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Shale companies: efficiency vs. productivity

Oilfield Technology,

Shale companies have proven more efficient but not more productive, according to analysis from Rystad Energy.

Dedicated tight oil activity in the US has been going on for over five years already, yielding more than 60,000 wells drilled to date. With such high activity level, significant learning has been achieved through the years mainly in drilling efficiency and well configuration. However, this learning has not been as noticeable in well performance – year after year wells have shown similar initial production rates and decline curves, especially in mature plays such as Eagle Ford and Bakken.

The chart shows the average 30-day initial production rate and light-oil content at wellhead for selected tight oil plays. For the Permian plays, only horizontal wells have been included.

From 2010 to 2014 the average 30-day initial production rate has slightly increased for wells drilled in Eagle Ford, Bakken, Permian Delaware and Niobrara, without exceeding 100 boepd. Wells drilled in Permian Midland, however, have experienced a larger increase with nearly double 30-day initial production rates during the same time span. The light-oil content has stayed nearly constant in Permian Midland, similar to Bakken, while it has significantly increased year after year in Eagle Ford, Permian Delaware and Niobrara. Operators have succeeded at targeting the areas with high oil content within these plays, indicating improvements in well placement.

In terms of efficiency, since 2010 companies have consistently decreased the drilling time mostly due to pad drilling. Bakken, Eagle Ford, Niobrara and the Permian plays have all experienced a significant increase in pad drilling since 2010. This trend is expected to continue during 2014. Among these plays, Permian Delaware has the most growth potential in the share of pad drilling to possibly reach 75%-95% similar to other tight oil plays. The increase in pad drilling has represented a slight reduction in the unit well cost since drilling accounts for only 30% of the total well cost. Meanwhile, completion costs have increased during the last years due to longer laterals, more frac stages and deeper wells in all tight oil plays. Lateral length alone has increased around 25%-55% from 2010 to 2014 in plays such as Bakken, Niobrara and Permian Delaware, according to official data. The average number of frac stages in Bakken wells increased from 22 to 30 during 2010-2013, with companies such as EOG Resources having 50-70 frac stages in several Bakken wells since 2013.

Even though the well configuration has become more complex with increased area of contact between the well and the formation (due to longer laterals and more frac stages), the average decline curves for Bakken and Eagle Ford wells have not shown significant changes since 2010. The major improvement can be observed in the increased 24-hr initial production, but this rate rapidly declines.

However, significant well curve improvement has been observed in the average Niobrara and Permian wells. Horizontal wells in Permian Midland have experienced the greatest well curve improvement since 2010. In this play, the wells drilled in 2013 had more than double cumulative production after 11 months than the wells drilled here in 2010, yielding much higher EUR. Niobrara and Permian are in earlier shale development phase than Eagle Ford and Bakken, hence well curve improvement going forward might not be as large as in the last four years.

Even though individual wells might not be recovering more volumes, the amount of wells per section has seen a significant improvement, which will ultimately yield higher resources recovered per section. The map shows the intense downspacing taking place in the core areas of the Eagle Ford.

Source: Rystad Energy

Edited by Katie Woodward

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