GAS PROCESSING

INTRODUCTION
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.
Natural gas processing plants are used to purify the raw natural gas extracted from underground
gas fields and brought up to the surface by gas wells. The processed natural gas, used as fuel by
residential, commercial and industrial consumers, is almost pure methane and is very much
different from the raw natural gas.
Contents
Composition of raw natural gas
Required quality of end-product processed gas
Types of raw natural gas wells
Description of a natural gas processing plant

Composition of raw natural gas
Raw natural gas typically consists primarily of methane (CH
4
), the shortest and lightest
hydrocarbon molecule. It also contains varying amounts of:
Heavier gaseous hydrocarbons: ethane (C
2
H
6
), propane (C
3
H
8
), normal butane (n-C
4
H
10
),
isobutane (i-C
4
H
10
), pentanes and even higher molecular weight hydrocarbons. When
processed and purified into finished by-products, all of these are collectively referred to
as NGL (Natural Gas Liquids).
Acid gases: carbon dioxide (CO
2
), hydrogen sulfide (H
2
S) and Mercaptan such as
methanethiol (CH
3
SH) and ethanethiol (C
2
H
5
SH).
Other gases: nitrogen (N
2
) and helium (He).
Water: water vapor and liquid water.
Liquid hydrocarbons: perhaps some natural gas condensate (also referred to as casing
head gasoline or natural gasoline) and/or crude oil.
Mercury: very small amounts of mercury primarily in elemental form, but chlorides and
other species are possibly present.


Required quality of end-product processed gas
Raw natural gas must be purified to meet the quality standards specified by the major pipeline
transmission and distribution companies. Those quality standards vary from pipeline to pipeline
and are usually a function of a pipeline systems design and the markets that it serves. In general,
the standards specify that the natural gas:
Be within a specific range of heating value (caloric value). For example, in the United
States, it should be about 1,035 5% Btu per standard cubic foot of gas at an absolute
pressure of 1 atmosphere and 60 F (41 5% MJ per normal cubic meter of gas at 1
atmosphere of absolute pressure and 0 C).
Be delivered at or above a specified hydrocarbon dew point temperature (below which
some of the hydrocarbons in the gas might condense at pipeline pressure forming liquid
slugs which could damage the pipeline).
Be free of particulate solids and liquid water to prevent erosion, corrosion or other
damage to the pipeline.
Be dehydrated of water vapor sufficiently to prevent the formation of methane hydrates
within the gas processing plant or subsequently within the sales gas transmission
pipeline.
Contain no more than trace amounts of components such as hydrogen sulfide, carbon
dioxide, mercaptans, nitrogen, and water vapor.
Maintain mercury at less than detectable limits (approximately 0.001 ppb by volume)
primarily to avoid damaging equipment in the gas processing plant or the pipeline
transmission system from mercury amalgamation and embrittlement of aluminum and
other metals.
Types of raw natural gas wells
Raw natural gas comes primarily from any one of three types of wells: crude oil wells,
gas wells, and condensate wells.
Natural gas that comes from crude oil wells is typically termed associated gas. This gas
can exist separate from the crude oil in the underground formation, or dissolved in the
crude oil.
Natural gas from gas wells and from condensate wells, in which there is little or no crude
oil, is termed non-associated gas. Gas wells typically produce only raw natural gas, while
condensate wells produce raw natural gas along with a low-boiling point mixture of
liquid hydrocarbons called natural gas condensate (sometimes also called natural
gasoline, casing head gasoline or simply condensate).
Raw natural gas can also come from methane deposits in the pores of coal seams. Such
gas is referred to as coalbed gas and it is also called sweet gas because it is relatively free
of hydrogen sulfide.


Description of a natural gas processing plant
There are a great many ways in which to configure the various unit processes used in the
processing of raw natural gas. The schematic block flow diagram below is a generalized, typical
configuration for the processing of raw natural gas from non-associated gas wells. It shows how
raw natural gas is processed into sales gas pipelined to the end user markets. It also shows how
processing of the raw natural gas yields these byproducts:
Natural gas condensate
Sulfur
Ethane
Natural gas liquids (NGL): propane, butanes and C
5
+ (which is the commonly used term
for pentanes plus higher molecular weight hydrocarbons)

1. Raw natural gas is commonly collected from a group of adjacent wells and is first
processed at that collection point for removal of free liquid water and natural gas
condensate. The condensate is usually then transported to a petroleum refinery and the
water is disposed of as waste water.

2. The raw gas is then pipelined to a gas processing plant where the initial purification is
usually the removal of acid gases (hydrogen sulfide and carbon dioxide). There a many
processes that are available for that purpose as shown in the flow diagram, but Amine gas
treating is the most widely used process. In the last ten years, a new process based on the
use of polymeric membranes to dehydrate and separate the carbon dioxide and hydrogen
sulfide from the natural gas stream is gaining acceptance.

3. The acid gases removed by amine treating are then routed into a sulfur recovery unit
which converts the hydrogen sulfide in the acid gas into elemental sulfur. There are a
number of processes available for that conversion, but the Claus process is by far the one
usually selected. The residual gas from the Claus process is commonly called tail gas and
that gas is then processed in a tail gas treating unit (TGTU) to recover and recycle
residual sulfur-containing compounds back into the Claus unit. Again, as shown in the
flow diagram, there are a number of processes available for treating the Claus unit tail
gas. The final residual gas from the TGTU is incinerated. Thus, the carbon dioxide in the
raw natural gas ends up in the incinerator flue gas stack.

4. The next step in the gas processing plant is to remove water vapor from the gas using
either the regenerable absorption (chemistry) in liquid triethylene glycol (TEG),
commonly referred to as glycol dehydration, or a Pressure Swing Adsorption (PSA) unit
which is regenerable adsorption using a solid adsorbent.
[9]
Other newer processes
requiring a higher pressure drop like using membranes or dehydration at supersonic
velocity using, for example, the Twister Supersonic Separator may also be considered.

5. Mercury is then removed by using adsorption processes (as shown in the flow diagram)
such as activated carbon or regenerable molecular sieves.

6. Nitrogen is next removed and rejected using one of the three processes indicated on the
flow diagram:

7. Cryogenic process using low temperature distillation. This process can be modified to
also recover helium, if desired.

8. Absorption process using lean oil or a special solvent as the absorbent.

9. Adsorption process using activated carbon or molecular sieves as the adsorbent. This
process may have limited applicability because it is said to incur the loss of butanes and
heaver hydrocarbons.

10. The next step is to recover the natural gas liquids (NGL) for which most large, modern
gas processing plants use another cryogenic low temperature distillation process
involving expansion of the gas through a turbo-expander followed by distillation in a
demethanizing fractionating column. Some gas processing plants use a lean oil absorption
process rather than the cryogenic turbo-expander process.

The residue gas from the NGL recovery section is the final, purified sales gas which is pipelined
to the end-user markets.

Fractionation of Natural Gas Liquefied (NGL by-products)

The recovered NGL stream is processed through a fractionation train consisting of three
distillation towers in series:

De ethanizer

The overhead product from the de ethanizer is ethane and the bottoms are fed to the
depropanizer.

De propanizer

The overhead product from the depropanizer is propane and the bottoms are fed to the
debutanizer.

De butanizer

The overhead product from the debutanizer is a mixture of normal and iso-butane, and the
bottoms product is a C
5
+ mixture. The recovered streams of propane, butanes and C
5
+ are each
"sweetened" in a Merox process unit to convert undesirable mercaptans into disulfides and, along
with the recovered ethane, are the final NGL by-products from the gas processing plant.

The next step in the process of producing natural gas is processing. This involves taking the 'raw'
natural gas obtained from underground, removing impurities, and ensuring that the gas is ready
for use prior to being transported to its destination.
Processing
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 'no
associated 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 (H
2
S), 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.
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 (NGL)
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.
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.
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.
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.


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
The absorption method of NGL extraction is very similar to using absorption for dehydration.
The main difference is that, in NGL absorption, 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 fractionators 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:
De ethanizer - this step separates the ethane from the NGL stream.
De propanizer - 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 De isobutanizer - 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.
Sulfur exists in natural gas as hydrogen sulfide (H
2
S), and the gas is usually considered sour if
the hydrogen sulfide content exceeds 5.7 milligrams of H
2
S 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, mono
ethanolamine (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.
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.