Growing associated gas production and rising breakeven prices for new oil wells are creating fresh challenges for Permian producers.
Oil output in the Permian basin in Texas and New Mexico is growing more slowly than expected. The EIA revised down forecasts for 2024 Permian production in this month's Short-Term Energy Outlook (STEO) following changes to historical output data. Permian production is now forecast to rise by 6.1pc this year and 3.6pc next, down from 7.8pc and 3.9pc, respectively, a month ago.
Activity in the Permian oil and gas sector edged down in the third quarter, firms participating in the Dallas Fed Energy Survey say. Low Waha natural gas trading hub prices prompted about a third of 23 active exploration and production (E&P) firms to curtail production, and another third to either delay and defer drilling or well completions. Permian gas prices were negative — meaning that sellers pay buyers to take gas — for most of the six months before early September, as associated gas production exceeded pipeline capacity to move it to market. But Waha prices turned positive again last month as gas began to flow out of the region along the new Matterhorn Express pipeline.
Deliveries on the 2.5bn cf/d (25bn m³/yr) Matterhorn pipeline have averaged about 600mn cf/d this month, Gelber & Associates analysts say. Flows are expected to ramp up to full capacity before the end of 2024, but robust associated gas production in the Permian remains a constant factor.
The Permian basin now accounts for around a fifth of US natural gas production and is the fastest-growing source of new supply, as rising oil output adds increasing volumes of associated gas (see graph). The GOR — the average ratio of gas output ('000 cf) to oil production (bl) — in the Permian has increased from around 2 to over 3.5 since 2012, data from analysts Novi Labs show. The GOR for Permian wells typically rises during the life of a well. The GOR for Midland wells trebles from 1 to 3 after five years of production and nearly doubles for Delaware wells from just over 2 to just over 4. So the GOR inevitably rises as the share of legacy wells in overall output grows.
Tiers for fears
Firms are also using up the better drilling locations. Shale is not a uniform resource. Despite impressive advances in productivity over the past decade, rock quality remains the most important driver of well performance. Operators target high-quality (tier 1) wells first if they can, leaving lower-quality tier 2–4 wells for later, hoping that improvements in drilling and completion technology and efficiency will offset poorer yields.
Less than two-fifths of the 25,000 drilling sites estimated to remain in the Midland basin offer a breakeven below $60/bl over a two-year period, according to a new assessment by Novi Labs using detailed rock quality data and incorporating the impact of infill well spacing patterns (see graph). Results reflect huge geologic variation within the basin and yield a weighted-average breakeven of $74/bl for the potential inventory of undrilled Midland wells. "Average tier 1 rock breaks even on average at $60/bl, but that number for tier 4 rises to $96/bl," Novi's Ted Cross says.
For comparison, breakeven WTI prices for drilling a new oil well in the Midland basin ranged from $40-85/bl and averaged $62/bl, according to 87 E&P firms surveyed by the Dallas Fed in March (see graph). Over the past five years, average breakeven prices for new Midland oil wells from the Dallas Fed Energy Survey increased by a just over a third from $46/bl. In 2020, Midland breakeven prices ranged from $30-60/bl.
