demonstration # 1
DESCRIPTION
natural gas documentsTRANSCRIPT
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The objective of a gas-handling facility is to separate natural gas,
condensate, or oil and water from a gas-producing well and condition
these fluids for sales or disposal.
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Gas Sweetening
Gas Dehydration
Gas Processing
Condensate Stabilization
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Gas-Handling
Figure : Gas field facility block diagram
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The well flow stream may require heating prior to initial separation.
Since most gas wells flow at high pressure, a choke is installed to
control the flow. When the flow stream is choked, the gas expands and
its temperature decreases.
If the temperature gets low enough, hydrates will form. This could
lead to plugging, so the gas may have to be heated before it can be
choked to separator pressure.
Low-temperature exchange (LTX) units and indirect fired heaters are
commonly used to keep the well stream from plugging with hydrates.
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Some gas reservoirs may be very deep and very hot. If a substantial
amount of gas and liquid is being produced from the well, the flowing
temperature of the well could be very hot even after the choke. In this
case, the gas may have to be cooled prior to compression, treating, or
dehydration.
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Separation and further liquid handling might be possible at high
temperatures, so the liquids are normally separated from the gas prior
to cooling to reduce the load on the cooling equipment.
Heat exchangers are used to cool the gas and also to cool or heat fluids
for treating water from oil, regenerating glycol and other gas treating
fluids, etc.
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In some fields, it may be necessary to provide heat during the early life
of the wells when flowing-tubing pressures are high and there is a
high temperature drop across the choke.
Liquids retain the reservoir heat better and have less of a
temperature drop associated with a given pressure drop
than gas.
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Typically, in a gas facility, there is an initial separation at a high
pressure, enabling reservoir energy to move the gas through the
process to sales. It is very rare that the flowing-tubing pressure
of a gas well, at least initially, is less than the gas sales pressure.
With time, the flowing-tubing pressure may decline and
compression may be needed prior to further handling of the
gas.
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The initial separation is normally three-phase, as the separator
size is dictated by gas capacity. That is, the separator will
normally be large enough to provide sufficient liquid retention
time for three phase separation if it's to be large enough to
provide sufficient gas capacity.
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Liquid from the initial separator is stabilized either by multistage flash
separation or by using a "condensate stabilization" process.
Stabilization of the hydrocarbon liquid refers to the process of
maximizing the recovery of intermediate hydrocarbon components (C3
to C6) from the liquid.
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Depending on the number of stages, the gas that flashes in the lower
pressure separators can be compressed and then recombined with the
gas from the high-pressure separator. Both reciprocating and
centrifugal compressors are commonly used. In low-horsepower
installations, especially for compressing gas from stock tanks (vapor
recovery), rotary and vane type compressors are common.
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Gas transmission companies require that impurities be removed from
gas they purchase. They recognize the need for removal for the
efficient operation of their pipelines and their customers' gas-burning
equipment. Consequently, contracts for the sale of gas to transmission
companies always contain provisions regarding the quality of the gas
that is delivered to them, and periodic tests are made to ascertain that
requirements are being fulfilled by the seller.
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Acid gases, usually hydrogen sulfide (H2S ) and carbon dioxide (CO2)
are impurities that are frequently found in natural gas and may have
to he removed. Both can be very corrosive, with CO2 forming carbonic
acid in the presence of water and H2S potentially causing hydrogen
embrittlement of steel. In addition, H2S is extremely toxic at very low
concentrations.
When the gas is sold, the purchaser specifies the maximum allowable
concentration of CO2 and H2S. A normal limit for CO2 is between 2 and
4 volume percent, while H2S is normally limited to 1/4 grain per 100
standard cubic feet (scf) or 4 ppm by volume.
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Another common impurity of natural gas is nitrogen. Since nitrogen
has essentially no calorific value, it lowers the heating value of gas. Gas
purchasers may set a minimum limit of heating value (normally
approximately 950 Btu/scf). In some cases it may be necessary to
remove the nitrogen to satisfy this requirement. This is done in very
low temperature plants or with permeable membranes.
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Natural gas produced from a well is usually saturated with water
vapor. Most gas treating processes also leave the gas saturated with
water vapor. The water vapor itself is not objectionable, but the liquid
or solid phase of water that may occur when the gas is compressed or
cooled is very troublesome. Liquid water accelerates corrosion of
pipelines and other equipment; solid hydrates that can form when
liquid water is present plug valves, fittings, and sometimes the
pipeline itself; liquid water accumulates in low points of pipeline,
reducing the capacity of the lines.
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Removal of the water vapor by dehydration eliminates these possible
difficulties and is normally required by gas sales agreements. When
gas is dehydrated its dewpoint (the temperature at which water will
condense from the gas) is lowered.
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Reference
Surface Production Operations Vol. 2 : Design of Gas-
Handling Systems and Facilities
by
KEN ARNOLD
MAURICE STEWART