Oil and Gas Separation
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.
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.
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 2.2 shows the difference between 2 and 3 phase separation.
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.
Figure 2-1 Phase equilibrium phase diagram for a typical production system.
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.
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.
Figure 2.2 The Difference between 2 & 3 Phase Separation.
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. 2-3 A schematic of a force balance on a droplet in a flowing gas stream.
Figures 2-4, and 2-5, 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 .2- 4.The liquid droplet in gas phase and gas bubble in liquid phase in horizontal separator.
Fig .2- 5.The liquid droplet in gas phase and gas bubble in liquid phase in vertical separator.
2.6: Factors Affecting Separation
Characteristics of the flow stream will greatly affect the design and operation of a separator. The following
factors must be determined before separator design:
• Gas and liquid flow rates (minimum, average, and peak),
• Operating and design pressures and temperatures,
• Surging or slugging tendencies of the feed streams,
• Physical properties of the fluids such as density and compressibility factor,
• Designed degree of separation (e.g., removing 100% of mist greater than 10 microns of gas stream),
• Presence of impurities (paraffin, sand, scale, etc.),
• Corrosive tendencies of the liquids or gas.
• Foaming tendencies of the crude oil.
It is important to highlight that: The degree of separation is dependent on the retention time provided. Retention time is affected by the amount of liquid the separator can hold, and the rate at which the fluids enter the vessel.
2.7: Separator categories and nomenclature:
Since, separators is any device of vessel will separate a certain phase from another immiscible phase, there are many types of vessel or devices performing this function, however, their names will differ as follows:
Two- phase separator: A vessel used to separate a mixed-phase stream into gas and liquid phases that are “relatively” free of each other. Other terms used are scrubbers, knockouts, line drips, and decanters.
Flash Tank: A vessel used to separate the gas evolved from liquid flashed from a higher pressure to a lower pressure.
Line Drip: Typically used in pipelines with very high gas-to-liquid ratios to remove only free liquid from a gas stream, and not necessarily all the liquid. Line drips provide a place for free liquids to separate and accumulate.
Liquid-Liquid Separators: Two immiscible liquid phases can be separated using the same principles as for gas and liquid separators. Liquid-liquid separators are fundamentally the same as gas-liquid separators except that they must be designed for much lower velocities. Because the difference in density between two liquids is less than between gas and liquid, separation is more difficult.
Scrubber or Knockout: A vessel designed to handle streams with high gas-to-liquid ratios. The liquid is generally entrained as mist in the gas or is free-flowing along the pipe wall. These vessels usually have a small liquid collection section. The terms are often used interchangeably.
Slug Catcher: A particular separator design able to absorb sustained in-flow of large liquid volumes at irregular intervals.
Usually found on gas gathering systems or other two phase pipeline systems. A slug catcher may be a single large vessel or a manifolded system of pipes.
Three Phase Separator: A vessel used to separate gas and two immiscible liquids of different densities (e.g. gas, water, and oil).
Filter Separators: A filter separator usually has two compartments.
The first compartment contains filter-coalescing elements. As the gas flows through the elements, the liquid particles coalesce into larger droplets and when the droplets reach sufficient size, the gas flow causes them to flow out of the filter elements into the center core. The particles are then carried into the second compartment of the vessel (containing a vane-type or knitted wire mesh mist extractor) where the larger droplets are removed. A lower barrel or boot may be used for surge or storage of the removed liquid.
Functional Sections of a Gas-Liquid Separator
Regardless of the size or shape of a separator, each gas-liquid separator contains four major sections. Figures 2-7 and 2-8 illustrate the four major sections of a horizontal and vertical two-phase separator, respectively.
Fig .2- 6.Gas liquid separation selection map.
Inlet Diverter Section
The inlet stream to the separator is typically a high-velocity turbulent mixture of gas and liquid. Due to the high velocity, the fluids enter the separator with a high momentum. Collision or abruptly changes the direction of flow by absorbing the momentum of the liquid and allowing the liquid and gas to separate. This results in the initial “gross” separation of liquid and gas. The inlet diverter, sometimes referred to as the primary separation section. Therefor this section is used to reduce the momentum of the inlet flow stream, perform an initial bulk separate ion of the gas and liquid phases, and enhance gas flow distribution. There are varieties of inlet devices available and these will be discussed in more detail in a later section.
Liquid Collection Section
The liquid collection section, located at the bottom of the vessel, it acts as a receiver for all liquid removed from the gas in the inlet, gas gravity, and mist extraction sections. The liquid collection section provides the required retention time necessary for any entrained gas in the liquid to escape to the gravity settling section. In addition, it provides a surge volume to handle intermittent slugs. In three-phase separation applications, the liquid gravity section also provides residence time to allow for separation of water droplets from a lighter hydrocarbon liquid phase and vice-versa. Due to the smaller difference in gravity between crude oil and water, compared to gas and liquid in two-phase separation, Liquid-liquid separation requires longer retention times than gas-liquid separation.
Also in in three phase separators, a coalescing packs are sometimes used to promote hydrocarbon liquid – water separation, though they should not be used in applications that are prone to plugging, e.g. wax, sand, etc.
Gravity Settling Section
As the gas stream enters the gravity settling section, its velocity drops and small liquid droplets that were entrained in the gas and not separated by the inlet diverter are separated out by gravity and fall to the gas liquid interface, preconditioning the gas for final polishing by the mist extractor.
. The gravity settling section is sized so that liquid droplets greater than 100 to 140 microns fall to the gas-liquid interface while smaller liquid droplets remain with the gas. Liquid droplets greater than 100 to 140 microns are undesirable as they can overload the mist extractor at the separator outlet.
In some horizontal designs, straightening vanes are used to reduce turbulence. The vanes also act as droplet coalescers, which reduces the horizontal length required for droplet removal from the gas stream.
Mist Extractor Section
Gas leaving the gravity settling section contains small liquid droplets, generally less than 100 to 140 microns. Before the gas leaves the vessel, it passes through a coalescing section or mist extractor. This section uses coalescing elements that provide a large amount of surface area used to coalesce and remove the small droplets of liquid. As the gas flows through the coalescing elements, it must make numerous directional changes. Due to their greater mass, the liquid droplets cannot follow the rapid changes in direction of flow. These droplets impinge and collect on the coalescing elements, where they fall to the liquid collection section. Quoted liquid carryover from the various types of mist extraction devices are usually in the range of 0.1 – 1 gal/MMscf.
Fig .2- 7.Horizontal Separator sections with gas bubble in liquid phase, and liquid droplet in gas phase.
Factors to be considered for separator configuration selection include:
• What separation quality is required by downstream equipment and processes?
• How well will extraneous material (e.g. sand, mud, corrosion products) be handled?
• How much plot space will be required?
• Will the separator be too tall for transport if skidded?
• Is there enough interface surface for 3-phase separation (e.g. gas/hydrocarbon/glycol liquid)?
• Can heating coils or sand jets be incorporated if required?
• How much surface area is available for degassing of separated liquid?
• Must surges in liquid flow be handled without large changes in level?
• Is large liquid retention volume necessary?
• What are the heat retention requirements (e.g. freeze protection)?
Fig .2- 8.Vertical Separator sections with gas bubble in liquid phase and liquid droplet in gas phase.