How Rich is Rich? – Gas Processing Economics Part 3: Computing NGL Quantities

Natural gas processing plants are being built or expanded at a feverish pace.  At least 90 projects are in the works around the U.S., expected to add more than 15 Bcf/d of capacity according to the latest Bentek NGL Facilities Databank numbers.  How do the economics of these investments work? We know that it is a lot more complicated than a simple frac spread.  But does that mean the calculations must be exclusively the purview of engineers armed with gas plant optimization models?  Heck no.  Anybody, even an MBA with a spreadsheet, a few standard factors and a gas analysis can figure out how a gas processing plant makes money.  So to prove that point today we’ll dive one more time into natural gas processing economics to understand how the composition of an inlet gas stream is converted to outlet streams of natural gas liquids and residue gas.

This posting continues the series that we started some weeks back focused on the details of natural gas processing economics.  In Another Fracing Problem? NGL Prices and the Natural Gas Processing Frac Spread we looked at recent NGL and natural gas price trends and the implications for the Frac Spread, a measure of the difference between gas prices and NGL prices on a BTU equivalent basis.  That analysis showed us that even though the natural gas processing business is not as lucrative today as it was back in November 2011, it is still in pretty good economic shape when compared to long run trends.  But we also noted that the Frac Spread is just that, a price spread.  It should not be interpreted as a gas processing margin.  That is because the Frac spread does not incorporate variables like gas quality and quantity into its calculations.  

That got us to Part II of the series, How Rich is Rich? – How BTU Content and GPM Determine NGL Quantities.   This is where we reviewed gas processing basics, then went deep into the math of a four factor model for understanding gas processing economics – MQQV, short for measurement, quantity, quality and value.  These four factors provide a framework for understanding how processing economics work.  We explained the first two of these factors in Part II.  Today we’ll review what we learned in Part II and then jump into the modeling abyss from there.  As we’ve noted before, this is a deep dive, not a casual read. Also, it will be difficult if not impossible to follow today’s discussion without having read Parts I and II of this series.  You have been warned!!

MQQV – Measurement and Quantity Revisited

Here’s the big picture -- 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. 

Thus the first factor in MQQV is Measurement, which encompasses the three units of measure used to describe volumes of gas, volumes of liquid and energy content:

#1 – Volume of gas in cubic feet. For inlet or raw gas we measure the volume of gas, expressed in cubic feet. 

#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. 

#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 or tailgate gas we measure the gas calorific content, expressed in BTUs. 

The second of our four factors is Quantity, which describes 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. 

#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. A typical BTU content number for pipeline quality gas is 1,028 BTU. 

#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.   BTU per gallon is used in our calculations to determine the heating value of NGLs that are removed from the gas during processing.

Given these three definitions we then examined the factors necessary to convert gas volumetric units to liquid volumetric units and to thermal (BTU) units.  The first was the BTU per gallon factor for each NGL, based on standards set by the Gas Processing Association, or GPA.   The second was Gallons per Pound Mole, used to convert gallons to standard cubic foot of each NGL, also based on GPA standards.  And finally we introduced the engineering ‘pound mole’ factor 379.482 which is used to convert gallons of any substance to standard cubic feet of that substance (at standard temperature and pressure).  If you didn’t get this the first time through, do a remedial back to Part II.

MQQV – The Third Factor: Quality

Finally we get to the subject of today’s blog – how the quality of the natural gas processed fits into the economics of gas processing.  To calculate the economics of a gas processing plant we need to understand the quality of the plant inlet stream and the quality of the plant tailgate streams.  The quality of the inlet gas stream is determined by a gas chromatograph analysis of a sample and yields the Mole Percent of each component in the inlet gas stream, including methane, NGLs and what we have called impurities or inerts (carbon dioxide, water vapor, hydrogen sulfide (H2S), helium, nitrogen, oxygen, etc.). 

A full natural gas analysis typically provides a mole percent breakdown on 20 to 30 components of the sample, including the inerts, methane, the five NGLs, and a wide range of heavier hydrocarbons such as hexanes, heptanes, benzene, toluene, octanes, xylene, etc.   To keep our explanations manageable, we are going to group all of the components equal to or heavier than normal pentane into one product category of natural gasoline.  Usually the heavier components are miniscule, and lumping them all into a natural gasoline category will not be a significant distortion of our analysis.  Likewise we are going to lump all of the inerts together into one number.

Now we can look at some examples of the analysis results from three typical Eagle Ford wells.  These samples are sourced from a memo from the American Petroleum Institute to EPA regarding Volatile Organic Compounds (VOCs) from producing operations which can be found here.

Note that the composition of the samples varies widely.  This is typical of wells across an individual shale play.  As we will see when we work through the gas plant economics calculations, each of these three samples is rich gas – with Sample #3 much richer than Sample #1.  Between the two samples there is an almost 10% swing between the methane content (round numbers 83% vs. 73%) and the NGL content (16% to 25%).  For today’s calculations we are going to focus on Sample #2 – the middle of the road for our Eagle Ford samples.

For our gas processing calculations we are going to assume that these gas streams will be run in a fully loaded 200,000 Mcf/d plant that has a liquids recovery rate (efficiency factor) of 99% for all NGLs except for ethane, which has a 90% recovery rate.  We’ll show how these numbers are used below.

The Energy Balance

There are only three variables we need to calculate all of the volumetric data for our gas plant economics: (1) the composition of the gas in Mole Percent as described above, (2) the estimated volume of inlet gas, and (3) the plant recovery efficiency factors.  Efficiency factors indicate the expected percentage recovery of each NGL stream based on the plant type (cryogenic expander, refrigeration, lean oil absorption) and the specific hardware configuration of the plant. 

Given these input variables and the basic energy conversion constants that we discussed in Part II of this series and recapped above (BTU/gallon of each NGL product, Gallons per Pound Mole of each NGL product, and the gas-to-liquids pound mole conversion factor of 379.482) we can compute the energy balance across our sample plant.  In other words, we know the energy content of our inlet gas stream, the volume of that inlet gas stream and the recovery efficiency of our plant.  From that we can compute the volume of liquids that will be produced and the volume (heat content) of the residue gas stream.  Since we are simply converting energy from one form to another across the plant, our inlet and outlet streams must balance – thus the term Energy Balance.

Computing the Energy Balance for Sample #2

We’ll split the process for computing the Energy Balance for Sample #2 into three sets of computations. In the first we’ll compute all of the Standard Factors needed for any energy balance, based on the steps outlined in Part II of this series.  In the second we’ll calculate NGL production, GPM and the BTU value of the inlet gas stream.  In the third (which must wait for the next installment of this blog series) we’ll compute the volume and heat content of the residue gas stream and confirm the energy balance across the plant.

Table #1 below shows the Standard Factors we will need for these calculations.  Input variables are in cells highlighted in green.  Calculated cells are in white.  Input column (b) is the heat content, or BTU value of each NGL based on GPA specs.  Column (b) also includes the input factor (379.482) used to convert a gallon of any substance to the number of cubic feet of that substance.  Column (c), also an input based on GPA specs, is the gallons per pound mole of each NGL, abbreviated “gal/lb-mol”.   There is only one other input factor needed, and that is the BTUs per cubic foot of methane in Column (f).  This is a standard value of 1,010 BTU/cubic foot.

Click Image to Enlarge

Standard Factor Calculations.  With those inputs we can now compute the other Standard Factors we will need for our analysis.  Most of these calculations were shown in Part II but are repeated here for continuity.

Column (d) is the cubic feet per gallon of liquid for each of the hydrocarbons.  The number in each cell is calculated by multiplying the pound mole factor in column (c) by the constant 379.482.  So for example, one liquid gallon of propane is equal to 36.39 cubic feet of propane gas.  Said another way, if we extract one gallon of propane out of 1,000 cubic feet of gas, there will only be 963.61 cubic feet of gas left.

We also need to know Column (e), the number of gallons per thousand cubic feet of each hydrocarbon.  That number is computed by dividing the pound mole factor in Column (c) by 379.482, then multiplying by 1,000.  Again using propane as an example, if we have 1,000 cubic feet of propane gas, that is the equivalent of 27.48 gallons of propane liquid.  And yes, Columns (d) and (e) are two ways of expressing the same relationship.

Finally Column (f) is the BTUs contained in a cubic foot of each hydrocarbon in its gaseous form.  We know how many BTUs per gallon there are for each hydrocarbon.  That is Column (b).  We know how many cubic feet there are in a gallon – that is Column (d).  And so Column (f) is simply Column (b) divided by Column (d).

Now the caveats.  We’ve simplified a couple of problems away that will offend some of our engineer readers.  First are adjustments in the BTU values for water content of the inlet stream. Second, there are adjustments to the BTU values of the hydrocarbons based on whether they are in gaseous or liquid form. Given the mind numbing complexity of this exercise, we felt that simplifying away these calculations was a necessary step to make this topic somewhat understandable.  If you are interested in the nitty gritty, I suggest you download GPA Standard 8173-94 - Method for Converting Mass of Natural Gas Liquids and Vapors to Equivalent Liquid Volumes.  That document will explain how to do these calculations the meticulous engineering way.

That’s it for the standard factors.  We can use these standard factors for any gas plant analysis we want to examine.  It’s important that you know where the factors come from, but fortunately we don’t ever have to look at these calculations again.

The Energy Balance Calculations: Liquids Quantities.  Now that we have our standard factors we can plug in our input variables to compute the liquids quantities associated with our processing plant running Sample #2 gas.  These calculations are shown in Table #2 below where inputs are in blue highlighted cells, key outputs are in light orange.

Note that you can download the spreadsheet containing Tables 1 and 2 below.  If you have trouble with the download, please email info@rbnenergy.com and we’ll send you a copy.

(click image to enlarge)

Column (1) contains the Mole percent analysis for Sample #2.  In Column (2) we calculate Available GPM.  That is the gallons per MCF of each hydrocarbon in the inlet gas stream, which is computed by multiplying Column (e) in the standard factors table by Column (1), the mole percent in the sample.  For example, we know there are 36.39 gallons per MCF of propane, and 5% of the molecules in our sample are propane molecules.  Thus the propane component of our inlet gas stream contributes 1.37 to the total GPM of the inlet stream.  Add up all five NGLs in Column (2) and we see that Sample #2 has a GPM of 6.02.

Note that we called this ‘Available GPM’.  That means that the GPM of our input stream is 6.02, but our plant will probably not be able to recover all of those liquids in the inlet stream.  We’ll see how that works a little later.

Recall that we said that our plant running Sample #2 gas is a 200,000 Mcf/d facility that is fully loaded, meaning that it is running 200,000 Mcf/d  inlet gas volume.  That number is input at the bottom of Column (4).  Using that number we can calculate the available gallons per day at the plant in Column (3) by multiplying GPM in Column (2) by the inlet gas volume.  So for example, our propane GPM is 1.37.  So 1.37 * 200 * 1000 = 274,796 gallons per day available for extraction.

That volume is available for extraction, but the extraction capability of our plant is limited.  We are running our Sample #2 gas through a cryogenic expander plant, but this particular configuration can only recover 99% of the propane, butanes and natural gasoline, and only 90% of the ethane.  That fact has two implications.   First our actual liquids recoveries will be less than the liquids available for extraction. Second, the NGL molecules that are not extracted from the inlet stream will show up in the outlet residue gas stream, effectively increasing the BTU content of the tailgate gas.  We’ll get back to the residue gas implications in the next blog in this series.

Our ‘Estimated % Recovery’ input variables are in Column (4).  Column (5) is simply Column (3) times Column (4).  By dividing the total of Column (5) by the inlet volume (200,000 Mcf/d), we can calculate the effective GPM, which is 5.65, slightly less than the available GPM of 6.02.  Column (6) is barrels per day of NGL products, calculated by dividing Column (5) by 42.  Column (7) computes the percent of each liquids product of the total.  In our Sample #2, note that ethane is 56% of the recovered liquids, far higher than the typical ethane percentage of 42% that we used in the Frac Spread calculation in Another Fracing Problem a few blogs back.  A high ethane percentage is typical of many of the rich shale plays like Eagle Ford and Wet Marcellus.

Finally we need to know the inlet stream BTU value.  To get that number we multiply the mole % in Column (1) by the BTU per cubic foot in Standard Factors Column (f).  For example, methane is 77.6% of the inlet stream.  There are 1,010 BTUs in a cubic foot of methane.  So methane contributes 784 BTUs of our total inlet stream.  When the NGL components are added to the methane, we find that the total inlet stream has 1,258 BTUs per cubic foot.  

Are We Done Yet?

Not quite. At this point in our review of MQQV we have explored Measurement, Quantity and half of the Quality factor.  The other half of the Quality factor is the residue gas calculation – how we compute the volume and BTU value of the residue gas stream.  After that we’ll have the data necessary to check our work – does the energy input and output across the plant balance out.  That’s where we’ll go next in this series.  Then we’ll be ready to get to the bottom line – the final MQQV factor – Value.  How we apply a price outlook to our calculations to find out how much money our plant is really making running Sample #2.  And we’ll also run the same model on Samples #1 and #3 to get a sense for the difference a few mole percents make.  Keep that seat belt fastened tight.