Shale Narrative Shift

Bloomberg: America’s Great Shale Oil Boom Is Nearly Over

With the crude price seemingly stuck close to where it is — despite the tensions in the Persian Gulf region which flared up again on Friday —  the next round of discussions between the shale producers and their lenders could be difficult. Some mergers may follow.

Yet fans of U.S. oil shouldn’t be disconsolate. The end of the second shale boom will usher in a third: the period of young adulthood. This will bring a range of new skills, but production will grow at a more measured pace.

This third boom will be driven by the international oil majors and will be characterized by a focus on better extraction, rather than rapid output growth. The application of enhanced oil recovery techniques, consolidation of ownership, automation of drilling, and rationalizing of supply chains will increase the volume of oil extracted over the lifetime of a well and reduce costs. But it won’t deliver the same pace of growth as seen recently.

The recovery rate of oil from shale deposits is typically about 5%-10%, but ConocoPhillips has pushed recovery as high as 20% in some parts of the Eagle Ford shale play in Texas, and it could reach 40% under the right circumstances. The upside to the lifetime recovery rate from Eagle Ford would be huge, potentially extending higher production rates for longer.

The third shale boom is coming. Just don’t expect it to look like the first two.

Bloomberg: Peak Shale: How U.S. Oil Output Went From Explosive to Sluggish

Giants like Exxon Mobil Corp. and Chevron Corp. have plans to expand in the Permian Basin. Unencumbered by the funding problems faced by independent producers, they plan to more than double production by the early 2020s.

Any Rare Earths Under There?

WSJ: If You Want ‘Renewable Energy,’ Get Ready to Dig

A single electric-car battery weighs about 1,000 pounds. Fabricating one requires digging up, moving and processing more than 500,000 pounds of raw materials somewhere on the planet. The alternative? Use gasoline and extract one-tenth as much total tonnage to deliver the same number of vehicle-miles over the battery’s seven-year life.

When electricity comes from wind or solar machines, every unit of energy produced, or mile traveled, requires far more materials and land than fossil fuels. That physical reality is literally visible: A wind or solar farm stretching to the horizon can be replaced by a handful of gas-fired turbines, each no bigger than a tractor-trailer.

Building one wind turbine requires 900 tons of steel, 2,500 tons of concrete and 45 tons of nonrecyclable plastic. Solar power requires even more cement, steel and glass—not to mention other metals. Global silver and indium mining will jump 250% and 1,200% respectively over the next couple of decades to provide the materials necessary to build the number of solar panels, the International Energy Agency forecasts. World demand for rare-earth elements—which aren’t rare but are rarely mined in America—will rise 300% to 1,000% by 2050 to meet the Paris green goals. If electric vehicles replace conventional cars, demand for cobalt and lithium, will rise more than 20-fold. That doesn’t count batteries to back up wind and solar grids.

Fracturing Tech Trajectory

JPT: Exploring the Innovative Evolution of Hydraulic Fracturing

  • 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.