By Richard Rostad, analyst, Oil & Gas 360

The Q4 2018 downturn in oil prices has made upcoming U.S. crude oil production growth a major uncertainty for markets. Companies have been announcing plans to scale back drilling activities for 2019, but what will the overall effect of the reduction in drilling be?

How much can activity drop before a lack of drilling causes a decrease in overall output? Remember the 2014-2016 downturn? That stopped seven years of production growth in its tracks, and American oil output declined from 2015 to 2016.

Only 558 rigs are needed to replicate 2014’s new production

The efficiencies companies have achieved in the past four years mean that a downturn in oil price will have less of an effect on overall U.S. production. Modern rigs in the major shale basins are yielding 2.9 times more production than rigs from January 2014. Improved technologies and techniques have combined with more optimal drilling locations and targets to produce significant improvements in efficiency over the past five years.

While rig counts never reached pre-downturn levels, production growth set records in 2018. American oil production surged by 1.58 MMBOPD in 2018, a 17% increase. This is the largest absolute growth in U.S history, and the second-largest percentage growth in 80 years.

Based on current per-rig productivity the major shale basins could replicate 2014 activity, when production grew by 1.29 MMBOPD, with only 558 rigs. Rig counts in the major basins, then, could decline by 40% and still yield new production at 2014 levels

However, 729 rigs are required to keep production constant

Simply replicating 2014’s new production is not enough, though, as the decline curve in shale is a ferocious thing.

Estimates suggest existing production in the major shale basins declined by 521 MBOPD and 2.5 Bcf/d in December 2018 alone. This decline is a treadmill that producers are running on, and new wells must produce even more than this to create growth.

Based on recent productivity, replacing declines in existing production in the major shale basins would require 729 rigs, 76% of current activity. The share of “surplus rigs” – those that are contributing to growth rather than production maintenance – varies significantly among different basins. Gas basins have the largest share of surplus rigs, as the Haynesville rig count could decline by 31% and the Appalachian count could drop by 28% while keeping production steady.

The Anadarko, Bakken and Eagle Ford all have low proportions of surplus rigs, with only about 17% of activity driving growth. The Permian and Niobrara have the most surplus rigs among oil basins, as approximately 25% of rigs are driving growth in each.

Rigs on A Treadmill: There’s Limited Room for a Fall

Source: EnerCom Analytics

In the event of an actual extended decline in overall activity, per-rig efficiencies are almost certain to improve. Drilling currently outpaces completions in four of the seven major shale basins, meaning that rig operations do not always immediately translate into new production. An extended decline in oil price would likely see a decline in DUC count, as producers shift to completing existing wells over drilling new ones. This means fewer rigs would be required to hold production steady.

Extended declines in prices would also affect the required rig count through a shift in the decline curve. If oil production held flat for an extended period, the monthly legacy production decline would likely decrease. Shale wells decline precipitously during the first year of operation, but this decline moderates significantly as time goes on. Steady production rather than growth would mean the average age of shale wells would increase, decreasing the production replacement requirements.


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