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.
Natural gas processing plants perform 3 basic tasks: (1) cleanup/remove remaining impurities, (2) extract gas liquids, and (3) distribute plant outputs into appropriate takeaway transportation systems. We are mostly interested in step (2), the extraction of gas liquids. Gas liquids are extracted for two reasons: (a) because most liquids have to be extracted for the processed gas (“residue” or “tailgate” gas) to meet natural gas pipeline quality specifications, and (b) to sell the liquids because they are usually worth more money than natural gas.
Plant inlet gas containing a high percentage of NGLs is called “rich” or “wet” gas (the term wet meaning saturated with hydrocarbon liquids, not water). Gas that contains a low percentage of NGLs is called “dry” or “lean” gas. Some inlet gas is so lean that NGLs may not need to be removed in order for output gas to meet pipeline quality specifications. Other gas is so rich that the NGLs have to be removed (even if they have little or no value) in order for the output gas to meet pipeline specs (recall that we discussed the 2008 period of negative Frac Spreads in Another Fracing Problem.)
Warning: The following is a relatively dense discussion of measurements and conversions that from time to time necessarily strays into the rarified world of molecular physics so we may lose the conversational style that we usually employ in RBN blogs. Sorry ‘bout that. Unfortunately getting rich quick from NGL processing requires understanding some complicated measurements and conversions without which you might get poor quick by mistake. It’s good stuff, you’ll feel good afterwards and you never know you might just get rich.
MQQV: Measurement, Quantity, Quality, Value
Now that we are all up to speed on gas processing, we can get to the important part of this blog – the relationship between measurement, quantity, quality and value, or the MQQV principle. Don’t go looking for this term in engineering textbooks, because we made it up. But it gets to the heart of our goal to really understand natural gas processing economics. In the remainder of today’s blog we’ll look at Measurement and Quantity, and in the next installment we will explore Quality and Value, then see how these four factors are combined into the math of gas processing.
Gas and Liquids Phases of Hydrocarbons: Gas processing economics are all about converting hydrocarbons from one state to another (gas to liquids, liquids to gas) and understanding how much energy each liquid or gas contains. NGLs enter the gas processing plant as gas – part of the inlet gas stream. The NGLs are extracted from the gas and converted to liquids. They exit the plant as liquids and then are sold in liquids units – gallons or barrels. At every stage in the process, the gases or liquids have a measurable energy content. As Meryl Streep and Alec Baldwin say, ‘It’s complicated’.
Measurement. We start with the basic one-dimensional units of measure commonly used to describe volumes of gas, volumes of liquid and energy content during natural gas processing:
#1 – Volume of gas in cubic feet. For inlet or raw gas we measure the volume of gas, expressed in cubic feet. The typical measurement units you hear are thousands of cubic feet (Mcf), millions of cubic feet (MMcf), or billions of cubic feet (Bcf). (In the hydrocarbons world, M=1,000, not millions; it is MM = 1,000,000).
#2 – Volume of liquid in gallons or barrels. For the output or tailgate volumes of natural gas liquids we measure the volume of liquid, expressed in gallons or barrels. There are 42 gallons in a barrel and the terms are used interchangeably, usually with daily quantities expressed in barrels and value expressed in gallons.
#3 – Energy content of gas or liquids in BTU. The BTU or British Thermal Unit is a measure of energy – also called calorific value or heat content. BTU’s can be measured in a gas or in a liquid. For outlet gas we measure the gas calorific content, expressed in BTUs. The typical measurement you hear is MMBtu, or millions of BTUs. For outlet liquids we use standard BTU factors for the various NGLs.
Quantity Per Volume. Next we turn to units that define the quantities of one of our three basic units of measure in terms of volume. Quantities per volume describe the volume of liquid per volume of gas, the energy content per volume of gas or the energy content per volume of liquids, using the following three units:
#1 – GPM: Gallons per MCF, or gallons of NGLs per thousand cubic feet of natural gas. This is the primary measure expressing the quantity of liquids contained in an inlet natural gas stream. Both numbers are volumetric measurements. Figure 2 below is a way to visualize what we are talking about. Imagine a room 10ft X 10ft X 10ft. That’s 1,000 cubic feet (1 MCF). The buckets represent gallons of liquid. Four gallons of NGLs in 1 MCF of gas is considered rich gas. As shown in the table to the right, if there are only 3 gallons of liquids, processing is probably required. Down in the 1-2 GPM range, processing may be optional. Gas at 1 GPM is dry, or lean. So that’s your answer to the question in our title: How rich is rich? It’s 4 GPM or greater!
#2 – BTU per cubic foot: Natural gas at the tailgate of a processing plant is sold on the basis of heating value - BTU content per volume of gas. Natural gas at the plant tailgate has a BTU content of somewhere between 1,000 and 1,100 BTU per cubic foot, typically 1,028 BTU. That’s a typical spec for a natural gas transmission pipeline. At the plant inlet the BTU content can vary greatly depending on the GPM of the gas and the composition of the NGL barrel. Lean gas in Figure 2 might have a BTU content of 1,100 or less, while rich gas might have a BTU content of 1,100-1,300. The BTU value of very rich gas can range between 1,300 and 1,800 or even higher.
#3 – BTU per gallon: Each NGL product has a different heat content or BTU factor per volume of liquid, based on the size and structure of its molecules. We used these BTU factors in Another Fracing Problem? to compute the Frac Spread. You can find various sources of these BTU factors that differ plus or minus a couple of percent. In the past few months we’ve used some variants on these numbers in RBN postings. But no more. Starting with this Blog we will standardize on the official BTU factors published by the Gas Processing Association (see the table below). The official document is GPA Standard 2145-09 titled “Table of Physical Properties for Hydrocarbons and Other Components of Interest to the Natural Gas Industry.” You can download your own copy for the low price of $45.00 at https://www.gpaglobal.org/publications/department/id/5/. Make sure you get S 2145-09.
Here’s the catch with these numbers. These BTU/Gallon factors are based on the chemical properties of 100% pure NGLs. They are the numbers we need to use for gas processing economics calculations. However, they are not the BTU factors for NGL products in the marketplace. That is because products in the marketplace are not 100% pure. For example, the propane you buy for your grill is HD-5 propane, which probably contains 5% ethane and up to 5% propylene. So the BTU factor for ‘street’ propane is different. We’ll need to take that into account when we compute the final product yield economics in our calculations.
Converting Quantity per Volume of Liquids to Quantity per Volume of Gas: The “quantity per volume” conversion factor from gas to liquids and from liquids to gas is the most complicated measurement we have tackled so far. That’s because it measures the conversion of a substance in its gaseous form to a substance in its liquid form and that process is as much about physics as it is about math. Grip the steering wheel tightly and proceed with caution.
In layman’s terms this conversion starts with the understanding that any substance condenses from a gas to a liquid (or boils from a liquid to a gas) at a certain temperature – a.k.a. the boiling point. That is easy enough – basic science right? Well the next step is trickier - namely the fact that condensing a cubic foot of ethane gas into ethane liquid produces a different volume of ethane liquid (gallons) than the volume of propane liquid (gallons) that you get from condensing a cubic foot of propane gas. In other words, the volumes of gas and liquids that result from converting any substance (in our case, hydrocarbons) between their gas and liquid forms are different - depending on the molecular properties of the substance.
This important principle is crucial to NGL plant economics because we are converting inlet gas hydrocarbons into a mixture of output liquids and output gas and we need to capture the dynamics of that conversion process in our calculations for all the different outputs. To do that we therefore need to know the gas to liquid and the liquid to gas conversion factors for NGLs.
One additional complication before we move on – conversions between gases and liquids can only be compared if they take place at standard temperature (usually 60 degrees F) and standard pressure - otherwise we are not comparing apples to apples. Conversion calculations need to be adjusted to reflect standard pressure and temperature.
Moles: Converting between volumes of gas and volumes of liquid for NGL processing starts with the mole. (I told you we were going to get to moles eventually). In this context a mole is neither a small insectivorous mammal digging up your yard, a spicy sauce over tonight’s Mexican dinner, nor a pigmented, hopefully benign growth on your skin. A mole is “The amount (weight) of a substance that contains as many atoms as the number of atoms in 0.012 kilogram of Carbon 12”. That is a fancy way of describing the molecular weight of a substance. Since the mole number is quoted in quantity per kilogram we Americanize it by converting kilograms to pounds. That gives us Gallons per Pound Mole molecular weight factor.
Each hydrocarbon has a “Gallons per Pound Mole” factor, abbreviated as “gal/lb-mol”. The gallons per pound mole for each of the NGLs are shown in the table below in column “b”. Like the BTU factors we used above these numbers are also from GPA Standard 2145-09.
Gallons per pound mole factors tell us about the molecular weight (pounds) of a volume of liquid (gallon)
To do our NGL conversions we actually need to know the gaseous molecular volume (cubic feet) of a volume of liquid (gallon).
Because one pound-mole of any gallon of liquid always occupies 379.482 standard cubic feet at a standard temperature and pressure we can convert molecular weight (pounds) to molecular volume (cubic feet) using this engineering constant conversion factor of 379.482.
In the table above, to arrive at cubic feet of gas per gallon of NGL (column (c)) we therefore simply multiply the pound mole factor in column “b” by the constant 379.482. If we divide the pound mole factor in column “b” by 379.482, that gives us the gallons per cubic foot of that NGL. Multiply by 1,000 and we get gallons per thousand cubic feet, or GPM. That number is shown in column “d”.
Congratulations! Now you know how to convert between cubic feet per gallon of liquid and gallons per thousand cubic feet of a gas. Tab over to linked in and send out a status update on your education!!
A Small Example
That’s as far as we’ll go today with the MQQV principle. But after all of your hard work getting this far, it seems like we should at least give you one small example of how we’ll eventually use these measurements and conversion factors. Let’s say we get a sample of natural gas from a well in the Eagle Ford. We run that sample through a gas chromatograph (fancy device for determining the properties of a gas) and the analysis tells us that propane has a Mol % of 3 percent. That means that in a given cubic foot of the gas we have sampled, 3% of the molecules are propane molecules. (That same analysis would have also given us the Mol % for other NGLs in the sample too.)
If we take the GPM factor for propane in column “d” of our conversion table or 27.48 gallons per MCF and multiply that by the 3% of propane in our sample, we get 0.82. That number tells us that the propane in our sample is 0.82 GPM. By making that calculation for the other NGLs in our sample we can calculate the GPM of our Eagle Ford natural gas stream. That’s where we are headed next.
But before we get to our full blown Eagle Ford calculations we need to go through one more tutorial exercise on the two remaining aspects of the MQQV principle - quality and value. That’s where we’ll go in Part III of this series, coming soon.
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