20 per cent reduction in energy consumption could be attained. In steam generation, which represents 90 per cent of energy used at typical in situ operations, some of the technology improvements identified included alternate fuels for boilers; microwave, nuclear and solar thermal technologies; electrical induction; plasma generator; downhole steam generation and organics removal technology to reduce organics in boiler feedwater.
Heat recovery technologies include ultrasonic or membrane separation, downhole pump technology and the use of organic Rankine cycle on boiler stacks and glycol circuits. Alternatives to SAGD also offer emissions- reductions improvements, including co-injection of surfactant, solvent, polymer or hydrogen, warm water extraction, water and air injection, catalyst injection to reduce viscosity and non-condensable gas injection. The report ranks the technologies in terms of potential energy benefit, relative risk and development timeline (see graph).
The largest prize in reducing emissions would be CCS, with existing or near commercial technologies able to capture upwards of 90 per cent of CO2 emissions from in situ operations (boilers and cogeneration units), resulting in an overall 75 per cent improvement (after factoring in increased energy needs). But while the ability of CCS to reduce emissions “is likely to be larger than what is expected to be attainable with other technologies,” it comes at a much higher cost, and complexity, with costs ranging from $75–$200 per tonne of CO2 avoided. Besides cost, other barriers include lack of suitable geological storage sites in the oilsands region as well as pipeline access and space constraints.
In bitumen mining and extraction operations, a more mature technology activity where the hot process-water needs are responsible for about half the energy consumed, energy efficiency projects identified could reduce GHG emissions by seven per cent, while new technology gains offer up to 30 per cent reduction.
Of a number of technology improvements examined, the study found the top ideas for improving energy efficiency were developing hybrid/electrical drive systems for heavy haulers, surfactant injection in the extraction process, improved ore analyzers and improved water separation from bitumen.
The road map also found the potential of integrating new in situ and extraction facilities with cogeneration can reduce GHG intensity of production five per cent. As well, integrating low-level waste-heat sources from upgraders or power generation with mining and extraction can reduce extraction GHG intensity 30–50 per cent, though the study notes most existing mining and extraction facilities already have a high degree of integration using waste heat.