NGL prices have been weak this year, but the same has been true for the price of natural gas. So how does this market scenario play out for gas processors who make their money extracting NGLs from gas? Last week we looked at what could be gleaned from the Frac Spread, and concluded that it missed a couple of key variables like the liquids content and the BTU value of the inlet gas. So today we’ll see what it takes to incorporate those factors into our analysis and in the process dive deep into the math of gas processing to learn about things like cubic feet, GPM and moles.
This is Part II of our series on natural gas processing economics. In Part I of this series, Another Fracing Problem? we reviewed the calculation methodology, the history and the pros and cons of the Frac Spread - the difference between the price of natural gas and the weighted average price of NGLs on a BTU basis. We noted that the Frac Spread is a good indicator of the relative health of natural gas processing over time. However the Frac Spread is not representative of the specific processing margin for a particular stream of input gas. That is because Frac Spreads do not take into account the quality of the gas being processed either in terms of the liquids content or the BTU content. Those two properties ultimately determine the quantity of NGLs that a given inlet gas stream can produce. To incorporate these two properties into gas processing margin calculations, we first have to understand how liquids content and BTU content are measured and then how to convert between liquid volumes and gas volumes, since we transform the input gas stream into both liquid and gas outputs in our processing plant. We begin that voyage of understanding today.
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Natural Gas Processing Basics
To get everyone on the same page, we need to spend just a few minutes on gas processing. Skip this section if you feel that you are up to speed on what happens in a gas processing plant.
The “raw” gas that is input into a gas processing plant (the “inlet” gas) has three components: methane, natural gas liquids, and everything else, a.k.a. impurities. Methane is the hydrocarbon we generally think of as natural gas (95% of the gas that moves in transmission pipelines to end-use markets is composed of methane molecules). Natural gas liquids (NGLs) – ethane, propane, normal butane, isobutane and natural gasoline – are the heavier hydrocarbons that come out of the wellhead mixed in with the methane. Also mixed up with the methane and NGLs are impurities – carbon dioxide, water vapor, hydrogen sulfide (H2S), helium, nitrogen, oxygen and other undesirables. Some of these impurities are knocked out of the gas stream by treating before the gas gets to the plant. Other impurities are removed as part of processing within the plant.
There is no such thing as a typical gas inlet stream, but to give you some sense of the breakdown you can consider 80% methane, 15% NGLs and 5% impurities as representative for “rich” gas (explained below). Note that methane and NGLs are hydrocarbons – they burn. Impurities generally don’t burn or have value as part of the hydrocarbon stream. (Some do have value and are processed and sold – helium for example, but they are a miniscule part of the processing economics so we are going to ignore them in our analysis).
Figure 1 below shows the basic flow of natural gas processing. The inlet gas is unprocessed natural gas that comes from the wellhead (where it is treated to remove some impurities). Plant output (tailgate gas) consists of processed gas that is injected into a natural gas pipeline and NGLs that leave the plant by pipeline, rail, truck, and sometimes barge.
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