Key insights from the Duvernay Shale

 July 2018

Key insights from the Duvernay Shale

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Ryan Carbrey, SVP Analysis
Thomas Jacob, Senior Analyst
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The Duvernay shale covers around 130,000 square kilometers in Alberta, Canada. The formation was deposited during the Upper Devonian age (372 million years ago) and consists of laminated bituminous shale and argillaceous limestone. The shale members within the Duvernay formation are the primary target zones for unconventional development. Net pay varies considerably across the play with thickness reaching 200 feet (~60 meters) in selected areas.

The large differences in formation depth for the Duvernay shale have resulted in three thermal maturity windows, including a dry gas window, a wet gas/condensate window, and a light oil window. The formation top of the Duvernay shale ranges from 5,600 feet (~1700 m) to 16,400 feet (~5000 m) deep. The depth, formation pressure and gas-oil-ratio increase as we move from northeast towards the southwest area of the play.

The Duvernay shale has experienced steady growth in production since 2010. Average daily production in 2017 was just over 70,000 barrels of oil equivalent per day on a 3-stream basis, a 25% YoY increase compared to 2016 numbers. The compounded annual growth rate (CAGR) from 2015-2017 was 45%, an indicator that the play is moving into a further development phase. The majority of the production from the play as a whole is still gas. In 2017, 75% of the total production from the play was gas while 25% was liquids.  This is the same hydrocarbon split we see for the Kaybob region, most active region in the play. This region straddles the gassy and liquids-rich windows of the play. The development of Duvernay is mainly focused on the Kaybob region and the Willesden Green region in the southeast.

Average Duvernay well curves have improved in the past few years. Wells put on production in 2017 were showing large improvements compared to the average well curve from 2014 to 2016 vintage wells. Looking at average lateral length for these wells, we can also see an increase year over year from 5,600 feet in 2014 to the average 8,000 feet we saw from wells put on production in 2017, indicating that the changes in well configuration are materializing into improved well productivity on average.

In terms of 90-day initial production rates, the Kaybob area has generally shown the most impressive performance. For wells put on production in 2017, the 90-day IP was almost 50% higher than in the Willesden Green region. On the other hand, the Willesden Green area has much higher light oil content compared to Kaybob. Wells turned in-line in 2017 showed an average ~88% light oil content from the Willesden Green region, mainly coming from the East Shale Basin. Compared to ~8% light oil content from the Kaybob region.

70% of wells spudded in 2017 were in the Kaybob region. Taking a closer look at the major operators in this region, we see the same trend with increased well productivity alongside the increased average lateral length for the well vintage. In 2017, Encana’s wells exhibited the highest average estimated ultimate recovery in the play as a whole at just over 800,000 barrels of oil equivalent. Since the chart only includes wells with at least 9 months of reported production, the decrease in EUR for Chevron’s 2017 wells can be due to this fact. The majority of Chevron’s 2017 wells were put on production in the last months of the year.

In the past, majors such as ExxonMobil, Shell, and Chevron have been the dominant drillers in the Duvernay shale, along with a few other E&P companies mostly focusing on the Kaybob region. In the past few years, however, more private companies and smaller E&P players have moved into the play. In the Willesden Green region and especially in East Shale Basin, we see mostly smaller E&P- and private companies operating. The large increase in light oil content in Willesden Green region in 2017 is mainly driven by two private operators: Artis Exploration and Vesta Energy. Vesta Energy spudded, completed and turned-in-line ~65% of all 2017 wells in the East Shale Basin. The company has 200,000 net acres in the southeast liquid-rich window of the Duvernay shale.

Duvernay is still considered as a play in the early development phase, with the Kaybob region being the most mature and the East Shale Basin still in an exploration phase. Due to the varying hydrocarbon phase windows, geomechanical drilling issues (mainly due to the middle carbonate member) and the fact that the wells in the area still are among the most capital intensive, the play is still not in a full development phase. However the improvements in well cost, where we saw an average well cost of ~$8.5 million in 2017 compared to almost $10 million in 2015, together with the improvements in well configurations, well productivity, and the fact that smaller companies are showing interest in the play, could potentially drive activity even further for this western Canadian liquid-rich play.