Tailings Management: New Techniques
With around 2 mt of “ore” needed to produce a barrel of bitumen, tailings management is a major aspect of oil sands mining, which since 2009 has been regulated by the requirements of Alberta provincial Directive 074. The tailings consist of sand, silt and clay, together with a small proportion of hydrocarbon that is not recovered as the bitumen is stripped away. The silt and clay means that tailings typically have a high water-retention capability, which requires treatment with desulphurization-sourced gypsum and “matured” tailings to help prepare the material for eventual reclamation.

5a-Suncor Pond 1 June 16 2010-3208 100Tailings Pond 1 in 2002 (inset) and under reclamation in mid-2010. (Photos courtesy of Suncor)

In September 2010, Suncor reported it had become the first oil sands company to complete surface reclamation of a tailings pond. Covering 220 ha, Pond 1 was its first tailings storage facility and was in operation for 40 years before being decommissioned in December 2006. Reclamation involved infilling the pond with 30 million mt of reclaimed tailings sand, with drainage systems then installed to manage water runoff. The final stage involved placing 1.2 Mm3 of topsoil over the surface, to a depth of 500 mm. The long-term aim, the company said, is to create an area of productive forest and wetland, with 630,000 shrubs and trees planted during 2010. It will be carrying out a 20-year soil, water and vegetation monitoring program.

Meanwhile, at Syncrude’s Aurora operation, a new tailings-management plant is scheduled to come on stream in September, with the aim of reducing the volume of fine tailings by converting large amounts into reclamation-ready material. The Aurora Tailings Management (ATM) project includes the construction of a new C$800-million Composite Tailings (CT) plant, designed to produce a combined material consisting of fine tailings, coarse sand and gypsum, which effectively flocculates the fines into larger particles that settle faster. CT is then capped with sand and soil for final revegetation.

According to Syncrude, the CT process has proved to be one of its most successful tailings-management technologies, and has been used since 2000 to fill the company’s former East mine at Mildred Lake in preparation for soil capping in as little as one-to-two years. It expects the ATM project to convert nearly two-thirds of Aurora’s total volume of fine tailings—some 150 Mm3—into reclamation-ready material over the life of the mine.

In February, Syncrude began the industry’s first commercial demonstration of tailings water-capping technology, with the ending of tailings deposition into the Base mine lake. After some 25 years of studies and the formation of 11 test ponds, the company is confident that fine tailings can be stabilized by covering them with a water layer, its research having indicated that, over time, a water-capped lake will evolve into a healthy aquatic environment.

The water depth in the Base mine lake has been increased from 3.5 m to 5 m with spring run-off, sourced from a nearby reservoir, helping to bring in nutrients and seeds to kick-start the revegetation process.

The Carbon Dioxide Debate
One of the principal accusations leveled at the oil sands industry is that the production of oil by this method produces more carbon dioxide per barrel than conventional production techniques. In 2012, IHS CERA issued an update to its 2010 report Oil Sands, Greenhouse Gases, and U.S. Oil Supply: Getting the Numbers Right, which had demonstrated that oil sands oil is by no means “top-of-the-pile” when it comes to production GHG emissions. While Saudi light oils do result in lower production emissions, it said, some U.S. and Nigerian heavy oils, for example, generate more CO2 during the process for getting the oil from the wellhead to the petrol pump.

One key point that IHS made is that the bulk of emissions from using oil as a transport fuel—comprising around 80% of the total—are the same, no matter what the source of the original crude. It is only at the production stage, from source to refinery, that Canada’s oil sands emit more CO2 than conventional wells, reflecting the higher energy requirements for mining or in-situ bitumen recovery. Without going into specific detail, of which the report contains plenty, IHS estimated that the average sands-derived oil refined in the U.S. in 2011 generated 9%–12% more CO2 per barrel of refined product than the overall average for the U.S., when taken on a “well-to-wheels” basis.

However, that average masks a considerable range, with in-situ SAGD synthetic crude production emitting markedly more CO2 per barrel of product than say, dilbit from a surface mining operation.

This is, of course, one of the principal weapons in the environmental lobby’s armory in the debate over future energy security and carbon emissions in the U.S., and in relation to Keystone XL. Critics suggest that it is unsustainable to use Canadian oil sands bitumen and synthetic crude because of their higher well-to-wheels production emissions. Supporters point out that oil sands oil is a secure supply, and reduces the need for the U.S. to import heavy crudes from countries such as Venezuela.

In the meantime, the producers such as Syncrude and Suncor are themselves looking at ways of reducing their own production-energy requirements. As an example, Syncrude cut its energy usage per barrel by 39% between 1982 and 2009, and targeted a further 11% reduction by this year. In its 2011 report, Oil Sands Technology: Past, Present and Future, IHS noted that from 1990 to 2010 the intensity of GHG emissions per barrel of output for mining and upgrading operations fell by 37% on a well-to-wheels basis, while those for SAGD operations fell by 8% in the first 10 years of commercial usage. This trend is expected to continue, although increased production will result in an overall rise in GHG emissions, perhaps doubling to around 10% of Canada’s total emissions by 2030.

Water consumption has also fallen on a per-barrel basis, IHS said, with more brackish water being used and less make-up water being drawn from the Athabasca River for bitumen recovery and upgrader operations.

The Old and the New
Suncor’s mining operations produced 103.3 Mbbl of SCO in 2012, sourcing upgrader feed from its Millennium mine. Output from Syncrude’s Mildred Lake mine and upgrader totaled 106.4 Mbbl of SCO, while its Aurora North mine produced 67.3 Mbbl of bitumen. The Shell-led Albian Sands operations, Muskeg River and Jackpine, produced 46.6 and 35.5 Mbbl of bitumen, respectively, with their output being pipelined to the project’s Scotford upgrader near Edmonton. This converted the bitumen feed to 77.8 Mbbl of SCO. Canadian Natural Resources’ Horizon mine contributed a further 31.8 Mbbl to the province’s total, which came to 330 Mbbl of SCO plus 263 Mbbl of bitumen derived from in-situ operations.

Horizon consists of a surface mine, bitumen-recovery plant and upgrader, and currently has the nameplate capacity to produce 110,000 bb/d of SCO. Canadian Natural is focusing on phased expansions that are manageable under financial and labor-availability constraints, with the aim of increasing output to 250,000 bbl/d initially, then potentially double this.

In May, the company reported that its expansion program was running some 10% under budget, with work on the 150,000-bbl/d-capacity increase about 20% complete. “The availability of construction contractors and related services has been better than expected,” said company President Steve Laut. “As a result, we continue to see bidders sharpen their pencils.”

Located about 70 km northwest of the industry’s hub, Fort McMurray, Horizon has started a new trend in the oil sands industry by offering camp housing for fly-in/fly-out workers from Edmonton, Calgary, and other regional centers, as well as permanent accommodations in Fort McMurray itself.

Latest out of the starting blocks has been Kearl, a joint venture between Imperial Oil and ExxonMobil Canada. Kearl, 75 km northeast of Fort McMurray, differs from the other mining projects in that it will only produce dilbit for the refining market, rather than having an associated upgrader. Regulatory approval for a 345,000-bbl/d operation is in place, based on a 4.6-billion-barrel resource, with an initial capacity of 110,000 bbl/d.

First output began in April, with the aim of reaching first-stage capacity later this year. Output will be doubled by 2015, with debottlenecking to achieve the nameplate capacity by 2020. Imperial Oil noted that Kearl’s energy needs have been reduced by using a proprietary froth treatment process and the installation of energy-saving cogeneration capabilities.

Having canceled the Voyageur upgrader, with C$3.5 billion already spent on the project, Suncor has yet to make a final investment decision for its Fort Hills mining project, held in joint venture with Total and Teck. Situated close to the northern margin of mineable resources, Fort Hills has been designed for an initial output of 160,000 bbl/d, with Suncor expected to make its call some time late this year. Meanwhile, Total is the lead partner for the 100,000-bbl/d Joslyn North mine project, provisionally scheduled for commissioning in 2018 at a capex cost of C$7-9 billion.

Which Way Now?
While the oil sands industry may not exactly be caught between the proverbial rock and a hard place, it is facing a new period of energy market uncertainty. Add to that the debates over CO2 emissions, pipeline integrity, previous well-publicized environmental incidents such as duck deaths on tailings ponds, and the question of possible human health impacts, it is clear to see that all industry participants will have their hands full for some time. The Alberta provincial government itself has come under criticism for failing to monitor water and airborne emissions adequately, with the report from a study group established subsequently agreeing in general that the operations are releasing polycyclic aromatic compounds and trace metals into the environment. And in June, the newly created Alberta Energy Regulator came into being with a mandate to regulate all aspects of energy industry projects from application to reclamation.

Energy consultants are still in the process of updating their assumptions on North America’s future energy needs in the new supply-source environment. This is bound to have an effect on the oil sands industry, and it is currently too early to tell whether the projected increase from 1.5 Mbb/d to 3.3 Mbbl/d by 2019 will actually happen.

According to Alberta Energy Resources Conservation Board projections, daily bitumen production is likely to double from 1.9 Mbbl in 2012 to 3.8 Mbbl in 2022. Of this, 1.6 Mbbl/d will come from mining, the board believes, but the bulk of the increase will be derived from new in-situ operations. In view of this, the proportion of raw bitumen that is upgraded in the province is likely to fall from 52% of total output to 38% over the same time-span.

Much obviously depends on the availability of pipeline capacity to carry SCO and dilbit to U.S. refineries. Aside from the Keystone XL project, Enbridge is in the process of doubling the capacity of its Seaway pipeline from Cushing, Oklahoma, to the Gulf Coast to 850,000 bbl/d, and has submitted plans for a new 525,000 bbl/d pipeline from Alberta to Kitimat in British Columbia. Kinder Morgan is also planning to increase capacity on its pipeline to Vancouver to 890,000 bbl/d, with both of these proposals aimed at increasing Canada’s oil exports.

In terms of emission controls, suggestions have been made that using mobile in-pit crushers could help mining operations reduce their CO2 footprint by reducing the sizes of truck fleets. At the other end of the process, last September, Shell gave the go-ahead for its C$1.35 billion Quest carbon-capture-and-storage project, designed to take 1 million mt/y of CO2 from the Scotford upgrader and sequestrate it 2-km underground. The first project of its kind for the oil sands industry, Quest has attracted C$865 million in provincial and federal government funding, and will store permanently 35% of the upgrader’s carbon emissions.

Oil sands mining is big business today, and will become bigger in the future. Meanwhile, the industry finds itself in the unenviable position of being a target for criticism from a number of quarters. Success in years to come will depend to a large extent on how it is able to respond.

Dilbit or SCO?

Oil sands bitumen is handled in one of two ways. Non-upgraded bitumen is too viscous to flow through pipelines without settling out, so it must first be diluted using a light hydrocarbon fluid such as condensates or synthetic crude oil (SCO) to form “dilbit” or “synbit.” The upgrading process adds hydrogen, removes carbon, or both, converting the bitumen into SCO that can be handled through pipelines in a similar way to conventionally produced oils. All of the bitumen produced by mining is currently upgraded, together with a small proportion of in-situ output.

Titanium Targets Zircon with Innovative Tailings-treatment Process

In May, Titanium Corp. received the last of the three core Canadian patents that together secure its innovative “Creating Value from Waste” technology for recovering residual bitumen, solvents and heavy minerals from the mining-process tailings stream. The company also received the final results of independent testing on its process by CanmetENERGY which, it said, confirmed its technology can do this.

Titanium Corp. reported that during a 10-week run, its pilot plant achieved 82% recovery of the residual bitumen from the oil sands tailings stream and 98% of the solvents. It also produced a large bulk sample of heavy mineral concentrate from which zircon and the titanium minerals, ilmenite and leucoxene, can be recovered in a separate operation.

The company said it is well-known that small amounts of heavy minerals occur in Alberta’s oil sands. Attracted to bitumen, they become concentrated during the bitumen extraction process, ending up in the tailings from the final froth treatment stage. These also contain residual bitumen. It also stated that using its technology raises the potential for reducing the intensity of CO2 and NOx emissions from oil sand mining, as well as those of volatile organic compounds (VOCs).

Since 2004, Titanium Corp. has carried out a sequence of projects on both fresh and older tailings, having attracted both provincial and federal government funding. Its work to date has indicated that its process can increase bitumen recovery by 2%, cut VOC emissions by 80%, save 25% of the fresh water make-up currently needed for bitumen recovery, and produce a thicker tailings product that is more amenable to early restoration, as well as producing zircon and titanium. Using 2010 oil sands production rates, this would be equivalent to extra bitumen worth C$700 million a year, plus 170,000 mt/y of zircon worth C$340 million.

“While it takes time to commercialize new technology, we are seeing increasing support from stakeholders for our technology, which would recover up to 7,000 barrels per day of currently wasted bitumen and solvent from individual oil sands operations,” said Scott Nelson, Titanium’s president and CEO. “Oil sands mining companies are the pioneers of this large industry and have introduced many innovations to their processes over the years. Our company is well-positioned to be among the next phase of breakthroughs in efficiency and environmental performance.”