g a s - h a n d l I n

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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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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