Separators Part 1

Field processing of natural gas includes: 

1. Gas and liquid separation operations to remove the free liquids crude oil, hydrocarbon condensate, and water, and the entrained solids. 

2. Recovery of condensable hydrocarbon vapors. Stage separation, or low temperature separation techniques are used. 

3. Further cleaning of the gas and oil streams after separation. 

4. Gas dehydration processing to remove from the gas condensable water vapor that may lead to the formation of hydrates under certain conditions. 

5. Removal of contaminants or otherwise undesirable components, such as hydrogen sulfide and other corrosive sulfur compounds, and carbon dioxide.

Separation Equipments:

To efficiently perform its separation functions, a well designed separator must,

1. Control and dissipate the energy of the wellstream as it enters the separator. and provide low enough gas and liquid velocities for proper gravity segregation and vapor-liquid equilibrium. For this purpose, a tangential inlet to impart centrifugal motion to the entering fluids is generally used.

2. Remove the bulk of the liquid from the gas in the primary separation section. It is desirable to quickly achieve good separation at this stage. 

3. Have a large settling section. of sufficient volume to refine the primary separation by removing any entrained liquid from the gas, and handle any slugs of liquid (usually known as "liquid surges" ). 

4. Minimize turbulence in the gas section of the separator to ensure proper settling. 

5. Have a mist extractor (or eliminator) near the gas outlet to capture and coalesce the smaller liquid particles that could not be removed by gravity settling. 

6. Control the accumulation of froths and foams in the vessel. 

7. Prevent re-entrainment of the separated gas and liquid. 

8. Have proper control device; for controlling the back-pressure and the liquid level in the separator. 

9. Have reliable equipment for ensuring safe and efficient operations. This Includes pressure gauges, thermometers, devices for indicating the liquid level, safety relief valves to prevent blowup in case the gas or liquid outlets arc plugged, and gas and liquid discharge ("dump'') valves. 

Type of Separators:

l) Vertical Separators

2) Horizontal Separators

3) Spherical separators

l) Vertical Separators:

Vertical Separator

The wellstream enters the vertical separator tangentially through an inlet diverter that causes an efficient primary separation by three simultaneous actions on the stream: gravity settling, centrifugati oil, and impingement of the inlet fluids against the separator shell in a thin film. The gas from the primary separation section flows upwards. while the liquid falls downward into the liquid accumulation section. A conical baffle is provided as a separation between the liquid accumulation section and the primary separation section to ensure an undisturbed liquid surface for proper liquid level control and release of any dissolved gas. The smaller liquid droplets that are carried along by the upwards rising gas stream are removed in the centrifugal baffles near the top. Finally a mist extractor at the gas outlet removes any entrained liquid droplets from the gas in the micron size range. The liquid particles coalesce and accumulate, until they become sufficiently heavy to fall into the liquid accumulation section. 

Advantages: 

A vertical separator can handle relatively, large liquid slugs without carryover into the gas outlet. It thus provides better surge control, and is often used on low to intermediate gas-oil ratio (GOR) wells and wherever else large liquid slugs are expected. Vertical vessels can handle more sand. A false cone bottom can be easily fitted to handle sand production. Liquid level control is not as critical in a vertical separator. The tendency of the liquid to revaporize is also minimized, because less surface area is available to the liquid for evaporation. It occupies less floor space, a particularly important advantage for operations on an offshore platform where floor area is at a premium.

Disadvantages:

vertical separators are more expensive to fabricate, and also more expensive to transport to location. A vertical separator for the same capacity is usually larger than a horizontal separator. since the upwards flowing gas in the ver. tical separator opposes the falling droplets of liquid. 

Horizontal Separators:

Horizontal Separator

These separators may be of a single-tube or a double-tube in design. In the single-tube horizontal separator, the wellstream upon entering through the inlet, strikes an angle baf£1e and then the separator shell, resulting in an efficient primary separation similar to the vertical separator. The liquid drains into the liquid accumulation section, via horizontal baffles. These baffles act as Sites for further release of any dissolved gas. Gas flows horizontally in a horizontal separator. It strikes baffles placed at an angle of 45°, thereby releasing entrained liquid by impingement. A mist extractor is usually provided near the gas out1et. In the double-tube type. the upper tube acts as the separator section, while the lower tube merely functions as a liquid accumulation section, Thus the double-tube separator is similar to a single-tube separator, but with ~ greater liquid capacity. The liquid generated in .the primary separation section near the inlet is immediately drained out into the lower tube. The wet gas flows through the baffles in the upper separator tube at higher velocities. Additional liquid generated is drained into the lower section through the liquid drains provided aJong the length of the separator. 

Advantages: 

Horizontal separators have a much greater gas-liquid interface area, permitting higher gas velocities. They can, therefore, handle large gas volumes economically and efficiently. They are cheaper to fabricate and ship than vertical separators. They are also easier and cheaper to install and service. Horizontal separators minimize turbulence and foaming. For a given capacIty, ?horizontal separators are smaller and cheaper than vertical separators. ~oTl.zontal separators are almost always used for high GOR wells, for foaming well streams, and for Liquid-Liquid separation.

Disadvantages:

Liquid level control is critical for horizontal separators, and the surge space is rather limited. They are much harder to clean. and are therefore not advisable to use where the well produces a lot of sand. They occupy a lot of space. The space requirements. however. can be minimized by stacking several of these on top of each other for stage separation operations.

Spherical Separators:

Spherical Separators

The spherical separator is designed to make optimum use of all the known means of gas and liquid separation such as gravity, low velocity. centrifugal force, and surface contact . An inlet flow diverter spreads the entering wellstream tangentially against the separator wall. The liquid is split into two streams that come together after going halfway around the circular vessel wall and then fall into the liquid accumulation section. Liquid droplets from the gas are removed mostly by the velocity reduction imposed upon the gas inside the vessel. A mist extractor is used for the final removal of smaller liquid droplets in the gas. 

Advantages: 

Spherical separators are very inexpensive, cheaper than either the vertical or the horizontal separators. They are very compact, and offer better cleanout and bottom drain features than even the vertical type. Spherical separators are applicable to well streams with low to intermediate GOR's. 

Disadvantages:

Liquid level control is critical to the spherical separator performance. They have very limited surge capacity and liquid settling section. Because of the limited internal space, it is difficult to use a spherical separator for three phase (gas-oil-water) separation. 

for, Quick notes on type of separators. click here.

  

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