Separators: Types and Designing Considerations

The separator is the pressure vessel that separates the liquid and gaseous constituents. For example, at the wellhead, hydrocarbon streams are composed of gas, liquid hydrocarbons, and free water. Most of the time, dividing these stages as soon as possible is preferable so that the two or three phases may be tackled independently. In a broader way and based on the type of separated streams, separators are categorized into two types: gas/liquid two-phase separator and gas/oil/water three-phase separator.

1 Separator Types

Separators may be of different sizes and geometry, but their main function always remains same. They are employed to divide the constituent that flow into them. Separators can be categorized according to layout or fluid flow.

1.1 Vertical Separator

A vertical separator is frequently utilized when well streams have a low/moderate gas-to-oil ratio, and a large liquid slug is anticipated. The action of the liquid level control is not as crucial since it can handle greater slugs of liquid without leaking into the gas exit. Due to the greater vertical separation between the liquid level and the gas outlet, the liquid is less likely to re-vaporize into the gas phase. A vertical divider is essential when restricted space/area is available on an offshore platform since it takes up less floor space.

Figure 1: Verticle Separator Schematic

1.1.1 Advantages

The substantial vertical distance between the liquid level and the gas outlet limits the possibility of the liquid re-vaporizing into the gas phase
There are fewer entrainment tendencies
Surge control is an additional advantage

1.1.2 Disadvantages

Reaching some equipment and safety devices may be challenging without ladders or access platforms
For a similar gas capacity as the horizontal separator, a separator with a wider diameter is needed

1.2 Horizontal Single Tube Separator

The horizontal separator consists of the huge, long, baffled gas-separation portion that enables greater gas velocities and has a significantly bigger gas-liquid contact surface. The huge liquid surface area makes it possible to extract gas from the liquid effectively. This vessel offers a sizable interface area between the liquid and gas phases, enabling more separation capability when gas capacity is a design consideration. The horizontal vessel is more economically viable in high-pressure separators since larger diameters necessitate thicker walls.

Figure 2: Horizontal Single Tube Separator Schematic

1.2.1 Advantages

They have a higher liquid/gas interface because of a large, protracted, and baffled gas-separation component
The price of the horizontal separator is lower than that of the vertical separator

1.2.2 Disadvantages

Level control is critical and should be maintained
Cleaning is challenging

1.3 Double Tube Horizontal Separator

A typical horizontal separator’s advantages are included in a horizontal double-tube separator, with a greatly increased liquid capacity. It features two vessels positioned horizontally and vertically. The synthesized fluid enters the top vessel, where baffles separate it into liquid and gas. When the liquid reaches the bottom vessel, it separates from the oil. More produced fluids may be processed by a horizontal separator having two barrels than by one.

Figure 3: Schematic of Double Tube Horizontal Separator

1.3.1 Advantages

This equipment is helpful in case of high gas flow rates and a chance of large liquid slugs
It makes it easier to deal with liquid floods

1.3.2 Disadvantages

It involves additional costs

1.4 Spherical Separator

Vertical separators also include spherical separators. This design is low cost and consists small vessel configuration. They are inefficient when a well stream is subjected to surging foamy components or has excessive muck or sand. These separators are no longer often utilized because of their drawbacks.

Figure 4: Schematic of Spherical Separator

1.4.1 Advantages

It is economical
It is advantageous for low or moderate gas-to-oil ratios
It is portable and straightforward to set up

1.4.2 Disadvantages

Liquid level management affects how well the spherical separator performs.
Both the liquid settling portion and surge capacity have deficient capacities.
It is challenging to use in three-phase due to the limited interior area (water, gas and oil).

1.5 Other Separator Types

Cyclone/centrifugal separators
Filter separators
Scrubbers

2 Separator Design and Associated Factors

A separator’s functioning and ability to separate the liquid and gas phases depend on several fundamental variables:

Operating temperature of the separator
Operating pressure of the separator
Fluid stream composition

The amount of gas and liquid exiting the separator will change if any of these variables changes for a particular fluid well stream. The well stream composition is a natural reality in most cases, and the operator has little influence over it.

Gas Capacity and Liquid Capacity calculation for a separator are important, and the main contributor to which procedure is given here:

Gas Capacity

The gas capacity of oil-gas separators is usually calculated using Souders-empirical Brown’s relationship:

Where;

v = Gas speed at the surface

A = Cross-sectional area separator area for vapor flow

q = Gas flow rate

ρ_L= Liquid density

ρ_g= Gas density

K = Empirical factor (value varies from 0.12 to 0.35, depending on the type of separator)

Liquid Capacity

The main factor that changes how much liquid a separator can hold is how long the liquid stays in the vessel. A good separation needs enough time for the liquid and gas phases to reach a state of equilibrium at the temperature and pressure of separation. The following equation can determine how much liquid a separator can hold or how much settling volume is needed based on retention.