US shale oil output is starting to increase again, but most operators are keeping a tight grip on spending and relying on productivity gains to deliver growth.
Output from new wells in the seven major formations covered by the EIA's Drilling Productivity Report (DPR) exceeded legacy declines from existing wells in May-June, setting shale oil production on a modest growth path (see graph). DPR-7 production rose by over 18,000 b/d in June, and is expected to rise by 28,000 b/d in July and close to 42,000 b/d in August, the EIA says. Almost all the growth comes from the Permian basin in Texas-New Mexico, with output in other shale regions except Appalachia still falling.
Rapid hyperbolic decline rates at legacy wells mean that operators must continuously bring enough new production on stream just to maintain capacity. Output from a shale well typically halves over its first year. With legacy declines in the DPR-7 estimated at just below 425,000 b/d in May-June and output per new well averaging 585 b/d, 725 new-well completions are needed a month. Completions averaged just over 800 in May-June, comfortably exceeding this level.
Firms continue to complete many more new wells than they are drilling each month by using up their backlog of drilled-but-uncompleted (DUC) wells to reduce the cost of bringing new output on stream. Shale operators accumulated a record inventory of nearly 9,000 DUC wells between mid-2018 and mid-2020. But that cache of inventory is back at mid-2018 levels after companies completed an average of 246 DUC wells/month from August 2020 (see graph). DUC wells contributed a third of completions in the DPR-7 regions in May-June, EIA figures show. But the share of DUC wells is expected to diminish in the future as better prospects have already been brought on stream.
Activity is recovering steadily from last year's pandemic-related oil price collapse and unprecedented output curtailments, but wells drilled and rig counts remain relatively depressed, and lag completions because of DUC wells. Completions last month were running at 77pc of pre-pandemic levels from the first quarter of last year, while wells drilled were at 51pc and rig counts at 59pc (see graph). Rig counts have nearly doubled since July last year, but private operators are behind much of this increase, consultancy Rystad Energy says. Private exploration and production firms held 208 onshore horizontal rigs in May — close to their pre-pandemic level of 221 in March 2020 after falling to 70 in July last year.
Solid base
Private producers are more willing to boost spending and output in response to higher oil prices than public companies, which must satisfy shareholder demands for better returns. The former account for just over a quarter of US tight oil output — but typically score lower on drilling efficiency and well productivity, and need to deploy more resources. Public producers are confident about their success. "Now we've seen some of the privates take advantage of the current market and they are growing, but they don't have the rock that we do, so they don't have the quality that we do," ConocoPhillips' chief executive Ryan Lance says.
ConocoPhillips has become a top Permian producer since merging with Concho Resources. "Our Permian position has the highest single-well EURs [estimated ultimate recoveries] in both Delaware and Midland," says former Concho chief executive Tim Leach, who now heads ConocoPhillips lower 48 operations. ConocoPhillips aims to use productivity and efficiency gains to reduce the cost of replacing capacity. Since 2019, the cost per foot of a single well in the Delaware has improved by 30pc, Leach says. New technologies have cut costs by $0.7mn/well, while refracturing selected wells can add 75pc to recovery for a fraction of the cost of a new well.
