There has been growing talk this year that the US shale revolution may be losing steam.
In May, executives from Halliburton and Liberty Energy signaled to investors that clients were cutting spending in response to rising capital costs and soft oil prices during the first part of the year. That same month, the CEOs of Diamondback Energy and Occidental Petroleum said that US onshore oil production may already be at or nearing its peak.
Then in early June, the US Energy Information Administration (EIA) echoed these concerns with a forecast that US crude output, now at a record 13.5 million B/D, would slip slightly to 13.3 million B/D by the end of next year.
While the armed conflict between Israel and Iran triggered a quick rebound from below $65/bbl oil prices to above $70/bbl just days later, it followed a cautious tone already set at this year’s Unconventional Resources Technology Conference (URTeC), where executives emphasized the need for more innovation to sustain long-term viability.
Among those voices was veteran energy investor Dan Pickering who explained to the gathering in Houston that what people are calling the “peak” of US shale is really a moving target shaped by prices.
“US production has probably peaked for oil at $65 (per bbl). Oil at $95, I think there’s plenty of locations that could likely supply growth,” said Pickering, founder and chief investment officer of Pickering Energy Partners.
He then challenged conferencegoers to make the shale revolution last longer, urging them to “stretch it out, make it give longer than it wants to.”
Many of the technical papers shared at URTeC aimed to do just that by showing the industry how extending the economic life of tight oil plays is being done today and how that effort may evolve through creative well designs, advanced lift solutions, and the mounting issue of water management.
ADD Needs Lower Drilling Costs
One of the most novel ideas shared in recent years comes from Hess Corp. and its Bakken Shale program. In URTeC 4233459, Hess revisited a concept first introduced in 2022 called augmented drainage development (ADD).
The pilot-tested approach involves drilling a passive well—either as a multilateral or a separate lateral—next to a standard hydraulically fractured well. The fractures of neighboring wells intersect with the otherwise unstimulated ADD well to expand the drainage area and recover oil that might otherwise be left behind.
The ADD remains in its infancy but the research work done by Hess and simulation firm ResFrac Corp. suggests that the industry may want to keep tinkering with the idea since it is likely applicable to other shale plays.
Their modeling shows that ADD wells could boost first-year production across a drilling section by 10% and increase estimated ultimate recovery (EUR) by 5% at 1,000-ft well spacing. The analysis also highlights that adopting the concept at scale will require a significant breakthrough in reducing drilling costs.
Hess said ADD wells in the Bakken become viable if the passive laterals can be drilled for half the cost of a regular horizontal wellboreand are highly attractive at 15% of the cost which would likely require multilateral drilling.
Another potential ADD option to drive down costs could be “combo” wells with alternating stimulated and passive sections. Hess also emphasized the importance of spacing optimization and larger fracture jobs to improve ADD performance, finding that the Bakken sweet spot typically falls between 800 ft and 1,000 ft.
Gas Lift in the Middle
If ADD represents a concept for the future, then what ConocoPhillips and SLB shared at URTeC may offer a more immediate opportunity to boost production.
In URTeC 4251001, ConocoPhillips and SLB detailed a pilot test that installed annular gas lift in the middle of a horizontal well, rather than at the heel where such systems are typically installed.
The gas lift was deployed in a well producing about 400 B/D of liquids and ran for 3 months resulting in an oil output increase of 20% compared with a nearby offset well. Both wells received a similar volume of gas injection, which the authors said supports the idea that, in longer laterals, it may be more effective to “push” liquids from the mid-lateral rather than “pull” them from the heel.
The approach is meant to be a remedy to the problems caused by another advancement, the 3- and 4-mile laterals that are now commonly drilled in the Permian Basin to lower development costs and raise per-well recovery. But as laterals extend and the wells age out, big challenges have emerged due to liquid loading which can choke off production and cause slugging that damages surface equipment.
The ConocoPhillips and SLB paper said the modeling work that followed the pilot indicates the newly tested gas-lift method may be “critical” for producing the hardest-to-reach resources at the well’s toe during the late-life stage of long laterals.
Managing a Water World
The challenges operators are facing in the Permian with longer laterals and liquid loading are a reminder that water management at the surface has also become one of the biggest issues facing the region’s sustainability.
Long a logistical burden, the scale of the water-management issue is now unprecedented. Subsurface injections in the Permian have surged from about 3 million B/D in 2012 to more than 15 million B/D today. Along with induced seismicity, the massive inflow of produced water has led to the rising risk of overpressurizing disposal wells.
Two recent studies presented at URTeC by Chevron and ConocoPhillips offer insight into how leading operators are addressing these risks through advanced monitoring and predictive modeling.
Chevron has turned to satellite-based imaging to monitor surface deformation across saltwater disposal sites in the Permian. In URTeC 4201468, the company shares an analysis focused on a site where measurable uplift was observed from space near one of its disposal facilities.
Though no earthquakes were recorded in the area, the satellite data indicated fault movement by tracking deformation patterns which suggested that injected fluids may have been migrating along a previously unmapped fault. This type of geospatial analysis is just one of the growing number of tools operators are using to manage injection pressures in increasingly crowded storage reservoirs.
ConocoPhillips has added to the toolbox detailed pressure models designed to forecast when disposal wells might approach critical pressure thresholds that could lead to the watering out of nearby oil producers or compromise containment in the produced-water storage reservoir.
In paper URTeC 4257880, the company described how these models are being used to guide big development decisions. For instance, engineers might realize that if a well is close to a highly pressurized storage reservoir they may order extra casing to protect against water invasion.
Those wells that need this extra capital expense can be prioritized or delayed. Conversely, wells that are close to the point of needing extra casing can be accelerated in the drilling schedule to avoid additional capital costs down the line. The approach allows planners to test various development sequences, each with its own projected impact on produced-water volumes and disposal requirements.
Taken together, the innovations highlighted above reflect the reality that the shale sector has entered a stage of maturity. No longer facing the growing pains of a greenfield sector, US shale now must contend with the aches and complications that come with age.
But as these technical papers also show, the playbook is vast and still very much a work in progress. Armed with the right tools and imagination, the US shale revolution may still have a few more surprises to the upside in store.
For Further Reading
URTeC 4233459 Augmented Drainage Development (ADD)—An Evaluation of Field Development Applications in the Bakken by C. Cipolla, M. McKimmy, J. Lassek, K. Shaarawi, Hess Corporation; and S. Morsy and M. McClure, ResFrac Corp.
URTeC 4257880 Comprehensive Probabilistic Pressure Prediction for Water Management in the Permian Basin by M. McGarvey, D. Vennes, C.-K. Huang, N. Rincones, H. Zhou, Q. Lu, M. Burkard, A.-P. Maynard, and L. Baez, ConocoPhillips.
URTeC 4201468 InSAR Characterization of Fluid Movement and Fault Slip Near a Saltwater Disposal Site in the Permian Basin by Z. Zhang, C. Comiskey, K. Nihei, K. Sirorattanakul, Z. Fang, J. Nunn, J. Palmer, L. Swafford, Chevron USA Inc.; and C. Lucente and G. Falorni, TRE ALTAMIRA.
URTeC 4251001 Gas Lift in the Lateral—Findings From a Midland Basin Pilot by S.L. Scott, M. Reynolds, and R. Fan, ConocoPhillips; and A. Soedarmo and I. Koshelkov, SLB.
