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Separator types

Figure 1: A schematic diagram of a separator. [1] Feed inlet  [2] Gas outlet  [3] Liquid outlet  [4] Inlet diverter  [5] Mist extractor  [6] Liquid level control valve

A separator is a pressure vessel used to separate well fluids produced from oil and gas wells into gaseous and liquid components in the oilfield. Hydrocarbon streams are made up of a mixture of gas, liquid hydrocarbons, and free water at the wellhead. In most cases, it's best to divide these phases as soon as possible so that the two or three phases can be handled separately. The liquids are separated from the gas phase by passing the good stream through an oil-gas water separator.

Figure 1 illustrates how a typical separator works. The gas/liquid stream passes through the feed inlet [1] and strikes the inlet diverter [4], which rapidly changes the direction of the flow of the entering stream, causing the initial gross separation. As a result of density difference, the liquid falls into the gravity settling section (the blue region) by gravity, while the gas rises and passes through a mist extractor [5]. The mist extractor acts as the final separating medium as it collects small liquid droplets and solid particles from the gas stream before it leaves the separator. The final gas product is expelled through the gas outlet [2], while the liquid is discharged through the liquid outlet [3].

While separators come in a variety of shapes and sizes, their primary purpose is the same. They are used to separate the elements that flow into them. Separators can be classified based on fluid flow or layout

Types based on layout

Vertical separator

When well streams have a low to moderate gas-to-oil ratio and significant slugs of liquid are predicted, a vertical separator is commonly used. It can handle larger slugs of liquid without leaking into the gas outlet, and the liquid level control's action is not as crucial. There is less tendency for the liquid to re-vaporize into the gas phase due to the higher vertical distance between the liquid level and the gas outlet. A vertical separator takes up less floor area, which is crucial when space is limited, such as on an offshore platform.

Advantages

• The potential for the liquid to re-vaporize into the gas phase is limited due to the significant vertical distance between the liquid level and the gas outlet.
• Have an adequate bottom-drain and clean-out system in place.
• There are fewer entrainment tendencies.
• Surge control is an added benefit.

Disadvantages

• Without ladders or access platforms, several equipment and safety devices may be difficult to reach.
• In comparison to the horizontal separator, a larger diameter separator is required for a comparable gas capacity.

Horizontal single tube separator

The horizontal separator has a substantially larger gas-liquid interface area, consisting of a large, long, baffled gas-separation section that permits much higher gas velocities. The large liquid surface area allows gas to be removed from the liquid efficiently. When gas capacity is a design criterion, this type of vessel provides a large interface area between the liquid and gas phases, which allows for extra separation capability. Due to the greater wall thickness required with large diameters, the horizontal vessel is more cost-effective in high-pressure separators.

Advantages

• Due to a large, lengthy and baffled gas-separation component, they have a substantially higher gas/liquid interface.
• The horizontal separator is less expensive than the vertical separator.

Disadvantages

• Level control is critical and must be maintained.
• More plan area is required to perform separation.
• Cleaning is difficult.

Double tube horizontal separator

A horizontal double-tube separator offers all of the benefits of a standard horizontal separator plus a significantly larger liquid capacity. it has two horizontal vessels mounted vertically. The produced fluid flows into the upper vessel, where it is separated into gas and liquid by baffles. The liquid then goes to the bottom vessel, where it is separated from the oil. The upper barrel emits oil-free gas, while the lower barrel emits gas-free oil. A horizontal separator with two barrels may process more generated fluids than a single horizontal separator.

Advantages

• When there are high gas flow rates with the likelihood of big liquid slugs, this device is useful.
• It Enhances the ability to handle liquid surges

Disadvantages

• It requires additional expenses

Spherical separator

Spherical separators are a type of vertical separator. It is affordable and has a compact vessel arrangement. These types of separators have relatively little surge room and a liquid settling section. They are ineffective when a well stream contains excessive mud or sand or is subjected to surging foamy components. Controlling the liquid level is crucial. Because to their limitations, these Separators are no longer widely used.

Advantages

• It is cost effective.
• It is beneficial for gas-to-oil ratios that are moderate or low.
• It is small and simple to transport and setup.

Disadvantages

• The performance of the spherical separator is dependent on liquid level control.
• Surge capacity and liquid settling section are both severely limited.
• Because of the restricted internal space, it is difficult to utilize in three-phase (oil, water, and gas).

Types based on arrangement

Two-phase separator

In the two-phase units, gas is separated from the liquid with the gas and liquid being discharged separately. A horizontal, vertical, or spherical separator can be used. A level-control or dump valve allows the liquid (oil, emulsion) to exit the vessel at the bottom. At the top of the vessel, the gas passes through a mist extractor, which removes any minute liquid droplets in the gas.

Three-phase separator

They are usually designed to separate related gas and oily water from crude oil, after which the oil can be transferred for further treatment. A horizontal, vertical, or spherical separator can be used. The major purpose of this type of separator, also known as a free-water knockout (FWKO), is to eliminate any free water that can create issues like corrosion and the production of hydrates or difficult-to-break tight emulsions. They are made on the basis of each phase having a varied density. The gas escapes from the top of the vessel, the crude oil remains in the middle, and the water, along with any entrained solids, sinks to the bottom (such as slugs, sand or debris). To create two independent layers, the two liquid phases require a particular retention time.

Other types of separators

Cyclone/centrifugal separators

Centrifugal force is used to operate cyclone separators. These designs are best suited for gas streams that are relatively pure. By centrifugal force, the whirling action of the gas stream as it enters the scrubber separates the droplets and dust from the gas stream. Although such designs can result in much smaller sizes, they are not typically utilized in production operations because their design is sensitive to flow rate and they require more pressure drop than the standard configurations discussed above.

Filter separators

As the gas flows through the filter tubes in the initial separation step, any liquid mist coalesces into bigger droplets. These aggregated droplets are removed by a secondary section of vanes or other mist extractor devices. This vessel can remove all particles larger than 2 microns and 99% of particles less than 1/2 micron.

Scrubbers

A scrubber is a two-phase separator used when the gas rate to liquid rate ratio is really high to collect liquids that have spilled over from production separators' gas outputs or to catch liquids that have condensed due to cooling or pressure drops.

External links

https://www.scribd.com/

https://oilfieldteam.com/en/a/learning/separators

See also

Separator types

Oil and gas separators