To say that the shale sector is on the cusp of a new era, one where fast-flowing streams of real-time well data and on-the-fly fracture designs are the norm, is not something one does lightly.

It’s a bold declaration.

It represents a step change that engineers have been told is just around the corner for several years. They’ve been promised software that will churn out truly optimized recipes of proppant concentration, rate, total volume, etc. to match each fracture stage’s piece of the rock.

In a neat world, this nets better production from good stages while injecting less capital into bad stages—the ultimate win-win for a sector that spends 60–70% of well costs on the completion.

We can pluck example after example from industry literature to prove the incremental existence of such tailor-made well pads. However, the mostly small-scale cases are far from representative of the aggregate.

For some, the absence of scale fuels skepticism over whether real-time optimization will ever amount to much more than avoiding screenouts and other costly operational drags. Then again, history is not always the best predictor of the future.

In this context, it discounts a slate of technologies and methods that didn’t exist 5 years ago or were still coming into their own. Some of these innovations are now part of the toolbox that operators are using to reach for the brass ring that is real-time optimization at scale.

“Much like self-driving cars, we see the future of a self-driving oil field that’s self-optimizing and operated autonomously—an element of this would be automating the fracturing process,” said Rob Fast, the chief technology officer of the Bakken Shale producer Hess Corp. He added that this vision of the future could be coming soon.

Hess and its service provider are scheduled to start the first field trials of an automated fracturing system sometime in June. While sharing details of the upcoming test, Fast emphasized that “this project is a collaboration project that combines automation and optimization and provides advanced measurements to optimize completions and well spacing.”

Fast was speaking during the SPE Hydraulic Fracturing Technology Conference plenary where he said the decision to invest in automated fracturing comes after Hess spent more than a decade producing some of the industry’s most in-depth tight reservoir studies.

Through that work, the operator has apparently concluded that right sizing fractures will require a reliable set of eyes and ears in the subsurface. That translates to an array of permanent fiber-optic cables and permanent downhole pressure gauges, along with temporary “dip in” fiber deployments.

Traditionally, such a big data-giving diagnostic program would be deemed a “science project,” the widely used euphemism for the sector’s illuminating but hard-to-scale look-back studies. But Hess sees dividends if the diagnostic jewelry helps achieve a new ambition to complete 40% fewer wells in the Bakken while still maintaining current recovery estimates. “Serious beef,” Fast said of the sought-after target.

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