Drilling Advances
In a book described as “geek humor at its finest,” Spurious Correlations takes a look at data obsession and conspiracy theories through wacky attempts at drawing a linear link between the statistically debunked correlation and causation relationship. For instance, how could one logically, as depicted in the satirical collection, correlate U.S. oil imports between 2000–2009 with per capita chicken consumption?
Statistical purists, however, could find a more worthy test subject in the contemporary shale community, where an intriguing relationship has emerged between the number of rigs making hole and production from said holes. More to the point, new-generation rigs are not only sinking unconventional wells—often more than twice as fast as their predecessors—they likewise are delivering more production per capita. As evidence, drilling down into federal data, we find that over the past three years, every rig in the Eagle Ford, for instance, was responsible for the delivery of nearly 200% more incremental oil, soaring from an average of 479 bopd/rig in July 2014 to 1,433 bopd/rig last month.
The literature has incessantly documented the emergence of super-spec rigs, advanced geosteering, cutting edge analytics and the like, which have elevated efficiencies and cleared the way for nearly universal, factory-style multi-well pad drilling. While the total rig count continued to climb at the heights of shalemania, it took the darkest days of the downturn to put the quality-quantity dynamic into the spotlight, at a time when only the best of the best were allowed to remain standing.
“Everyone was paying close attention to productivity, speed and cost of each drilling crew,” Troy Eckard, CEO of Richardson, Texas-based Eckard Enterprises, LLC, a private asset management company with upstream and midstream holdings, wrote in an April 24 investor note. “The most mechanically sharp, efficient and best-equipped drilling rigs and crews were left operating in the downturn. That created the ‘A-Team.’”
Other variables. Aside from technology-driven efficiencies, gutter-level prices forced operators to stay within their well-delineated core, targeting only the sweetest of the sweet spots. Further increasing per-rig production is a growing trend that has ever-longer laterals—combined with high-intensity completions—becoming commonplace.
In recent years, operators have focused on blocking up acreage, either through bolt-on acquisitions or direct asset swaps, to accommodate once lease-restricted longer laterals. Earlier this year, Chesapeake Energy Co., for example, drilled a well in Dimmitt County, Texas, with an Eagle Ford-record lateral length of just under 17,000 ft, which still falls short of Eclipse Resources’ Purple Hayes well in the Utica Shale, constructed with an unconventional record 18,544-ft lateral reach. At 27,048 ft MD, the record-setting well was drilled in mid-2016 in 17.6 days.
Of course, the faster drilling of longer-reach shale wells only tells part of the story. As validated in a dissection of U.S. Energy Information Administration (EIA) statistics, groundbreaking efficiencies have led to progressively higher per-rig production rates, in line with the marching order of the day that calls for producing more with less.
By the numbers. For historical perspective, in 2014, before oil prices began to steadily nose dive, a high of 2,168 active land rigs were working across North America, according to Baker Hughes data. Of the 1,790 active rigs in the U.S., 1,031 were stationed in the Eagle Ford, Bakken, Permian basin and the gassy Marcellus, which were generally acknowledged as the Big Four shale plays.
To evaluate rig efficiency in the unconventional sector, the EIA established its Drilling Productivity Report (DPR), which explores the historical relationship between the Baker Hughes active rig count, the newly drilled wells completed, and the incremental oil and gas volumes flowing from those wells. A comparative analysis of output per rig between July 2014 and July 2017 puts the Eagle Ford front and center. According to the DPR model, incremental production attributed to each of the 213 rigs active in July 2014, delivered a cumulative 102,027 bopd. Fast forward to July 2017, and 80 rigs on average produced an aggregate 114,640 bpd of incremental oil volumes.
Results were equally eye-opening in the gas-dominant Marcellus, where the 79 active rigs in July 2014 produced on average 6,552 MMcfd/rig, but over three years, more than doubled to 15,149 MMcfd/rig. Consequently, the average 45 rigs active last month produced a combined 681,705 MMcfd, compared to the cumulative incremental production of 517,608 MMcfd delivered from 34 more rigs three years prior.
Interestingly, the red-hot Permian, a comparably late comer to multi-well pad, unconventional drilling, was home to 558 rigs in July 2014, but incremental production was a comparatively modest 148 bopd/rig. In July 2017, an average 371 rigs were delivering additional oil production of 607 bopd/rig.
In the Bakken, 181 rigs were operating in the play in July 2014, each producing an additional 510 bopd. In July 2017, 52 rigs were active in the oily play, accounting for 1,169 bopd/rig.
The bottom line, says Chesapeake CEO Doug Lawler, is that operators no longer require once-bloated rig fleets. Speaking to the Oklahoma State University Energy Conference in May 2016, at a time when only 375 land rigs were active throughout the U.S., Lawler, as quoted by the Oklahoman, said, “We don’t need to run 175 rigs anymore. Forty or 50 rigs can deliver the same volume today. We don’t need to go back to 2,000 rigs [nationwide].” 
