Analyst touts industry’s cost reductions in U.S. shale plays

By KURT ABRAHAM, Editor on 9/22/2016

HOUSTON -- Recent analysis and statistical research have shown that break-even prices for oil production in the major U.S. shale plays have fallen, on average, at least $30/bbl for WTI. Speaking to a recent monthly meeting of the National Oil-equipment Manufacturers and Delegates Society (NOMADS) in Houston, IHS Markit’s associate director for Plays and Basins, Reed Olmstead, said that the drop can be attributed to a combination of four factors.

Since early 2014, peak rates for wells in the major oil plays have seen a consistent increase averaging over a 30% improvement. This increase in per-well production has buoyed production in the face of falling oil prices. However, as more oil is sourced from each well, the implication is that fewer wells are needed to maintain production. Image: IHS Markit.

“One of these factors is high-grading, where operators are drilling only the better acreage,” said Olmstead. “This item accounted for about 35% of the break-even price reduction.” He went on to say that service sector cost reductions account for another 40% of the lower break-even price, with in-field learnings amounting to 6% of the savings, and operational changes constituting the remaining 20%.

Another interesting take-away from Olmstead’s presentation was that while the oil price fell from late 2014 forward, peak crude production rates actually went up. “Since early 2014, peak rates for wells in the major [U.S.] oil plays have seen a consistent increase, averaged over a 30% improvement,” noted the analyst. “This increase in per-well production has buoyed production in the face of falling oil prices. However, as more oil is sourced from each well, the implication is that fewer wells are needed to maintain production.”

Bakken situation. Olmstead pointed out that high-grading was already underway in the Bakken shale of North Dakota, when oil prices fell. “EOG had largely exited the Parshall [field of North Dakota] and was turning the asset into a cash-generator, funding activities in the Eagle Ford and Permian,” pointed out Olmstead. “The primary high-grading in the Bakken was to terminate activity in the lower-productivity Periphery sub-play. This has led to a modest increase in the play’s average productivity, but given the maturity and well control in the play, operational efficiencies were mostly already captured.”

Eagle Ford improvement. Given its point in development, the Eagle Ford shale of South Texas has seen the greatest productivity increases from high-grading, going from 100 boed per 1,000 lateral feet, to nearly 150 boed per 1,000 lateral feet. “Unlike the Bakken, the variation between subplays is relatively high,” said Olmstead, “perhaps causing concern of productivity degradation, as rigs return to activity in less-prolific regions of the play.”

Performance in the Permian. To no one’s great surprise, the Bone Spring play in the Permian basin’s Delaware formation has shown the highest average productivity of any set of North American unconventional reservoirs. “However, due to lack of correlation between geography and geology (the play’s productivity is more governed by the producing zone), high-grading by sub-play has not shown any result,” said Olmstead. “Bench productivity has improved slightly since mid-2014, but given the mix of bench and location, overall play productivity has not shown more production per foot of wellbore.

Meanwhile, in the Wolfcamp Midland formation of the Permian, perhaps the greatest improvement in overall play productivity has occurred, driven primarily by operator migration. “As the play has been successfully delineated, operators have curtailed activity in the Southern Midland, while operators in the northwest have increased rigs and drilling activity,” explained Olmstead. “The Northern Midland sub-play also has shown a productivity increase, further increasing the play’s average.”

Proppant gains. In a move pioneered by EOG during 2014, proppant intensities (measured by lbs of sand per lateral ft) have been increasing across most major oil plays, said the analyst. “Through much of 2015 and early 2016, operators were pushing the limits of proppant loading and seeing a corresponding increase in productivity. However, the most recent data have given indications that this may be plateauing.”

Yet, per-ft productivity has increased across the major plays, driven primarily by high-grading and proppant loading. “As activity returns, productivity may be pushed down, though it is likely to remain relatively flat, as operational improvements provide some support to counterbalance the impact,” continued Olmstead. He noted that after settling on a steady-state of well design in the Eagle Ford and Bakken, lateral lengths have seen increases of up to 5% since 2014. “Bakken operators are somewhat limited in their ability to drill laterals longer than 2 mi,” he explained, “but Eagle Ford operators are continuing to push the bounds. Permian wells have seen faster adoption of longer laterals, with many operators continuing to push further.”

Outlook for the next 18 months. In terms of where the break-even prices go, from this point forward, Olmstead said that some gains will remain (structural), while some will be eroded, due to changes in the industry (cyclical). “In the next 18 to 24 months, the impact of these factors will net out to a reduction of $24.90/bbl. Service sector cost reductions will drop to a 30% share ($9.00) of the break-even impact, with high-grading accounting for 20% ($6.00), in-field learnings constituting 6% ($1.80), and operational changes representing 19% ($5.70/bbl).”

Olmstead also has some thoughts on oil prices, themselves, and rig counts. “Generally speaking, we think the market will approach the high $50s/bbl in early 2018, with $60 more likely in second-half 2018,” he offered. “We’re still working through the details, but generally speaking, this is the feeling around the office. We also are expecting to exit 2017 just above 620 rigs in the U.S., and will average close to 650 in first-quarter 2018. There will be a moderate increase [in rig count] through 2018.”

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