Over the past three years, the U.S. frac sand market has been transformed. Demand for the sand used in hydraulic fracturing is more than twice what it was in early 2016. Dozens of new “local” sand mines have come online, slashing the need for railed-in Northern White Sand in the Permian and a number of other fast-growing plays. Frac sand prices have fallen sharply from their 2017 highs. And exploration and production companies, which traditionally outsourced sand procurement and “last-mile” sand logistics to pressure pumpers and other specialists, are taking a more hands-on approach. It’s a whole new world. Today, we continue our series on the major upheavals rocking the frac sand world in 2019 with a look at the development of local sand sources in the Eagle Ford, SCOOP/STACK and the Haynesville.
What we’ve been witnessing in shale plays in Texas, Oklahoma, Louisiana and other energy-producing states in recent years is the industrialization — or, better yet, the assembly-lining — of crude oil and natural gas production. Like Henry Ford and his Model T more than a century ago, Shale Era pioneers started out small and in experimental mode, first with single wells, then with small groups of wells as they learned more about what worked (and what didn’t). By the latter half of the 2010s, exploration and production companies (E&Ps) had learned a lot: where the best “rock” is, for one thing, but also how they can improve their economics by (for example) drilling much longer laterals from multi-well pads, using more frac sand per linear foot of lateral, and developing pipelines to transport large volumes of produced water from the lease to disposal wells. They, like Ford, learned that nothing beats a robust, repeatable system. As a result, oil-field productivity in most plays is way up, and the break-even price for crude and gas production is way down.
A major focus of E&Ps since 2016 has been optimizing the procurement, delivery and use of frac sand, which had become a costly line item in their budgets as sand use soared (along with drilling lateral lengths) and — in 2017 — when the price of Northern White Sand (long the preferred sand type for hydraulic fracturing) took off. As we said in Part 1, the frac-sand market responded by developing “local” sand mines much closer to shale production areas, especially in the Permian. There — mostly between the play’s Delaware and Midland basins — more than a dozen new sand mines have come online in the past couple of years, bringing the Permian’s total sand-mine count to about 20 and its sand-production nameplate capacity to more than 70 million tons per annum (MMtpa). That would appear to be more than enough to meet the play’s current needs of about 50 MMtpa, but (1) nameplate capacity often overstates a mine’s realistic output, and (2) RBN’s Mid-Price Scenario forecast sees Permian crude production rising by nearly 70% over the next five years (to 6.6 MMb/d by 2024), so even more local sand mines (or expansions of existing ones) may need to be developed.
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