- Category: Archived News
- Published: Wednesday, 06 February 2013
- Author: Maurice Smith
Despite lack of GHG regulation, thermal oilsands operators test variety of carbon capture technologies
Producers of bitumen in situ have many advantages over oilsands open-pit mining operators. With a relatively small surface footprint—mainly consisting of wellheads, pipes and associated steam-producing and treatment facilities—they avoid the representations of a scarred landscape and massive tailings ponds commonly associated with surface mines.
But they have an Achilles' heel—as CO2-intensive as mining operations are, thermal in situ operations are even bigger emitters of gases associated with climate change, and as they approach production levels rivaling mining operations, they play an increasingly dominant role in an industry that already represents Canada's fastest growing source of greenhouse gases (GHGs).
While emitting GHGs to the atmosphere comes at almost no cost to companies operating in Canada today, some of those companies are actively preparing for the day when a cost could be put on their emissions, either via a price on carbon or by regulation (Alberta has pledged to be sequestering 30 megatonnes of CO2 per year by 2020 as part of its plan to slow its rapid growth in CO2 emissions—a commitment out of reach without some kind of regulatory or carbon price provision). A handful of companies promoting very different technologies to capture that carbon are piloting their methods in hopes of breaking into the oilsands market.
They range from Connecticut-based international gas separation specialist Praxair, Inc., to small technology startups like Quebec City's CO2 Solutions Inc., Regina's HTC Purenergy Inc. and Burnaby, B.C.–based Inventys Thermal Technologies, Inc. Each is working with oilsands majors to advance their technologies in hopes of winning a big piece of the pie if and when regulation kicks in. While previous studies have pegged the cost of CO2 capture anywhere in the $100-to-$230-per-tonne range, some companies suggest the cost could drop as low as $20 per tonne if the technologies work as anticipated.
Cost is not the only barrier to the technology—the lack of conventional oilfields that could benefit from CO2 injection for enhanced oil recovery (EOR) or deep saline aquifers in which to sequester CO2 in the oilsands region around Fort McMurray leave few options to dispense with the CO2 short of the costly option of building a CO2 pipeline hundreds of kilometres south, where oilfields and aquifers are plentiful.
Companies are exploring creative ways to get around that problem as well. HTC Purenergy is working with Husky Energy Inc. to capture CO2 at that company's heavy oil fields in Saskatchewan, where the steam assisted gravity drainage (SAGD) production method most commonly associated with the oilsands is also used. There, the captured carbon can be readily injected into the reservoirs to enhance recovery, with virtually no transportation cost to deal with.
And Cenovus Energy Inc. is among those investigating co-injection of CO2 into bitumen to enhance oilsands recovery. It is conducting a small scale CO2 co-injection pilot project. While CO2 flooding is a proven EOR technique in light oil, it has not been proven in the oilsands. However, if successful, it could provide a much-needed market for CO2 in the oilsands region. "We are conducting a test to gather more information on how CO2 interacts with bitumen in a thermal environment. However, we're still in the early stages and I'm not able to provide any more details," says Jessica Wilkinson, Cenovus's media relations advisor.
One source of CO2 is Praxair's oxy-fuel combustion technology, which dates back several decades in other industries. By combusting the fuel with oxygen, the flue gas contains high concentrations of CO2 that is relatively easy to separate. It is the only technology under trial that applies its process primarily pre-combustion, rather than attempting to separate the CO2 out of the flue gas stream after combustion.
In situ oilsands operators typically combust natural gas—in once-through steam generators (OTSGs)—to create the large quantities of steam required to inject into bitumen deposits to make the bitumen flow. The resulting flue gas typically consists of only about eight per cent CO2, too dilute to be of any use in enhanced oil recovery (EOR) or to sequester underground. But by combusting the natural gas in pure oxygen rather than air, Praxair can create the required pure stream of CO2 by cooling the flue gas and separating the CO2.
But the process does require some modifications to the boiler, which will be tested as part of an industry/government-funded pilot project scheduled for this summer at Cenovus's Christina Lake SAGD facility. Participants include the CO2 Capture project (a partnership of BP plc, Chevron Corporation, Eni S.p.A., Petrobras, Royal Dutch Shell plc and Suncor Energy Inc.), along with Cenovus, Devon Energy Corporation, Statoil ASA, MEG Energy Corp. and Praxair. The project received $2.5 million in funding from Alberta's Climate Change and Emissions Management Corporation (CCEMC), which collects fees for excess carbon emissions to fund technology to lower GHG emissions.
A design and cost estimate for a commercial-scale OTSG boiler with built-in carbon capture, purification and compression technology has already been completed. Phase two, now underway, will test the reliability, efficiency and cost-effectiveness of an OTSG boiler, equipped with oxy-fuel technology.
The first phase calculated costs in the range of $125–$150 per tonne of CO2 captured, not including compression and transportation, says Candice Paton, Cenovus energy management and environment engineer. "We are now working to retrofit a boiler with the oxy-fuel system and then we will be running a test for two weeks in the summer," Paton says. "While we are not going to capture the CO2 from the boiler as part of this test, ultimately oxy-fuel combustion systems would be able to capture about 99 per cent of CO2 emitted."
Compared to post-combustion capture technologies, "there is a lot less processing that has to happen, and so the overall system can be much more efficient. With our pilot we are looking at whether we get the same or better performance from our boiler than a traditional air-fired system, how the heat flux profile within the boiler will look, and to make sure that we are getting the same steam quality," she says.
"If it is successful, it has the potential to significantly reduce the cost associated with carbon capture, so we want to make sure we can prove this technology in the SAGD environment with the type of steam generators that Cenovus and other operators use."
One of the biggest advantages of oxy-fuel technology is that it is proven, albeit in different applications, says Mike St. James, Praxair manager of business development, noting it has been used in the steel and glass industries for several decades. "The components of the technology are safe and proven, so it's not a high-risk application.
"The real test isn't that the combustion process works, it is that the furnace can be modified appropriately and economically to make this process work. We have a couple of schemes that we are looking at and we are testing one of them with this test run with Cenovus."
According to St. James, there are two main components to retrofitting the OTSG: preventing anything but oxygen and fuel from entering the furnace—air is mostly nitrogen and "nitrogen makes carbon capture in furnaces much harder," he says—and installing flue gas recirculation to make up for the reduced flue gas flow in the boiler that results when nitrogen is removed.
"If you think of air as 80 per cent nitrogen, 20 per cent oxygen, normally you have all of that flue gas flowing through and that gas flow determines the amount of heat transfer in the boiler as it is designed to work with air. When you go with oxygen combustion, you still only need the same amount of oxygen, but you are missing more than 70 per cent of the flue gas, which is normally nitrogen. With oxy-fuel combustion we add this gas by re-circulating flue gas, which is CO2 and water vapour, from the furnace stack back to the front end. Adding this loop is a big part of the boiler retrofitting process. You can take the flue gas out in the back, put it through a blower, add oxygen and put it back into the burner. That is not very expensive to do."
For the trial, 99.9 per cent pure liquid oxygen will be trucked to the site, though on-site oxygen production would be used in a commercial operation. "Cryogenic air separation is a 100-year-old technology. It basically involves cooling air down to around the minus-200 [degrees Celsius] range, so that you can separate liquid oxygen from the nitrogen," St. James says.
He estimates the boiler retrofit can be completed for a single-digit percentage of the cost of the furnace itself. "The real cost of this technology is the capital required to purify oxygen, and then all the capital required to do something with the CO2. The incremental energy consumption to operate all of the facilities could be up to 10 per cent of the SAGD facility's overall energy use.
"To put it into context from an industry perspective, at $100-per-tonne capture cost, for the amount of CO2 a SAGD plant is producing, would amount to about a $5-per-barrel bitumen cost. Part of the testing here is to determine whether capture costs will be $70 or $100 or $150 per tonne."
While a cost "north of $100 a tonne" of CO2 captured sounds high, St. James notes "there are potential markets at this price point; one of our tasks as an industry would be to grow this market."
HEAVY OIL APPLICATION
Positioning its technology atop a reservoir that can benefit from the injection of CO2 is what HTC Purenergy is trialling in an innovative use of its amine-based post-combustion separation technology with Husky Energy. The company announced in July a $10-million CO2 capture demonstration project (with $2.9 million from CCEMC) at Husky's Lashburn, Sask., heavy oil field that will see CO2 transported a short distance to an existing compression facility, and injected into a partially depleted reservoir.
Husky has applied a cookie-cutter approach in quietly building small SAGD projects to produce heavy oil that are capable of extracting up to 50 per cent of oil in place, many times the recovery rates of cold heavy oil production.
The 35-tonne-per-day field pilot follows on the heels of a front-end engineering design (FEED) study for Devon's Jackfish SAGD facility to demonstrate HTC's modular approach. Modelling the separation of 1,000 tonnes of CO2 per day from three OTSGs, targeting 90 per cent recovery, the study found costs would be under $70 per tonne of CO2 captured. Conducted with $315,000 in CCEMC funding, the FEED study calculated capital costs at $83 million, or $37 per tonne of carbon captured. Operating costs would add another $30 per tonne.
Like other CO2 capture technology companies, HTC has shifted from a focus on an expectation of GHG regulations to one responding to profitable uses for CO2, such as for EOR, CO2 hydraulic fracturing and as a feedstock in industrial processes. It set up subsidiary HTC CO2 Systems Corp. a year ago for that purpose.
"We have refocused our company over the last couple of years into dealing with areas where CO2 capture becomes more of a commodity, such as using CO2 for food-grade CO2, where they use CO2 in pop and beer and things like that," says Jeff Allison, senior vice-president and chief financial officer.
Among other initiatives, the company examined the possibility of capturing and pipelining CO2 from the Graymont Exshaw limestone plant near Canmore, Alta., to be used for EOR in the Turner Valley area south of Calgary, which has drawn interest from several oil producers in the area.
The company's pre-engineered, modular system—which it refers to as the world's first such unit—provides post-combustion CO2 capture customizable to the site requirements of various industrial emitters. "It's about taking an existing process and improving it, and making it more efficient and more cost-effective," says Allison.
Working with partner companies and research institutions, such as U.K.-based Doosan Power Systems and the University of Regina, HTC says it has brought costs down in part by better management of the solvent system and utilization of heat energy, and by reducing the amount of solvents that need to be added (make-up) due to degradation.
While the basic amine process isn't new, HTC says its many improvements bring costs down. "Our Thermo Kinetics Optimization is based on utilizing customized thermo-kinetic solvents and innovative configurations, and optimum operation of the plant," says Ahmed Aboudheir, HTC chief technology officer and adjunct professor at the University of Regina Engineering Department.
"We arrive on a smaller-sized, more efficient plant, with less circulation rate and minimum operating costs in terms of steam and other utilities, like the cooling water and so on. And with a modular approach we have a standard design. That means we can reduce the engineering time and use standard design components, and by doing the fabrication inside the shop, we have a higher level of quality control and much greater efficiency versus field labour."
Its proprietary Solvent Management Reclaimer System is capable of reclaiming single, mixed and formulated solvents at lower cost and with a higher recovery rate for solvent than competing products, the company says. Solvents are the lifeblood of modern amine-based CO2 capture and acid gas treatment systems, the company says, and the reclaimer unit is needed to remove degradation products and particles suspended in the solvents.
HTC uses the analogy of reclaimers acting as the "kidneys" of the CO2 capture units to filter the chemical solvents and restore their absorption efficiencies. If impurities are not removed on a predetermined basis, the solvent will quickly degrade, reducing the acid-gases absorption capacity of the solvent and the overall efficiency of the system, which in turn will increase the operating cost.
HTC hopes to reduce costs further as it embarks on its pilot with Husky by adding heat integration. "Whenever you introduce a process such as CO2 capture, there is going to be a certain energy penalty involved, often around 15–20 per cent of the plant's energy requirement. So the secret to more efficient CO2 capture is, can you reduce the amount of heat that is required to do the stripping process, and the amount of energy to run the pumps and blowers and everything else that makes that plant run?" says Allison.
"The other thing is, can you reduce the capital cost by designing a more efficient system? When we look at how we improve our system, it's not just about one sort of miracle gadget that we install that makes it work better; it's about looking at the overall process and how can we reduce the energy costs three per cent here and one per cent there all through the system? When you add it all up, are we 30 per cent better than somebody else—that's the objective."
The fact the technology is established—a similar system was selected for use at Saskatchewan's Boundary Dam CO2 separation facility—shows there is little risk to its use, he adds. "There are a lot of boutique technologies around," he notes, though few have been proven out on a large scale. "There are always people with new ideas on CO2 capture. But we have a commercial technology that is ready to go and ready to build, and it has been implemented for many years worldwide."
Quebec's CO2 Solutions, meanwhile, believes its technology can separate CO2 from flue gas significantly cheaper than any standard chemical absorption process, which typically uses a monoethanolamine (MEA) solvent. "By using our enzyme, we can use other solvents that are much less energy-intensive or require less energy for regeneration. Our benchmark is we are going to be 30–40 per cent less costly than the MEA approach," says Glenn Kelly, president and chief executive officer.
CO2 Solutions was selected in October to receive up to $500,000 from CCEMC for a year-long project to optimize its technology for capture of CO2 from oilsands production. The $2-million project involves a large bench-scale pilot for CO2 capture from SAGD operations. In January, the company announced another $348,000 in non-reimbursable funding from the National Research Council of Canada's Industrial Research Assistance Program.
"The large bench pilot is basically the same sized unit as we would be putting out in the field. It is already built and is in an indoor facility in Europe, and we will be testing the technology under operating conditions that are specific to the oilsands—specifically, SAGD flue gas—in the first phase of the project. The subsequent phases are to take our learnings from that and design and build a pilot, and test it in situ in Alberta," Kelly says.
The company is working with a large oilsands producer for the field pilot, which it could not yet name. CO2 Solutions has an extensive patent portfolio covering the use of carbonic anhydrase (CA), or analogues thereof, for the efficient post-combustion capture of CO2 with low-energy aqueous solvents. In a packed tower scrubbing system, the technology has the potential to substantially improve CO2 capture efficiency with low-energy solvents (see "An Industrial Lung?", New Technology Magazine, December 2011).
CO2 Solutions has teamed with Procede Group B.V. of the Netherlands, which has extensive carbon capture–process expertise, as an engineering partner where the bench testing will take place. It has also partnered with Codexis, Inc. of Redwood City, Calif., to assist in improving the stability of CA enzymes for harsh industrial conditions and to further pilot and demonstrate the technology. Codexis, a leader in developing and manufacturing "super enzymes" that gained success in genetically modifying enzymes for pharmaceutical production, is genetically engineering CO2 Solutions' CA to survive at higher temperatures.
Originating from research at Quebec's Université Laval conducted in the 1990s, CO2 Solutions technology exploits the capabilities of CA, a naturally occurring enzyme produced by humans and other living things to manage CO2. In the body, CO2 is first converted to bicarbonate, then transported to the lungs, where it is transformed back to CO2, a process assisted by CA. The potent biocatalyst, however, was initially far too costly to produce, at about $250,000 per gram a decade ago. Through bio-engineering and large-scale production, that cost can be whittled down to under $100 per kilogram.
CHANGING THE EQUATION
Though not currently testing its technology in the oilsands, Inventys has worked with Suncor, which invested an undisclosed sum to help advance the technology, and is performing preliminary conceptual design of a pilot plant with a major heavy oil producer for CO2 EOR.
In the meantime, it is proceeding with a carbon capture project with Nova Chemicals Corporation at Joffre, near Red Deer, Alta., that has one major advantage: a ready market for CO2. Inventys intends to supply CO2, captured from a natural gas steam boiler, to Penn West Petroleum, which has been using CO2 for an EOR flood for 30 years.
Last July, Inventys was awarded $3 million in CCEMC funding for the $6-million project, to be installed in the spring of 2014. Assuming a 90 per cent capture rate and taking into account the energy penalty to separate, compress and ship the CO2, it is estimated the project will sequester one megatonne of CO2 over the next decade.
The project will be closely watched by oilsands producers, since Inventys estimates it could significantly undercut costs of other methods. Based on modelling, its own testing and a third-party engineering firm's evaluation, it estimates a CO2 capture cost as low as $20 per tonne. Compression could add another $10 or $30 to the cost before transportation is factored in.
Inventys changed the structure of the CO2 adsorbent it uses and applied a capital- and energy-efficient rotary adsorption technology to cut costs significantly. Brett Henkel, Inventys' co-founder and vice-president of operations, calls the company's VeloxoTherm process "a completely different technology [compared to the conventional solvent process] using a solid sorbent that has the potential to be a step change in cost."
VeloxoTherm uses a novel continuous rotary adsorption technology in which a large wheel made of adsorbent turns about one revolution per minute. On one side of the wheel, the spokes collect CO2 while allowing other gases such as nitrogen and water vapour to pass through. On the other side, the spokes comes into contact with counter-current steam that releases the CO2. The structured adsorbent can recover and store thermal energy evolved during adsorption and reuse the energy during regeneration, ensuring a minimum of energy is required for regeneration (see "Back to the Oil Age," New Technology Magazine, January 2012).
"It's not proven yet at scale—that's why we are doing demonstrations to prove that, but the potential for the technology to be that cost-effective is there," says Henkel.
Inventys will have a one-tonne-per-day CO2 capture demonstration with all the features of a full plant operating in its lab by September, he says, and has another pilot plant scheduled for the field with an undisclosed partner at 10 tonnes per day. The Joffre pilot is 50 tonnes per day.
If Inventys proves out the technology and hits $20 a tonne, "maybe that will change the equation," for CO2 EOR in western Canada, which has been slow to adopt the EOR technique, Henkel says. "We are pretty confident that the CO2 EOR market is going to be there, it's just a matter of time. As for carbon capture and storage, it depends on who you talk to whether that is actually going to be a market or not. Maybe our low cost will change that equation too."