It’s been an exciting and productive few years for Permian producers, but it’s also been a period fraught with challenges. Dealing with a mid-decade crash in crude oil prices. Struggling to improve yields from the Wolfcamp, Bone Spring and other hydrocarbon-rich formations to lower breakeven costs. Coping with major pipeline takeaway constraints — for crude and natural gas — and the resulting price discounts. Now, the challenge of produced water has come to the fore. Horizontal wells in some parts of the Permian generate six, eight, even 10 barrels of produced water per barrel of crude, and all of it needs to be either disposed of or treated. The volumes are enormous, the permitting and logistics mind-boggling, and the costs — well, you can imagine. Today, we consider the Permian’s produced-water conundrum as crude and gas production volumes ramp up. Warning!: Today’s blog is a blatant advertorial for new reports by B3 Insight on Permian produced water.
Crude oil production in the Permian now averages more than 4 MMb/d, and natural gas output tops 10 Bcf/d — extraordinary numbers. Over the next few months, new pipeline capacity (most of it from West Texas to the Gulf Coast) will reduce and then eliminate takeaway constraints that have plagued Permian producers for a year or two now, and enable production growth to accelerate. The catch is that, as production of crude (and associated gas) speeds up, so will the volumes of produced water generated.
As we said in our Drill Down report on Permian produced water last year, several million barrels a day of super-salty water emerges from wells in the play, and all that water needs to be gathered and safely disposed of. The task affects both legacy conventional (vertical) wells and newer unconventional (horizontal) wells. Because “water cuts” (the ratio of produced water to crude) increase over time, the large number of older vertical wells generate significant volumes of produced water — but most of that produced water can be re-injected into nearby pressure-depleted, conventional oil reservoirs for enhanced oil recovery (EOR). The re-injected water boosts pressure within the reservoirs and stimulates the production of still more crude. The thornier problem for Permian producers comes from all those new horizontal wells producing water and needing infrastructure capable of handling it to be developed. Large numbers of these wells are being drilled and completed, and in some areas — especially parts of the Permian’s Delaware Basin, but in the Midland Basin too — the water cuts can be quite high: as much as 10:1 (or even higher in a few cases), and the disposal of those water volumes is much more problematic.
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