Completion capacity constrains US shale output growth

US shale oil output growth expectations are being revised down as operators concede that upstream capacity constraints and shareholder demands for higher returns will limit production increases.

US lower-48 onshore oil production will rise by 450,000 b/d this year and 240,000 b/d next, after growing by 600,000 b/d last year, the EIA's latest Short-Term Energy Outlook (STEO) says. This time a year ago, the March 2022 STEO expected a 950,000 b/d increase in 2023. Output from the seven major US shale formations covered by the EIA's monthly Drilling Productivity Report (DPR) accounted for 89pc of the lower-48 onshore oil production last year.

Shale oil firms must strike a delicate balance between investing in new production capacity and rewarding shareholders. Companies in the past pursued output growth at the expense of shareholders, reinvesting more cash than the business was generating. But this is no longer a viable strategy. "We are committed to returning significant capital to shareholders," the chief executive of Permian basin producer Pioneer Resources, Scott Sheffield, says.

Output from new shale wells falls very rapidly after initial production, meaning that firms must keep drilling and completing more new wells to maintain output. Nearly three-quarters of a shale oil well's initial production is lost in the first 12 months and a further half in the next 12 months. The EIA estimates that legacy declines from existing wells in the DPR-7 formations are running at just under 575,000 b/d, or 6.3pc, of DPR-7 output this month. But production from recent well start-ups is keeping ahead of legacy declines, and DPR-7 oil production is expected to rise by 86,000 b/d in March.

Yet the excess of new-well production over legacy declines is slowly shrinking, as fewer new wells are completed, while the decline from existing wells rises in the wake of growing output (see graph). New-well production peaked in June-July last year after rising very sharply as the industry used up its huge backlog of drilled-but-uncompleted (DUC) wells accumulated during the Covid-19 pandemic. Operators must drill wells from scratch without the benefit of the DUC backlog to draw on, which costs more and takes longer. Well completions in the DPR-7 regions peaked in October last year at 1,050, before falling to 971 by last month (see graph).

Spread betting

Sharp increases in oil industry service costs together with a shortage of hydraulic fracturing capacity, or "frac spreads", are restricting the number of wells that can be completed — or drilled. Fewer wells are being drilled since completions peaked and rig counts are also down since the end of last year. Existing frac capacity is being fully utilised, according to service firm Liberty Energy's chief executive, Chris Wright, and more is being used to offset declines. "As oil and gas production reaches new heights, there is a rising level of frac activity simply required to keep our customers' production flat," he says.

Effective capacity is around 300 frac spreads and the industry has not deployed more than that since before the pandemic, data from industry monitor Primary Vision show (see graph). Older diesel-powered plant is still being used at shale oil sites, but is more expensive to run than newer natural gas-powered fleets and becoming harder to maintain. "Today, frac fleet demand sufficient to keep production roughly flat or drive only very modest growth requires all existing frac capacity," Wright says. Until this well completion bottleneck is eased by more frac capacity, it will become increasingly hard for the shale sector to sustain production growth.

By David Long

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