Whether or not anyone likes the idea of ripping up the landscape of northern Alberta or poking lots of well holes into it to access oil-rich sand deposits, the world—and more specifically the U.S. and China—needs the oil. Because of this need for petroleum, and the billions of dollars and nearly 140,000 jobs that already go with oil sands development, the process is going to continue.
Oil companies would like to proceed unimpeded because they have faith that new technologies will emerge to minimize the environmental impact as oil sands development expands. On the other hand, environmental groups and some scientists believe Earth’s atmosphere and northern Alberta’s once-pristine boreal forests and Athabasca River can’t take the abuse. They argue that oil sands operations should be shut down, or at least slowed down, in favor of cleaner energy options.
One concern is greenhouse gas emissions, which come mainly from burning natural gas to heat water for extracting the oil sands and to power refineries. Another concern, and one that is more immediately problematic, is the loss of regional water quality. This decline stems from billions of gallons of water used to extract the oil sands since the first operation began in 1967.
Scientists and engineers are working hard to develop processes that clean up or reduce the huge volumes of water necessary to extract and upgrade the petroleum.
The Albertan and Canadian governments, trying to provide some balance, are advocating that oil sands can be developed in an ethical way through stringent water and other environmental regulations and through the oil companies’ sense of responsibility. Time will tell, and given the size of Alberta’s oil sands deposits, there will be plenty of time.
Called oil sands, and usually referred to as tar sands by opponents, the deposits are known technically as bituminous sands. The material is a mixture of about 85% sand, clay, and water and up to about 15% of a viscous form of crude oil called bitumen. The bitumen itself is a complex mixture of hundreds of heavy hydrocarbons along with sulfonated, nitrogenated, and oxygenated compounds. It defies full characterization.
Oil sands deposits occur throughout the world, but the largest deposits by far are in Alberta and in Venezuela. To date, only Alberta’s oil sands have proven profitable to extract. Alberta’s deposits, estimated by the International Energy Agencyat some 2.3 trillion barrels of oil, spread across 54,000 sq miles of northern Alberta. That volume is roughly equal to all of the known reserves of conventional crude oil in the rest of the world. About 175 billion bbl of the Alberta reserves are recoverable with available technology.
The province currently produces about 1.5 million bbl per day from oil sands, most of it delivered to the U.S.—Canada has already leveraged its oil sands to quietly become the U.S.’s largest supplier of crude oil, providing about 20% of U.S. imported oil and refined products. A proposed pipeline to the Pacific Ocean would give Canada a route to ship refined oil to China. Accounting for eventual production rates of 5 million bbl per day or more, Alberta’s oil sands extraction is destined to last for at least the next 100 years.
“The water processing has to be intensive to facilitate separating the bitumen, and the efficient and environmentally acceptable use of water is obviously going to be key,” says Paul Turgeon, president and chief operating officer of BWA Water Additives, a specialty chemical company that produces antiscalants, corrosion inhibitors, and biocides for industrial water treatment, including oil-field applications. “The technology to handle water is available, but the limiting issue is the sheer volume that needs to be cleaned up.”
Turgeon adds, “Oil sands operators in Alberta typically make the comment that they are in the business of water management, treatment, and reuse, and that the oil is simply a lucrative by-product.”
The volume is only going to grow, Turgeon points out. “Water consumption in Alberta is slated to reach about 400 million gal per day by 2030,” he says. “It’s huge.”
Water plays several key roles in extracting fuels from tar sands. To extract conventional oil from the ground, companies drill wells into a petroleum reservoir. The oil then flows out by natural pressure or is forced out by pumping in water or CO2. But bitumen is too thick to flow—it’s about the consistency of peanut butter. So it must be physically extracted from the sand, or the ground must be warmed up so the bitumen will seep into a well where it can be pumped.
About 20% of the Alberta deposits are within about 300 feet of the surface and can be excavated economically by strip-mining. Workers remove the thin overburden layer of peat and soil and then excavate the oil sands, loading the material onto giant trucks and transporting it to extraction and upgrading facilities.
Technicians next treat the sands with hot water and caustic soda to create a slurry. This soupy mix is agitated to develop a frothy layer of oil, which is skimmed off. The froth is diluted with naphtha and centrifuged to remove residual water and solids, rendering the bitumen fluid enough to be transported and refined. Companies can recover roughly 90% of the bitumen from the excavated oil sands—it takes about 2 tons of oil sands to produce 1 bbl of oil.
For the remaining 80% of the deposits, which are deeper and not amenable to strip-mining, workers drill wells and use steam to warm up the sands in place before pumping the bitumen. The leading technology for this in situ processing is called steam-assisted gravity drainage (SAGD).
For SAGD, two horizontal wells, one about 20 feet above the other, are drilled into a deposit. Technicians initially inject steam into both wells, heating the bitumen. After days or weeks, steam is cut off to the lower well, and the softened bitumen flows down into the lower well where it can be pumped out. This strategy allows companies to drill multiple wells from a single hole, reducing damage to the landscape. But it’s less efficient than surface mining, allowing recovery of only about 55% of the bitumen.
Once extracted by either process, the bitumen is upgraded in a series of refinery processes. The primary product is light sweet “synthetic” crude that is piped to refineries in Alberta and the U.S. for a full workup.
For BWA, the SAGD process is a hot area. BWA doesn’t work directly with oil companies, Turgeon notes, but rather it supplies products to engineering service companies that support oil company operations. Its antiscalants, for example, prevent formation of calcium carbonate and other types of scale that reduce process efficiency and damage the thermal evaporators that process and recycle steam.
“These additives are relatively simple synthetic organic compounds that have a small environmental footprint,” Turgeon explains. They help increase the length of time that companies can cycle the water, he says.
About 250 sq miles of Alberta has been mined so far. Albertan and Canadian law requires oil companies to return the meadows, wetlands, and boreal forest they disturb to their original state, or at least very close to it. But land reclamation is lagging way behind the mining: Only about 0.4 sq mile—1 sq km—has been certified reclaimed by the Albertan government. Another 28 sq miles has been reclaimed but not certified. The holdup is, not surprisingly, water related.
Companies pump leftover sand and clay from surface mining, suspended in water, to tailings ponds for the solids to settle out. Some of the ponds also serve as reservoirs to hold water before it is recycled back into the extraction process. By law, there is a zero-discharge policy in place, so none of the water drawn from the Athabasca River or from wells and used in oil sands operations can return to the river. Although about 85% of the water is recycled in oil sands operations, millions of gallons of fresh water per day is added to the process.
In the ponds, sand, clay, residual bitumen, and chemical leftovers from the extraction settle out, eventually allowing the water to be pumped off for recycling or for treatment and disposal in underground wells. But this settling process is painstakingly slow—it can take decades. Once the sediment is deemed stable, the tailings are covered with overburden from other mine sites, or the tailings are dug up and used to fill mine sites and then covered with overburden. To finish up, a crop such as barley is planted to control erosion, and then native trees and other vegetation are planted.
The big, unsightly, and difficult-to-reclaim retention ponds that dot the Alberta landscape are a highly visible strike against the oil industry. They collectively hold about 250 billion gal of waste and cover more than 50 sq miles.
On average, about 4 bbl of water is needed to remove 1 bbl of oil. With technology improvements, that number has dropped over time. For example, in 1975, about 5 bbl of fresh water was used to extract 1 bbl of bitumen from oil sands. Today, with more efficient water recycling possible with in situ processes, only 0.5 bbl of fresh water per 1 bbl of oil needs to be added to the process stream. But because oil production is increasing, the total volume of water used—along with the volume of material in the tailings ponds—is still increasing.
Many people worry that ruptures of the tailings ponds could spread toxic mining debris. The breach of a coal-ash sludge pond in Kingston, Tenn., in late 2008, and the failure of an alumina tailings reservoir in Hungary last year loom large in the memories of environmental groups.
In addition, keeping birds out of the Alberta ponds is a challenge. Although rare, when birds land on the ponds they can get mired in the thick sediment and may not be able to take off again; at one tailings pond in 2008, some 1,600 ducks perished in a single incident. Oil companies have implemented a few simple measures to ward off such disasters, including installing scarecrows called “bitu-men” and using noisemaker cannons.
“Everyone with a stake in oil sands would like to see tailings reclamation speed up,” says Keng C. Chou, a surface science chemist at the University of British Columbia who studies the interaction of sand, clay, and bitumen in the extraction and reclamation processes. “We would like to eventually avoid tailings ponds altogether.”
The sand and large clay particles are heavy enough to settle out in the ponds relatively quickly, Chou explains. But fine clay particles below about 50 μm in size remain suspended in the water above the sediment layer. These particles are charged and repel each other, so they don’t clump together and settle. This layer, floating midlevel in the ponds, is about 70% water and 30% clay and has the consistency of yogurt; left alone, it can take 40 to 100 years for the water and clay to separate.
“The challenge is how to make these fine clay particles settle more quickly,” Chou says. “We need to start with a better understanding of how the fine particles interact with sand, other clay particles, bitumen, water, and solvent molecules. It’s a tricky business that requires special spectroscopy techniques.”
Chou’s group uses infrared-visible sum frequency generation vibrational spectroscopy to probe the competitive interactions of the various components at water-mineral and solvent-mineral interfaces (Langmuir, DOI: 10.1021/la1020737). This interfacial surface chemistry controls the rate and efficiency of bitumen extraction from the oil sands and controls interactions in the tailings ponds, Chou says.
His research project receives support from the Centre for Oil Sands Innovation at the University of Alberta, which is funded by the Alberta government and by Imperial Oil, one of Canada’s largest oil companies; Imperial Oil is majority owned by ExxonMobil and has a major stake in oil sands operations. The experiments are providing molecular-level information that can help develop chemical treatments for the tailings ponds. The end goal of his group’s work, Chou says, is to help others develop bitumen separation and upgrading processes that use less water or that avoid water altogether.
Chou says he would be happy if he helped discover a solution in the next five years. But it would take years beyond that to develop a large-scale application, he points out.
However, a viable solution may already exist, says Canadian Association of Petroleum Producers spokesman Travis Davies. Scientists and engineers at Suncor Energy, one of a handful of oil companies in a consortium working on oil sands process technologies, have developed the “tailings reduction operation,” or TRO process, which uses a polymer flocculant—one that is already used in municipal sewage treatment—to capture and lock up the fine clay particles.
Currently, oil companies add gypsum, a soft calcium sulfate mineral, to the tailings to help speed up reclamation. That approach has shortened the process of cleaning up tailings ponds by about 10 years, to 30 years or so. Other approaches include pumping CO2 into the silt to form solid carbonates that permanently trap CO2 along with the tailings. But with these alternatives, the sheer volume of tailings to manage still presents a challenge.
“The breakthrough with Suncor’s TRO strategy is that you can scale it up,” Davies says. The polymer-based process can potentially reduce the time for cleaning up tailings ponds to less than 10 years.
The polymer, which Suncor declines to name, is added to a tailings pond and then the thickened material is pumped onto sand. The water evaporates within a few weeks, and the dried material can be scooped up and used as fill at mine reclamation sites.
Suncor is spending several hundred million dollars this year to ramp up implementation, Davies says, and the company is confident enough in the process that it has suspended plans to build new tailings ponds. If it works out, each mining site in the future will need only a single, smaller tailings pond that will serve primarily as a reservoir for recycling water.
For the future, other process technologies are lining up to help reduce water and energy costs associated with oil sands processing. In one example, Sarah A. Brough and Sean McGradyof the University of New Brunswick and coworkers have developed a one-step, low-temperature supercritical fluid process to extract and upgrade bitumen from oil sands.
In an initial report last year, McGrady’s group used CO2/H2 mixtures with heterogeneous rhodium, ruthenium, and cobalt hydrogenation catalysts to process small samples of Alberta oil sands. The researchers extracted the bitumen and produced crude oil containing low levels of sulfur and heavy-metal impurities (Chem. Commun., DOI: 10.1039/c0cc00417K). The team has more recently used pentane or hexane as the supercritical medium with industrial CoMoNi petroleum-refining catalysts.
Supercritical fluid extraction of oil sands was proposed in the 1970s, McGrady notes, and hydrogenation of organic substrates in supercritical fluids has been practiced since the 1990s. But his team’s work is the first example of marrying the two processes in a single operation, he says.
The process saves a lot in energy costs because it can run at low temperature. And it’s potentially a lot cheaper than existing bitumen upgrading because it reduces hydrogen consumption, which is the most costly part of refining, McGrady says. For now, his group is looking for a business partner to commercialize the supercritical fluid process for upgrading bitumen.
Because the industry has invested so much money in the SAGD process, McGrady expects little commercial interest just now in scaling up supercritical fluid processing to extract oil sands. “That is not to say that one day this dual, nonwater process wouldn’t be attractive to oil companies,” he says. “But we have to keep in mind that the scale at which any process involving oil sands will need to operate is mind-boggling.”