Natural gas, as it is used by consumers, is much different from the natural gas
that is brought from underground up to the wellhead. Although the processing of natural gas is in many respects
less complicated than the processing and refining of crude oil, it is equally as necessary before its use by end
The natural gas used by consumers is composed almost entirely of methane. However, natural gas found at the wellhead,
although still composed primarily of methane, is by no means as pure. Raw natural gas comes from three types of
wells: oil wells, gas wells, and condensate wells. Natural gas that comes from oil wells is typically termed 'associated
gas'. This gas can exist separate from oil in the formation (free gas), or dissolved in the crude oil (dissolved
gas). Natural gas from gas and condensate wells, in which there is little or no crude oil, is termed 'nonassociated
gas'. Gas wells typically produce raw natural gas by itself, while condensate wells produce free natural gas along
with a semi-liquid hydrocarbon condensate. Whatever the source of the natural gas, once separated from crude oil
(if present) it commonly exists in mixtures with other hydrocarbons; principally ethane, propane, butane, and pentanes.
In addition, raw natural gas contains water vapor, hydrogen sulfide (H2S), carbon dioxide, helium, nitrogen, and
Natural gas processing consists of separating all of the various hydrocarbons and fluids from the pure natural
gas, to produce what is known as 'pipeline quality' dry natural gas. Major transportation pipelines usually impose
restrictions on the make-up of the natural gas that is allowed into the pipeline. That means that before the natural
gas can be transported it must be purified. While the ethane, propane, butane, and pentanes must be removed from
natural gas, this does not mean that they are all 'waste products'.
In fact, associated hydrocarbons, known as 'natural gas liquids' (NGLs) can be very valuable by-products of natural
gas processing. NGLs include ethane, propane, butane, iso-butane, and natural gasoline. These NGLs are sold separately
and have a variety of different uses; including enhancing oil recovery in oil wells, providing raw materials for
oil refineries or petrochemical plants, and as sources of energy.
While some of the needed processing can be accomplished at or near the wellhead (field processing), the complete
processing of natural gas takes place at a processing plant, usually located in a natural gas producing region.
The extracted natural gas is transported to these processing plants through a network of gathering pipelines, which
are small-diameter, low pressure pipes. A complex gathering system can consist of thousands of miles of pipes,
interconnecting the processing plant to upwards of 100 wells in the area. According to the American Gas Association's
Gas Facts 2000, there was an estimated 36,100 miles of gathering system pipelines in the U.S. in 1999.
In addition to processing done at the wellhead and at centralized processing plants, some final processing is also
sometimes accomplished at 'straddle extraction plants'. These plants are located on major pipeline systems. Although
the natural gas that arrives at these straddle extraction plants is already of pipeline quality, in certain instances
there still exist small quantities of NGLs, which are extracted at the straddle plants.
The actual practice of processing natural gas to pipeline dry gas quality levels can be quite complex, but usually
involves four main processes to remove the various impurities:
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In addition to the four processes above, heaters and scrubbers are installed, usually at or near the wellhead.
The scrubbers serve primarily to remove sand and other large-particle impurities. The heaters ensure that the temperature
of the gas does not drop too low. With natural gas that contains even low quantities of water, natural gas hydrates
have a tendency to form when temperatures drop. These hydrates are solid or semi-solid compounds, resembling ice
like crystals. Should these hydrates accumulate, they can impede the passage of natural gas through valves and
gathering systems. To reduce the occurrence of hydrates, small natural gas-fired heating units are typically installed
along the gathering pipe wherever it is likely that hydrates may form.
Oil and Condensate Removal
In order to process and transport associated dissolved natural gas, it must be separated from the oil in which
it is dissolved. This separation of natural gas from oil is most often done using equipment installed at or near
The actual process used to separate oil from natural gas, as well as the equipment that is used, can vary widely.
Although dry pipeline quality natural gas is virtually identical across different geographic areas, raw natural
gas from different regions may have different compositions and separation requirements. In many instances, natural
gas is dissolved in oil underground primarily due to the pressure that the formation is under. When this natural
gas and oil is produced, it is possible that it will separate on its own, simply due to decreased pressure; much
like opening a can of soda pop allows the release of dissolved carbon dioxide. In these cases, separation of oil
and gas is relatively easy, and the two hydrocarbons are sent separate ways for further processing. The most basic
type of separator is known as a conventional separator. It consists of a simple closed tank, where the force of
gravity serves to separate the heavier liquids like oil, and the lighter gases, like natural gas.
In certain instances, however, specialized equipment is necessary to separate oil and natural gas. An example of
this type of equipment is the Low-Temperature Separator (LTX). This is most often used for wells producing high
pressure gas along with light crude oil or condensate. These separators use pressure differentials to cool the
wet natural gas and separate the oil and condensate. Wet gas enters the separator, being cooled slightly by a heat
exchanger. The gas then travels through a high pressure liquid 'knockout', which serves to remove any liquids into
a low-temperature separator. The gas then flows into this low-temperature separator through a choke mechanism,
which expands the gas as it enters the separator. This rapid expansion of the gas allows for the lowering of the
temperature in the separator. After liquid removal, the dry gas then travels back through the heat exchanger and
is warmed by the incoming wet gas. By varying the pressure of the gas in various sections of the separator, it
is possible to vary the temperature, which causes the oil and some water to be condensed out of the wet gas stream.
This basic pressure-temperature relationship can work in reverse as well, to extract gas from a liquid oil stream.
In addition to separating oil and some condensate from the wet gas stream, it is necessary to remove most of the
associated water. Most of the liquid, free water associated with extracted natural gas is removed by simple separation
methods at or near the wellhead. However, the removal of the water vapor that exists in solution in natural gas
requires a more complex treatment. This treatment consists of 'dehydrating' the natural gas, which usually involves
one of two processes: either absorption, or adsorption.
Absorption occurs when the water vapor is taken out by a dehydrating agent. Adsorption occurs when the water vapor
is condensed and collected on the surface.
An example of absorption dehydration is known as Glycol Dehydration. In this process, a liquid desiccant dehydrator
serves to absorb water vapor from the gas stream. Glycol, the principal agent in this process, has a chemical affinity
for water. This means that, when in contact with a stream of natural gas that contains water, glycol will serve
to 'steal' the water out of the gas stream. Essentially, glycol dehydration involves using a glycol solution, usually
either diethylene glycol (DEG) or triethylene glycol (TEG), which is brought into contact with the wet gas stream
in what is called the 'contactor'. The glycol solution will absorb water from the wet gas. Once absorbed, the glycol
particles become heavier and sink to the bottom of the contactor where they are removed. The natural gas, having
been stripped of most of its water content, is then transported out of the dehydrator. The glycol solution, bearing
all of the water stripped from the natural gas, is put through a specialized boiler designed to vaporize only the
water out of the solution. While water has a boiling point of 212 degrees Fahrenheit, glycol does not boil until
400 degrees Fahrenheit. This boiling point differential makes it relatively easy to remove water from the glycol
solution, allowing it be reused in the dehydration process.
A new innovation in this process has been the addition of flash tank separator-condensers. As well as absorbing
water from the wet gas stream, the glycol solution occasionally carries with it small amounts of methane and other
compounds found in the wet gas. In the past, this methane was simply vented out of the boiler. In addition to losing
a portion of the natural gas that was extracted, this venting contributes to air pollution and the greenhouse effect.
In order to decrease the amount of methane and other compounds that are lost, flash tank separator-condensers work
to remove these compounds before the glycol solution reaches the boiler. Essentially, a flash tank separator consists
of a device that reduces the pressure of the glycol solution stream, allowing the methane and other hydrocarbons
to vaporize ('flash'). The glycol solution then travels to the boiler, which may also be fitted with air or water
cooled condensers, which serve to capture any remaining organic compounds that may remain in the glycol solution.
In practice, according to the Department
of Energy's Office of Fossil Energy, these systems have been shown to
recover 90 to 99 percent of methane that would otherwise be flared into the atmosphere.
To learn more about glycol dehydration, visit the Gas Technology Institute's
Solid-desiccant dehydration is the primary form of dehydrating natural gas using adsorption, and usually consists
of two or more adsorption towers, which are filled with a solid desiccant. Typical desiccants include activated
alumina or a granular silica gel material. Wet natural gas is passed through these towers, from top to bottom.
As the wet gas passes around the particles of desiccant material, water is retained on the surface of these desiccant
particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto the desiccant material,
leaving the dry gas to exit the bottom of the tower.
Solid-desiccant dehydrators are typically more effective than glycol dehydrators, and are usually installed as
a type of straddle system along natural gas pipelines. These types of dehydration systems are best suited for large
volumes of gas under very high pressure, and are thus usually located on a pipeline downstream of a compressor
station. Two or more towers are required due to the fact that after a certain period of use, the desiccant in a
particular tower becomes saturated with water. To 'regenerate' the desiccant, a high-temperature heater is used
to heat gas to a very high temperature. Passing this heated gas through a saturated desiccant bed vaporizes the
water in the desiccant tower, leaving it dry and allowing for further natural gas dehydration.
Separation of Natural Gas Liquids
Natural gas coming directly from a well contains many natural gas liquids that are commonly removed. In most instances,
natural gas liquids (NGLs) have a higher value as separate products, and it is thus economical to remove them from
the gas stream. The removal of natural gas liquids usually takes place in a relatively centralized processing plant,
and uses techniques similar to those used to dehydrate natural gas.
There are two basic steps to the treatment of natural gas liquids in the natural gas stream. First, the liquids
must be extracted from the natural gas. Second, these natural gas liquids must be separated themselves, down to
their base components.
There are two principle techniques for removing NGLs from the natural gas stream: the absorption method and the
cryogenic expander process. According to the Gas Processors Association, these two processes
account for around 90 percent of total natural gas liquids production.
The Absorption Method
The absorption method of NGL extraction is very similar to using absorption for dehydration. The main difference
is that, in NGL absorption, an absorbing oil is used as opposed to glycol. This absorbing oil has an 'affinity'
for NGLs in much the same manner as glycol has an affinity for water. Before the oil has picked up any NGLs, it
is termed 'lean' absorption oil. As the natural gas is passed through an absorption tower, it is brought into contact
with the absorption oil which soaks up a high proportion of the NGLs. The 'rich' absorption oil, now containing
NGLs, exits the absorption tower through the bottom. It is now a mixture of absorption oil, propane, butanes, pentanes,
and other heavier hydrocarbons. The rich oil is fed into lean oil stills, where the mixture is heated to a temperature
above the boiling point of the NGLs, but below that of the oil. This process allows for the recovery of around
75 percent of butanes, and 85 - 90 percent of pentanes and heavier molecules from the natural gas stream.
The basic absorption process above can be modified to improve its effectiveness, or to target the extraction of
specific NGLs. In the refrigerated oil absorption method, where the lean oil is cooled through refrigeration, propane
recovery can be upwards of 90 percent, and around 40 percent of ethane can be extracted from the natural gas stream.
Extraction of the other, heavier NGLs can be close to 100 percent using this process.
The Cryogenic Expansion Process
Cryogenic processes are also used to extract NGLs from natural gas. While absorption methods can extract almost
all of the heavier NGLs, the lighter hydrocarbons, such as ethane, are often more difficult to recover from the
natural gas stream. In certain instances, it is economic to simply leave the lighter NGLs in the natural gas stream.
However, if it is economic to extract ethane and other lighter hydrocarbons, cryogenic processes are required for
high recovery rates. Essentially, cryogenic processes consist of dropping the temperature of the gas stream to
around -120 degrees Fahrenheit.
There are a number of different ways of chilling the gas to these temperatures, but one of the most effective is
known as the turbo expander process. In this process, external refrigerants are used to cool the natural gas stream.
Then, an expansion turbine is used to rapidly expand the chilled gases, which causes the temperature to drop significantly.
This rapid temperature drop condenses ethane and other hydrocarbons in the gas stream, while maintaining methane
in gaseous form. This process allows for the recovery of about 90 to 95 percent of the ethane originally in the
gas stream. In addition, the expansion turbine is able to convert some of the energy released when the natural
gas stream is expanded into recompressing the gaseous methane effluent, thus saving energy costs associated with
The extraction of NGLs from the natural gas stream produces both cleaner, purer natural gas, as well as the valuable
hydrocarbons that are the NGLs themselves.
Natural Gas Liquid Fractionation
Once NGLs have been removed from the natural gas stream, they must be broken down into their base components to
be useful. That is, the mixed stream of different NGLs must be separated out. The process used to accomplish this
task is called fractionation. Fractionation works based on the
different boiling points of the different hydrocarbons in the NGL stream. Essentially, fractionation occurs in
stages consisting of the boiling off of hydrocarbons one by one. The name of a particular fractionator gives an
idea as to its purpose, as it is conventionally named for the hydrocarbon that is boiled off. The entire fractionation
process is broken down into steps, starting with the removal of the lighter NGLs from the stream. The particular
fractionators are used in the following order:
- Deethanizer - this step separates
the ethane from the NGL stream.
- Depropanizer - the next step separates
- Debutanizer - this step boils off
the butanes, leaving the pentanes and heavier hydrocarbons in the NGL stream.
- Butane Splitter or Deisobutanizer
- this step separates the iso and normal butanes.
By proceeding from the lightest hydrocarbons to the heaviest, it is possible to
separate the different NGLs reasonably easily.
Sulfur and Carbon Dioxide Removal
In addition to water, oil, and NGL removal, one of the most important parts of gas processing involves the removal
of sulfur and carbon dioxide. Natural gas from some wells contains significant amounts of sulfur and carbon dioxide.
This natural gas, because of the rotten smell provided by its sulfur content, is commonly called 'sour gas'. Sour
gas is undesirable because the sulfur compounds it contains can be extremely harmful, even lethal, to breathe.
Sour gas can also be extremely corrosive. In addition, the sulfur that exists in the natural gas stream can be
extracted and marketed on its own. In fact, according to the USGS, U.S. sulfur production from gas processing plants
accounts for about 15 percent of the total U.S. production of sulfur.
Sulfur exists in natural gas as hydrogen sulfide (H2S), and the gas is usually considered sour if the hydrogen
sulfide content exceeds 5.7 milligrams of H2S per cubic meter of natural gas. The process for removing hydrogen
sulfide from sour gas is commonly referred to as 'sweetening' the gas.
The primary process for sweetening sour natural gas is quite similar to the processes of glycol dehydration and
NGL absorption. In this case, however, amine solutions are used to remove the hydrogen sulfide. This process is
known simply as the 'amine process', or alternatively as the Girdler process, and is used in 95 percent of U.S.
gas sweetening operations. The sour gas is run through a tower, which contains the amine solution. This solution
has an affinity for sulfur, and absorbs it much like glycol absorbing water. There are two principle amine solutions
used, monoethanolamine (MEA) and diethanolamine (DEA). Either of these compounds, in liquid form, will absorb sulfur
compounds from natural gas as it passes through. The effluent gas is virtually free of sulfur compounds, and thus
loses its sour gas status. Like the process for NGL extraction and glycol dehydration, the amine solution used
can be regenerated (that is, the absorbed sulfur is removed), allowing it to be reused to treat more sour gas.
Although most sour gas sweetening involves the amine absorption process, it is also possible to use solid desiccants
like iron sponges to remove the sulfide and carbon dioxide.
Sulfur can be sold and used if reduced to its elemental form. Elemental sulfur is a bright yellow powder like material,
and can often be seen in large piles near gas treatment plants, as is shown. In order to recover elemental sulfur
from the gas processing plant, the sulfur containing discharge from a gas sweetening process must be further treated.
The process used to recover sulfur is known as the Claus process, and involves
using thermal and catalytic reactions to extract the elemental sulfur from the hydrogen sulfide solution.
In all, the Claus process is usually able to recover 97 percent of the sulfur that has been removed from the natural
gas stream. Since it is such a polluting and harmful substance, further filtering, incineration, and 'tail gas'
clean up efforts ensure that well over 98 percent of the sulfur is recovered.
Gas processing is an instrumental piece of the natural gas value chain. It is instrumental in ensuring that the
natural gas intended for use is as clean and pure as possible, making it the clean burning and environmentally
sound energy choice. Once the natural gas has been fully processed, and is ready to be consumed, it must be transported from those areas that produce natural gas, to those areas that require it.