Separation & Separators PDF Print E-mail
Written by Norrie   
Tuesday, 26 January 2010 08:23
Article Index
Separation & Separators
Well Fluids & Well Classification
Separator Functions
Gravity Settling & Coalescing
Types of Separator - Gas / Liquid Separators
Types of Separator - Liquid / Liquid Separators
All Pages


A SEPARATOR is a vessel in which a mixture of immiscible fluids are separated; e.g. Crude oil, Natural gas and Water. A separator may be a 'Horizontal', 'Vertical' or 'Spherical' vessel and generally consists of the following :

  1. A primary separation section to remove the bulk of the liquid from the gas.
  2. Sufficient liquid capacity to handle surges of liquid from the line.
  3. Sufficient length or height to allow the small droplets to settle out by gravity (to prevent undue entrainment).
  4. A means of reducing turbulence in the main body of the separator so that proper settling may take place.
  5. A mist extractor to capture entrained droplets or those too small to settle by gravity.

Where a vessel is simply separating total liquid from gas, it is called a 'Two-Phase Separator' When the process requires the separation of two liquids and a gas, the separator is called a 'Three-Phase Separator'. 'Two or Three Phase separation', refers to the number of streams leaving the vessel and not the inlet fluid stream.

Petroleum as produced from a reservoir is a complex mixture of hundreds of different compounds of hydrogen and carbon, all with different densities, vapour pressures, and other physical characteristics. A typical well stream is a high velocity, turbulent, constantly expanding mixture of gases and hydrocarbon liquids, intimately mixed with water vapour, free water, solids, and other contaminants.

As it flows from the hot, high pressure petroleum reservoir, the well stream is undergoing continuous pressure and temperature reduction. Gases evolve from the liquids, water vapour condenses, and some of the well stream changes in character from liquid to free gas. The gas is carrying liquid mist droplets, and the liquid is carrying gas bubbles.

The function of field processing is to remove undesirable components and to separate the well stream into sellable gas and petroleum liquids, recovering the maximum amounts of each at the lowest possible overall cost.

Field processing of natural gas actually consists of four basic processes:

  1. Separation of the gas from free liquids such as crude oil, hydrocarbon condensate, water, and entrained solids.
  2. Processing the gas to remove condensable and recoverable hydrocarbon vapours.
  3. Processing the gas to remove condensable water vapour which, under certain conditions, might cause hydrate formation.
  4. Processing the gas to remove other undesirable components, such as Hydrogen Sulphide and / or Carbon Dioxide.


Fluid flow from a well can include gas, free water, condensable vapours (water or hydrocarbons), crude oil, and solid debris (basic sediment). The proportion of each component varies in different well streams.

When water is produced with crude oil, it is mixed in either or both of the following forms:

  1. FREE WATER: Water mixed with the oil but will separate easily into a clear layer when the mixture is allowed enough time to settle.
  2. EMULSION: Water can also be mixed with the oil in the form of very small droplets of water coated with oil. A mixture like this is called an EMULSION.

Water in this case cannot be easily separated from oil. As for the gas, it can be found in the well as:

  1. SOLUTION GAS: Gas dissolved in the well fluids under the effect of pressure of the reservoir. As the fluids flow from the reservoir into the well and up to the surface, the pressure of the fluid decreases. The capacity of the liquid to hold gas in solution also decreases and gas starts to separate out of the oil.
  2. FREE GAS: Gas that is NOT held in the oil under reservoir conditions.
  3. ASSOCIATED GAS: Total gas produced with the oil in a crude oil well.

Wells are generally classified according to the type of fluid they produce in the greatest quantity. The main three types of well are:

  1. CRUDE OIL WELL: A well that produces mostly crude oil with varying proportions of water, solution gas, possibly free gas and some solid debris.
  2. DRY GAS WELL: A well that produces mostly gas with no crude oil (or liquid hydrocarbon). The produced gas can contain some water.
  3. GAS CONDENSATE WELL: A well that produces both gas and light liquid hydrocarbon (condensate) and maybe some water, but no crude oil.

Much of the hydrocarbon condensate is very light, and changes from liquid to vapour at near atmospheric conditions. Therefore, when they are produced from high-pressure reservoirs to a surface line at near atmospheric pressure, they vaporise.

Gas, which is produced from a well together with oil, is called 'CASING HEAD GAS' or 'ASSOCIATED GAS'.

Gas produced alone or with water is called 'NON ASSOCIATED GAS'. This gas is produced from both dry gas wells and gas condensate wells.

The following table shows well classifications, fluid compounds, and processing methods.


Oil well fluids are produced normally in two phases - vapour and liquid. These two phases require entirely different handling, measuring, and processing methods. Therefore, it is necessary to separate the phases as soon as practical after leaving the wellhead. The basic equipment used for this purpose is the 'OIL & GAS SEPARATOR'.

Reservoir pressures are generally much higher than atmospheric pressure. As well fluids reach the surface, pressure on them is decreased. The liquid ability to hold gas in solution decreases, and the liquids begin to release 'Solution Gas'.
Light fluids begin to separate naturally when the pressure on them is lowered.
The solution gas released as Free Gas is held by the surface tension of the oil.
This free gas is released from the oil when the well fluids are warmed to reduce the surface tension of the oil. Gravity alone will eventually cause heavy components to settle out and light components to rise.

In summary, there are variables which aid in the separation of a fluid stream.

  1. Temperature of the fluids.
  2. Pressure on the fluids.
  3. Density of the components.

In addition to using the force of gravity, modern separators make use of other forces to get the best possible separation of oil and gas. The way in which each of these forces is used can be better understood by following the flow of a mixture of oil and gas through a separator.


A wellstream separator must perform the following:

  1. Cause a primary phase separation of the liquid hydrocarbon from those that are Gas.
  2. Refine the primary separation by removing most of the entrained liquid mist from the gas.
  3. Further refine the separation by removing the entrained gas from the liquid.
  4. Discharge the separated gas and liquid from the vessel and ensure that no re-entrainment of one into the other takes place.

If these functions are to be accomplished, the basic separator design must:

  1. Control and dissipate the energy of the well stream as it enters the separator.
  2. Ensure that the gas and liquid flow rates are low enough so that gravity segregation and vapour-liquid equilibrium can occur.
  3. Minimise turbulence in the gas section of the separator and reduce velocity.
  4. Control the accumulation of froth and foam in the vessel.
  5. Eliminate re-entrainment of the separated gas and liquid.
  6. Provide an outlet for gases, with suitable controls to maintain the required operating pressure.
  7. Provide outlets for liquids, with suitable liquid-level controls.
  8. If necessary, provide clean-out ports at points where solids may accumulate.
  9. Provide relief for excessive pressure in case the gas or liquid outlets should be plugged.
  10. Provide equipment (Pressure gauges, Thermometers, and Liquid Level gauge assemblies), to check visually for proper operation.

Most platforms have a series of production separators, starting with a high-pressure separator, which separates the (HP) gas from the liquids. Liquids are then piped to a medium pressure (MP) separator, which removes more gas and then passes the liquids to a low pressure (LP) separator that removes even more gas and then separates water from the oil.

The water from the low-pressure separator is piped to a skim tank or to a drain pit, with the oil being piped to a metering and pumping station to be piped to other processes or storage tanks.

Well fluid separation depends on the composition of the fluids, and on their pressure and temperature.

The pressure of the fluids is controlled by the back - pressure regulator and the temperature may be regulated by expanding the fluids through a choke, by addition of heat in a furnace or by heating or cooling in a heat exchanger. Therefore, separators can be designed to handle fluids according to the fluid composition.

Separators are built in various designs, such as horizontal and vertical. The internal structures of the vessel, to aid in the mechanical separation of the gas and liquids, are of a spherical design, depending upon the manufacturer.

Although most separators are two -phase in design, separating the gas and total liquids, three - phase vessels can be built to separate natural gas, oil or other liquid hydrocarbons, and free water.

The main principles used to achieve physical separation of gas and liquids are: GRAVITY SETTLING and COALESCING Any separator may employ one or more of these principles, but the fluid phases must be 'Immiscible' (cannot mix), and have 'Different Densities' for separation to occur.


During the separation process, the gas is moving in an upward direction into the vapour section of the separator and the liquid particles are tending to fall to the vessel bottom under the influence of gravity.

Gas will separate more quickly from a liquid when it is flowing 'HORIZONTALLY'. In a 'VERTICAL' separator, the gas is moving vertically upwards and the liquid droplets, due to gravity, are falling vertically downwards. The contra-flow of the two fluids therefore interferes with the flow paths and separation is slower.

Generally, because of the above factors, the vapour section of a Horizontal separator will be of a smaller volume than that of a Vertical vessel.


Very small droplets such as fog or mist cannot be separated practically by gravity. However, they can be coalesced to form larger droplets that will separate out.

Coalescing devices in separators force gas to follow a tortuous path. The momentum of the droplets causes them to collide with other droplets or with the coalescing device, forming larger droplets. These can then separate out of the gas phase due to the influence of gravity.
Wire mesh screens, Vane elements, and Filter cartridges are typical examples of coalescing devices.

Separation vessels usually contain four major sections, plus the necessary pressure and liquid level controls. These sections are:

1. Primary Separation Section:

For removing the bulk of the liquid from the inlet stream. For example, free liquids, slugs and large droplets. This is usually accomplished by a change in the direction of fluid flow, either by baffles or deflection plates near the inlet nozzle or by using a tangential inlet nozzle as in 'Tangential Feed' or 'Cyclone' separators which operate by centrifugal force being set up within the vessel.

2. Secondary Separation Section:

For removing the maximum amount of small liquid droplets without an elaborate design. The major separation principle in this section is by gravity settling of the liquid droplets from the vapour stream.

3. Mist Extraction Section:

For removing the maximum amount of tiny liquid droplets remaining in the gas stream. The mist extractor may be of the impingement type; (mesh pads) and/or may use the centrifugal force principle; (the vane type).

4. Liquid Accumulation Section:

For receiving and disposing of the liquid collected. Sufficient volume and proper level control equipment should be provided to handle surges that may occur during operations.

The length of a horizontal separator has a greater effect on capacity than the height of a vertical type. In the horizontal vessel the path of any droplet ideally has a trajectory similar to that of a shell from a gun. Therefore, the length required depends on:

  1. Droplet size.
  2. Gas velocity.
  3. Droplet density.
  4. Vessel diameter.
  5. Degree of turbulence

In the above picture, the system consists of three separators - all are 3-phase separation vessels.

The 1st stage on the right, is the Low Pressure suction KO drum to a LP compressor, the 2nd stage (in the middle), is the Medium Pressure separator - discharge from the LP compressor and, suction to the HP compressor. The 3rd drum, on the left, is the final separation stage for the HP discharge gas. Cooling stages are installed after each discharge.

Separated water is usually dumped to a disposal pit. The gas condensate will then be metered and pumped to further treatment facilities and, the gas will be metered and go on to further processing units.

The following diagrams depict common types of separator.



A. The simplest type of Horizontal separator is shown in Figure : 10.

They are used to separate a two or three-phase inlet fluid into liquids and gas. The vessel inlet and gas outlet nozzles, consist of curved pipes which cause a change in direction of the inlet flow and the gas outlet. The liquid particles fall to the vessel bottom by gravity, while the gas rises to the top. This type of simple separator is not very efficient.

B. The 'Knock-Out Drum' is another simple type of separator as shown in Figure : 11.

It is used to separate a two or three phase inlet fluid into liquid(s) and gas.

The vessel inlet flow generally hits an inlet deflector plate to begin the separation process. Between the inlet and the gas outlet, some form of de-misting element may be installed which can be a wire mesh 'screen' or 'pad' or an angled vane type.

The demister construction presents a large surface area to the liquid mist entrained in the gas which causes small droplets of liquid to coalesce into larger drops which fall to the vessel bottom by gravity. The gas outlet nozzle exits the gas from the vessel above the demister screen


Figure : 10 - Separator

Figure : 11 -K.O. Drum


The following table shows some of the factors that affect separation :

1. Difference in Fluid Densities The greater the difference in densities, the easier the separation.
2. Residence Time The longer the fluids are in the separator, the better the separation.
3. Coalescing Element Surface Area The greater the area of the coalescing element, the better the separation.


Figure 12, is a field separator labelled as an actual operating unit together with control systems (The 'M's' are the inlet manifolds). After separation and metering, the oil and gas are re-combined and piped to the main production line feeding the plant GOSP facility. This operation saves the need for two pipelines - gas and oil - to the main facility where they will be separated along with other produced wells.

Figure: 12 -Typical, Single tube, 3-Phase Separator and Control System.

Figure 13, Shows a typical horizontal, Single tube, 3 - phase separator internal arrangement.

Figure 14, Shows a Double tube, 2 - phase separator internal arrangement.


Figure: 13 - Typical Horizontal, Single tube, Separator Internals

Figure: 14 - Double-tube Horizontal Separator

A: Fluid Inlet.
B: Primary Separation Section.
C: Secondary Separation Section.
D: Liquid Down-pipes to Lower Tube.
E: Gas Outlet.
F. Liquid Outlet


Figure : 15 -Typical Knock-Out Drum (3-Phase)

C. The Tangential or Cyclone Separator (Figures : 16 & 17).

This type operates by centrifugal force. It is used to separate a two or three phase inlet fluid into liquid(s) and gas. The inlet flow enters the vessel side at a tangent to the circumference.

This causes the fluids to rotate at high speed inside the drum. The centrifugal force of rotation causes the heavier liquid particles to be forced downwards while the lighter gases are forced upwards.

Again, a demister screen may be installed near the vessel top to coalesce liquid droplets from the gas and drop them back into the liquid.

Some de-misters consist of 'Packing' type materials like 'Raschig Rings', 'Ceramic Saddles' or other suitable materials. As seen in Figure: 17

Note: Demister screens can become fouled and lose efficiency. From time to time, it is necessary to shut down the separator and remove the demister for cleaning or renewal.

Figure 16: Tangential or Cyclone Separator

Figure 17: Two-Phase Cyclone Separator

The two magnified drawings indicate 2 types of demister systems that may be used in separators.

    A. Represents 'Conical Impingement' contacting devices.
    B. Shows a packed bed of loose 'Raschig Rings'.

Each type coalesces the droplets of mist entrained in the gas and, as they form larger droplets, they fall into the bottom liquid. (Droplet size is exaggerated)


This type of separator is referred to as a 'Coalescer' and is used to separate two immiscible liquids like hydrocarbon and water emulsions. Tiny water droplets entrained in the hydrocarbon liquid would take a long time to separate out in a conventional separator.

The Coalescer vessel contains 'Filter' type elements, generally made of fibre-glass. As the mixed liquids pass through the elements, the heavier (more dense) water droplets are slowed down and stick to the fibre-glass surfaces of the elements where, as more droplets collide with them, they coalesce into larger drops and fall to the bottom of the vessel and flow into a 'Boot' in the vessel bottom.

The lighter hydrocarbon liquid rises to, and leaves by the top, of the Coalescer.

The Coalescer is operated 'Liquid Full' and, should any gases be released during the process, they are vented to flare or fuel system by automatic 'Vent-trap' systems in order to maintain the liquid-filled state of the vessel. (If gases were allowed to build up in the vessel, the liquid level in the vessel would be forced down by the gas. This would gradually decrease the efficiency of the Coalescer operation). (See Figures : 18 & 18A)

Figure 18: Coalescer

Figure 18a: Coalescer with Controls

LOW PRESSURE SEPARATION (Recovery of Naphtha-rich Gases)

After the 1st - Stage (High Pressure - HP) and 2nd - Stage (Medium Pressure - MP) separators (GOSPS), the liquids, (oil & water) still contain some heavy solution gases rich in Naphtha compounds – Propane, Butane & heavier.

The liquids are piped to further separation units to recover this heavy gas.

The first unit is called a 'Degassing Boot' where the liquids are decreased to a Low Pressure (LP) causing most of the gas to be released from the liquid and piped to a compressor station.

The liquids leaving the degassing boot, is finally passed via an Oil Boot into a 'Surge Tank' where the pressure is decreased to just above atmospheric causing most of the last traces of gas to leave the liquid as Very Low Pressure (VLP) gas that is then piped to a small compressor where its pressure is increased to that of the LP boot gas and added to it.

The total gas stream is then compressed further, cooled and the resulting condensate (C3 + Naphtha) is separated, metered and put to other processes. The lighter gases in the surge tank, the oil and water are also separated. (A demulsifying agent is added to the liquids upstream of the

degassing system to speed up the separation of the water from the oil).

The water is then pumped to a de-oiling station and drained away to a disposal pit.

The oil is metered and pumped to storage for distribution.

The following diagrams and picture show such a degassing system.

(Figures: 19 & 20, & photo)


Figure: 19 - Degassing System

Figure: 20

Last Updated on Wednesday, 24 February 2010 19:58