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 users.
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 other compounds. To learn about the basics of natural gas,
including its composition, click here.
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’.
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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.
| A Natural Gas Processing Plant |
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:
- Oil and Condensate Removal
- Water Removal
- Separation of Natural Gas Liquids
- Sulfur and Carbon Dioxide Removal
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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 wellhead.
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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.
| Gas Processing Engineers |
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.
Water Removal
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.
Glycol Dehydration
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 website here.
Solid-Desiccant Dehydration
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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.
| Absorption Towers |
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.
| Gas Processing Plant with Absorption Towers |
Separation of Natural Gas Liquids
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| Source: Duke Energy Gas Transmission Canada |
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.
NGL Extraction
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
| Pipes and Absorption Towers |
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 extracting ethane.
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 the propane.
- 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.
To learn more about the fractionation of NGLs, click here.
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. For
information on the production of sulfur in the United States, visit the
USGS here.| Gas Sweetening Plant |
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.
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.
Click here to learn about the transportation of natural gas.
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