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Fifty Shades Lighter – What Should be Done with Condensates?

The new domestic energy rush has supplied North America with a potent new cocktail of hydrocarbons. Not only are we producing more oil and gas here than we have in decades, but we are producing more of certain kinds of hydrocarbons than North America’s existing energy infrastructure is built to handle.

We’re talking about the “C” word: Condensates. Today we introduce a blog series on condensates.

As RBN Energy explained last February (see “neither fish nor fowl”), condensates are a highly volatile hydrocarbon mixture that is classified somewhere between crude oil and natural gas liquids. Condensates are showing up in abundance both in new “wet gas” plays, where they drop down as liquids from gas streams during the field production process, and in oil shale plays, where condensate is part of the liquid coming straight out of a wellhead.

Condensates per se have always been around. What is new is how fast the supply has grown: As much as 50% of the “crude” coming out of some of the wells in the Eagle Ford in Texas is actually condensate, according to energy consultant Muse, Stancil & Co., which authored a highly informative presentation on the subject at the recent Platts NGLs conference in Houston. Condensate is far lighter than crude oil, with an API gravity of 45 to 75 degrees compared with the NYMEX benchmark West Texas Intermediate (WTI) 39 API and international benchmark Brent’s 38 API. (The lower the API gravity number, the more viscous, i.e., thicker the oil). The generally accepted delineation between a condensate and a crude oil is 45 API. However, the lack of an agreed standard definition for Condensate is a challenge for the industry.

Statistics from the Railroad Commission of Texas (the oversight body for the oil & gas industry in Texas) show that the Eagle Ford shale of South Texas is quickly becoming the new “Capital of Condensate” and that production statewide of condensate is rising rapidly (see the chart and table below).

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