Analysis: Sunny Days Ahead For Duvernay Shale Oil

It may be early days for development of the Duvernay shale in Alberta, but it is increasingly looking like the next liquids-rich formation to take off in North America.

A recent report by the National Energy Board (NEB) and Alberta Geological Survey (AGS) paints development of the Duvernay as an attractive alternative investment for companies to the oilsands region, albeit on a much smaller scale. In addition, global majors, many of whom missed the U.S. shale rush, are looking elsewhere to invest in short-cycle shale oil — and natural gas. As a result, rapid development of Duvernay shale could contribute to significantly higher Western Canadian oil production through 2030 than generally forecast.

Duvernay shale in west-central Alberta encompasses 20 per cent of the province. The shale is rich in organic matter, ranges in thickness from zero to 100 metres and is found between one and five kilometres underground. The formation tends to get prospective at depths below 2 km, is generally oily in areas shallower than 3 km and gassier in areas deeper than that.

The joint NEB-AGS report released in September estimates Duvernay shale to have 3.4 billion barrels of marketable crude oil and condensates and 6.3 billion barrels of NGLs —  compared to 165 billion barrels of crude bitumen for the oilsands —  and 76.6 trillion cubic feet of natural gas. The marketable liquids are almost half of Eagle Ford’s in Texas, while the report indicated its estimate for the Duvernay is likely “conservative,” especially for crude and condensates, given the oily eastern portion of the formation is barely explored.

The NEB released a follow up report in November providing the economics for marketable Duvernay shale resource. Based on 2017 light sweet crude prices, natural gas prices and well costs, 1 billion barrels of crude oil, 1.4 billion of NGLs and 12 trillion cubic feet are economic. At slightly lower well costs and modestly higher crude oil and natural gas prices, the Duvernay’s economic crude oil, NGLs and natural gas production jump to 2.2 billion barrels, 3.4 billion barrels and 32.9 trillion cubic feet.

Companies have been drilling for shale gas and oil in the Duvernay since 2011, with most development activity focused in the NGL-rich West Shale Basin, such as the Kaybob field northwest of Edmonton. But recent provincial land sales have been showing increasing industry interest in the oily East Shale Basin.

Royal Dutch Shell and Encana had been leading development of the West Shale Basin, but a Canadian subsidiary of U.S. major Chevron — with Kuwait Foreign Petroleum Exploration Company holding roughly a 30 per cent stake — recently jumped on the bandwagon. In November, Chevron Canada made a formal decision to begin commercial development in a section of its holdings in the Kaybob field, after a three-year appraisal program in the area. In making its announcement, Chevron referred to the Duvernay as “one of the most prospective liquids-rich shale plays in North America.”

Interestingly, Chevron has proven a trendsetter by leading development of Argentina’s Vaca Muerta shale over the past several years in conjunction with state-owned Yacimientos Petroliferos Fiscales (YPF). A number of other global majors have since followed Chevron’s path to Argentina, including ExxonMobil, Royal Dutch Shell, Total and BP-controlled Pan American Energy.

Global majors tend to be underweight shale production, as smaller independent companies led the boom in the U.S., and many of them are looking to add additional short-cycle shale to their portfolio, but at lower cost than in the U.S. The best shale resource, such as Duvernay, has relatively low upfront investment and quick payout compared to other plays such as deep offshore and oilsands, which is especially attractive in a volatile, lower oil price world. Shale in established oil producing regions, with well-developed pipeline networks and regulatory regimes, is especially attractive to oil companies.

Relative minnows such as Artis Exploration, Vesta Energy and Raging River Exploration have been leading the charge in the East Shale Basin the past few years, but based on recent land sales the region appears to be garnering attention of more substantial oil companies. Activity in the East Shale Basin is believed to be largely responsible for the province collecting $180 million in land sale revenue in the first half of this year, up from $64 million for the same period last year. At a land sale on April 26, an undisclosed buyer paid $4,200 per hectare for the right to drill on a parcel of land in the East Shale Basin. For the sake of comparison, land sales in the area seldom exceeded $300 per hectare in 2016, and these parcels were small and adjacent to successful wells.

Kaush Rakhit, chief executive officer of Western Canadian oil and gas consultancy Canadian Discovery has recommended further study of the East Shale Basin be undertaken as he believes its oil potential is substantially greater than estimated. According to Rakhit, the East Shale Basin could hold between 30 billion and 60 billion barrels of oil, with drilling costs below $5 million per well — less than half the cost of wells in the West Shale Basin — as the resource tends to be between 2 km and 2.2 km below the surface and trending towards $4 million given continuing improvements in drilling efficiencies.

Development of the Duvernay shale formation may be in its infancy, but it could ramp up quickly based on the experience of major U.S. shale plays. For example, the Eagle Ford region saw exponential growth in production between January 2010 and March 2015, increasing from 55,000 b/d to a peak of 1.72 million b/d, before slipping back to 1.22 million b/d since the oil price crash.

Assuming spot WTI averaging at least US$60 to US$70 per barrel and a moderate decline in well costs, liquid production from Duvernay could easily hit 500,000 b/d by 2030, if not substantially higher, especially with deep-pocketed global majors in the hunt for affordable shale resource.

In this case, oil supply from Western Canada would be significantly higher than anticipated in the future. For example, the Canadian Association of Petroleum Producers (CAPP) is forecasting regional oil supply to increase by 1.5 million b/d to 5.4 million b/d between 2016 and 2030, with oilsands the sole driver of this growth. In fact, CAPP is projecting conventional oil production —including shale oil — in Western Canada to decline 86,000 b/d to 815,000 b/d over this period.