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High Grading – Better Rock or Better Completions?

As producers roll out earnings announcements, the themes continue to be reduced capital budgets and a focus on the best rock with optimized completions. The prevailing question remains, “which is the bigger driver of productivity improvements for 2015: better rock or better completion designs?”.  In December 2014, BTU Analytics explored the impact of High grading to production for a single county in the Permian. In preparation for a board meeting and this month’s Upstream Outlook, I’ve been exploring the potential for high grading in the Bakken, the Permian, and the Eagle Ford. On January 6, 2015, Continental Resources (NYSE: CLR) published a new investor deck highlighting its 2015 plans to focus on high rate of return projects in the core of the Bakken.

Continental indicates that its high graded program should yield wells with initial production rates of over 800 B/d, but will have a first year decline of nearly 80%.  To put this into perspective, I dug into ND state data, which shows the average well in the Central Williston (McKenzie, Dunn, Williams, and Mountrail counties) for 2014 averaged 453 B/d for the peak month of production, with Dunn and McKenzie counties performing the best  averaging  512 B/d and 453 B/d, respectively.

The data also shows that since 2011, producers have increased the average initial production (IP) rates for both Dunn and McKenzie counties through a combination of several factors including the use of longer laterals, increased proppant, and other changes to completion designs. While IP rates have indeed increased, so has the average decline in the first year, confirming Continental’s expectation that a focus on new completion designs will result in bigger initial production rates at the cost of steeper decline rates. In addition to completion techniques, producers can also focus on drilling better rock. In October 2014, BTU Analytics highlighted the areas with the best breakevens in the Bakken, and, as Continental is one of the largest operators in the basin, much of their acreage coincides with the core that BTU Analytics has delineated.

Continental is not the only operator we expect to pull back to its core acreage and even without changes in completion designs, we would expect to see higher average well results as producers drop from the fringes.

Eliminating the bottom 25% of well results in the Bakken improves the average initial production rate by nearly the exact same margin, boosting the average to ~568 B/d. While operators are cutting activity rapidly, incremental gains in average well productivity could significantly slow the pace of production declines in the region. Similar trends are occurring in the Eagle Ford, and producers in the Permian could make significant strides in increasing well productivity as they focus on the best rock with long lateral wells. For more on high grading, estimates of remaining locations, and maps highlighting the most economic parts of each of the major plays, see the February Upstream Outlook.

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Erika Coombs is Manager of Consulting Services at BTU Analytics. She leads the team to deliver customized energy-market analysis and provides BTU Analytics’ customers with critical information for a variety of energy markets including oil, gas, and NGLs from wellhead to downstream markets. She also leads research on upstream analysis, crude oil midstream infrastructure, breakeven economics, and commodity pricing dynamics for several BTU Analytics’ reports. She holds a M.S. in Mineral and Energy Economics from the Colorado School of Mines.

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