Understanding the Lingo is Key to Mastering the Natural Gas Value Chain

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Thursday, 06/06/2024  Published by: John Abeln  rbnenergy.com

To closely analyze the natural gas market is to be constantly bombarded with vast amounts of information — weather forecasts, pipeline flows, LNG feedgas, power demand and storage — that is frequently updated, impacting both spot and future prices. But before you can get into the deeper analysis, you’ve got to understand the natural gas value chain and its terminology. In today’s RBN blog, we’ll explain the various terms used to describe natural gas as it moves from wellhead to consumer. 

Natural gas is one of the most widely tracked and traded commodities in the world and, while it may seem straightforward on the surface, the devil is in the details. There’s way too much terminology in the gas business to try to cover it all in a single RBN blog so we are going to sidestep topics like landfill gas, biogas, acid gas and any other gas that differs from the norm, either by its origin or its chemical makeup. And we will also stay away from certain terms crucial to the engineering side of the business, such as flanges and casing heads. Instead, our focus will be on the main metrics of gas production and how they diverge. When trying to analyze production data, outsiders often quickly become tangled up in the different figures for gross withdrawals, marketed production and dry gas production. Today, we will dispel some of that confusion.

In this journey through gas industry lingo, we will be referring to the terms used by the Energy Information Administration (EIA). As the federal government has access to data sources on the U.S. energy business that are inaccessible to others, its historical data serves as a baseline for natural gas-related statistics. That is not to say that market participants and observers never disagree with the EIA’s data, just that they generally go by the same nomenclature and definitions. We’ll be diving into the way EIA defines supply and demand measures, so see the schematic in Figure 1 below if you need to get your bearings on how the definitional chain operates. These definitions don’t precisely follow points in the physical flow of gas — keep that in mind as we discuss these terms. The four steps noted below are used to establish the different classifications of natural gas production. Later, we will compare these four steps to the actual movement of gas in the system and discuss how it differs from the definitional framework.

Figure 1. Natural Gas Production Classifications. Source: RBN 

Step 1 — Origin at the Wellhead

Gross Withdrawals — Also called wellhead gas, this refers to natural gas in its original state as soon as it comes out of the ground. Any liquids or impurities that are not dissolved in the gas as they come out of the ground aren’t counted, so water or heavier hydrocarbons that “drop out” at the lease separator are excluded — as is any liquid stream that the gas may be “associated” with.

All other natural gas liquids (NGLs) and field condensate (mostly C6+) that remain entrained in the gas stream are counted in the gross withdrawals total. The figure also includes inert gases such as water vapor, nitrogen, carbon dioxide (CO₂) and hydrogen sulfide. It even includes gas that is consumed in field operations. Natural gas can be used for on-site generators or reinjected to maintain a constant level of pressure in oil or gas reservoirs (a subject for an upcoming blog). This reinjection can be especially impactful in regions like Alaska where the ratio of natural gas to oil in wells is high and there are limitations on piping gas out of the area.

Since significant portions of the gross withdrawal are either inert or not combustible with standard natural gas generators and heating equipment, the gross withdrawal figure is measured in standard cubic feet (or a multiple thereof), as opposed to British thermal units (Btus), which is a measure of the heat content produced by burned gas. For 2023, gross withdrawals totaled roughly 120 Bcf/d.

Notably, gas from the wellhead is often referred to as either associated gas or non-associated gas. If the gas comes from a formation like the Permian where drilling economics are largely determined by oil prices, then the gas production volumes are “associated” with crude production. Alternatively, if the gas comes from a basin like the Haynesville in Texas and Louisiana that produces little or no liquids and therefore has economics contingent on natural gas prices, it might be called non-associated, lean or even dry gas. However, even a “dry gas” basin like the Haynesville has some NGL extraction loss (covered below), meaning that the wellhead gross gas number from a dry gas basin is not synonymous with the “dry gas” metric after processing. We know that’s confusing but hopefully the next couple of steps will help clarify.

Step 2 — Calculating Marketed Production

Vented and Flared Gas — When the production of gas from a well becomes more than the supporting infrastructure can handle it may be vented or flared. This amount includes both the gas vented and flared at the lease/well (the vast majority) and at gas processing plants. (Getting a flaring permit for a natural gas processing plant is very difficult, which is why close to all flaring takes place at the wellhead). Vented gas is released directly into the atmosphere and is especially bad for air quality and greenhouse gas (GHG) emissions because methane is a more potent GHG than the CO₂ produced when methane burns. Additionally, vented gas releases nearly four times more key pollutants that can prove hazardous to humans and animals relative to flared gas. Where a large amount of gas must be disposed of, it can be ignited and flared, which is somewhat less environmentally damaging.

Venting or flaring may happen during maintenance, emergency shutdown events or if there’s a sudden pressure increase that must be alleviated. It has been the case that the surge in initial production for a well after stimulation can overwhelm the infrastructure that was sized to support the steady-state production rate. Especially in oil-focused regions where natural gas is often a byproduct, producers were known to flare gas rather than spend the capital required to capture it. However, in recent years as more gas pipelines have gone into service, relieving constraints, and as producers and regulators have become more environmentally conscious, the amount of flared gas has been drastically reduced. That said, substantial regional disparities persist. Notably, some flaring still occurs in the Bakken and in the Permian Basin (see Cover Me). Going forward, with the introduction of the federal government’s Methane Emissions Reduction Program (MERP; see Time Has Come Today) it’s expected that the proportion of gas that’s vented or flared will continue to decline.

Repressuring and Nonhydrocarbon Gases – Repressuring gas is when gas is reinjected into a reservoir so that more oil or gas will ultimately be recovered. While this falls under the umbrella of enhanced oil recovery, or EOR, it differs from the CO₂ flooding techniques we’ve discussed in previous blogs (see The Air That I Breathe) that involve injecting CO₂ and water deep underground into the production zone of an oil field. Nonhydrocarbon gases are the inert gases, like CO₂ and nitrogen, referred to in the gross withdrawals segment.

Marketed Production — Here we have everything left over after some gas has been vented, flared or reinjected, and after inert gases have been removed. However, the gas used in field operations and processing plant operations is still included, as are most NGLs. This is sometimes referred to as “wet” gas. This is a case in which the EIA definitions diverge a bit from the physical flow of gas. Marketed production includes some gas that is used on the lease/well in generators or other engines, so not all marketed production is gas that leaves the lease. In 2023, marketed production averaged 113 Bcf/d. Since gross withdrawals were 120 Bcf/d, that means that 7 Bcf/d (120 – 113 = 7) was used in the repressuring and non-hydrocarbon gas removal processes described above as well as losses in the gathering lines (including precipitation of heavier hydrocarbons).

Step 3 — Calculating Dry Gas Production

Natural Gas Plant Liquids Production — Natural gas processing plants perform three basic tasks: (1) cleanup/remove remaining impurities, (2) extract gas liquids, and (3) distribute plant outputs into appropriate takeaway transportation systems. In Task 2, the extracted liquids stream is generally Y-grade, which includes ethane, propane, butane, isobutane and natural gasoline. NGLs have been covered extensively in countless RBN blogs but suffice to say these hydrocarbons have many uses after the Y-grade is separated from natural gas at a processing plant (see our Good to Be a Gas Processor series).

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 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) for the output gas to meet pipeline specs.

Because the removal of NGLs decreases the volume of the natural gas stream, it is sometimes referred to as “extraction loss” or “shrink.” Note that some ethane is often “rejected" into the natural gas stream that goes into gas pipelines, thereby raising the Btu content of the gas stream (see Take It To the Limit). This rejected ethane is counted as part of dry natural gas (see entry below).

Dry Natural Gas — Finally, we get to the main event; dry gas is what is usually being referenced when we discuss gas production numbers. This is also sometimes referred to as “residue” or “tailgate” gas since it’s the gas that remains after processing. Alternatively, it’s also called “pipeline quality” gas because it meets the specifications typically demanded by contracts on transmission and distribution pipelines. (The specifications on gathering pipeline systems that move gas from the well to the processing plant are far more permissive, so meeting those isn’t what we talk about when we say “pipeline quality.”)

It still includes gas that is used in field operations other than reinjections, and it also includes gas that is used to operate a processing plant, so this is another divergence from the physical flow. The flow of gas from the well doesn’t include the field-use gas, and the flow out of the processing plant doesn’t include the gas used in processing. More precisely, the gas that leaves gas processing plants is dry gas minus lease and plant fuel.

Ideally, dry natural gas is a fungible commodity with inert gases removed so that downstream equipment powered by natural gas can run smoothly. While pipelines and utilities measure gas by volume for the purposes of facilities design, the buying and selling of gas occurs in units of millions of Btus (MMBtus).

However, impurities can still exist in gas that is classified as dry. For example, we wrote in It’s a Gas, Gas, Gas that the Permian’s Midland Basin frequently produces gas that contains more nitrogen than other producing regions. Also note that some gas has enough inert gases, NGLs or other contaminants to violate pipeline specifications. This gas can damage downstream equipment, which can cause major headaches for utilities and industrial customers. In addition, since pipelines measure gas based on heating content rather than volume, there is also the potential for dry gas volume to be overstated if inert gases are not excluded.

As shown in Figure 2 below, gross withdrawals (blue bars) averaged 125 Bcf/d in 2023 (far-right cluster of columns). After venting, flaring, repressuring and the removal of inert gases, we were left with 113 Bcf/d in marketed production (orange bars). Finally, with the NGLs removed we see the more familiar figure of 104 Bcf/d (green bars) for dry gas production that gets quoted in most natural gas market reports, including ours.

Figure 2: Natural Gas Supply by Classification. Source: EIA

While all measures of natural gas production (gross withdrawals, marketed production, and dry gas production) have increased significantly over the past year, the ratios between them have remained roughly constant, with dry gas about 83% of gross withdrawals, as it was in 2017. Far less stability is seen in the ratios on the consumption side of the balance. We won’t go into those today, other than to identify the four major consumption sectors (see below), but they are discussed in detail in Heat of the Moment and other blogs on the gas balance.

In terms of how the dry gas gets consumed, we’ll start upstream and go from there.

Step 4 — Uses of Natural Gas

Lease and Plant Fuel — As mentioned above, lease gas is used in drilling operations at the wellhead and the lease, burned in engines, and used as a pressure source to operate valves and other machinery. Plant fuel is used at natural gas processing plants to power their operations.

Pipeline and Distribution Use — Pipelines need gas to operate, almost entirely to run the compressors that keep gas flowing. This also includes a minor amount of line loss, or gas that seeps out of a pipeline and into the atmosphere (see Time Has Come Today). Lease and plant fuel, pipeline and distribution use, plus other minor uses, have fluctuated between 6% and 10% of all dry gas usage in the Lower 48; however, there is no strong trend in this data over the Shale Era. Nevertheless, the size of these uses combined can be significant and can impact the gas balance at the margins even as it is dwarfed by the main uses for gas: residential/commercial demand, industrial demand, power generation and exports. Inaccuracies in classifications for any of the supply or demand components risk creating an invisible oversupply or undersupply of gas that may not show up on paper but will eventually be reflected in prices.

Four Major Consumption Sectors — The major components of natural gas demand are residential demand, commercial demand, industrial demand and power generation. These are broken down individually in EIA data and accounted for an average of 80 Bcf/d in combined usage in 2023.

Exports — Exports have been a quickly growing segment of natural gas demand over the past decade. This includes exports through LNG terminals as well as pipeline exports to Mexico and Canada. This data is broken down by the EIA by type of export and point of exit. Net exports in 2023 were around 13 Bcf/d.

While the major components of supply and demand may get the most attention, recognizing the minor components is crucial to getting a true sense of the market. The way that gross withdrawals are transformed into marketed production and then dry natural gas is not intuitive. At crucial points it contradicts the way gas actually flows through the processing and transmission system.

Observe the physical flow of gas in Figure 3 below and how it differs from Figure 1, which has guided our discussion so far. Our terminology removes repressuring and nonhydrocarbon gases at the same point (before gross withdrawals become marketed production). In the real world, repressuring gas will be removed immediately after the gas emerges from the wellhead, while nonhydrocarbons are removed at gas processing plants alongside NGLs.

Figure 3. Physical Flow of Produced Volumes. Source: RBN.

Similarly, in the nomenclature, lease and plant fuel are considered part of dry natural gas just like the gas that would flow to a residential meter. However, in the physical flow, lease fuel is used right after gas is removed from the wellhead, and plant fuel is used at the gas processing plant. So the way we talk about the gas market does not always conform to the way the gas flows, but it is important to understand both the operational and reporting realities to know how the fundamentals stack up.

This raises the obvious question: Why do the EIA’s definitions vary from the physical flow? The major variance is the treatment of lease and plant fuel. These are not losses, or movements into other fuels. They are productive uses of natural gas, and this is the biggest hint. Though the EIA doesn’t specifically address this question, its mandate is to promote “sound policymaking, efficient markets, and public understanding of energy and its interaction with the economy and the environment.” Since lease and plant fuel is gas being consumed, not lost (like venting) or recovered (like repressurization), if you’re trying to classify the world, it looks a lot like demand, not lost supply. So, regardless of where in the flow it happens, we need to understand that 6% to 10% of all gas is consumed in operating the natural gas system itself.

What’s more, the EIA’s treatment of these upstream consumption sources is also meant to allow for the modeling of supply in a way that allows for improvements in efficiency, or the displacement of natural gas use by other fuels, like electrification. If the numbers did not reflect those uses, and just reported a net number for field production and a net number for residue gas, there would be a missed opportunity to address those uses.

Even though we often speak of marketed gas and dry gas as if they were quantities of natural gas that you can point to in the world, these classifications are conceptual realities that do not correspond directly to a specific point in the physical flow. This means that to really understand how much gas is in the market, we need to be aware of the volumes recorded in the physical process and how they must be reconfigured to get more comparable metrics for production.