Fluids Separation


The main purpose of any oil and gas production facility is to separate the well effluent that consists of oil, water, and gas produced into their original phases. This is achieved by a stepwise reduction in pressure down to atmospheric pressure; using gas-oil-separation plant (GOSP), flashing off the gas and then dehydrating the crude oil to meet its export specification of less than 0.5% water in oil.

In the two-phase units, gas is separated from the liquid with the gas and liquid being discharged separately. Oil and gas separators are mechanically designed such that the liquid and gas components are separated from the hydrocarbon steam at specific temperature and pressure.

Separation of hydrocarbon liquids and gasses from water and sediments is a challenging operation.

Based on the configuration, the most common types of separator are horizontal, vertical, and spherical. Large horizontal gas-oil separators are used almost exclusively in processing well fluids in the Middle East, where the gas-oil ratio of the producing fields is high. Multistage GOSPs normally consist of three or more separators.


Well effluents flowing from producing wells are usually identified as turbulent, high velocity mixtures of gases, oil, and salt water. As these streams flow reaching the surface, they undergo continuous reduction in temperature and pressure forming a two-phase fluid flow: gas and liquid. The gathered fluids emerge as a mixture of crude oil and gas that is partly free and partly in solution. They must be separated into their main physical components, namely: oil, water, and natural gas. The separation system performs this function w'hich is usually made up of a free water knock-out (FWKO), flow line heater, and gas-oil (two-phase) separators, or gas-oil-water (three-phase separators). Gas-oil separators work on the principle that the three components have different densities, which allow them to stratify when moving slowly with gas on top, water on the bottom, and oil in the middle.

The physical separation of these three phases is carried out using what is called stage separation in which a series of separators operating at consecutively reduced pressures are used. The purpose of stage separation is to obtain maximum recovery of liquid hydrocarbons from the fluids coming from the wellheads and to provide maximum stabilization of both the liquid and gas effluents, as shown in Figure 16.1.

Case studies presented in the chapter include finding the “Optimum Separating Pressure for Three Stage Separators” and to investigate the causes of tight emulsions in GOSPs.

The process involved in a gas-oil separator encompasses two main stages in order to free oil from gas. These are recognized as: flash separation of the gas-oil mixture followed by oil recovery.

16.1.1 Flash Separation

In order to understand the theory underlying the separation of well-effluents of hydrocarbon mixtures, it is assumed that such mixtures contain essentially three main groups of hydrocarbons (Table 16.1).

  • • Light group, which consists of methane (CH4) and ethane (C2H6)
  • • Intermediate group, which consists of two subgroups: propane (C,Hs)/butane (C4H|0) and pentane (C5Hw)/hexane (ChH,2)
  • • Heavy group, which is the bulk of crude oil and is identified as C7H,4+

Basically, our objective in separating the gas-oil mixture is a dual function:

a. To get rid of all C, and C2, i.e., light gases

b. Save the heavy-group components as our liquid product

Three stage GOSP

FIGURE 16.1 Three stage GOSP.

TABLE 16.1

Constituents of Crude Oil and Natural Gas

In order to accomplish these objectives, we unavoidably loose part of the intermediate group in the gas stream, whose heavier components (C5/C6) would definitely belong to the oil product.

The problem of separating gases in general from crude oil in the well-fluid effluents breaks dowm to the w'ell-known problem of flashing a feed mixture into two streams: vapor and liquid. This takes place using a flashing column (a vessel without trays). Gases liberated from the oil are kept in intimate contact. As a result, thermodynamic equilibrium is established between the tw'o phases. This is the basis of flash calculations, which is carried out to make material balance calculations for the flashing streams.

16.1.2 Oil Recovery

Once flashing takes place, our concern centers next on recovering the crude oil. The effective method used implies tw'o consecutive steps:

a. To remove oil from gas: Here, we are primarily concerned in recovering as much oil as we can from the gas stream. Density difference or gravity differential between oil and gas is the first means to accomplish separation at this stage. At the separator’s operating condition of high pressure.

this difference in density becomes large (gas law); and the oil is about eight times as dense as the gas. This could be a sufficient driving force for the oil particles to settle down and separate. This is true for large size having diameter of 100 microns or more. For smaller ones, mist extractors are needed.

Other means of separation would include change of velocity of incoming flow, impingement, and the action of centrifugal force. These methods would imply the addition of some specific designs for the separator to provide the desired method for achieving separation.

b. To remove gas from “locked” oil: The objective here is to recover and collect any non-solution gas that may be entrained or “locked” in the oil. The recommended methods are: settling, agitation, and applying heat chemicals.


Regardless of their configurations, gas-oil separators usually consist of four functional sections:

Section A: Initial separation takes place in this section at the inlet of the separator. It is used to collect the entering fluid.

Section B: It is designated as the gravity settling section through which the gas velocity is substantially reduced allowing for the oil droplets to fall and separate.

Section C: Is known as the mist extraction section. It contains woven-wire mesh pad. which is capable of removing many fine droplets from the gas stream.

Section D: Is the final component in a gas-oil separator. Its main function is to collect the liquid recovered from the gas before it is discharged from the separator.

In addition to these main components, gas-oil separators normally include the following control devices:

  • • Oil level controlling system that consists of oil level controller (OLC) plus an automatic diaphragm motor-valve on the oil outlet. In case of a 3-phase separator, additional system is required for the oil-water interface. Thus, a liquid level controller plus a water discharge control valve is needed.
  • • An automatic back-pressure valve on the gas stream leaving the gas-oil vessel to maintain a fixed pressure inside it.
  • • Pressure relief devices.

These control devices are shown in Figure 16.2.

Gas oil separator fully automated

FIGURE 16.2 Gas oil separator fully automated.


In the separator, crude oil separates out, settles, and collects in the lower part of the vessel. The gas lighter than oil fills the upper part of the separator. Crude oil with high gas-oil ratio (GOR) must be admitted to two or three stages as indicated in Figure 16.3. Movement of crude oil from one separator to the next takes place under the driving force of the flowing pressure. Pumps are needed for the final trip to transfer the oil to its storage tank.

The essential characteristics of a gas-oil separator are:

i. To cause a decrease in the flow velocity, permitting separation of gas and liquid by gravity.

ii. To operate at temperature above the hydrate point of the flow ing gas.

The conventional method using multistage flash separators is recommended for relatively high pressure high GOR fluids. Separation takes place in a stage by w'hat is knowrn as Flash Distillation (unit operation). Generally speaking, the number of stages is a strong function of: the API gravity of oil, GOR, and flowing pressure. Based on configuration, three types of separators are known: horizontal, vertical, and spherical. It is most common to see large horizontal gas-oil separators used in processing well fluids in the Middle East, with three or more separators.

Flow of crude oil from well through GOSP

FIGURE 16.3 Flow of crude oil from well through GOSP.

The need for what is called "Modern GOSP” may arise as the water content of the produced crude increases. The function of such set-up is a multipurpose one. It will separate the hydrocarbon gases from oil. Remove water from crude oil. Finally, it will reduce salt content to the acceptable limits. Three phase separators are common in many fields in the Middle East.

If the effect of corrosion due to high salt content in the crude is recognized, then modern desalting equipment could be included as a third function in the GOSP design.

The functions of a modern GOSP could be summarized as follows: [1]


Before presenting the design equations, it is necessary to state first some basic fundamentals and assumptions relevant to the sizing of gas-oil separators:


  • • The difference in densities between the liquid and gas is taken as a basis for calculating the gas capacity.
  • • In the gravity settling section, liquid drops will settle at a velocity determined by equating the gravity force acting on the drop with the drag force caused by its motion relative to the gas phase.
  • • A normal retention time to allow for the gases to separate from oil is considered to be between 30 seconds and 3 minutes. Normally retention time is defined as the residence time or the time for a molecule of liquid is retained in the vessel.

Mathematically: Retention time = Volume of vessel/Liquid flow rate

  • • For vertical separators, liquid particles (oil) separate by settling downward against upflowing gas stream; while for horizontal ones liquid particles assume a trajectory-like path, while it flows through the vessel.
  • • For vertical separators, the gas capacity is proportional to the cross-sectional area of a separator; while for a horizontal one the gas capacity is proportional to the area available for disengagement. The volume of accumulation of either type will be the determining factor for the liquid capacity.


  • • No oil foaming takes place during the gas-oil separation (otherwise retention time should be increased to 5-20 minutes).
  • • The cloud point of the oil and hydrate point of the gas are below the operating temperature of 60°F.
  • • The smallest separable liquid drops are spherical ones having diameter of 100 microns.
  • • Liquid carryover with separated gas does not exceed 0.10 gallon/MMSCF.

Sizing of gas-oil separators requires the calculation of two parameters:

  • • The oil capacity, a separator can handle
  • • The gas capacity to be processed by a separator

The equations needed to calculate the oil capacity and gas capacity are presented as


where d is inside diameter of the vessel in ft, L is the shell height in ft, t is the retention time in minutes.

where: C, = [PJTf],[520/14.7], C, = difference in densities of oil & gas/density of gas, C, = separation coefficient of the vessel with typical values of 0.167 and 0.5 for vertical and horizontal separators respectively, z is the gas compressibility factor, P( and T( designates the flowing pressure and flowing temperature respectively.

It is to be noted that Equation (16.1) is applicable for horizontal separators. Equation (16.2), on the other hand, applies for both horizontal and vertical separators depending on the value of A.

For horizontal, A = the cross section area, while for vertical, A = the entire cross section = I1/4D2

Equation (16.2) relates the gas capacity of gas-oil separator, Q, to the corresponding cross section area, A. This enables finding the diameter of a separator needed to handle a given input of a gas flow rate.



As we have seen earlier, GOSPs are needed for environmental reasons. It is not appropriate to burn off the gases associated with crude oil. The economic reasons for processing and treating the produced crude are obvious. Recovering associated gases prevents wasting a natural resource, which was originally flared off. There are also other economic reasons for using GOSP. Removing contaminants from the crude, such as salt and hydrogen sulfide, protects plants from corrosion damage caused by corrosion.

During crude-oil processing at the GOSP, one of the most important variables that determines the efficiency of oil/water/gas separation is the tightness of the incoming emulsion. The tighter the emulsion, the higher the dosage of demulsifier needed to break them. The performance of the GOSP is closely tied to the characteristics of the feed emulsions.

Another aspect of GOSP performance is related to the process facilities (hardware) and process variables. The hardware includes the number and type of separators, dehydrators and desalters, water/oil separators (WOSs), and other hardware at the GOSP. Process variables include oil and water-flow rates, temperatures, water cuts, and GOSP operating conditions. A higher residence time of fluids in the GOSP will generally lead to better separation and better performance, all other variables being constant. Besides the residence time, process retrofits in the vessels also tend to enhance performance.

Usually it is most economical to use three to four stages of separation for the hydrocarbon mixture. Five or six stages may payout under favorable conditions, when, for example, the incoming wellhead fluid is found at very high pressure. However, the increase in liquid yield with the addition of new stages is not linear. For instance, the increase in liquids gained by adding one stage to a single-stage system is likely to be substantial. However, adding one stage to a three- or four-stage system is not as likely to produce any major significant gain. In general, it has been found that a three-stage separating system is the most cost effective.

The following parameters are detrimental in evaluating the performance and the economics of GOSP:

  • • Optimum separation conditions: separator pressure and temperature
  • • Compositions of the separated gas and oil phases
  • • Oil formation volume factor
  • • Product GOR
  • • API gravity of the stock tank oil


Objective: Optimizing the gas-oil separation facility in order to find the optimal conditions of pressure and temperature under which we would get the most economical profit from the operation.

16.6.1 Process Description

It is assumed that we have three separators: high, intermediate, and low pressure separators. It is the pressure of the second stage (intermediate) that could freely be changed and optimized. The pressure in the first separator (high pressure), on the other hand, is usually kept fixed either to match the requirement of a certain pressure gas injection facilities, or to meet a sale obligation through a pipe line, or it is the flow conditions of the incoming feed line. Similarly, the pressure in the third separator (low pressure) is fixed; usually it is the last stage functioning as the storage tank.

The optimum pressure is defined as the one that gives the desired separation of gases from crude oil, with the maximum recovery of oil in the stock tank. Under these conditions, we should have minimum gas/oil ratio.

If R designates the recovery of the oil and is defined:

R = O/G of oil per SCF gas. then the optimum operating pressure in the 2nd stage. (P2)0 should be the value that makes R maximum; or 1/R is minimum.

16.6.2 Approach

The method depends on using a pilot unit to do experimental runs, in which he pressure in the 2nd stage is to be changed from run to run. A sample of the gases leaving the three separators is to be analyzed for the content of some key component, say C5+. It is established, therefore, to minimize the loss of C5+ in the gas stream separated from the crude oil.

Variation of (G/O) with P

FIGURE 16.4 Variation of (G/O) with P2.

The experimental runs will look as follows:

Run No

P2 [psi]

(G/0)2 [scf/bbl]

(G/0)3 [scf/bbl]



The change in (G/0) for both separators with P, is plotted as shown in Figure 16.4. It is seen that with the increase in P2, (G/O), decreases indicating more condensation of heavier hydrocarbons. On the other hand, increasing P, will increase (G/0)3, because the pressure difference between stages 2 and 3 will increase causing more hydrocarbons to vaporize from stage 3. The cumulative sum of (G/O), plus (G/0)3, named (G/0)T is plotted against P2.

It is concluded right away, that the value of (P2)0 corresponds to the minimum (G/OV

This minimum (G/0)T leads to 1/R or (O/Gf,-, the maximum oil recovery, bbl per SCF of gas separated.

16.6.3 Conclusion

This optimization approach, would lead us to calculate the value of oil revenue for the system, by simply using the following formula: Effect of pressure in GOSP on crude oil yield

FIGURE 16.5 Effect of pressure in GOSP on crude oil yield.

The effect of operating pressure in gas/oil separation on crude yield has to be taken into consideration as indicated in Figure 16.5.



Problem Number 16.7 Case Study: Causes of Tight Emulsions in Gas Oil Separation Plants

The giant Ghawar field in Saudi Arabia has several wet crude handling facilities referred to as gas oil separating plants or GOSPs, located at Mubarraz area (These GOSPs process Arabian Light crude and their primary function is to separate oil, water, and gas.


To evaluate the relative performance of de-emulsifiers and to optimize their usage in GOSPs while meeting crude and water specifications. The case study was brought to the attention of the Ch.E. department at KFUPM, Saudi Arabia.


Formation of emulsions during oil production is a costly problem, both in terms of production losses and chemical costs. In these days of high oil prices and the need to reduce production costs, there is an economic necessity to control, optimize, or eliminate the problem by maximizing oil-water separation.

Analysis of crude oils from wells in Ghawar indicates that these oils are produced in the form of tight water-in-oil emulsions. Tight or strong emulsions are difficult to separate and cause production and operational problems. These problems have led, at times, to an increase in de-emulsifier usage, production of off-spec crude, and occasionally caused equipment upsets in the GOSP.

The main causes of emulsion problems are (a) The presence asphaltenes and fine solids in the crude, (b) lower temperatures in the winter time, and (c) an increase in water production.


In this case study of tight emulsions, once you have collected all the positive and negative factors and have quantified them you can put them together into an accurate Cost-Benefit analysis.

On the cost side, one can envisage the following: [2]

17 Operations Handling

  • [1] To separate the hydrocarbon gases from crude oil and remove water fromcrude oil. • To reduce the salt content to the acceptable level (BS&W). A GOSP can function according to one of the following process operations: • Three-phase, gas-oil-water separation. Read also Three-Phase, oil-water-gas separators • Two-phase, gas-oil separation. Read also Two-Phase, gas-oil separators • Two-phase, oil-water separation • De-emulsification • Washing • Electrostatic coalescence
  • [2] Cost of de-emulsifier. • The addition of asphaltenes dispersants and surfactants to the crude oil. • Using elaborate techniques to quantify the oil-water separation process, such as Emulsion Separation Index (ESI) (method developed bySuadi Aramco). On the benefit side, we get: • A reduction in the quantity of de-emulsifiers used • Less production losses • Less operation problems • An increase in oil revenue • Fast rate of separation in the GOSP, which gives less residence time.This reduces the diameter of the separator
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