Two-Phase Gas–Oil Separation

Vertical Separator
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At the high pressure existing at the bottom of the producing well, crude oil contains great quantities of dissolved gases. When crude oil is brought to the surface, it is at a much lower pressure. Consequently, the gases that were dissolved in it at the higher pressure tend to come out from the liquid. Some means must be provided to separate the gas from oil without losing too much oil.

Vertical SeparatorIn general, well effluents flowing from producing wells come out in two phases: vapor and liquid under a relatively high pressure. The fluid emerges as a mixture of crude oil and gas that is partly free and partly in solution. Fluid pressure should be lowered and its velocity should be reduced in order to separate the oil and obtain it in a stable form. This is usually done by admitting the well fluid into a gas–oil separator plant (GOSP) through which the pressure of the gas–oil mixture is successively reduced to atmospheric pressure in a few stages.
Upon decreasing the pressure in the GOSP, some of the lighter and more valuable hydrocarbon components that belong to oil will be unavoidably lost along with the gas into the vapor phase. This puts the gas–oil separation step as the initial one in the series of field treatment operations of crude oil. Here, the primary objective is to allow most of the gas to free itself from these valuable hydrocarbons, hence increasing the recovery of crude oil.
Crude oil as produced at the wellhead varies considerably from field to field due not only to its physical characteristics but also to the amount of gas and salt water it contains. In some fields, no salt water will flow into the well from the reservoir along with the produced oil. This is the case we are considering in this chapter, where it is only necessary to separate the gas from the oil; (i.e., two-phase separation).

on the other hand, salt water is produced with the oil, it is then essential to use three-phase separators, oil-field separators can be classified into two types based on the number of phases to separate:
1. Two-phase separators, which are used to separate gas from oil in oil fields, or gas from water for gas fields.
2. Three-phase separators, which are used to separate the gas from the liquid phase, and water from oil.
Oil from each producing well is conveyed from the wellhead to a gathering center through a flow line. The gathering center, usually located in some central location within the field, will handle the production from several wells in order to process the produced oil–gas mixture.
Separation of the oil phase and the gas phase enables the handling, metering, and processing of each phase independently, hence producing marketable products.



In order to understand the theory underlying the separation of well effluent hydrocarbon mixtures into a gas stream and oil product, it is assumed that such mixtures contain essentially three main groups of hydrocarbon,
1. Light group, which consists of CH4 (methane) and C2H6 (ethane)
2. Intermediate group, which consists of two subgroups: the propane/butane (C3H8/C4H10) group and the pentane/hexane (C5H12/C6H14) group.
3. Heavy group, which is the bulk of crude oil and is identified as C7H16.

read also Crude Oil Components

In carrying out the gas–oil separation process, the main target is to try to achieve the following objectives:
1. Separate the C1 and C2 light gases from oil
2. Maximize the recovery of heavy components of the intermediate group in crude oil
3. Save the heavy group components in liquid product To accomplish these objectives, some hydrocarbons of the
intermediate group are unavoidably lost in the gas stream. In order to minimize this loss and maximize liquid recovery, two methods for the mechanics of separation are compared:
1. Differential or enhanced separation
2. Flash or equilibrium separation
In differential separation, light gases (light group) are gradually and almost completely separated from oil in a series of stages, as the total pressure on the well-effluent mixture is reduced. Differential separation is characterized by the fact that light gases are separated as soon as they are liberated (due to reduction in pressure). In other words, light components do not come into contact with heavier hydrocarbons; instead, they find their way out.
For flash separation, on the other hand, gases liberated from the oil are kept in intimate contact with the liquid phase. As a result, thermodynamic equilibrium is established between the two phases and separation takes place at the required pressure.
Comparing the two methods, one finds that in differential separation, the yield of heavy hydrocarbons (intermediate and heavy groups) is maximized and oil-volume shrinkage experienced by crude oil in the storage tank is minimized. This could be explained by the fact that separation of most of the light gases take place at the earlier high-pressure
stages; hence, the opportunity of loosing heavy components with the light gases in low-pressure stages is greatly minimized. As a result, it may be concluded that flash separation is inferior to differential separation because the former experiences greater losses of heavy hydrocarbons that are carried away with the light gases due to equilibrium conditions.
Nevertheless, commercial separation based on the differential concept is very costly and is not a practical approach because of the many stages required. This would rule out differential separation, leaving the flash process as the only viable scheme to affect gas–oil separation using a small number of stages, a close approach to
differential separation is reached by using four to five flash separation stages.

The conventional separator is the very first vessel through which the well effluent mixture flows. In some special cases, other equipment (heaters, water knockout drums) may be installed upstream of the separator.
The essential characteristics of the conventional separator are the following:
1. It causes a decrease in the flow velocity, permitting separation of gas and liquid by gravity.
2. It always operates at a temperature above the hydrate point of the flowing gas.
The choice of a separator for the processing of gas–oil mixtures containing water or without water under a given operating conditions and for a specific application normally takes place guided by the general classification.

Functional Components of a Gas–Oil Separator

Regardless of their configuration, gas–oil separators usually consist of four functional sections:
1. Section A: Initial bulk separation of oil and gas takes place in this section. The entering fluid mixture hits the inlet diverter.
This causes a sudden change in momentum and, due to the gravity difference, results in bulk separation of the gas from the oil. The gas then flows through the top part of the separator and the oil through the lower part.
2. Section B: Gravity settling and separation is accomplished in this section of the separator. Because of the substantial reduction in gas velocity and the density difference, oil droplets settle and separate from the gas.
3. Section C: Known as the mist extraction section, it is capable of removing the very fine oil droplets which did not settle in the gravity settling section from the gas stream.
4. Section D: This is known as the liquid sump or liquid collection section. Its main function is collecting the oil and retaining it for a sufficient time to reach equilibrium with the gas before it is discharged from the separator.

In separating the gas from oil, a mechanical mechanism could be suggested which implies the following two

(a) To separate oil from gas: Here, we are concerned primarily with recovering as much oil as we can from the gas stream. Density difference or gravity differential is responsible for this separation. At the separator’s operating condition of high pressure, this difference in density between oil and gas becomes small (gas law). Oil is about eight times as dense as the gas. This could be a sufficient driving force for the liquid particles to separate and settle down. This is especially true for large-sized particles, having diameter of 100 mm or more. For smaller ones,
mist extractors are needed.

(b) To remove gas from oil: The objective here is to recover and collect any non solution gas that may be entrained or ‘‘locked’’ in the oil. Recommended methods to achieve this are settling, agitation, and applying heat and chemicals.

read also:
Gas – Oil Separators part. 1
 Gas – Oil Separators Part.2

1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook.