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Oil and gas separators
An oil/gas separator is a pressure vessel used for separating well fluids produced from oil and gas wells into gaseous and liquid components.
Other separator names
Conventional oil/gas separator names:
- Oil/gas separator
- Stage separator
These separating vessels are normally used on a producing lease or platform near a wellhead, manifold, or tank battery to separate fluids produced from oil/gas wells into oil/gas or liquid/gas. They must be capable of handling “slugs” or “heads” of well fluids. Therefore, they are usually sized to handle the highest instantaneous rates of flow.
Flash chamber, flash vessel, or flash trap
A flash chamber (trap or vessel) normally refers to a conventional oil/gas separator operated at low pressure, with the liquid from a higher-pressure separator being partially vaporized or “flashed” into it. This flash chamber is quite often the second or third stage of separation, with
Expansion separator or expansion vessel
An expansion vessel is the first-stage separator on a low-temperature or cold-separation unit. This vessel may be equipped with a heating coil to melt hydrates, or a hydrate-preventing liquid (such as glycol) may be injected into the well fluid just before expansion into this vessel.
Scrubber (gas scrubber), dry or wet type
A gas scrubber is similar to an oil/gas separator. Usually, it handles fluid that contains less liquid than that produced from oil/gas wells. Where they are not required to handle slugs or heads of liquid, as is often the case with oil/gas separators, gas scrubbers are normally used in:
- Compressor trains
- Gas gathering
- Distribution lines
The dry-type gas scrubber uses mist extractors and other internals similar to oil/gas separators with preference shown to the coalescing-type mist extractor. The wet-type gas scrubber passes the stream of gas through a bath of oil or other liquid that washes dust and other impurities from the gas. The gas is flowed through a mist extractor, in which all removable liquid is separated from it. A “scrubber” can refer to a vessel used upstream from any gas-processing vessel or unit to protect the downstream vessel or unit from liquid hydrocarbons and/or water.
Filter (gas filter), dry or wet type or Filter/separator
The “filter” (gas filter or filter/separator) refers to a dry-type gas scrubber, especially if the unit is being used primarily to remove dust from the gas stream. A filtering medium is used in the vessel to remove liquids and solids from the gas. A gas/liquid filter generally follows a scrubber to remove fine liquid drops. Separators are also classified by their design process conditions, which are shown in Table 2.
Knockout vessel, knockout drum, knockout trap, water knockout, or liquid knockout
In the case of a water knockout for use near the wellhead, the gas and liquid petroleum are usually discharged together, and the free water is separated and discharged from the bottom of the vessel. A liquid knockout is also used to remove all liquid (oil plus water) from the gas. The water and liquid hydrocarbons are discharged together from the bottom of the vessel, and the gas is discharged from the top. also known as:
An oil/gas separator generally consists of essential components and features:
- A vessel that includes a primary separation device and/or section; secondary “gravity” settling (separating) section; mist extractor to remove small liquid particles from the gas; gas outlet; liquid settling (separating) section to remove gas from liquids, to separate water from oil, and to separate solids from the liquids; and oil outlet and water outlet.
- Adequate volumetric liquid capacity to handle liquid surges (slugs) from the wells and/or flow lines.
- Adequate vessel diameter and height or length to allow most of the liquid to separate from the gas so that the mist extractor will not be flooded.
- A means of controlling oil/water levels in the separator, which usually includes a liquid-level controller and a control valve on the oil/water outlets.
- A backpressure valve on the gas outlet to maintain a steady pressure in the vessel.
- Pressure relief devices.
In most oil/gas surface production equipment systems, the oil/gas separator is the first vessel the well fluid flows through after it leaves the producing well. However, other equipment such as heaters may be installed upstream of the separator.
Function of a separator
The primary functions of an oil/gas separator, along with separation methods, are summarized in Table 1.
Requirements of separators
Separators are required to provide oil/gas streams that meet saleable pipeline specification as well as disposal.
- Oil must have less than 1% (by volume) water and less than 5 lbm water/MMscf gas.
- Water stream must have less than 20 ppm oil for overboard discharge in the Gulf of Mexico (GOM).
Stage recovery of liquid hydrocarbons - Staged separation (depressurization) - to maximize the liquid hydrocarbon volumes Fig. 1 shows a typical deepwater GOM process train. There are four stages of depressurization:
- high pressure (HP)
- intermediate pressure (IP)
- free water knockout (FWKO)
- the degasser/bulk oil treater (BOT) combination
Bulk water is removed in the third stage, FWKO, and final dewatering is accomplished in the BOT. In the North Sea and other locations, water may be removed in the HP and/or IP vessels. The BOT is typically an electrostatic treater. Sometimes, the BOT will include a degassing section, eliminating the need for a separate degasser vessel. Typical deepwater GOM platform pressures for degrasser stages are:
- 1,500 psig for HP
- 700 psig for IP
- 250 psig for IP
- 50 psig for FWKO
Protection of pumps and compressors
Booster compressor unit
Fig. 2 shows the associated booster compressor unit
Fig. 3 the glycol dehydration unit. Both systems make use of separators as a major component in their design.
Table 3 compares the advantages and disadvantages of vertical and horizontal separators. This table should be used as a guideline in selection.
The separators are typically sized by the settling theory or retention time for the liquid phase. More details show on the separator sizing page.
Separation performance depends on many factors, such as:
- Flow rates
- Fluid properties
The gas capacity of most gas/liquid separation equipment is sized on the basis of removing a certain size drop. The main unknown is the incoming drop-size distribution. Without this, the effluent quality cannot realistically be estimated. For example, a specification that the gas outlet should have less than 0.1 gal/MMscf liquid is somewhat difficult to guarantee because of the unknown drop-size distribution. Pressure drops across upstream piping components and equipment can create very small drops (1 to 10 μm) while coalescence in piping and inlet devices can create larger drops. A removal drop size of 10 μm for scrubbers is more realistic to specify. The same discussion applies to water-in-oil and oil-in-water specifications. To the author’s knowledge, a correlation is not available to predict water-in-oil or oil-in-water concentrations. For example, prediction of whether a separator can produce an oil stream with less than 20%v water is generally based on experience or analogous separators.
The liquid capacity of most separators is sized to provide enough retention time to allow gas bubbles to form and separate out. More retention time is needed for separators that are designed to separate oil from water, as well as gas from liquid (three-phase compared to two-phase separators).
A major factor in separator performance is the internals that can affect:
- Flow distribution
- Drop/bubble shearing and coalescence
- Foam creation
- Level control
The separator or scrubber is generally divided into three zones:
Some type of inlet device is needed to obtain an initial bulk separation of liquid/gas. In most cases, gas will have already come out of solution in the pipeline, leading to the separator (because of pressure drop across an upstream choke or control valve). Hence, the majority of the gas is separated from the liquid in the inlet zone. Because of foaming issues and the need for higher capacities, cyclonic inlets are now becoming more widely used. For applications of inlet momentum typically less than 9 kPa, a vane inlet can be used. Typical inexpensive inlets include:
- Flat impact plates
- Dished-head plates
- Half-open pipes
- Open pipes directed at vessel heads
These inlets, although inexpensive, may have the shortcoming of negatively affecting separation performance. However, for higher-momentum fluids, these inlets can cause problems. The flat or dished-head plates can result in small drops and foam. The open-pipe designs can lead to fluid short-circuiting or channeling. Although inlet momentum is a good starting guideline for selection, the process conditions, as well as the demister choice, should also be considered. For example, if the liquid loading is low enough that a demister can handle all the liquid, then inlet devices can be applied beyond their typical momentum ranges.
Regardless of the size of the vessel, short-circuiting can result in poor separation efficiency. Integral to any inlet device is a flow straightener such as a single perforated baffle plate. A full-diameter plate allows the gas/liquid to flow more uniformly after leaving the vane-type inlet, inlet cyclones, or even the impact plates. The plate also acts as an impingement demister and foam breaker as well. Typical net-free area (NFA) ranges in the 10 to 50% range. As the NFA lowers, the shear of the fluids gets higher, so the NFA should be matched to the particular application. One concern of these plates is solids buildup on the upstream side. Generally, the velocities are high enough in the inlet zone to carry the solids through the perforations. In any case, a flush nozzle should be installed in the inlet zone. Other designs include flow straightening vanes. However, the open area is generally too high to be effective.
To assist in coalescing (and foam breaking), mesh, vanes, and/or plate/matrix packs are sometimes placed in the gas/liquid phases. These internals provide impingement or shearing surfaces for the dispersed phase. For the gas phase, matrix/plate packs and vanes have been used to aid in liquid drop coalescence or foam breaking. The theory behind installing the high surface internals such as plate packs for foam breaking is that the bubbles will stretch and break as they are dragged along the surfaces. However, if most of the gas flows through the top portion of the pack, the foamy layer will not be sufficiently sheared, and the bubbles will meander through to the other end.
Gas outlet zone
Mist capture can occur by three mechanisms; it should be kept in mind that there are no sharply defined limits between mechanisms. As the momentum of a droplet varies directly with liquid density and the cube of the diameter, heavier or larger particles tend to resist following the streamline of a flowing gas and will strike objects placed in their line of travel. This is inertial impaction, the mechanism responsible for removing most particles of diameter > 10 μm. Smaller particles that follow the streamlines may collide with the solid objects, if their distance of approach is less than their radius. This is direct impaction. It is often the governing mechanism for droplets in the 1- to 10-μm range. With submicron mists, Brownian capture becomes the dominant collection mechanism. This depends on Brownian motion—the continuous random motion of droplets in elastic collision with gas molecules. As the particles become smaller and the velocity gets lower, the Brownian capture becomes more efficient. Almost all mist elimination equipment falls into four categories:
When pressure is reduced on certain types of crude oil, tiny bubbles of gas are encased in a thin film of oil when the gas comes out of solution. This may result in foam, or froth, being dispersed in the oil and creates what is known as “foaming” oil. In other types of crude oil, the viscosity and surface tension of the oil may mechanically lock gas in the oil and can cause an effect similar to foam. Oil foam is not stable or long-lasting unless a foaming agent is present in the oil.
Whether crude oil is foamy is not well known. The presence of a surface active agent and process conditions play a part. The literature indicates organic acids as being a foaming agent. High-gravity oils and condensates typically do not result in foaming situations, as described by Callaghan et al.
Foaming greatly reduces the capacity of oil/gas separators because a much longer retention time is required to adequately separate a given quantity of foaming crude oil. Foaming crude oil cannot be measured accurately with positive-displacement meters or with conventional volumetric metering vessels. These problems, combined with the potential loss of oil/gas because of improper separation, emphasize the need for special equipment and procedures in handling foaming crude oil.
The main factors that assist in “breaking” foaming oil are:
- Agitation (baffling)
- Centrifugal force
These factors or methods of “reducing” or “breaking” foaming oil are also used to remove entrained gas from oil. Many different designs of separators for handling foaming crude oil have evolved. They are available from various manufacturers—some as standard foam handling units and some designed especially for a specific application.
Silicone- and fluorosilicone-based chemical defoamers are typically used in conjunction with cyclonic inlets to break foam. The chemical defoamer concentration is generally in the range of 5 to 10 ppm, but for many GOM crudes, 50 to 100 ppm is common.
Fig. 16 is a gamma ray scan of a 48-in.-diameter horizontal gas separator showing the problems resulting from foam. The horizontal axis is signal strength, and the vertical axis is height within the separator. High signal strength indicates less mass or more gas. Less signal strength indicates more mass or liquid. As the chemical rate is decreased, the interface between gas/liquid becomes less defined. The bottom of the vessel becomes gassy (more signal), while the upper portion becomes foamy (less signal). Liquid carryover occurs as the foam is swept through the demister. Gas carry-under occurs as the bubbles cannot be separated.
Fig. 17 shows a horizontal separator used to process foamy crudes. The fluids flow through inlet cyclones, where the centrifugal action helps break the large bubbles. A perforated plate downstream of the inlet cyclones aids in promoting uniform flow as well as demisting and defoaming. Demisting cyclones in the gas outlet remove large amounts of the liquid that results from a foamy oil layer. The foamy oil pad results from the small bubbles that cannot be removed in the inlet cyclones.
In between the perforated plate and the demister, high-surface internals such as plate or matrix packs are sometimes installed to break the large bubbles. As previously discussed, the theory behind the high-surface internals is that the bubbles will stretch and break as they are dragged along the surfaces. However, if most of the gas flows through the top portion of the pack, the foamy layer will not be sufficiently sheared, and the bubbles will meander through to the other end.
Paraffin deposition in oil/gas separators reduces their efficiency and may render them inoperable by partially filling the vessel and/or blocking the mist extractor and fluid passages. Paraffin can be effectively removed from separators by use of steam or solvents. However, the best solution is to prevent initial deposition in the vessel by heat or chemical treatment of the fluid upstream of the separator. Another deterrent, successful in most instances, involves the coating of all internal surfaces of the separator with a plastic for which paraffin has little or no affinity. The weight of the paraffin causes it to slough off of the coated surface before it builds up to a harmful thickness.
In general, paraffinic oils are not a problem when the operating temperature is above the cloud point (temperature at which paraffin crystals begin to form). The problems arise, however, during a shutdown, when the oil has a chance to cool. paraffin comes out of solution and plates surfaces. When production is restored, the incoming fluid may not be able to flow to the plated areas to dissolve the paraffin. In addition, temperatures higher than the cloud point are required to dissolve the paraffin.
Solids and salt
If sand and other solids are continuously produced in appreciable quantities with well fluids, they should be removed before the fluids enter the pipelines. Salt may be removed by mixing water with the oil, and after the salt is dissolved, the water can be separated from the oil and drained from the system.
Vertical vessels are well suited for solids removal because of the small collection area. The vessel bottom can also be cone-shaped, with water jets to assist in the solids removal. In horizontal vessels, sand jets and suction nozzles are placed along the bottom of the vessel, typically every 5 to 8 ft. Inverted troughs may be placed on top of the suction nozzles as well to keep the nozzles from plugging. A sand-jet system is shown in Fig. 18. This type of system is sometimes difficult to use while the vessel is in operation because of the effect of the jetting and suction on separation and level control. For vessels that must be designed to enable sand jetting while in service, see the discussion on Emulsion Treating.
Produced well fluids can be very corrosive and cause early failure of equipment. The two most corrosive elements are hydrogen sulfide and carbon dioxide. These two gases may be present in the well fluids in quantities from a trace up to 40 to 50% of the gas by volume. A discussion of corrosion in pressure vessels is included in the page of water treating.
Because of the action of waves or current on a floating structure, some excitation of the separator liquid contents will occur, resulting in internal fluid sloshing motions. It is particularly a problem in long horizontal separators. Sloshing degrades the separation efficiency through additional mixing, resulting in liquid carry-over in the gas line, gas carry-under in the liquid line, and loss of level control. In three-phase separators, oil/water and gas/liquid separation efficiency is degraded. It is therefore necessary to design internal baffle systems to limit sloshing. Emphasis is generally placed on internals for wave dampening in gas-capped separators because of the larger fluid motions.
The liquid level changes from end to end must be considered in the design of the inlet and outlet devices. Too low a liquid level can result in gas blow-by of inlet cyclones, whereas too high a liquid level can cause siphoning of liquid through the mist extractor.
Table 4 gives some estimates of the natural period of the liquid for vessels undergoing lengthwise motions (sway). The periods are in the order of 10s, which is similar to the period found for floating platforms such as tension leg platforms (TLP) and floating production, storage and offloading (FPSO) vessels under a 10-year storm condition.
The alignment of the separators with the structure motion should be considered when designing the layout. For example, on TLP, the vessels are recommended to be aligned with their long dimension, perpendicular to the TLP prevailing motion. On ships, the magnitude and period of the pitch and roll should be considered when aligning the vessels. Normally, it is recommended to align the separators with their long dimension along the length of the ship.
The available literature, as described by Roberts et al., highlights two main features of wave-damping internals:
- Elimination of the gas/liquid interface
- Shifting of the natural sloshing frequency of the separator away from the platform frequency
On some ships, fuel tanks fill with sea water, as the fuel is spent, to prevent problems associated with sloshing.
Shifting the natural frequency is usually accomplished by segmenting the vessel with transverse baffles. The baffles are perforated, can be placed throughout the liquid phase, or can be placed in the region of the oil/water interface. However the following are major concerns:
- Vessel access
- Solids collection
- Mixing are major concerns
Horizontal perimeter baffles can be used, but they have disadvantages as well. Other baffle shapes include angled wings along the length of the vessel to mitigate waves because of roll as well as vertical perforated baffles down the length of the vessel. Table 5 highlights the differences between horizontal and vertical baffles.
Stable control of the oil/water and gas/oil interfaces is important for good separation. The typical two-phase separator level settings are shown in Table 6. For three-phase operation, level settings are placed on both the oil/water interface and oil/gas interface levels.
Typically, the spacing between the different levels is at least 4 to 6 in. or a minimum of 10 to 20 seconds of retention time. The location of the lowest levels must also consider sand/solids settling. These levels are typically 6 to 12 in. from the vessel bottom. Minimum water/oil pad thicknesses are approximately 12 in. Note that these minimum settings may dominate the vessel sizing as opposed to the specified retention times.
In a two- or three-phase horizontal separator with very little liquid/water, a boot or “double-barrel” separator configuration is used. All the interface controls are then located within the boot or lower barrel. Examples of these types of separators can be seen at Separator types.
To coerce the liquid to exit through the tube-wall gap, a slipstream of gas is also withdrawn. The slipstream is induced to exit through the gap by maintaining a lower pressure in the outer annular space than that which is inside the tubes. This is done by constructing ducts between the annular space and the hollow core pieces of all the spin generators. The tails of these hollow cores are, in turn, open to the low pressure of the newly generated gas vortices. A gas slipstream of about 5% is recycled out of the tubes to pull liquid out, then back to the spin generator and out its tail end, where it joins the main gas stream.
|ρc||=||continuous phase density, kg/m3;|
|μc||=||continuous phase dynamic viscosity, kg/(m∙s) or N∙s/m2;|
|Vc||=||continuous phase velocity, m/s;|
|Vr||=||drop/rise velocity, m/s;|
|Vh||=||horizontal water velocity, m/s;|
|L||=||plate-pack length, m;|
|dpp||=||plate-pack perpendicular gas spacing, m.|
|ρw||=||water density, kg/m3;|
|ρo||=||oil density, kg/m3;|
|μw||=||water dynamic viscosity, kg/(m∙s) or N∙s/m2;|
|g||=||gravitational acceleration, 9.81 m/s2;|
|Do||=||drop diameter, cm.|
|Vm||=||design velocity, m/s;|
|ρg||=||gas-phase density, kg/m3;|
|ρl||=||liquid-phase density, kg/m3;|
|K||=||mesh capacity factor, m/s.|
- Callaghan, I.C., McKechnie, A.L., Ray, J.E. et al. 1985. Identification of Crude Oil Components Responsible for Foaming. SPE J. 25 (2): 171–175. SPE-12342-PA. http://dx.doi.org/10.2118/12342-PA.
- Roberts, J.R., Basurto, E.R., and Chen, P.Y. 1966. Slosh Design Handbook I, NASA-CR-406, Contract No. NAS 8-11111. Huntsville, Alabama: Northrop Space Laboratories.
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read