DENVER — In spring of 2016 nobody had much to say about the Bakken or Niobrara plays. With oil prices stalled and all eyes on the Permian Basin, these two former powerhouse shale plays were languishing, with very little activity and even less enthusiasm.

Fast forward a year, and that’s starting to change. Oil prices are consistently nudging above the $50 per barrel (bbl) mark, and operators in the shale plays have driven efficiencies to lower their breakeven requirements and remain competitive in a lower-for-longer environment. Two speakers at Hart Energy’s recent DUG Bakken & Niobrara conference in Denver had the numbers to show just how successful they’ve been.

Joe Quoyeser, a senior expert with McKinsey & Co., recalled his early days with ExxonMobil Corp. (NYSE: XOM) looking at the Red River play in North Dakota. “I remember sitting in a geologist’s office in Midland,” Quoyeser said. “I pointed at this section on a well log called the Bakken and said, ‘There’s a lot of oil in here, but we can’t figure out a way to get it out. Some people, mad scientist types, are talking about drilling it horizontally.’ That was 1985.”

Obviously in the intervening 32 years those mad scientists have figured out the recipe, and Quoyeser gave the industry credit for its perseverance.

“It’s obvious that perhaps the most seminal feature of the industry discussion of shale gas and tight oil has been the continuous operational improvement both in cost reduction and productivity improvement in initial rates and ultimate recovery,” he said, adding that he and his colleagues have been studying these “learning curve” dynamics.

On the productivity side, he said, McKinsey is attempting to quantify the relevant contributions of acreage high-grading, longer laterals and completion designs. During the downturn it also studied the frack sand market and examined the shifts in the quantity and types of proppants being used by operators.

These studies were motivated by curiosity about whether and when the classical economic concepts of diminishing returns to scale become relevant, he said.

“As operators incur costs in the form of longer laterals and/or bigger stimulation treatments, they expect to, and do, achieve higher productivity on average,” he said. “But is there a point at which the lines cross, or is bigger always better?”

The goal of the study was to quantify the levels of improvement in Bakken well performance, investigate the underlying drivers of that improvement (with a focus on well design) and test the degree to which optimal well designs are sensitive to commodity prices. Focusing on the Nesson Anticline, the most productive of the Bakken sub-basins, some of the productivity trends included:

* An increase in proppant from 350 pounds per ft (lb/ft) in 2012 to 674 lb/ft in 2016 and a significant move from ceramic-coated proppant to sand during that time frame;

* A move from mostly cross-linked gels in 2012 to an almost even balance of gels, slickwater and hybrids in 2016;

* A growth in average lateral length from 8,580 ft in 2012 to 9,308 ft in 2016; and

* A grown in peak month oil rate from 722 barrels per day (bbl/d) in 2012 to 841 bbl/d in 2016.

“We think the findings are interesting because we’re in a time when activity levels are increasing sharply,” he said. “There’s consistent and maybe incessant operator concern about higher factor costs, yet little or no expectation of meaningfully higher oil prices.”

He drew four conclusions from the study:

  • High proppant well designs on the Nesson anticline have generated substantial net present value gains at low service pricing and oil prices;
  • The deflation in service costs was conducive to experimentation with high-proppant well designs;
  • The shift away from ceramics mitigated some of the marginal cost increases for proppant, but that lever is exhausted for high-proppant wells; and
  • If/when higher activity levels produce inflationary pressure on sand and pumping costs, well designs will respond accordingly.

Trisha Curtis, co-founder of PetroNerds

Trisha Curtis, co-founder of PetroNerds, examined overall shale productivity gains in her presentation. (Source: Hart Energy)

Trisha Curtis, co-founder of PetroNerds, examined overall shale productivity gains in her presentation. Her company published a study in November 2016 in conjunction with the Oxford Institute for Energy Studies on the productivity gains taking place in the U.S. She said the study was spurred by comments during conference calls saying that the “cost efficiencies” taking place weren’t real; they were simply a response to depressed service prices.

“It had me thinking that there had to be more to it,” Curtis said, adding that studying productivity requires looking at more than just IP rates; EURs must also be taken into consideration, as should completions.

“The major step changes in completions were largely missed by a lot of analysts,” she said. “When prices first came down, there was this big focus on high-grading and high-intensity completions. A lot of folks thought this was a flash in the pan, kind of, ‘You’re pumping a bunch of sand down these wells, and then you’re going to get these increased IPs, but the overall well performance is not going to change very much.’ But that didn’t happen to be the case.”

Of note, one of the reasons companies have switched from ceramics to sand is because they’ve rethought their fracture patterns. “A huge conceptual change took place,” she said. “You no longer wanted your fractures to go out as far as they can go. A few years ago at this conference, there were people talking about only using ceramics in the Bakken because they provided the conductivity and the flow. Now operators want to keep their fractures close to the wellbores, so using cheaper sand and cheaper fluids makes a lot more sense.”

Curtis examined several other basins, including the Permian and Eagle Ford, and concluded that overall operators will be looking at shorter cycles, lower costs and rising productivity. This is predicated on several factors:

  • Costs are rising for higher proppant loads, fluids and pressure pumping;
  • Some cost cuts such as those in the service sector are temporary, but productivity improvements should not be underestimated, such as increasing output and lowering long-term costs;
  • Spud-to-total depth days have been dramatically reduced, down to less than a week in the Eagle Ford and Bakken;
  • The industry is experiencing efficiency savings in water handling, faster drilling and completion times, and better facilities management; and
  • U.S. shale/tight/unconventional oil now accounts for 5% of global supply.

Rhonda Duey can be reached at