U.S. well productivity gains posted last year may not repeat in 2019 with the same magnitude, but domestic output still should drive the global market in the next decade, according to Raymond James & Associates Inc.

J. Marshall Adkins, John Freeman and their team of analysts in a note Monday said in the past eight years, onshore development has upended oil markets worldwide, putting the nation on the path to become energy independent for the first time in 70 years.

Well efficiencies had slowed a bit, “only to buck the downtrend last year with an unexpected 2018 productivity surge” of 20% year/year. Can U.S. producers repeat that feat this year? Analysts say gains should continue but probably not at the same magnitude.

Oil well productivity “exploded” in the Lower 48 from 2022-2015, climbing 35% a year on average. Gains slowed in 2016 to 17% and were down to 11% in 2017.

In 2018, however, productivity reversed the downturn and surged to more than twice the 8% annual growth originally modeled.

“Needless to say, our original 2018 U.S. oil supply model forecast ended up well below the actual growth seen last year,” driven by several multinationals, including ExxonMobil Corp., Chevron Corp. and Occidental Petroleum Corp. Each of those operators accelerated their 2018 Permian Basin activity in core areas.

The big operators benefited from the learning curve provided by major Permian exploration and production (E&P) companies, notably EOG Resources Inc., Pioneer Natural Resources Co., Concho Resources Inc. and Parsley Energy Inc., which “jumped from ‘version 1’ well designs to ‘version 5’ designs in just one year.

“This allowed a one-time step change in Permian well productivity that is unlikely to be repeated again over the next few years,” Adkins and his colleagues said. The Raymond James team expects U.S. oil well productivity to slow to 10% in 2020, with 5% annual gains in the next decade.

“Even though our U.S. production model assumes these perpetual gains in U.S. well productivity, it is important to note that there is a very high likelihood that well productivities turn negative in the next few years as parent-child, and core acreage issues overwhelm the industries ability to complete longer laterals with more sand.”

The Raymond James analysts believe the biggest drivers to well productivity growth has been increasing lateral lengths and increased proppant loading, allowing the industry to use a metaphorical “bigger hammer” to improve output per well.

Before 2014, the longest lateral increases on average were in the Permian Midland, which improved to 7,000 from 3,000 feet, and in the Bakken Shale, which increased to 9,000 from 7,500 feet, analysts said.

However, laterals in other basins are also lengthening, with Permian Delaware laterals last year improving to 6,500 feet from 5,000 in 2014, while Eagle Ford Shale laterals increased to 7,500 feet from 5,500. A huge shift to horizontal wells from verticals in the same time frame also improved the impact of the longer laterals.

“Although it is technically feasible to drill longer lateral lengths than the current 8,000-foot U.S. averages, there are two reasons why we think gains in U.S. lateral lengths will slow in the coming years,” said Adkins and his colleagues. “First, horizontal completions (particularly coiled tubing) operations become exponentially more difficult (and expensive) beyond 10,000 feet.

“Secondly, to achieve 10,000-foot laterals, operators need to assemble sizable contiguous acreage positions, i.e. two contiguous 640-acre leaseholds, to drill wells that are nearly two miles in horizontal length.”

Longer laterals can be difficult to do as operators often are challenged by mineral ownership issues and legal constraints. As such, most operators have settled on 10,000-foot laterals as leaseholds allow.

“Given limits in leasehold boundaries, we believe that the average U.S. lateral length will begin to max out in the 8,500-foot (overall U.S. average) length over the next few years.”

Another driver in well efficiencies has been the steadily increasing volume of proppant/lateral foot in wells. The Raymond James team estimated U.S. proppant loadings have had a slightly more post-2014 weighted growth profile averaging 12% growth year/year since 2010.

Not surprisingly, the Permian’s twin Delaware and Midland sub-basins reported the biggest boost in loadings from 2010’s 500 pounds/foot to almost 2,000 in the Delaware and 1,800 in the Midland.

“Like lateral lengths, however, we believe that the recent surge in higher sand concentrations may fade over the coming years,” analysts said. “Specifically, recent reports from operators suggest that optimal sand loadings seem to be around 2,500-3,000 pounds/foot with diminishing returns for higher concentrations.”

As E&Ps have begun full-field development, many are drilling a higher proportion of infill wells, i.e. child wells, relative to their initial parent wells. That has caused issues on another level.

“Put simply, the child wells tend to be less productive that the parent wells” when adjusted for the size and design of the fracture, Raymond James analysts. Lateral lengths, proppant loading, stage/well spacing and the time lag may impact the data, but the parent-child well dynamic likely will become a bigger factor as infill drilling accelerates.

E&Ps are also moving out of the sweet spots into acreage likely to be less productive.

“To simplify, as each play/basin's sweet spot is drilled out, it's reasonable to assume that well productivity will eventually be hampered by a shift to tier two acreage,” Adkins and team said. “An operator can only do so much with the lateral length and completion design to overcome lower quality reservoirs.”