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An oil facility encompasses the equipment between the oil wells and the pipeline or other transportation system. The purpose of an oil facility is to make the oil ready for sale to the purchaser's standards (maximum allowable water, salt, and other impurities). This article describes the key equipment and functions found in an oil facility.

Overview

Fig. 1 is a block diagram of a simple oil facility. Each of the blocks is described here, except for gas dehydration, which is covered in Gas Facilities.


Function of a facility

Main process

The main function of an oil facility is to:

  • separate the oil, gas, water, and solids
  • treat the oil to meet sales specifications (e.g., BS&W, salt content, vapor pressure)
  • measure and sample the oil to determine its value
  • 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 oil 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 heat is usually needed for oil treating.

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

Separation

The first step in the process is separating the gas from the liquid and the water from the oil. This is usually done in a separator—a pressure vessel into which the wellstream flows to allow the gas, oil, and water to separate because of gravity. To aid separating the streams, separators may contain:

  • inlet diverters
  • outlet vortex breakers
  • buckets
  • weirs
  • mist extractors

A separator may be either of the following:

  • two-phase: separating gas from liquids
  • three-phase: separating gas, oil, and water, which are removed through three outlets

The first separator in a facility that receives fluid from the wells is called a production, or high-pressure (HP), separator. If the production is at high pressure, (e.g., 500 to 1,200 psig) and if the oil from the separator is put directly into a pipeline, gas will flash as the pressure decreases owing to friction losses in the pipeline. Gas takes up a much larger volume than its equivalent mass of oil, so a pipeline sized for liquid flow will be undersized if some of the liquid flashes into gas, resulting in excessive velocities and pressure drop. For this reason, oil pipeline owners generally specify a maximum vapor pressure allowed to prevent the lighter components in the oil from flashing into gas. The process of reducing the vapor pressure in the oil to meet oil-pipeline specifications is called “stabilization.”

For the simplest form of stabilization, the oil is put into an atmospheric tank for storage. This allows the gas to flash from the liquid in the tank when the pressure is reduced to atmospheric. This process would get the true vapor pressure of the oil down to atmospheric, or even lower if some heating were added in addition to the pressure reduction, and could be used to make the oil meet pipeline specifications for vapor pressure. The gas that flashes in the tank must then be compressed back to the original pressure of the separator and combined with the separator gas.

If the oil is sent to an intermediate pressure (IP) separator instead of going directly into an atmospheric tank, the gas that flashes in the IP separator will be at a higher pressure, requiring less compression horsepower. In addition, the total amount of oil stabilized in the atmospheric tank is greater with an intermediate separation stage than with a single flash to atmospheric pressure. This is because of the gas/liquid equilibrium for the higher-pressure flash and the altered composition of the oil that is flashing in the tank.

While there still would be gas flashed as the liquid flowed from the IP separator to the tank, the quantity would be much smaller than in the first case in which liquid goes directly from the HP separator to the tank. Thus, adding a second stage of separation has two benefits:

  • first, the horsepower required to compress the gas is lower because some of the gas flashes at higher pressure
  • second, more stabilized oil will be produced

If we add a third, low-pressure (LP) stage of separation, the total liquid in the tank increases even further, with additional gas flashing at a higher pressure, reducing compressor horsepower. Fig. 2 shows a typical three-stage separation with flash-gas compression. Adding additional stages of separation and compression would increase liquids and reduce compression horsepower further; however, at this point, the capital cost of adding additional separation stages is generally not worth the small increase in hydrocarbon value.


A typical separation train might have a well producing into an HP separator at 1,100 psig, with the oil to an IP separator at 450 psig, an LP separator at 150 psig, and possibly an oil treater at 50 psig (see Oil Treating) before storage in an atmospheric tank. The separator pressures are chosen so that the flash gas from each stage of separation feeds into a stage of compression with reasonable compression ratios for each stage of the compressor. (See page: Compressors)

Oil treating

No separation is perfect, there is always some water left in the oil. Water content can range from less than 1% water to more than 20% water in the oil by volume. The lower the American Petroleum Institute (API) gravity (i.e., the higher the molecular weight and the oil viscosity), the less efficient the separation.

To get the last of the water out of the oil, the oil is processed through an oil treater or a treating system, as described in the page of Emulsion Treating. A treater is similar to a separator, but with special features to help separate the water from the oil. Treaters or treating systems usually provide heat to reduce oil viscosity and large settling sections to allow the water time to settle from the oil, and may provide an electrostatic grid to promote coalescing of the water droplets. Conventional treaters usually have a front section with a heater in which the emulsion is heated and initial separation of the “free water” takes place. The oil then flows to a second section of the vessel, where additional coalescence and settling of the water droplets takes place. Gas is flashed (i.e., liberated) from the emulsion as the pressure is lowered and the temperature is raised from the upstream separator. For a conventional treater with a heater, free-water knockout section, and settling section, the water content in the oil can be reduced to less than 1%. An electrostatic treater, which is a conventional treater with an electrostatic grid in the settling section, can reduce the water content to 0.3 to 0.5% by volume.

The contract between the oil seller, who is normally the producer and the purchaser and who may be a pipeline company, specifies the allowable water content and may specify the maximum salt content in the crude oil. High water content can make corrosion problems worse in pipelines and other transportation systems and can cause problems with downstream processing. High salt content, which is caused by the salinity of the produced water left in the oil, may cause a refining problem when the water is boiled off in the refinery distillation unit.

The oil from the treater is usually sent into a dry oil tank, from which it is pumped through a sales meter for custody transfer and then into a pipeline for transportation. For additional information, see the pages on Storage tanks and Pumps.

Produced-water treating

As mentioned previously, separation is not perfect, and the amount of oil left in the water from a separator is normally between 100 and 2,000 ppm by mass. This oil must be removed to acceptable levels before the water can be disposed of. The regulatory requirements for oil-in-water content for overboard water disposal vary from place to place, and some locations do not allow any discharge of produced water. As an example, in the Gulf of Mexico outer continental shelf (U.S. federal waters), producers are limited to a maximum measurement of 42 ppm for any one sample and no more than 29 ppm average for a given month. In contrast, on shore, no discharge of produced water is permitted. In the case in which discharge is not permitted, produced water is usually injected into disposal wells.

Various types of equipment for water treating are described in the page of Water treating facilities. Equipment types used in this case include:

  • water skimmers
  • plate coalescers
  • gas flotation devices
  • hydrocyclones

Additional equipment, including desanders and filters, may be needed to remove solids before injection.

Hydrocyclones require a pressure drop in excess of 100 psi to work well and would usually be placed between a separator and its water-level control valve. In addition to removing oil from the water, hydrocyclones have a tendency to coalesce the remaining oil droplets in the water streams, making the droplets easier to separate with the downstream equipment. Water skimmers use gravity separation to remove the remaining oil from produced water and are usually placed downstream of separators or hydrocyclones.

A good rule of thumb is to use two types of water-treating equipment for a gas facility and three types for an oil facility in which the oil may be more difficult to separate. For example, a water-treating system might consist of a hydrocyclone, followed by a water skimmer and a gas flotation cell.

References

Noteworthy papers in OnePetro

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External links

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See also

PEH:Oil and Gas Processing

PEH:Water-Treating Facilities in Oil and Gas Operations

Water treating facilities

Oil and gas processing

Gas facility

Storage tanks

Pumps

Emulsion Treating

Compressors

Oil and gas separators