Natural-gas processing is a complex industrial
process designed to clean raw natural gas by separating impurities and various non-methane hydrocarbons and fluids to
produce what is known as pipeline quality dry natural gas.
Natural-gas processing begins at the well head. The
composition of the raw natural gas extracted from producing wells depends on
the type, depth, and location of the underground deposit and the geology of the
area. Oil and natural gas are often found together in the same reservoir. The
natural gas produced from oil wells is generally classified as associated-dissolved,
meaning that the natural gas is associated with or dissolved in crude oil.
Natural gas production absent any association with crude oil is classified as
“non-associated.” In 2009, 89 percent of U.S. wellhead production of natural
gas was non-associated.
Most natural gas extracted from the Earth contains, to
varying degrees, low molecular weight hydrocarbon
compounds; examples include methane (CH4), ethane (C2H6),
propane (C3H8)
and butane (C4H10).
The natural gas extracted from coal reservoirs and mines (coalbed
methane) is the primary exception, being essentially a mix of mostly
methane and about 10 percent carbon
dioxide (CO2).
Natural-gas processing plants purify raw natural gas
from (a) underground gas fields and (b) from well heads
with associated gas by removing common contaminates such as water, carbon
dioxide (CO2) and hydrogen
sulfide (H2S). Some of the substances which contaminate natural
gas have economic value and are further processed or sold. A fully operational
plant delivers pipeline-quality dry natural gas that can be used as fuel by residential,
commercial and industrial consumers.
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
called associated gas. This gas can have existed as a gas cap above the
crude oil in the underground formation, or could have been dissolved in the
crude oil.
Natural gas from gas wells and from condensate wells, in
which there is little or no crude oil, is called non-associated gas. Gas
wells typically produce only raw natural gas, while condensate wells produce
raw natural gas along with other low molecular weight hydrocarbons. Those that
are liquid at ambient conditions (i.e., pentane and
heavier) are called natural gas condensate (sometimes also called natural
gasoline or simply condensate).
Natural gas is called sweet gas when relatively free
of hydrogen sulfide; however, gas that does contain
hydrogen sulfide is called sour gas. Natural gas, or any other gas mixture,
containing significant quantities of hydrogen sulfide, carbon dioxide or
similar acidic gases, is called acid gas
Raw natural gas can also come from methane deposits in the
pores of coal seams, and especially in a more concentrated state of adsorption
onto the surface of the coal itself. Such gas is referred to as coalbed gas
or coalbed methane (coal
seam gas in Australia). Coalbed gas has become an important source of
energy in recent decades.
Contaminants in raw natural gas
Raw natural gas typically consists primarily of methane (CH4),
the shortest and lightest hydrocarbon molecule. It also contains varying amounts
of:
- Heavier gaseous hydrocarbons: ethane (C2H6), propane (C3H8), normal butane (n-C4H10), isobutane (i-C4H10), 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 (CO2), hydrogen sulfide (H2S) and mercaptans such as methanethiol (CH3SH) and ethanethiol (C2H5SH).
- Other gases: nitrogen (N2) and helium (He).
- Water: water vapor and liquid water. Also dissolved salts and dissolved gases (acids).
- Liquid hydrocarbons: perhaps some natural gas condensate (also referred to as casinghead 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.
- Naturally occurring radioactive material (NORM): natural gas may contain radon, and the produced water may contain dissolved traces of radium, which can accumulate within piping and processing equipment. This can render piping and equipment radioactive over time.
The 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 system's 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 1035 ± 5% BTU per cubic foot of gas at 1 atmosphere and 60 degrees Fahrenheit (41 MJ ± 5% per cubic metre of gas at 1 atmosphere and 15.6 degrees Celsius).
- 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 that could damage the pipeline).
- Dew-point adjustment serves the reduction of the concentration of water and heavy hydrocarbons in natural gas to such an extent that no condensation occurs during the ensuing transport in the pipelines
- 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. A typical water content specification in the U.S. is that gas must contain no more than seven pounds of water per million standard cubic feet (MMSCF) of gas.
- Contain no more than trace amounts of components such as hydrogen sulfide, carbon dioxide, mercaptans, and nitrogen. The most common specification for hydrogen sulfide content is 0.25 grain H2S per 100 cubic feet of gas, or approximately 4 ppm. Specifications for CO2 typically limit the content to no more than two or three percent.
- 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.
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 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 C5+ (which is the commonly used term for pentanes plus higher molecular weight hydrocarbons)
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 an oil refinery and the water is disposed of as wastewater.
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 are many processes that are available for
that purpose as shown in the flow diagram, but amine treating is the process that was
historically used. However, due to a range of performance and environmental
constraints of the amine process, a newer technology based on the use of
polymeric membranes to separate the carbon dioxide and hydrogen sulfide from
the natural gas stream has gained increasing acceptance. Membranes are
attractive since no reagents are consumed.
The acid gases, if present, are removed by membrane or amine
treating can then be routed into a sulfur recovery unit which converts the
hydrogen sulfide in the acid gas into either elemental sulfur or sulfuric acid.
Of the processes available for these conversions, the Claus
process is by far the most well known for recovering elemental sulfur,
whereas the conventional Contact process and the WSA (Wet sulfuric acid process) are the most
used technologies for recovering sulfuric
acid.
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 and for that purpose a WSA
process is also very suitable since it can work autothermally on tail gases.
The next step in the gas processing plant is to remove water
vapor from the gas using either the regenerable absorption in liquid triethylene glycol (TEG), commonly referred to
as glycol dehydration, deliquescent chloride
desiccants, and or a Pressure Swing Adsorption (PSA) unit
which is regenerable adsorption using a solid adsorbent. Other newer processes
like membranes may also be considered.
Mercury is then removed by using adsorption processes (as
shown in the flow diagram) such as activated
carbon or regenerable molecular sieves.
Although not common, nitrogen is sometimes removed and
rejected using one of the three processes indicated on the flow diagram:
- Cryogenic process (Nitrogen Rejection Unit), using low temperature distillation. This process can be modified to also recover helium, if desired .
- Absorption process, using lean oil or a special solvent as the absorbent.
- 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 heavier hydrocarbons.
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 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.
The recovered NGL stream is sometimes processed through a
fractionation train consisting of three distillation towers in series: a
deethanizer, a depropanizer and a debutanizer. The overhead product from the
deethanizer is ethane and the bottoms are fed to the depropanizer. The overhead
product from the depropanizer is propane and the bottoms are fed to the
debutanizer. The overhead product from the debutanizer is a mixture of normal
and iso-butane, and the bottoms product is a C5+ mixture. The
recovered streams of propane, butanes and C5+ may be
"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. Currently, most cryogenic plants do not include fractionation
for economic reasons, and the NGL stream is instead transported as a mixed
product to standalone fractionation complexes located near refineries or
chemical plants that use the components for feedstock. In
case laying pipeline is not possible for geographical reason,or the distance
between source and consumer exceed 3000 km, natural gas is then
transported by ship as LNG
(liquefied natural gas) and again converted into its gaseous state in the
vicinity of the consumer.
Consumption
Natural gas consumption patterns, across nations, vary based
on access. Countries with large reserves tend to handle the raw-material natural
gas more generously, while countries with scarce or lacking resources tend to
be more economical. Despite the considerable findings, the predicted
availability of the natural-gas reserves has hardly changed.
Applications of natural gas
- Fuel for industrial heating and desiccation process
- Fuel for the operation of public and industrial power stations
- Household fuel for cooking, heating and providing hot water
- Fuel for environmentally friendly compressed or liquid natural gas vehicles
- Raw material for chemical synthesis
- Raw material for large-scale fuel production using gas-to-liquid (GTL) process (e.g. to produce sulphur-and aromatic-free diesel with low-emission combustion)
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