Oil sands back in the game

Some of the biggest oil companies in the world gathered for meetings last week in Davos restated their intentions to increase efforts to standardize equipment in order to reduce supply costs, despite recent signs of recovery in oil prices. The message matches with recent changes in the Canadian oil sands industry to address a scenario where a new long-term boom in crude prices seems still unrealistic. By redesigning systems and replicating technologies, some Canadian producers have experienced significant cost savings, reducing the distance to the benchmark US crude oil price.

Oil sands operators are among the most costly producers in the world. Unlike conventional oil, recovered by traditional drilling and pumping, oil sands production involves extensive mining and refining processes, and requires massive upfront investment in infrastructure. Large deposits of oil sands, such as the Kearl project in the Athabasca region, can cost more than $15 billion to develop.

After the oil price downturn in 2014, Canada experienced a progressive write-down of oilsands reserves. According to the EIA, commercially recoverable reserves in Canadian oil sands projects dropped by 5 billion barrels among 67 oil companies listed on U.S. stock exchanges in 2015-2016. The oil sands write-down included giants such as ExxonMobil and ConocoPhillips. Other companies, such as Shell, Marathon Oil, and Norway's Statoil, scaled back oil sands operations or completely dropped out of the projects.

However, while big companies shrank their oil sands portfolios in favour of fast returns at shale plays in Texas and Oklahoma, or even at Brazil's offshore sub-salt, Canadian independent oil companies stayed at home actively lowering supply costs through innovation and replication in order to boost recovery and production on existing projects.

Companies such as Canadian Natural Resources and Cenovus kept investing in the oil sands after the oil drop, in spite of their high cost. According to the Canadian investment bank GMP FirstEnergy, the latest expansion of 80,000 barrels per day at Canadian Natural's project Horizon, will require a WTI US$20, comparable to the $25 Texas’ Permian Basin break-even price. Cenovus Energy, in turn, estimated a break-even price for 2017 just over WTI US$40, down from over WTI US$60 in 2014. 

Although greenfield oil sands project are still not economically feasible under the current oil prices, recent expansions in the oil sands are coming up at considerably less cost than original estimates a few years ago. In its 2017 outlook, the Canadian Energy Research Institute reported that the rising marginal barrel cost in oil sands still requires increasingly complex supply developments, but the drive for more efficiencies and innovative technology will partially limit the overall expenditure.

A recent estimate for oil sands cost production in Canada showed independent Suncor Energy with a break-even of WTI US$37, when the best wells in U.S. shale basins requires typically WTI US$30 to US$35. The cost was reduced as Suncor cut back the engineering hours at well pads by 90%. According to the news, Suncor plans to use identical facilities in 10 other locations with a potential of 40,000 barrels per day. Imperial Oil also would express the intention to use the same strategy for leaner facilities.

Companies are also focusing on shrinking the size of their well pads and reducing the amount of equipment they use. Husky Energy, for example, has manifested the intention to build well pads at its operations along the Alberta-Saskatchewan border in small 10,000 barrel-per-day increments. The strategy is selecting smaller-scale projects that can be executed in a couple of years and be flexible to manage costs more effectively, say analysts.

Advances are being achieved in situ oil sands production, when the bitumen is deep within the ground. About 80% of the oil sands reserves in Canada are recoverable through in situ technology, while in 20% the bitumen has to be mined close to the surface through extensive open-pit mining operations.

Most in situ operations use the steam-assisted gravity drainage method (SAGD), where steam is pumped underground through a horizontal well to liquefy the bitumen, then recovered through a second well. Technologies such as directional drilling are enabling in situ operators to drill multiple wells from a single location, gradually reducing the number of well pads required. Complementary savings are coming from improvements in drilling and completion, reducing time-cost per well.

The company MEG Energy reported decreasing costs of at WTI US$45 per barrel by implementing innovations such as injection of non-condensed gas into wells to retain heat in the reservoir. The change reduces the use and cost of natural gas used to heat water at SAGD facilities. Canadian Natural plans to use a similar technology at its Kirby North project, currently under construction. In turn, rival Suncor is running tests using radio waves, instead of steam, to heat the sand in order to increase the flow of oil to the surface.

Improved well pad designs and other recent efficiencies are seen by analysts in Canada as part of a rebirth momentum of the oil sands. These innovations are being considered by some experts a force similar to the impact that hydraulic fracturing had on tight oil.

New oil sands projects will most likely not be announced until oil prices rise in a more consistent uptrend. Meanwhile, production increases on existing projects will help to compensate new project deferrals.

With the recent oil price rise, shale plays in Texas and Oklahoma are again experiencing incremental increases in investments, but oil sands producers count at least on one advantage against their rivals in the Permian basin: many of the tar sands deposits hold 50 years of oil, while shale wells are typically exhausted within months.