- Laterals lengthen to reach more rock and hydrocarbons. For example, in the Utica Shale of the Appalachia region, lateral lengths almost doubled to 8,628 ft during 2011–2017, according to DrillingInfo data. In the Williston Basin, the average lateral now stretches more than 2 miles with a limited surface footprint thanks in part to North Dakota setting the standard drilling and spacing unit at 1,280 acres.
- Proppant and fluid volumes grow to new heights. During 2010–2017, average proppant mass spiked to 1,600 lb/ft from 500 lb/ft, and fluid volumes increased to 33 bbl/ft from 13 bbl/ft. Operators are shattering basin records, Weijers et al. noted, with some wells taking in a proppant mass equivalent to a 100-car unit train, surpassing 20 million lbs/well. This has come with the increased use of high-viscosity friction reducers.
- Stage count and intensity boom. The average stage count has risen to 40 stages/well, with average stage spacing dropping to 200 ft/stage in 2017 from 350 ft/stage in 2010.
- Pump rates take off. The rate per lateral foot increased to 0.42 bpm/ft in 2017 from 0.16 bpm/ft in 2010 in an effort to improve diversion, accompanied by a rapid increase in frac fleet horsepower.
During the downturn, operators tweaked designs to incorporate cheaper sand and lower gel loadings with cheaper fluid systems. The impact on D&C spending was dramatic. Citing data from Coras Research, Weijers et al. noted that the average well cost in four major US liquids-rich basins fell to $5.1 million in 2017 from $7.2 million in 2012. The average cost per barrel of oil produced—meaning all D&C costs for barrels in the first year of production—was just $46/bbl in 2017, compared with $128/bbl in 2012.