Two-phase Oil and Gas Separation - Brief - Chapter 3

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Two-phase Oil and Gas Separation - Brief - Chapter 3

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Detailed Two-phase Oil and Gas Separation can be found in Fundamentals of oil and gas processing
Chapter 2 .
Fundamentals of Oil and Gas Processing Book
Basics of Gas Field Processing Book
Prediction and Inhibition of Gas Hydrates Book
Basics of Corrosion in Oil and Gas Industry Book ... scns_share
Chapter 3 61
Two-phase Oil and Gas Separation 61
3.1 Introduction 61
3.2 Phase Equilibrium 61
3.3: Separation process: 62
3.4: Principles of Physical Separation: 62
3.5: Gravity Separation: 62
3.6: Stage Separation 65
3.6.1: Initial Separation Pressure 65
3.6.2: Stage Separation 66
3.6.3: Selection of Stages 67
3.6.4: Fields with Different Flowing Tubing Pressures 68
3.6.5: Determining Separator Operating Pressures 68

Chapter 3

Two-phase Oil and Gas Separation

3.1 Introduction
The production system begins at the wellhead. Fluids produced from oil and gas wells generally constitute mixtures of crude oil, natural gas, and salt water. Crude oil–gas–water mixtures produced from wells, are generally directed, through flow lines and manifold system, to a central processing and treatment facility normally called the gas–oil separation plant (GOSP).
The goal is to attain in the downstream (output) of the “gas oil separation plant”, the following components:
Oil free of water and meets other purchaser’s specifications.
Gas free of hydrocarbon liquid meets other purchaser’s specifications.
Water free of oil and meets environmental, and reservoir regulation for disposal or reinjection.
The first step in processing of the produced stream is the separation of the phases (oil, gas, and water) into separate streams.
Oil may still contain between 10% and 15% water that exists mostly as emulsified water, once initial separation is done, each stream undergoes the proper processing for further field treatment.
3.2 Phase Equilibrium
Equilibrium is a theoretical condition that describes an operating system that has reached a “steady-state” condition whereby the vapor is condensing to a liquid at exactly the same rate at which liquid is boiling to vapor. Simply stated, phase equilibrium is a condition where the liquids and vapors have reached certain pressure and temperature conditions at which they can separate. In most production systems, true equilibrium is never actually reached; however, vapors and liquids move through the system slow enough that a “pseudo” or “quasi” equilibrium is assumed. This assumption simplifies process calculations.
Figure 2-1 illustrates several operating points on a generic phase equilibrium diagram. Point A represents the operating pressure and temperature in the petroleum reservoir. Point B represents the flowing conditions at the bottom of the production tubing of a well. Point C represents the flowing conditions at the wellhead. Typically, these conditions are called flowing tubing pressure (FTP) and flowing tubing temperature (FTT). Point D represents the surface conditions at the inlet of the first separator.
Figure 3-1 Phase equilibrium phase diagram for a typical production system.

3.3: Separation process:
The process can be described as:
Two phase separation, or
Three phase separation
The phases referred to are oil, water and gas.
In two phase separation, gas is removed from total liquid (oil plus water).
In three phase separation, however, in addition to the removal of gas from liquids, the oil and water are separated from each other.
Figure 3.2 shows the difference between 2 and 3 phase separation.
3.4: Principles of Physical Separation:
Three principles used to achieve physical separation of gas and liquids or solids are momentum, gravity settling, and coalescing.
Any separator may employ one or more of these principles, but the fluid phases must be "immiscible" and have different densities for separation to occur.

3.5: Gravity Separation:
Since a separation depends upon gravity to separate the fluids, the ease with which two fluids can be separated depends upon the difference in the density or weight per unit volume of the fluids. (Density of liquid is much higher than density of gases).
In the process of separating, separation stages are as follows:
1- Separate liquid mist from the gas phase.
2- Separate gas in the form of foam from the liquid phase.
3- In case of 3 phase separation, in addition to the above two requirements, water droplets should be separated from oil phase, and oil droplets should be separated from water phase.
Figure 3.2 The Difference between 2 & 3 Phase Separation.

Droplets of liquid mist will settle out from gas, provided:
The gas remains in the separator long enough for mist to drop out.
The flow of the gas through the separator is slow enough that no turbulence occurs, which will keep the gas stream stirred up so that the liquid has no chance to drop out.
The objective of ideal two-phase separation, is to separate the hydrocarbon stream into liquid-free gas and gas-free-liquid. Ideally, the gas and liquid reach a state of equilibrium at the existing conditions of Pressure and Temperature within the vessel.
Liquid droplets will settle out of a gas phase due to the difference in densities if the gravitational force acting on the droplet is greater than the drag force of the gas flowing around the droplet (see Fig. 2-3). The drag force is the force resulted from the velocity of gas and affecting the entrained droplet of liquid, forcing it to move in the gas flow direction.
Fig. 3-3 A schematic of a force balance on a droplet in a flowing gas stream.

Figures 3-4, and 3-5, illustrates the liquid droplet in gas phase and gas bubble in liquid phase in both configurations of horizontal and vertical separators.
From both figures, it’s clear that, in vertical separator, the gravitational settling force is countercurrent or opposite of the drag force resulted from gas movement. While in horizontal separator, the two forces are perpendicular to each other.
The same for the gas bubble entrained in liquid in vertical and horizontal separators.
Fig. 3- 4.The liquid droplet in gas phase and gas bubble in liquid phase in horizontal separator.
Fig. 3-5 The liquid droplet in gas phase and gas bubble in liquid phase in vertical separator.

3.6: Stage Separation
3.6.1: Initial Separation Pressure
Because of the multicomponent nature of the produced fluid, the higher the pressure at which the initial separation occurs, the more liquid will be obtained in the separator. This liquid contains some light components that vaporize in the stock tank downstream of the separator. If the pressure for initial separation is too high, too many light components will stay in the liquid phase at the separator and be lost to the gas phase at the tank. If the pressure is too low, not as many of these light components will be stabilized into the liquid at the separator and they will be lost to the gas phase.
This phenomenon, which can be calculated using flash equilibrium techniques discussed in previous chapter, is shown in Figures 3-6 and 3-7.
Fig. 3-6. Single stage separation.

It is important to understand this phenomenon qualitatively. The tendency of any one component in the process stream to flash to the vapor phase depends on its partial pressure. The partial pressure of a component in a vessel is defined as the number of molecules of that component in the vapor space divided by the total number of molecules of all components in the vapor space times the pressure in the vessel [refer to Eq. (3-1)]:

PPN =P × MolesN / ∑ MolesN Eq. 3-1
PPN = partial pressure of component “N,”
MolesN = number of moles of component “N,”
Ʃ MolesN = total number of moles of all components,
P = pressure in the vessel, psia.
Thus, if the pressure in the vessel is high, the partial pressure for the component will be relatively high and the molecules of that component will tend toward the liquid phase. This is seen by the top line in Figure 3-7.
As the separator pressure is increased, the liquid flow rate out of the separator increases.
The problem with this is that many of these molecules are the lighter hydrocarbons (methane, ethane, and propane), which have a strong tendency to flash to the gas state at stock-tank conditions (atmospheric pressure). In the stock tank, the presence of these large numbers of molecules creates a low partial pressure for the intermediate-range hydrocarbons (butanes, pentane, and heptane) whose flashing tendency at stock tank conditions is very susceptible to small changes in partial pressure. Thus, by keeping the lighter molecules in the feed to the stock tank, we manage to capture a small amount of them as liquids, but we lose to the gas phase many more of the intermediate-range molecules. That is why beyond some optimum point there is actually a decrease in stock-tank liquids by increasing the separator operating pressure.

Fig. 3-7. Effect of separator pressure on liquid recovery.

3.6.2: Stage Separation
Figure 3-6 deals with a simple single-stage process. That is, the fluids are flashed in an initial separator and then the liquids from that separator are flashed again at the stock tank. Traditionally, the stock tank is not normally considered a separate stage of separation, though it most assuredly is.
Figure 3-8 shows a three-stage separation process. The liquid is first flashed at an initial pressure and then flashed at successively lower pressures two times before entering the stock tank.
Because of the multicomponent nature of the produced fluid, it can be shown by flash calculations that the more stages of separation after the initial separation, the more light components will be stabilized into the liquid phase. This can be understood qualitatively by realizing that in a stage separation process the light hydrocarbon molecules that flash are removed at relatively high pressure, keeping the partial pressure of the intermediate hydrocarbons lower at each stage. As the number of stages approaches infinity, the lighter molecules are removed as soon as they are formed and the partial pressure of the intermediate components is maximized at each stage. The compressor horsepower required is also reduced by stage separation as some of the gas is captured at a higher pressure than would otherwise have occurred. This is demonstrated by the example in Table 3-1.
Table. 3-1. Effect of separation pressure for a rich condensate stream.
Fig. 3-8. Stage separation
3.6.3: Selection of Stages
As shown in Figure 3-9, as more stages are added to the process there is less and less incremental liquid recovery. The diminishing income for adding a stage must more than offset the cost of the additional separator, piping, controls, space, and compressor complexities. It is clear that for each facility there is an optimum number of stages. In most cases, the optimum number of stages is very difficult to determine as it may be different from well to well and it may change as the well’s flowing pressure declines with time. Table 2-7 is an approximate guide to the number of stages in separation, excluding the stock tank, which field experience indicates is somewhat near optimum. Table 3-2 is meant as a guide and should not replace flash calculations, engineering studies, and engineering judgment.
Fig.3-9. Incremental liquid recovery versus number of separator stages.

Table. 3-2. Stage separation guidelines.

3.6.4: Fields with Different Flowing Tubing Pressures
The discussion to this point has focused on a situation where all the wells in a field produce at roughly the same flowing tubing pressure, and stage separation is used to maximize liquid production and minimize compressor horsepower. Often, stage separation is used because different wells producing to the facility have different flowing tubing pressures. This could be because they are completed in different reservoirs, or are located in the same reservoir but have different water production rates. By using a manifold arrangement and different primary separator operating pressures, there is not only the benefit of stage separation of high-pressure liquids, but also conservation of reservoir energy. High-pressure wells can continue to flow at sales pressure requiring no compression, while those with lower tubing pressures can flow into whichever system minimizes compression.

3.6.5: Determining Separator Operating Pressures
The choice of separator operating pressures in a multistage system is large. For large facilities many options should be investigated before a final choice is made. For facilities handling less than 50,000 bpd, there are practical constraints that help limit the options.
A minimum pressure for the lowest-pressure stage would be in the 25- to 50-psig range. This pressure will probably be needed to allow the oil to be dumped to a treater or tank and the water to be dumped to the water treating system. The higher the operating pressure, the smaller the compressor needed to compress the flash gas to sales. Compressor horsepower requirements are a function of the absolute discharge pressure divided by the absolute suction pressure.
Increasing the low-pressure separator pressure from 50 psig to 200 psig may decrease the compression horsepower required by 33%. However, it may also add backpressure to wells, restricting their flow, and allow more gas to be vented to atmosphere at the tank. Usually, an operating pressure of between 50 and 100 psig is optimum.

As stated before, the operating pressure of the highest-pressure separator will be no higher than the sales gas pressure. A possible exception to this could occur where the gas lift pressure is higher than the sales gas pressure. In choosing the operating pressures of the intermediate stages, it is useful to remember that the gas from these stages must be compressed.
Normally, this will be done in a multistage compressor. For practical reasons, the choice of separator operating pressures should match closely and be slightly greater than the compressor inter-stage pressures.
Fig. 3-10. Compressor stages and inlet points of separated gas from multistage separation.

The most efficient compressor sizing will be with a constant compressor ratio per stage. Therefore, an approximation of the intermediate separator operating pressures can be derived from

R = (Pd/Ps)1/n Eq. 3-2

R = Compression ratio per stage,
Pd = discharge pressure, psia,
Ps = suction pressure, psia,
n = number of stages.
In order to minimize inter-stage temperatures, the maximum ratio per stage will normally be in the range of 3.6 to 4.0. That means that most production facilities will have either two- or three-stage compressors. A two-stage compressor only allows for one possible intermediate separator operating pressure. A three-stage allows for either one operating at second- or third-stage suction pressure or two intermediate separators each operating at one of the two compressor intermediate suction pressures.( fig. 3-10).
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