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| Source: Duke Energy
Gas Transmission Canada |
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'.
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.
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| A Natural Gas Processing Plant |
| Source: Duke Energy
Gas Transmission Canada |
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:
Scroll down, or click on the links above to be transported
to a particular section.
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.
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.
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| Gas Processing Engineers |
| Source: ChevronTexaco
Corporation |
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
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.
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| Absorption Towers |
| Source: Duke Energy
Gas Transmission Canada |
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.
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| Gas Processing Plant with Absorption
Towers |
| Source: Duke Energy
Gas Transmission Canada |
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.
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
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| Pipes and Absorption Towers |
| Source: Duke Energy
Gas Transmission Canada |
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.
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| Gas Sweetening Plant |
| Source: Duke Energy
Gas Transmission Canada |
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.
For more information on sulfur recovery and the Claus
process, click here.
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| Elemental Sulfur Production
in a Gas Treatment Plant |
| Source: Duke Energy
Gas Transmission Canada |
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.
To learn more about the environmental effects of sour
gas treatment and flaring, click here.
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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