The Bakken region, stretching across the plains of North Dakota, Montana, and parts of Canada within the Williston Basin, produced approximately 1.2 million barrels of crude oil per day in 2025, according to data from the U.S. Energy Information Administration (EIA). Maintaining its status as the globe’s top crude oil supplier, the U.S. averaged 13.6 million barrels of daily crude output in 2025, meaning this volume made up roughly 9% of the nation’s overall production.
While Texas often dominates public perception of American domestic oil extraction, the northern tier has spent decades quietly reshaping the nation’s energy landscape. Development across the basin extends beyond the Bakken Formation itself to include the underlying Three Forks Formation, with operators routinely targeting both zones in tandem as the Bakken-Three Forks petroleum system.
Engineering and Technology Drive Shale Production
Commercial-scale oil extraction in the region accelerated significantly in the late 2000s, driven by advancements in horizontal drilling and hydraulic fracturing that unlocked tight-rock resources. Rather than drilling exclusively downward, operators steer drill bits horizontally through target formations, maintaining thousands of feet of wellbore contact with oil-bearing rock. Hydraulic fracturing subsequently opens fissures through the dense rock, establishing pathways for crude oil and natural gas to flow toward the wellbore.
Those technological shifts transformed national production figures, enabling steady gains in drilling productivity and operational efficiency across major U.S. shale basins, as tracked by the EIA. Yet engineers on the ground emphasize that possessing the technology marks only a baseline requirement for commercial viability.
The basic concept is pretty straightforward: drill the well, complete it and then produce it,
noted Phoenix Energy CEO Adam Ferrari, a chemical engineer whose oil and gas firm operates within the Williston Basin. The challenge is doing each of those things efficiently and repeatedly.
That distinction underscores the reality that modern oil development functions as much as an exercise in economics as it does in geology.
Longer Laterals Redefine Williston Basin Operations
Operators navigating mature producing regions face strict economic constraints, lacking any direct control over global crude prices. Consequently, companies focus heavily on variables they can manage, including internal costs, drilling speeds, and operational downtime.
A primary driver of recent efficiency gains has been the lengthening of horizontal well sections, known as laterals. By extending lateral wellbores for miles underground, operators access substantially larger volumes of oil-bearing rock from a single surface location. This configuration concentrates surface infrastructure, reduces the need for constant new drilling pads, and accelerates the timeline required to bring new wells into production.
The Williston Basin has served as a testing ground for these extended-reach techniques. Phoenix Energy expanded its deployment of four-mile laterals within its regional footprint, reporting the drilling of its first four-mile lateral switchback wells in Montana in 2026 alongside an eight-well, four-mile lateral unit development in the state.
Managing these assets requires balancing initial production spikes against natural decline rates. Shale wells typically produce at their highest volumes early in their life cycles before tapering off, forcing operators to continually weigh the output of existing wells against the capital required to drill and complete new units.
