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When the Levee Breaks - Why U.S. Natural Gas Liquids Production is Surging

Since the advent of the Shale Revolution way back in 2008, U.S. production of natural gas liquids from gas processing has grown pretty much non-stop, from an annual average of 1.8 MMb/d 15 years ago to 5.9 MMb/d in 2022 — a 9% compound annual growth rate. Today, NGL production exceeds 6.1 MMb/d and that number might be even higher if the glut of supply wasn’t depressing prices and discouraging the recovery of a lot of ethane. All that production has major implications for domestic pricing, upstream economics, midstream infrastructure, and downstream consumers like petrochemicals, not to mention international markets, which now receive roughly 40% of U.S. output. In today’s RBN blog, we examine what’s causing NGL production to continually increase.

To understand what’s going on with U.S. production of the mixed stream of natural gas liquids collectively known as NGLs (ethane, propane, butane, isobutane and pentanes+), it’s important to recognize the relationship between NGLs and the production of crude oil and natural gas — after all, they all come from the same holes in the ground in hydrocarbon-rich areas like the Permian, Bakken, and Eagle Ford. Because of their common origin, RBN refers to the three commodity streams (crude, gas and NGLs) as the “drillbit hydrocarbons.”

These days, about 80% of drilling in the U.S. is primarily directed at crude oil production, which makes sense because (generally speaking) crude is the most valuable of the drillbit hydrocarbons on a per-Btu basis. Crude doesn't emerge from shale plays on its own, of course — instead, it comes out of the ground mixed with what’s typically referred to as associated gas, a gurgling combination of methane (natural gas), mixed NGLs and various impurities. The composition of this oil/natgas/NGLs stew varies widely, not only between shale basins but within each basin and from well to well — and even within each well over time.

The differences in drillbit-hydrocarbon composition between oil-focused basins, within basins and from well to well is easy to wrap your head around — depending on location, there will be variations in rock and hydrocarbon content within that rock. As for the changes in composition over time at individual oil-focused wells in key shale basins, they tend to result from an increasing gas-to-oil ratio (known as the GOR and calculated as Mcf of gas per barrel of oil). In other words, the output of individual wells and entire shale basins tend to become “gassier” from year to year. As we discussed in the blog Don’t Stop Me Now, the main reason for rising GORs is that gas type curves generally tend to be shallower — meaning they decline less quickly — than oil type curves. Also, additional natural gas and NGLs tend to be captured as gathering and processing infrastructure is built out and restrictions on flaring tighten.

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