Oil Sands: Canadian Producers Practice Cost Control

Crude bitumen being recovered in a separation cell at Suncor’s primary extraction plant. Mine-won bitumen is then usually upgraded before being shipped south to U.S. and Canadian refineries. (Photo: Suncor)

Record oil production from the U.S., coupled with nearly static consumption, has the oil sands industry looking for new pathways to profitability

By Simon Walker, European Editor

What a difference 12 months can make. As E&MJ reported in its last article on the North American oil sands industry (August 2014, pp. 28–34), the major players in Alberta were in the main comfortable with their lot, with capex dollars still readily available for both expansions and new project development. In mid-2014, oil, as measured by the value of industry standard West Texas Intermediate (WTI), was trading at around US$105/barrel (bbl), albeit within an economic setting that had already encountered rocketing U.S. shale gas production and burgeoning “tight oil” output from previously inaccessible formations.

Roll the calendar along to mid-2015, and what has changed? For a start, a barrel of WTI on the spot market would have cost barely $60 in June, although that was hardly bargain-basement for the year. According to data published by the U.S. Energy Information Administration (EIA), in mid-March that same barrel had a value of just under $44.

As for markets, the U.S. is the key factor. According to BP’s annual Statistical Review of World Energy, the U.S. not only became the world’s leading oil producer in 2014, but also reported an unprecedented trend in increasing oil production by more than 1 million bbl/d for three consecutive years. On the other hand, while overall energy consumption rose by 1.2% relative to 2013, oil consumption was only marginally higher, and was 1.8 million bbl/d lower than the record set in 2005. It does not take much interpretation to see that record production coupled with near-stagnant consumption means there is a fairly large pond of oil available in the marketplace: hence the lower price.

And, of course, the long-standing questions about transporting Canadian bitumen and synthetic crude to consuming refineries south of the border remains unanswered. Last year’s article looked at the proposed Keystone XL pipeline, noting that no presidential decision was likely before the November 2014 congressional elections. How right indeed; come mid-2015, and no presidential decision not only remains the status quo, but seems likely to remain so for the rest of President Obama’s tenure.

Against that backdrop, it would be understandable if Alberta’s oil sands industry had considered taking a cautious view on its economic base, and had trimmed output accordingly. Not a bit of it, with its main thrust being to cut production costs in order to maintain margins at the lower prices. Operating cost belt-tightening is the order of the day, as well as reining in on capital spending.

Oil Sands in a World Market

Before looking at the individual companies, their projects and their plans, it is perhaps helpful to take an overview of how the world energy market has changed in recent years. Northern Alberta may be geographically isolated, but once the output from its bitumen mines reaches consumers south of the border, that oil faces direct competition from domestic U.S. producers, who in turn have to operate within the wider international context.

Welcome to the world of energy politics. Whether or not the cartel members of the Organization of Petroleum Exporting Countries (OPEC) felt threatened by growing U.S. domestic production and the country’s reduced reliance on oil imports is a moot point; they have just kept pumping despite the falling price. Indeed, the view within some sectors of the world oil industry is that Saudi Arabia in particular is aiming to undercut U.S. producers who do not have the cost resilience to withstand long periods of low prices. The Saudis have done it before, Pipeline & Gas Journal Editor Jeff Share reminded the industry in his January column, and now seem to be intent on weeding out higher-cost U.S. production in order to push prices up again.

Whether that strategy works has yet to be seen. With both oil and natural gas production up dramatically over recent years, the U.S. economy is riding high on the energy boom, with industry in general benefiting from lower energy costs. Not that that is good news all round, of course—low-priced oil and gas has led to significant job losses within the energy sector, in western Canada as well as in the U.S.

Work on Syncrude’s C$1.9 billion tailings centrifuge plant has taken three years to complete. The plant removes water for recycling, while transforming slow-settling clays into solid residue. (Photo: Syncrude)

Alberta’s Oil Sands Keep Growing

Data collected by the Alberta Energy Regulator (AER) show that the province’s oil sands industry produced 366,300 m³/d (2.3 million bbl/d) of crude bitumen last year, up 10.5% on 2013. Of this, bitumen from the six mining operations totaled 165,100 m³/d, while in-situ producers contributed a further 201,200 m³/d; bitumen accounted for 81% of Alberta’s total oil and bitumen production during the year.

On an annual basis, in 2014, Alberta produced 133.7 million m³ (841 million bbl) of crude bitumen, comprising 60.3 million m³ (379 million bbl) from the mines and 73.4 million m³ (462 million bbl) from in-situ. In terms of upgraded production, there was a big disparity between the two sources, with 92.3% of mined crude bitumen, but just 10.5% of in-situ output being upgraded in the province. The total provincially upgraded yield reached 55.3 million m³ (348 million bbl), up about 2% year-on-year.

With lower capital costs and shorter startup times, in-situ production has been the growth leader in Alberta’s oil sands industry. The AER noted that in-situ production overtook mined output of crude bitumen in 2012, and last year accounted for 55% of the province’s total—a figure that is expected to reach 60% in 2024, when output from this source may reach as much as 384,000 m³/d. This is slightly more than the AER forecast last year, while its view for mined output in 2024 is lower, at 258,000 m³/d as some projects are delayed or canceled. The number of producing in-situ wells in northern Alberta has risen steadily since 1998, when around 65 were in operation, with the number producing bitumen having nearly tripled to some 180 in 2014.

Table 1—Run-of-mine ore and bitumen production, 2014.

Looking at the individual mining producers (See Table 1), Syncrude’s crude bitumen output for the year was 18 million m³ (113.3 million bbl), won from 170.7 million m³ of sand. Suncor produced a little more than 100 million bbl from its base operations, having stripped 149.1 million m³ of sand. Output from the two operations in which Shell is the lead partner totaled 88.9 million bbl from 134 million m³ of ore, while Canadian Natural Resources’ Horizon mine produced 77 million m³ of sand and 47.4 million bbl of bitumen. The newcomer to the list, Imperial Oil’s Kearl operation, was still in ramp-up during the year, and contributed 29.1 million bbl of bitumen from 48.7 million m³ of sand mined.

In terms of reserves, the widely held view is that Alberta hosts the world’s third largest oil resource, after Venezuela and Saudi Arabia. Bitumen resources are estimated at 26.4 billion m³ (166.3 billion bbl), with mineable reserves (to a depth of 65 m) comprising just under 20% of the total. Reserves and cumulative production in the current mining operations are shown in Table 2.

Table 2—Mineable crude bitumen reserves in areas under active development, December 2014.

Transport Issues Still Unresolved

If the dramatic growth in U.S. oil and natural gas production has done nothing else, it has certainly focused attention on shortfalls in the country’s transport infrastructure. As an example, while North Dakota has become a center for “tight” oil production, companies operating there have experienced considerable constraints in getting their output to market. The existing pipeline network basically missed out what had previously been assumed to be barren ground for oil and gas, leading to an unacceptable level of gas flaring simply because oil producers have had no other way of handling it.

The short-term solution in many cases has been to draft in fleets of rail wagons, with a massive increase in the rail transport of oil from areas that are not on the main pipeline routes. As the recently published Quadrennial Energy Review noted, in 2009, some 10,900 car-loads of crude oil originated on the U.S. rail network. Last year, the figure was more than 493,000, with the EIA estimating that more than 1 million bbl/d of U.S. and Canadian crude was moved by rail during the year.

The challenge, as ever, is to ensure safety, with the pipeline lobby vocal in pointing out the dangers inherent in accidents involving oil wagons. And, of course, pipelines are not exactly renowned for providing 100% integrity, which has been a key debating point for opponents of TransCanada’s Keystone XL and other proposed long-distance pipelines such as Enbridge’s Alberta Clipper.

Both companies are now supplying U.S. Gulf Coast refineries with Canadian oil-sands dilbit and crude, using their existing pipelines and newly built extensions that run from Oklahoma into Texas. Both networks can carry up to 850,000 bbl/d, while the proposed Keystone XL and Alberta Clipper pipelines would add a further 2 million bbl/d in capacity.

However, it is not just in the U.S. that TransCanada is seeking approval for new oil pipeline capacity. Its proposed 4,600-km-long Energy East line, which could move 1.1 million bbl/d of western Canadian crude to refineries in eastern Canada, involves both converting existing natural gas pipelines and laying new oil pipe. Carrying a $12 billion price tag, the project envisages Alberta oil-sands crude flowing to Ontario, Québec, and New Brunswick by 2018, if permitting is achieved.

Meanwhile, the U.S. Department of Transportation and Canada’s Ministry of Transport recently published the last in a set of new safety rules for trains that include oil wagons. Among these are requirements for new tank construction designs, enhanced automatic braking systems, and a 50-mph (80 km/h) speed restriction. Not surprisingly, the Association of American Railroads was quick to flag up the implications for other traffic—and hence network capacity—of slow-moving trains.

Since coming on stream in 2010, TransCanada’s original, less direct Keystone pipeline has carried more than 900 million bbl of Canadian crude to U.S. consumers. Speaking at the company’s annual meeting in May, CEO Russ Girling said, “We need a pipeline from Alberta to the Gulf Coast, and in the absence of that, we’ve moved to greater rail transportation.

“We’ve seen rail transportation go from essentially zero to 1.5 million bbl/d,” he added. “Certainly that has greater impact on [greenhouse gas] emissions, safety and the environment than building a pipeline.” So with the Keystone XL project in limbo, President Obama having vetoed Senate approval for it in February, Syncrude and the other oil-sands miners will have to hold on a while yet to see whether they can get easier access to their main market.

Oil pipeline under construction in North Dakota. Transport bottlenecks are proving a major handicap to Canada’s oil sands miners and U.S. tight oil producers alike. (Photo: TransCanada Corp.)

Fort Hills Keeps the Mining Flag Aloft…

The three project partners, Suncor (40.8% and operator), Total E&P Canada (39.2%) and Teck Resources (20%), gave the go-ahead for the $13.5 billion Fort Hills project in October 2013. By the end of last year, engineering and construction were, respectively, more than 65% and 20% complete, with Teck reporting in February that equipment and material deliveries had started, civil works were under way and some off-site modular and process facility construction had begun.

Lying about 90 km north of Fort McMurray, Fort Hills has a 3.3-billion-bbl bitumen proven and probable reserve. Production is planned to begin in late 2017, with a ramp up to 90% of its nameplate 180,000 bbl/d achieved within a year. Mine production of 110 million mt/y will come from two open pits at a throughput of 14,500 mt/h, with run-of-mine ore being treated using solvent-based extraction technology that produces bitumen for direct sale to the market. Secondary extraction will involve the use of high-temperature paraffin to recover a cleaner bitumen product than can be achieved using conventional naphtha.

Speaking at BMO Nesbitt Burns’ mining conference in February, Teck CEO Don Lindsay confirmed the partners’ commitment to Fort Hills, notwithstanding the slide in oil prices. “The short-term oil price weakness does not affect our decision on a 50-year asset,” he was reported as saying. “All three of us are fully committed to finishing the project. By the end of this year, we should be 50%–55% complete.

“At this point, about C$11 billion of the C$15 billion of contracts have been committed,” Lindsay added, noting as well that from Teck’s operational perspective, low oil prices were no bad thing. “A low oil price is very, very good for Teck for the next three years,” he said. “In fact, my preference would be about $40 this year, next year and 2017. And then back to $70 or even $80 would be just fine.”

As Lindsay stated, many of the major contracts for Fort Hills have been awarded. Fluor Corp. picked up the $1.3 billion EPFC utilities contract (See E&MJ, October 2014, p. 10), relying on its proprietary modular design and execution strategy. South Korea’s SK Engineering and Construction Co. (SK E&C) has a $2.55 billion contract for engineering the primary extraction facilities, which are scheduled to be commissioned a year before the secondary recovery unit in order to reduce the risk of cost inflation.

SK E&C had already done the basic front-end engineering design work for the project, and will be building some of the smaller plant modules in South Korea. Vessels, piping and structural steel will come from South Korea and the Philippines.

Another company that built successfully on previous work on the project, WorleyParsons has the $140 million detail engineering contract for the ore-preparation plant, primary extraction and tailings. Honeywell Process Solutions is the main automation contractor for Fort Hills, handling all aspects of automation, while Aecon has a C$123 million contract covering mine-site development.

A $250 million turnkey contract for the cogeneration plant went to Spain’s Tecnicas Reunidas, including two 85-MW gas turbines and two heat recovery steam generators, while KSB subsidiary GIW industries is to supply 12 process water pumps with capacities of up to 6,125 m³/h. And telecoms needs are being supplied by SNC Lavalin subsidiary Kentz Canada, which has a C$70 million contract covering the full engineering, design and procurement of the project’s telecommunication systems.

As far as moving product to market is concerned, TransCanada is spending $800 million on constructing the twin Northern Courier pipelines to link Fort Hills to Fort McMurray, and Enbridge has committed $1.4 billion to its new Norlite pipeline, which will transport an initial 270,000 bbl/d of diluent from Edmonton up to the oil sands region. Enbridge also has plans for the $1.6 billion, 490,000-bbl/d Wood Buffalo crude oil pipeline in the opposite direction, providing transport capacity for Fort Hills and for Suncor’s other operations.

…While Others Pull Back

While Fort Hills is going ahead at full throttle, the uncertain oil market has also taken its toll on the oil sands project. In February, Total, Suncor and their partners withdrew their application for amended permitting for the Joslyn North mine, having already spent a year trying to re-engineer the 160,000-bbl/d project—originally permitted in 2011—to trim costs. Total booked a $2.2 billion write-down against its Canadian oil sands operations in its 2014 accounts, while focusing on Fort Hills and its 118,000-bbl/d Surmont steam-assisted gravity drainage (SAGD) joint venture with ConocoPhillips, where first Phase-2 steam came on stream in May.

Already in production at Muskeg River and Jackpine through the Athabasca Oil Sands Project partnership with Chevron and Marathon, Shell has also withdrawn its application for permitting at the 200,000-bbl/d Pierre River mining project, to the west of the Athabasca River, north of Fort McMurray. “The Pierre River mine remains a very long-term opportunity for us but it’s not currently a priority,” said Lorraine Mitchelmore, president of Shell Canada. “Our current focus is on making our heavy oil business as economically and environmentally competitive as possible. We will continue to hold the leases and can reapply in the future when the time is right.”

These two companies’ announcements followed those made last September by Statoil, which has suspended activities at its Corner in-situ project for at least three years.

Enhancing the Technology

The basic principle of using warm water to separate bitumen from its sand host was invented in 1925, since when it has provided the foundation for bitumen recovery in Alberta. Nonetheless, all of the producers have realized the value of improving the technology as a means of enhancing recovery, with a provincial government requirement covering resource recovery during both mining and processing.

As an example, in 2012, the Alberta Energy Regulator placed Shell’s Muskeg River mine under high-level enforcement action, the company acknowledging that it had challenges in meeting its bitumen recovery commitments. Following the completion of two technical upgrades, the company received compliance clearance in March.

The work included extending the plant’s slurry conditioning line, so allowing the bitumen longer to separate in the warm water. Shell also undertook studies on increasing the temperature of the piping into the ore preparation area, to warm the bitumen before separation and increase recovery during warm-water extraction. The company noted that these modifications were incorporated during the construction of its Jackpine recovery plant, which had already been certified as being compliant.

Imperial Oil’s Kearl is the latest mine to have come on stream, with production ramping up to the initial 110,000-bbl/d capacity. The company noted that the proprietary paraffin-based froth treatment process used means that it does not need an upgrader, while its energy costs are lower. Kearl has also commissioned an 85-MW cogeneration plant to cut its demands on the provincial grid and reduce emissions, and recently completed its 110,000-bbl/d expansion project, doubling the number of processing trains to six.

At the other end of the pipeline, Shell is virtually ready to begin injecting CO₂ from its Scotford upgrader near Edmonton into sequestration reservoirs. The Quest project aims to capture and store more than 1 million mt/y of CO₂, representing about 35% of the upgrader’s annual emissions.——–

Cut Costs to Keep Profitable

With their huge capex commitments, oil sands mining projects are clearly at a disadvantage in the competitive oil market. To give an idea of the disparity, in the middle of last year, Norwegian consultancy Rystad Energy presented a comparison between different currently untapped oil sources. Within wide bands, onshore conventional oil then had an average break-even price of $55/bbl, U.S. shale “tight” oil $62/bbl and oil sands $74/bbl, compared to Middle Eastern onshore at just $29/bbl.

However, those very high capital budgets may well act as a foundation for oil sands mining survival in a low-price oil market, for the very good reason that operators will prefer to run at cost or even below rather than incur the vast expense of idling capacity. After all, multibillion-dollar projects are rarely built to be swing producers.

In a report last year comparing Alberta’s oil sands with U.S. shale oil, Scotiabank Economics estimated that existing oil sands mining operations have break-even full cycle costs of $60–$65/bbl, although pointing out that new projects are considerably higher at $100/bbl if upgrading is included.

In the meantime, good news for the industry is that the differential that has traditionally existed between WTI and bitumen-based heavy crude has narrowed significantly in recent months, mainly reflecting increased demand from Gulf Coast refineries. What is normally a 20% discount had fallen to 12% in July, while Syncrude Sweet synthetic crude was trading at a premium.

Another reason for the reduced discount had been a cut in supplies over the first half of this year, as several operators undertook major maintenance on their systems. Shell, Canadian Natural Resources and Suncor have all had planned maintenance under way on their upgraders; last year, both Syncrude and Suncor suffered production losses when critical equipment became unserviceable.

A further plus point for the industry has been the depreciation of the Canadian dollar against the greenback. Local costs in Canadian dollars, revenue in U.S. dollars has helped mitigate lower U.S. prices to a degree, with companies striving to get those C$ costs down further. Suncor, for example, reported cash costs down from $37/bbl in 2013 to $33.80/bbl in 2014.

Interviewed earlier this year, Andrew Leach, Enbridge professor of energy policy at the University of Alberta, gave his views on the road ahead for the province’s oil sands. “Oil sands production will continue to increase in the near term, likely through 2020 if not beyond, unless prices decrease materially relative to today.

“If they remain as low as they are, there’s certain to be a downward revision in the long-term growth forecasts for oil sands, but don’t expect production to decline in the near term,” Leach advised.