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Gas facility

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A gas facility encompasses the equipment between the gas wells and the pipeline or other transportation method. The purpose of the gas facility is to remove impurities and contaminants from the gas, remove liquids and solids, and prepare the gas to meet the sales requirements of the purchaser.


Overview

Fig. 1 is a block diagram of a simple gas facility. Each of the main blocks is described here.

Function of a facility

Main process

The main function of a facility is to:

  • separate the oil, gas, water, and solids
  • deliver it to the transportation system (i.e., the pipeline, truck, ship, or railroad car)

The gas must be treated for sales or disposal. In the past, disposal sometimes meant flaring or venting, but now gas that can’t be transported is usually compressed for reinjection into the reservoir. Gas treating may involve only separation from the liquids, or it may include additional processes such as:

  • compression
  • dehydration
  • removing H2S and CO2
  • gas processing to condense heavier components that can be transported as a liquid

Secondary process

In addition to processing the gas for sale, the produced water and solids must be treated for disposal. For produced water, treating usually includes removal of dispersed and dissolved hydrocarbons and, in addition to separation or oil skimming, may include:

  • filtration
  • deionization
  • pumping

If treating of solids is required, it may include water washing and agitating the solids to remove the oil and then separating the water from them.

Auxiliary systems

In addition to the process systems, auxiliary process heating and cooling may be required. Process superheating fuel gas for use in gas turbine generators or compressors. Process cooling is usually required for gas compression.

While, if necessary, facilities can be run without electric power, power generation and electrical systems will usually be included for a facility that is large or complex or for living quarters that are provided for personnel.

All facilities require safety systems, including:

  • safety instrumentation and shutdown system
  • fire and gas detection
  • fire-fighting equipment
  • a means of evacuation, such as life rafts and escape capsules for offshore
  • other equipment, depending on the location and complexity of the facility and whether it is manned

Heating

Gas wells are often high pressure with a shut-in tubing pressure of 5,000 to 15,000 psig and a flowing tubing pressure in excess of 3,000 psig. This pressure must be reduced to the appropriate pipeline pressure at the point at which the gas flows through a wellhead choke. When gas pressure is reduced, the gas cools, liquids can condense, and hydrates can form. Hydrates are crystalline solids made up of hydrocarbon and water molecules and form in the presence of hydrocarbon gas and liquid water at temperatures significantly higher than the freezing point of water. These hydrates can plug the choke and flowline, so high-pressure gas wells usually require a line heater that contains the flowline and choke inside a hot water bath to keep the well from freezing.

Hydrate formation can be inhibited by injecting a solvent, such as methanol, into the flowline. This is done for subsea and other wells in which a line heater is not possible. For most wells with high flow rates, the expense of the methanol makes a line heater the better choice.

Separation

The separator provides a place for any liquid to settle out from the gas. The separator pressure is set higher than the pipeline pressure so that the gas can go through the required cooling, treating, dehydration, and gas processing—each with some pressure drop—and arrive at the required pipeline pressure.

Cooling

If the gas flowing temperature is high, the temperature downstream of the choke may be high enough so that it will not be necessary to install a line heater upstream of the HP separator. If the flowing tubing temperature is even higher, the hot gas leaving the HP separator could cause process and corrosion problems with the downstream treating system. In addition, the hot gas will carry more water vapor, which makes the dehydration system larger and much more expensive than if the gas were cooled first. Thus, it is sometimes necessary to install a gas cooler downstream of the first-stage separator.

The cooler may be an aerial cooler or a shell-and-tube exchanger that uses either direct seawater or a contained cooling-water loop, which is cooled by seawater or some other water source.

Treating

Natural gas may have a number of impurities, such as:

  • H2S and CO2, referred to as “acid gases”
  • natural gas containing H2S, called a “sour gas”
  • gas that contains no H2S or from which the H2S has been removed, called “sweet gas”

The process of removing the H2S, and possibly CO2, is referred to as “sweetening.”

H2S gas is highly toxic. CO2 forms a strong acid that is highly corrosive in the presence of water. Combined, they are corrosive; if the corrosion results in a leak, they can be deadly.

A common way to remove H2S and CO2 from natural gas is with an amine system, which uses a contact tower with trays or structured packing to pass the sour gas through the amine liquid, absorbing the H2S and some of the CO2. The amine is then regenerated in a stripping tower in which the H2S and CO2 are removed.

There are also several licensed physical solvent and batch processes (chemical or adsorption) available commercially.

For a more detailed description of gas treating, refer to the chapter on Hydrocarbon Testing in the Engineering Data Book[1].

Dehydration

To avoid water condensing in the gas pipeline with resulting corrosion and hydrate-formation problems, pipeline specifications usually limit the amount of water vapor in the gas. A standard pipeline specification in most of the southern U.S. is 7 lbm of water per million standard cubic feet of gas (lbm/MMscf). This corresponds to a water dewpoint of approximately 32°F at 1,000 psi. In northern areas, or in very deep water in which temperatures outside the pipe could be much lower, it is common to see a specification of 4 lbm/MMscf (approximately 0°F dewpoint at 1,000 psi).

Water is often removed from gas with a glycol dehydration system, as described here. Other methods include:

  1. solid-desiccant adsorption
  2. refrigeration
  3. membrane permeation

Glycol dehydration systems commonly use triethylene glycol to absorb the water vapor from the gas. This is done in a contact tower in which the lean, or dry, glycol flows by gravity from the top of the tower through trays or structured packing. The gas flows countercurrent up through the tower so that the driest gas contacts the driest glycol.

The dry gas exiting the tower is used to precool the lean glycol before it enters the tower. The gas then continues to sales or to further processing to remove natural-gas liquids (NGLs).

The rich, or wet, glycol exiting the bottom of the tower is regenerated in a continuous process. First, the rich glycol goes to a separator to remove any condensed hydrocarbons, then it is preheated and filtered before being sent to a “reboiler” or “regenerator.”

The rich glycol is heated in the regenerator up to 390 to 400°F, and the water is boiled off. This vapor is either discharged directly to the atmosphere or is cooled and condensed to separate the small amount of hydrocarbon vapors from the water.

The resulting hot, lean glycol is then cooled through a cross exchanger with the cool, rich glycol coming from the contact tower. The cross exchanger makes the process more efficient and preheats the glycol going to the reboiler, which reduces the overall energy requirements. The reboiler may be heated by any of the following:

  • a gas-fired heater
  • electric heating elements
  • a heat-medium system

For a more detailed description of gas dehydration, refer to the chapter on Dehydration in the Engineering Data Book[1].

Processing

The dry gas may be further processed to recover liquid hydrocarbons in the form of:

  • NGLs
  • liquefied natural gas (LNG)
  • liquefied petroleum gas (LPG)

NGLs are hydrocarbon liquids that can be separated from a natural-gas stream after the heavier hydrocarbon components have already been removed by separation at ambient temperatures. NGLs include:

  • ethane
  • propane
  • butane
  • natural gasoline.

LPG is a mixture of hydrocarbons—principally butane and propane—that can be transported as a liquid under pressure, or at very low temperatures. and converted to gas on release of the pressure. LNG is a liquid composed of mostly methane that is liquefied to make it easy to transport if a pipeline is not feasible.

The most common processes used to separate NGL or LPG are:

  • lean-oil absorption
  • refrigeration
  • turbo-expander plants

The lean gas remaining can be used as fuel, reinjected into the reservoir, or put into a pipeline.

Stabilization

Stabilization removes the light hydrocarbons from the liquid stream, either by reducing the pressure and letting the lighter components flash, as discussed previously, or by a combination of pressure reduction and heating. Most of the water will be removed during separation. The resulting stable condensate has a low vapor pressure so it can be stored in tanks for shipping at atmospheric pressure by truck, train, barge, or ship without excessive vapor venting. Often, there are vapor-pressure limitations that require liquid stabilization for pipeline shipments as well.

The water removed in the separation/stabilization process must be treated and disposed of, as described in the page of Water treating facilities.

Compression

The lighter components removed in the gas phase during the stabilization process will be at a lower pressure than the main gas stream. These components must be compressed to the HP-separator pressure so they can be processed with the rest of the gas.

References

  1. 1.0 1.1 Arendt, H.P., Dines, C., and Heard, T. 1978. Pumpdown (TFL) Technology for Subsea Completions. J Pet Technol 30 (10): 1481-1485. SPE-6692-PA. http://dx.doi.org/10.2118/6692-PA.

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