Drilling longer horizontal wells is enabling shale oil firms to produce more oil while employing fewer rigs and completion crews.
US oil production is expected to rise by just 2pc this year, down from 9pc last year, the EIA's latest Short-Term Energy Outlook (STEO) says. An extreme cold snap forced operators to shut in wells during January, cutting 650,000 b/d from onshore lower-48 output relative to December and denting annual growth forecasts. North Dakota's Bakken and the Permian and Eagle Ford formations in Texas-New Mexico bore the brunt of the weather in the shale sector.
Production from the seven major formations covered by the EIA's Drilling Productivity Report (DPR) rebounded strongly last month, but high decline rates at existing wells mean there is always a net loss of capacity from interruptions to production. The EIA estimates that legacy declines at DPR-7 formations are running at nearly 650,000 b/d per month, meaning operators must start up enough new wells to replace this lost capacity every month, or output falls. The latest DPR expects DPR-7 output to rise by more than 4,000 b/d this month and by nearly 10,000 b/d next month, as new-well output exceeds legacy declines.
Shale activity slowed rapidly in the first nine months of last year. Onshore rig counts fell from 621 in the last week of December 2022 to 502 in the last week of September last year, according to service firm Baker Hughes, a 19pc drop. Counts have stuck at 500 since then, albeit rising a little recently (see graph). Fewer rigs means fewer wells, and the number of new wells drilled in the DPR-7 dipped by 17pc in January-September, mirroring the decline in the rig count (see graph).
But output still increased — DPR-7 production rose by nearly 7pc in January-September before falling slightly in October-March owing to January's exceptionally cold weather. This is partly because firms used their stocks of drilled-but-uncompleted (DUC) wells to bring on new output without having to drill more — 840 DUC wells were completed last year, helping to offset the impact of the lower rig counts on output. Last year saw 7pc more DPR-7 wells completed than drilled.
Artificial gains
DUC wells help to account for some of the observed fluctuations in rig productivity reported in the DPR. Improved drilling and completion technology, and more efficient operations have boosted rig productivity over the past decade, but there are also wide variations around an upward trend that partly correspond to changes in DUC wells (see graph). New-well production per rig averaged 300 b/d in the DPR-7 in 2014 but had tripled to just over 1,000 b/d by last year. But it also accelerated last year, from 914 b/d in January to 1,043 b/d in December, as DUC wells artificially boosted rig productivity with output from wells already drilled.
Improved productivity is the main driving force behind rising shale output, as most firms remain focused on improving returns to shareholders. "We still believe it is prudent to deploy a steady capital programme designed to optimise returns while maintaining volumes around levels where we exited 2023," Devon Energy chief executive Rick Muncrief says. "A key contributor... will be the well productivity improvements we expect to achieve in the Delaware basin."
The biggest gains are coming from drilling longer wells that need fewer rigs and completion crews, which is why firms are merging and trading land rights to create longer corridors for horizontal drilling. "The overall lateral length will be up by about 10pc versus 2023," EOG Resources' chief operating officer, Jeff Leitzell, says. "We're going to require four less rigs and two less frac feets and then also four less net wells, but we're still going to be completing a similar amount of total lateral length as we did with our 2023 programme."
