Oil sands have always been tough to mine
Oil sands have always been tough to mine—and tough on equipment. Syncrude, for example, has estimated that the abrasive sands grind enough metal off its loading and haulage equipment on a daily basis to make two full-size pickup trucks. However, with only 3% of oil sands reserves amenable to surface mining, the industry will increasingly turn to in situ recovery methods.

Nobody disputes that Canada’s oil sands represent a major energy resource, not only in regional terms, but globally as well. According to the Alberta government, the province’s proven 168-billion-barrel reserve is the third largest in the world, with mineable oil sands extending over some 4,800 km2. As of the end of 2012,767 km2 of this had been either cleared or disturbed by the current generation of surface mines. However, with surface-mineable reserve representing only 3% of the province’s total, in situ production projects are continuing to increase their proportion of Alberta’s annual bitumen output. Indeed, in situ production, using steam-assisted gravity drainage (SAGD) techniques, overtook conventional mined production in 2012, with the trend certain to continue as the technology matures and more SAGD operations come on stream.

Statistics collected by the Alberta Energy Regulator show that the province’s oil sands mines produced 58.7 million m3-369 million barrels (bbl)-of crude bitumen during 2013. Out of this, Syncrude produced 97.5 million bbl of synthetic crude oil, at an average of 267,000 bbl/d, although that figure masked a monthly range from 183,000 bbl/d in July to 323,000 bbl/d in November as the joint venture was faced with two cokers-the reactors that remove carbon from raw bitumen as part of the conversion to synthetic light crude oil-being offline at the same time. And, while one unit was undergoing planned maintenance, the other, which had already been the subject of earlier-than-planned work in 2012, suffered anotherfailure that had to be fixed. Industry sources suggest that this reflects the age of some of Syncrude’s upgrader equipment, with average daily output in 2013 lower than in both the previous two years and the operationstill performing below its 350,000-bbl/d nameplate capacity.

The other long-standing oil sands miner, Suncor Energy, also has 350,000 bbl/d of upgrading capacity, with an average output of 282,600 bbl/d of synthetic crude oil and diesel (the company refines its own mining-fleet fuel) last year. Including its in-situ operations and its proportion of Syncrude’s output, the company achieved an average of 392,500 bbl/d during 2013, a figure that included a record 409,600 bbl/d to its account during November. In fact, during the year, its oil sands-based output exceeded its inland refining capacity, Suncor noted in its 2013 annual report.

The Athabasca Oil Sands Project’s (Shell Albian Sands) 2013 output averaged 236,000 bbl/d from its Muskeg River and Jackpine mines, with diluted bitumen (dilbit) being upgraded at the Scotford refinery near Edmonton. Meanwhile, the more recently established operations also maintained growth in output. Canadian Natural Resources’ Horizon mine produced synthetic crude at an average rate of alittle more than 100,000 bbl/d last year, but a staged expansion there meant that its fourth-quarter output of 112,000 bbl/d was well up on the 83,000 bbl/d achieved in the comparable period of 2012.

And, for Imperial Oil, 2013 marked the successful inauguration of its Kearl mining operation, the largest single investment in the company’s history, with an average output of 52,000 bbl/d during the last quarter of the year. Expansion is already under way there, with a target of 110,000 bbl/d this year and 345,000 bbl/d by 2020. Imperial also booked 67,000 bbl/d from its holding in Syncrude.

Capturing Oil Sands CO

With carbon dioxide emissions forming the focus for one of the principal criticisms of Canada’s oil sands industry, it is hardly surprising that there has been increased interest from government and operators alike in investigating the potential for carbon capture and storage (CCS). The concept has already been proved at the Weyburn project in Saskatchewan, which takes CO2 from the Great Plains lignite gasification plant in North Dakota and injects it into old oil fields, and elsewhere in the world. Alberta’s oil sands industry was the source of some 49 million metric tons (mt) of CO2 emissions in 2010, although to put that into perspective, in a recent presentation, Enhance Energy pointed out that emissions from U.S. coal consumption that year totaled more than 1,100 million mt.

The first CCS project directly related to the oil sands industry, Quest has been designed to take over 1 million mt/y of CO2 from Shell’s Scotford upgrader, transport it some 80 km and then store it at a depth of around 2 km. The scheme, which will reduce the upgrader’s CO2 emissions by up to 35%, was given the go-ahead in 2012, with the first CO2 injection scheduled for 2015.

Shell's Quest Carbon Capture and Storage project will reduce CO<sub>2</sub> emissions from AOSP's oil sands operations by more than 1 million mt a year by capturing CO<sub>2</sub> from its Scotford upgrader and permanently storing it deep underground.
Shell’s Quest Carbon Capture and Storage project will reduce CO2 emissions from AOSP’s oil sands operations by more than 1 million mt a year by capturing CO2 from its Scotford upgrader and permanently storing it deep underground.

Unlike Syncrude and Suncor, which upgrade their bitumen production on-site, the AOSP refines its bitumen at Scotford, where Shell commissioned an expansion to 255,000 bbl/d in 2011. Having been providing preliminary services and front-end engineering and design for Quest since 2009, in 2012 Fluor was selected as Shell’s engineering, procurement and construction (EPC) contractor for the project.

“Shell’s confidence in choosing Fluor as its EPC contractor for this first-of-its-kind CCS project is a testament to our long-term, successful business relationships established by building Shell projects in Canada and throughout the world,” said Peter Oosterveer, president of Fluor’s Energy & Chemicals Group, speaking at the time. “Fluor has more than two decades of experience with carbon capture technologies and the Canadian oil sands industry, so this unique opportunity will demonstrate our project execution abilities to bring clean energy to the marketplace. The use of CCS technology will allow our customers to address their carbon footprint and sustainability needs,” Oosterveer added.

Meanwhile, the Alberta Carbon Trunk Line (ACTL) is a completely integrated CCS project that will take CO2 from industrial sources and transport it to aging oil fields for enhanced oil recovery (EOR) and CO2 storage. Supported by the Alberta and Canada federal governments to the tune of C$495 million and C$63 million, respectively, out of the C$1.2 billion project cost, the ACTL will have a designed pipeline capacity of 14.6 million mt/y of CO2. The initial phase of the project involves the construction of a 240-km-long pipeline from Alberta’s industrial heartland, north of Edmonton, to the Clive oil field between Edmonton and Calgary, where the CO2 will be injected for enhanced oil recovery and permanent storage.

Two CO sources have been selected: Agrium’s Redwater fertilizer plant, the largest in North America, which will generate an initial 800 mt/d of high-purity CO2, and the North West Redwater Partnership’s Sturgeon upgrader, which will have an initial capacity to process 50,000 bbl/d of bitumen. The world’s first upgrader and refinery with an integrated carbon-management system, Sturgeon’s CO2 compression system is designed for a capacity of 4,200 mt/d.

North West Redwater Partnership (NWR) is a joint venture between North West Upgrading Inc. and Canadian Natural Upgrading Ltd (CNUL), a wholly owned subsidiary of Canadian Natural Resources. The first new refinery to be built in Canada for 30 years, construction of the Sturgeon upgrader began last September. Three-quarters of its feedstock will come from bitumen received by the Alberta government under its royalties-in-kind scheme, with Canadian Natural Resources supplying the balance. The plant will produce ultra low-sulphur diesel as its main output, while selling its CO2 for EOR.

In December 2013, NWR announced that the cost for building Sturgeon had ballooned from C$5.7 billion in late 2012 to C$8.5 billion. In addition, the company said, the original startup date of mid-2016 has been pushed back to September 2017 “in order to optimize work force productivity and ensure that the project remains cost, not schedule focused.”

ACTL pipeline construction is currently under way, with the scheme now licensed to handle 5.5 million mt/y of CO2. According to Enhance Energy, the project operator, the ACTL has the ability to unlock 1 billion bbl of light oil and store 2,000 million mt of CO2.

In its 2014 budget, the Alberta provincial government committed C$144 million to the two CCS projects this year, with the aim of investing almost C$1.3 billion over 15 years.

As noted in E&MJ‘s previous report on oil sands (August 2013, pp. 28–35), there is a lot more to the industry than merely mining the resource and processing it into synthetic crude or dilbit (unrefined diluted bitumen). Transport has a critical role in the economics of the entire project, with a network of pipelines extending far across Canada and into the industry’s principal export market, the U.S.

However, as the last report noted, a major link in the export infrastructure has yet to be completed, with little progress having been achieved in the intervening 12 months on determining whether or not it can go ahead. The key point is that the Keystone XL pipeline crosses the international border between Canada and the U.S., and because of this, approval rests with the U.S. Department of State and, ultimately, with President Barack Obama.

TransCanada, which has been planning the 1,660-mile-long pipeline since 2008, has already completed and commissioned its final stage, which runs from Oklahoma to Texas. However, the route through Nebraska remains subject to legal challenges that remain unresolved, and until this happens, the U.S. Department of State cannot make its final decision.

In point of fact, Keystone XL has become much more than just a debate about a pipeline. It is widely seen as a proxy for environmental issues, with President Obama reportedly having already said that he would not give approval for the pipeline if it would “significantly exacerbate” global climate change. And it has become a party political hot potato, to the extent that some sources suggest that no decision is likely before the November elections in the U.S., in an effort to avoid damaging the re-electoral chances of a number of incumbent politicians.

The lack of a decision has even reached ambassadorial level, with the U.S. ambassador to Canada commenting on it in an interview with the Canadian media in early July. “I think that people need to just have some patience here with us as we are going through this process,” Ambassador Bruce Heyman reportedly said. “A lack of an answer is not a yes, it is not a no, it’s just that we are working through this.”

With Canada looking to increase its exports of oil sands products significantly, and the U.S. now in the position of having its own energy glut, some are questioning the viability of transporting synthetic crude and dilbit right across the Midwest to Gulf Coast refineries. Not only will much of the refined production be exported, it is suggested, but transport fuel prices along the pipeline route may actually rise as inland Midwestern refineries that have previously received oil sands products are bypassed.

Transport safety forms a further focus for debate. Anti-XL campaigners point to spills and leaks from pipelines. The pro-XL lobby cites enhanced safety over other transport methods, and points to incidents such as the Lac Mégantic rail disaster in Québec last year, involving a train loaded with oil.

In the meantime, Keystone XL remains on hold.


Looking for Other Opportunities

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The Alberta Carbon Trunk Line (ACTL) is a completely
integrated CCS project that will take CO2 from industrial
sources and deliver it to older oilfields for
enhanced oil recovery and sequestration.

If the U.S., the traditional main export market for Alberta’s oil sands industry, is in prevarication mode, then why not explore other potential routes to bring Canadian synthetic crude to willing buyers? The pipeline operator, Enbridge, is doing just that with its proposed Northern Gateway project, which would take Alberta crude to tanker terminals on British Columbia’s Pacific coast.

The current proposal, which received federal government approval-albeit with more than 200 conditions attached-in June, envisages a 1,177-km-long twin pipeline to the port of Kitimat. It would have a capacity of 525,000 bbl/d of oil for export, and 193,000 bbl/d of return capacity for condensate.

Just because federal approval has been gained is no guarantee that the project will go ahead as planned, however.

Questions remain about the suitability of Kitimat as the export terminal, with Prince Rupert being suggested as a better option from the sea safety perspective, although that would carry higher construction costs. The British Columbia government has imposed its own conditions on the project, while Enbridge has yet to reach agreement with the aboriginal communities along the pipeline route over its construction. That alone could make or break it, as the company’s CEO, Al Monaco, acknowledged in an interview in June.

“We still have more work ahead of us,” he was reported as saying. “The scrutiny on our industry is sometimes difficult, but it’s broadened, I think, the discussion around energy issues and engaged more and more people in a key question. And that question is how do we achieve the right balance between the need for energy and ensuring safety and protection for the environment.”

If all goes to plan, Enbridge could conceivably begin work on the Northern Gateway next year, offering the potential for exporting dilbit and synthetic crude to markets in Asia. However, environmental concerns over the transport of dilbit could also provide the incentive for a new generation of refineries in Alberta, with higher-value refined products being exported rather than feedstock for refineries in consumer countries. Meanwhile, the company has noted that it could take until the second-half of 2015 to satisfy the pre-construction conditions that have been imposed by the federal government.

U.S. Oil Sands, a Canadian company
In the U.S., oil sands recovery activity is focused largely on deposits in eastern Utah, where U.S. Oil Sands, a Canadian company, has conducted test mining and processing and is prepared to move ahead with development of a 2,000-bbl/d project at its PR Springs deposit.


U.S. Oil Sands to Go Ahead?

Canada is not alone in having oil sand resources; more than 500 natural bitumen deposits have been identified in the U.S., with the principal resources occurring in Alabama, Alaska, California, Kentucky, New Mexico, Oklahoma, Texas, Utah and Wyoming. However, as a U.S. Geological Survey (USGS) fact sheet on U.S. oil sand resources acknowledges resource estimates vary widely from source to source, with the organization suggesting that the 29 largest deposits in the country could contain some 36 billion bbl of oil.

Current interest is focused on deposits in Utah, where in June the state’s supreme court dismissed the only outstanding regulatory challenge made against U.S. Oil Sands Inc.’s PR Spring project, located in the eastern part of the state. The Canadian-domiciled company had already given the go-ahead to the project, which will have an initial capacity of 2,000 bbl/d of bitumen.

Oil sands mining is not, in fact, something new in Utah, where the three largest deposits are Tar Sand Triangle, Sunnyside and PR Spring. According to a 1976 Eyring Research Institute report for the U.S. Bureau of Mines, surface mining began at Sunnyside in 1892 to provide paving material for streets in Salt Lake City, with the run-of-mine “rock asphalt” only being crushed before being spread on the roads and rolled into place. In the 1960s, Shell was one of a number of companies to experiment with steam extraction at the deposit, but failed to make the concept work. However, little was done subsequently, despite the substantial resource potential in the state, until U.S. Oil Sands began work at PR Spring in 2005.

With a budget that has recently escalated from $50 million to $60 million, the company will be using a proprietary extraction process that uses an orange-peel extract to recover the bitumen. The solvent is recycled as part of the process, with the $10 million cost increase mainly due to plant enhancements that will allow higher water and solvent recovery rates. A major advantage claimed for the process is that it does not create tailings ponds—unlike the admittedly much larger Canadian operations—with bitumen-stripped sand being replaced directly in the mined-out areas.

The recovery technique that U.S. Oil Sands has developed, and for which the company received a patent earlier this year, reflects a major difference between the oil sands found in Utah and their Alberta counterparts. In Canadian oil sand deposits, the bitumen is naturally separated from the sand grains by a film of water—so-called “water-wet” deposits. Utah oil sands are “oil-wet,” in that the sand grains are coated directly with bitumen. Using the conventional extraction process for water-wet deposits in oil-wet sands results in low recoveries; hence the need for a different approach.

Aside from the use of a recyclable solvent, the main benefits that U.S. Oil Sands is claiming for its process include the need for much less mechanical agitation of the sand slurry, which means that less clay is liberated and the production of middlings is minimized. With a clean separation between sand, water and bitumen, there is no need for tailings ponds either, since long-term settling and consolidation is avoided.

The process itself involves the ore being slurried with hot water and solvent, with the solvent dissolving the bitumen. After a 30-minute period to separate the water, solvent and sand phases, some minor polishing is needed to remove any mixed components. Solids are thickened and sent for backfilling, water is recycled, and the solvent is recovered by distillation for recycling back into the process. The company claims recycling rates of 98% for solvent and 95% for water, with the process using around half the energy needed for conventional hot-water bitumen extraction.

With the PR Spring deposit hosting a resource base of some 180 million bbl of oil, and U.S. Oil Sands also having extensive exploration acreage at its Cedar Camp and Northwest Project areas, the company now expects production to begin next year.


Fort Hills Begins to Move

In October 2013, the partners in the Fort Hills project, Suncor, Total E&P Canada and Teck Resources, gave it the go-ahead. When it comes on stream in 2017, Fort Hills will have an initial capacity of 160,000 bbl/d, with a further 20,000 bbl/d expected once debottlenecking has been undertaken. The mining capacity will be 110 million mt/y of oil sand, and as the majority shareholder, Suncor is the project developer and operator.

“With an expected mine life in excess of 50 years, Fort Hills is one of the best undeveloped assets in the Athabasca region and is a natural fit with our business strategy of acquiring and developing long-life assets in stable jurisdictions,” said Don Lindsay, Teck’s president and CEO. Current estimated capex to bring the operation into production is some C$13.8 billion. The project’s capital intensity of approximately $84,000 per daily flowing barrel of bitumen is within the range of similar recent oil sands projects, Teck noted in its 2013 annual report.

The Fort Hill partners have selected Enbridge to build a new pipeline from the Fort McMurray area to the Hardisty hub. Budgeted at C$1.6 billion, the 450-km-long Norlite pipeline will have a capacity of up to 490,000 bbl/d of dilbit sourced both from Fort Hills and from Suncor’s existing operations. (See this month’s Suppliers Report, p. 125, for news on additional developments related to oil sands mining and the Fort Hills project.)

Teck is also the 100% owner of the Frontier prospect, for which the company has submitted a mining application. If granted, the operation could come on stream by 2021 at an initial capacity of 74,600 bbl/d. Last year, Teck and Shell exchanged some assets between Frontier and Shell’s adjoining Pierre River lease, with the aim of optimizing both projects.

Canada’s federal government has approved Shell’s 100,000-bbl/d Jackpine mine expansion project, despite finding that it may cause significant adverse environmental effects—that it believes are justified in the circumstances. The project will double Jackpine’s capacity, but has yet to receive provincial approval.

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The Mining Association of Canada announced Syncrude’s Sandfill Fen research project, pictured here, as the winner of its inaugural Toward Sustainable Mining Award for Environmental Excellence. The project covers 52 hectares of sand-capped soft tailings from Syncrude’s former East mine, where the company has introduced a variety of wetland plants, and planted trees and shrubs on the surrounding uplands.


Technology Advances

Despite hot-water recovery having been in use for nearly 50 years, Canada’s oil sands producers are always looking for process innovations. Progress in developing new systems has led to significant reductions in energy usage, as well as lower emissions, while the first fruits of successful tailings-pond reclamation are now on display.

Nonetheless, research efforts are continuing in a number of areas. According to a recent edition of the Alberta Oil Sands Industry Quarterly Update, Western Hydrogen Ltd. has begun two pilot projects that could benefit the oil sands sector—one by reducing the cost of hydrogen needed for upgrading, and the other by removing the need for diluent.

Bitumen upgrading can follow two routes; either using cokers to remove carbon, or by adding hydrogen. Western Hydrogen’s molten salt gasification process uses water and a carbonaceous feedstock to produce hydrogen and compressed CO2, which can be sequestered or used in EOR. Meanwhile, its molten sodium bitumen upgrading concept breaks down bitumen, extracts sulphur and heavy metals, and produces an oil that is light enough to transport without diluent.

Looking further ahead, in June Syncrude committed funding for a five-year University of Saskatchewan research program that aims to help the oil sands industry make sustainable mine closure decisions. The researchers will study byproducts such as sand, treated fluid fine tailings and petroleum coke, and analyze changes to these materials after they are used to form reclaimed landscapes. The study aims to develop strategies for the placement of these materials to minimize their potential environmental impact.

And in May, the Mining Association of Canada named Syncrude’s Sandfill Fen research project as the winner of its inaugural Toward Sustainable Mining Award for Environmental Excellence. Syncrude developed the project on 52 hectares of sand-capped soft tailings at its former East mine, introducing a variety of wetland plants and planting trees and shrubs on the surrounding uplands. With monitoring scheduled to last for 10–20 years, the project will be invaluable in improving wetland reclamation design and practices, Syncrude believes.

Last December, Shell Canada and Caterpillar signed an agreement to test a new engine and fuel mix using liquefied natural gas (LNG) that could reduce operating costs and lead to reduced emissions from oil sands mining. Caterpillar will design and build a fully integrated mining truck where LNG displaces most of the diesel power, and will test it at Shell’s operations. Shell also plans to retrofit some of its existing trucks with the new engine for the trial.

Field testing of the dual-fuel trucks should begin in 2016, with the trial expected to last up to one year.

In a report published in October 2012, the Conference Board of Canada noted that cumulative investment in Canada’s oil sands in the past decade has surpassed C$100 billion, and that C$364 billion in price-adjusted investment is expected to take place over the next 25 years. As a result, Canada is expected to become the fourth-largest oil producer in the world before 2035, only behind Saudi Arabia, the U.S. and Russia. The report pointed out that domestic policy-makers will need to consider issues such as sustainable development, building adequate infrastructure, workforce training, labor force mobility and fiscal implications, amongst others. Given the role of foreign businesses in both developing the oil sands and ultimately in where the final product will be consumed, Canada’s foreign policy will also be a factor, it added.

In the meantime, Canada’s oil sands producers have other issues to contend with. U.S. oil inventories are high, pipeline capacity is constrained, U.S. “tight” oil production is increasing rapidly and Canadian synthetic oil trades at a discount to its U.S. domestic counterpart. And, of course, environmental issues continue to dog the industry. Nonetheless, investment is continuing apace, with high-cost new mines and SAGD projects under construction and awaiting approval. That is hardly a sign of an industry under unmanageable pressure.