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PEH:Oil and Gas Separators

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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume III – Facilities and Construction Engineering

Kenneth E. Arnold, Editor

Chapter 2 – Oil and Gas Separators

Robert W. Chin, CDS Separation Technologies Inc.

Pgs. 13-59

ISBN 978-1-55563-118-5
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This chapter is a discussion of the design of two- and three-phase gas/liquid separators used in the oil/gas industry. Vertical and horizontal configurations are considered. Various internals to enhance gas/liquid and liquid/liquid separation are described. Level control and platform motion issues are also discussed. This chapter presents typical equations for sizing the vessels along with worked examples.



The term "oil/gas separator" in petroleum terminology designates a pressure vessel used for separating well fluids produced from oil/gas wells into gaseous and liquid components. Separation is required for stage recovery of liquid hydrocarbons, producing saleable oil and gas streams, well testing, metering, and protection of pumps and compressors.

Separators are required to provide oil/gas streams that meet saleable pipeline specifications, as well as a water/solids stream for disposal. Typically, the oil must have less than 1% (by volume) water and less than 5 lbm water/MMscf gas. The water stream must have less than 29 ppm oil for overboard discharge in the Gulf of Mexico (GOM). Staged separation (depressurization) is required to maximize the liquid hydrocarbon volumes.

Fig. 2.1 shows a typical deepwater GOM process train. There are four stages of depressurization: high pressure (HP), intermediate pressure (IP), free water knockout (FWKO), and 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 are 1,500, 700, 250, and 50 psig for the HP, IP, FWKO, and degasser stages, respectively. Fig. 2.2 shows the associated booster compressor unit and Fig. 2.3 the glycol dehydration unit. Both systems make use of separators as a major component in their design. The separation equipment associated with water cleanup, such as hydrocyclones and flotation cells, is not shown. Additional descriptions of production facilities can be found in Arnold and Stewart[1].

The primary functions of an oil/gas separator, along with separation methods, are summarized in Table 2.1. A separating vessel also may be referred to in the following ways: oil/gas separator; separator; stage separator; trap; knockout vessel, knockout drum, knockout trap, water knockout, or liquid knockout; flash chamber, flash vessel, or flash trap; expansion separator or expansion vessel; scrubber (gas scrubber), dry or wet type; filter (gas filter), dry or wet type; and filter/separator.

The terms "oil/gas separator," "separator," "stage separator," and "trap" refer to a conventional oil/gas 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.

A knockout vessel, drum, or trap may be used to remove only water from the well fluid or to remove all liquid (oil plus water) from the gas. 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.

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 the liquid being discharged from the flash chamber to storage.

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.

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. Gas scrubbers are normally used in compressor trains, gas gathering, sales, and distribution lines, where they are not required to handle slugs or heads of liquid, as is often the case with oil/gas separators. 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.

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 2.2.

Well Fluids and their Characteristics

This section outlines some of the physical characteristics of well fluids handled by oil/gas separators.

Crude Oil. Crude oil is a complex mixture of hydrocarbons produced in liquid form. The American Petroleum Inst. (API) gravity of crude oil can range from 6 to 50° API and viscosity from 5 to 90,000 cp at average operating conditions. Viscosities are nearly always smaller in the reservoir. Color varies through shades of green, yellow, brown, and black.

Condensate. This is a hydrocarbon that may exist in the producing formation either as a liquid or as a condensable vapor. Liquefaction of gaseous components of the condensate usually occurs with reduction of well-fluid temperature to surface operating conditions. Gravities of the condensed liquids may range from 50 to 120° API and viscosities from 2 to 6 cp at standard conditions. Color may be water-white, light yellow, or light blue.

Natural Gas. A gas is a substance that has no shape or volume of its own. It will completely fill any container in which it is placed and will take the shape of the container. Hydrocarbon gas, associated with crude oil, is referred to as natural gas and may be found as "free" gas or as "solution" gas. Specific gravity of natural gas may vary from 0.55 to 0.90 and viscosity from 0.01 to 0.024 cp at standard conditions.

Free Gas. Free gas is a hydrocarbon that exists in the gaseous phase at operating pressure and temperature. Free gas may refer to any gas at any pressure that is not in solution or mechanically held in the liquid hydrocarbon.

Solution Gas. Solution gas is homogeneously contained in oil at a given pressure and temperature. A reduction in pressure and/or an increase in temperature may cause the gas to be evolved from the oil, whereupon it assumes the characteristics of free gas.

Condensable Vapors. These hydrocarbons exist as vapor at certain pressures and temperatures and as liquid at other pressures and temperatures. In the vapor phase, they assume the general characteristics of a gas. In the vapor phase, condensable vapors vary in specific gravity from 0.55 to 4.91 (air = 1.0), and in viscosity from 0.006 to 0.011 cp at standard conditions.

Water. Water produced with crude oil and natural gas may be in the form of vapor or liquid. The liquid water may be free or emulsified. Free water reaches the surface separated from the liquid hydrocarbon. Emulsified water is dispersed as droplets in the liquid hydrocarbon. The water may be fresh or briny in nature and may contain undesirable gases such as CO2.

Impurities and Extraneous Materials. Produced well fluids may contain such gaseous impurities as nitrogen, carbon dioxide, hydrogen sulfide, and other gases that are not hydrocarbon in nature or origin. Well fluids may contain liquid or semiliquid impurities such as water and paraffin. They may also contain solid impurities, such as drilling mud, sand, silt, and salt.

Separator Components

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.

Separator Orientation

Table 2.3 compares the advantages and disadvantages of vertical and horizontal separators. This table should be used as a guideline in selection.

Separator Performance

Separation performance depends on many factors, such as flow rates, fluid properties, internals, etc. 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, mixing, and level control. The separator or scrubber is generally divided into three zones: inlet, gravity/coalescing, and outlet. Various types of internals for these three zones are discussed next.

Inlet Zone. General. 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.

Inlets to production vessels have received less attention and "science" than the gas outlets. The main concept involves impacting the inlet stream on a surface, causing a momentum change, enabling the liquid droplets to fall and the gas bubbles to rise. Typical inlets, as depicted in Fig. 2.4, are flat impact plates, dished-head plates, half-open pipes, and open pipes directed at vessel heads.

These inlets, although inexpensive, may have the shortcoming of negatively affecting separation performance. The inlets previously mentioned are more appropriate for handling low-momentum fluids (momentum is density times velocity). 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.

Inlet Cyclones. In recent years, because of foaming issues and the need for higher capacities, cyclonic inlets are now becoming more widely used. See Figs. 2.5a , 2.5b , and 2.6 for typical examples. The advantages of a cyclonic or vortex inlet are high allowable inlet momentums, defoaming characteristics, liquid/liquid coalescing benefits, gas demisting benefits, and high liquid levels.

The inlet cyclone can be used with inlet momentums, a factor of 10 higher than pipe inlets. Typically, pipe inlets are used for momentums (ρV2, where ρ is bulk density, kg/m3, and V is bulk velocity, m/s) less than 1,000 Pa. Inlet cyclones have been used successfully to 65,000 Pa. Although ρV2 is energy, it is referred to as (transport of) momentum.

Because of the centrifugal flow, large foam bubbles are broken, liquid drops are removed from the gas phase, and liquid/liquid coalescence occurs within the cyclone. A problem with some cyclones is that a poorly designed liquid outlet can shear the liquids, offsetting the benefits of the coalescence and possibly making the situation worse. For cases in which a high liquid level is required in the separator, the inlet cyclone can be submerged up to the gas outlet level.

Depending on the flow rates, more than one cyclone tube may be required to rapidly degas the oil. This allows the use of a shorter oil retention time. Degassing is rapid, and large bubble foam is minimized or eliminated. Without the cyclonic inlet, foam can occupy a considerable volume in the separator. The use of a cyclonic inlet often allows foam to be ignored as a sizing consideration. Thus, for high-capacity crude-oil separators (which are the ones most limited by foam), the cyclone inlet can significantly reduce the required vessel liquid and foam holdup volume, size, weight, and cost.

A cyclone/vortex tube cluster, shown in Fig. 2.5, is a separator internal device that can be part of the original separator design or may be retrofitted into existing separators to increase capacity. In Fig. 2.5a, fluids enter the cyclones from a top shell side inlet nozzle and are split to the different cyclones. In Fig. 2.5b, incoming process fluids are accelerated in the manifold to a desired velocity. Each tube peels off a portion of that stream, which enters the tube tangentially, generating rotational flow. In both cases, within each tube, the swirling fluids create a high force for separation of gas/liquid. The gas accumulates in the center, forming a gas core, exits through an orifice in the top of the tube, and flows into the separator gas phase. Liquids are slung to the tube wall, where they migrate downward as a continuous sheet. They exit the tube through a peripheral gap in the tube wall at the bottom and flow out into the separator liquid bath, in which the bottoms of the tubes are submerged.

Fig. 2.6 shows two different types of inlet cyclones. One cyclone has a simple tangential inlet with or without a gas vortex finder. In cyclones without a vortex finder, gas can escape quickly out the top. This has two effects: the loss of gas yields a lower centrifugal acceleration within the cyclone, and as the gas leaves the top, it carries liquid with it as well as shearing the liquid. More mist is generated, which may impact the downstream demister. With a tangential inlet, the fluids may also circle back on the inlet, disrupting the incoming flow. The bottom of the cyclone is submerged below a liquid level to prevent gas from blowing out the bottom (blow-by). A simple flat plate baffle beneath the liquid outlet spreads the flow out radially.

The other cyclone has stationary turbine blades used to provide spin. This has the advantage of lowering the shear on the fluids. Lower shear results in less mist generation and droplet shearing. In the liquid section, the liquid outlet with proprietary internals is designed to prevent gas from escaping. The bottom of the cyclone also provides some backpressure through low shear channel flow or a perforated cylinder. This additional backpressure allows the cyclone to operate at higher gas capacities than the first cyclone and, hence, with higher centrifugal accelerations. A bottom flat plate, in conjunction with the perforated cylinder, spreads the liquid flow out more uniformly.

The cyclonic-type inlet device is used to diffuse the momentum of the incoming feed stream and allows for the removal of any bulk liquids and solids that may be present. The cyclonic inlet device is designed such that it can operate at both high and low gas/oil ratios without the possibility of gas blow-by and excessive liquid re-entrainment into the gas phase.

The main characteristics to look for in an inlet cyclone are listed next.
  • High liquid drainage capacity: This is necessary to prevent internal "choking" of the cyclone. In this case, the liquid carryover into the gas phase will be excessive, which could cause too high a liquid load on the downstream devices. Also, there would be considerable disruption to the internal flow field, which means the cyclone will not operate correctly.
  • Low re-entrainment of liquid into the gas phase: This means that the downstream mist eliminating devices will not be overloaded. Also, the mist eliminating section will be working optimally; therefore, the best separation performance from the separator can be realized.
  • Liquid re-entrainment: The main cause of liquid re-entrainment within the gas phase is "creep" that is caused by internal pressure differences causing liquid to move along internal surfaces. Within the cyclone, the effect of creep can be minimized by use of rings located around the gas vortex finder.
  • Low shear forces on the re-entrained liquids in the gas: Low shear forces are beneficial, given that the droplet distribution of the re-entrained liquids leaving the cyclone is not too fine. The finer the droplets, the more difficult it becomes for the downstream mist eliminating section to remove them—hence, the overall liquid carryover from the separator increases.
  • Low shear forces on the dispersed phase within the liquid outlet: Low shear forces are beneficial in that the droplet distribution of the dispersed phase liquid leaving the cyclone is not too small and does not form an emulsion. As the droplets get finer, it becomes more difficult for the downstream gravity settling devices to coalesce and remove them; hence, more is carried over in the exiting streams. This can be accomplished by ensuring that the liquid flow channels within the cyclone are relatively large and that any perforated holes are of the correct size to minimize shear.
  • Minimum gas blow-by to the liquid outlet: Gas blow-by is seen when gas exits with the liquid phase from the bottom of the cyclone. If the amount of gas is considerable, a bubbling mass of liquid/gas is formed, which has a negative effect because of foam generation and mixing.

Care must be taken when designing inlet cyclones for separators. Cyclones are designed on the basis of a pressure balance between the pressure drop needed to force the gas up and out the top of the cyclone and that required to push the liquid out the bottom of the cyclone. If the gas pressure drop is higher than the liquid pressure drop, the liquid level inside the cyclone will be lower than that of the level of the surrounding liquid in the separator and vice versa. Flow rate turndown and changes in producing gas-to-oil ratio (GOR) then play important roles in the determination of the operating range of the cyclones. For example, cyclones may be properly designed for, say, 50,000 B/D of liquids at 1,000 GOR. However, if the GOR is actually 1,500, gas may blow out the bottom of the cyclones and create foam throughout the separator.

Vane Inlet. For applications of inlet momentum typically less than 9 kPa, a vane inlet can be used. Fig. 2.7 shows a typical vane inlet.

The fluids are "sliced" off to either side while flowing through the inlet device. The spacing between the blades typically has been designed using computational fluid dynamics (CFD) to achieve uniform flow. Because the area of the vane inlet is several times larger than the inlet nozzle, the fluid velocities are much smaller, allowing for good gas/liquid separation as well as smooth entry into the vessel.

Flow Distribution. 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.

Gravity/Coalescing Zone. 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 liquid/liquid coalescence in three-phase separators, FWKO, and other separators in which it is desired to have separate liquid outlets for oil/water, plate packs provide less turbulent/more laminar flow and a smaller distance over which drops have to settle. Plate packs also have been installed to promote degassing.

Laminar flow is indicated by the flow Reynolds number, which is defined as
ρc = continuous phase density, kg/m3;
μc = continuous phase dynamic viscosity, kg/(m∙s) or N∙s/m2;
Vc = continuous phase velocity, m/s;
dh = hydraulic diameter.

For a plate pack with a perpendicular gap spacing of dpp, the hydraulic diameter is approximately equal to 2 dpp. Transition to turbulent flow occurs in the Re range of 1,000 to 1,500.

To determine the drop size that can be removed, consider the schematic in Fig. 2.8 of an oil droplet rising in a waterflow between plates. The distance a drop has to settle is dpp/cos(α), where dpp is the perpendicular spacing of the plate, and α is the inclination angle. For liquids with "nonsticky" solids, the plate spacing and the angle of inclination can be increased to mitigate plugging.

For the plate pack to be effective, the drop must reach the plate before exiting the pack. A ballistic model of the drop results in
Vr = drop/rise velocity, m/s;
Vh = horizontal water velocity, m/s;
L = plate-pack length, m;
dpp = plate-pack perpendicular gas spacing, m.

For a low-drop Reynolds number, the drop/rise velocity is given by Stokes’ law, which is written as

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.

For a higher-drop Reynolds number, a more general form of Eq. 2.3 can be used. For a given plate-pack geometry and fluid conditions, the minimum drop that can be removed by the plate pack is obtained from Eqs. 2.2 and 2.3.
For water drops in oil, the water viscosity in Eq. 2.4 is replaced with the oil viscosity, and the horizontal velocity is that of the oil phase. Typical design drop size removal in plate packs is approximately 50 μm.

Other designs use mesh and matrix packing for liquid/liquid coalescing. However, plugging issues should be addressed when selecting the coalescer. In general, if solids are present in significant quantities, no coalescing internals are installed.

For the gas phase, matrix/plate packs and vanes have been used to aid in liquid drop coalescence or foam breaking. Vanes are discussed in the next section. 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, as shown in Fig. 2.9. 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: mesh, vanes, cyclones, and fiber-beds.

The demisters can be sealed in the liquid or within a gas box with a liquid drain sealed in the liquid. In the later case, enough space must be provided between the bottom of the gas box and the liquid level to prevent siphoning of liquid up the drain tube.

Mesh. As a vapor stream carrying entrained liquid droplets passes through a knitted mesh, the vapor moves freely through the mesh. However, the inertia of the liquid droplets causes them to contact the wire surfaces, coalesce, and ultimately drain as large droplets.

The knitted mesh can be made in various materials and densities. See Fig. 2.10. Each manufacturer has its own method of knitting the mesh, which accounts for the differences in separation efficiency. Some meshes have different materials interwoven together to account for different fluids such as glycol and condensate. Other types use layers of different styles of meshes.

For general design, the mesh area can be determined with Eq. 2.5.
Vm = design velocity, m/s;
ρg = gas-phase density, kg/m3;
ρl = liquid-phase density, kg/m3;
K = mesh capacity factor, m/s.

The recommended value of K varies and depends upon several factors such as liquid viscosity, surface tension, liquid loading, and operating pressure. Each manufacturer has its own recommended values. For general sizing, a K value of 0.1 m/s can be used as a guideline. Pressure drops are generally a few inches of water (one inch of water equals 25 Pa.)

Vane-Type Mist Extractors. Vane-type mist extractors are widely used in oil/gas separators. They can be of many designs. Fig. 2.11 shows typical single- and double-pocket vanes.

As the mist-laden gas stream passes through the parallel vane plates, it is forced to change direction several times. The mist droplets are separated by the subsequent centrifugal forces and are collected on the vane blades. The coalesced liquid film is then drained through hooks (single pockets) or slits (double pockets) on the blades.

In the double-pocket design, the liquid is more protected from being re-entrained by the gas. The double-pocket design also can be used in vertical flow, as shown in Fig. 2.11. This coalesced liquid film is then drained through slits ("double pockets") in the hollow blades, thereby reducing the gas disturbance. This leads to a higher throughput and greater efficiency in comparison with simpler vane-type separators.

The separating efficiency of a vane mist extractor depends on the number of vanes in the element, distance between the vanes, angle of the vanes, and size of liquid particles. It is claimed that this mist extractor will remove all entrained liquid droplets that are 8–10 μm and larger. However, this is generally true only for low pressures, on the order of a few hundred psi. If smaller liquid particles are present in the gas, an agglomerator should be installed upstream.

Eq. 2.5 can also be used as a guideline for sizing vane-pack areas. Typical K values are in the 0.15–0.25-m/s range.

Cyclones. Typical demisters in production vessels have generally been mesh pads and vane packs. However, axial-flow cyclones are becoming more frequently used because of their advantages: high efficiency at high pressures; high gas/liquid capacities; foam breaking; and nonfouling.

For instance, vane packs cannot remove droplets that are 10–20 μm at pressures greater than 500 to 600 psi. Additionally, cyclones have approximately 10 times the capacity of mesh pads and 4 times that of vane packs. Because of these features, the cyclones are suitable for upgrading existing vessels and for designing smaller, more compact new vessels. Because of their high centrifugal accelerations, the cyclones can be placed horizontally or vertically. Deposition is usually not a concern because of the high velocities. When cyclones are used in conjunction with mesh pads (as coalescers), high turndowns can be achieved.

Fig. 2.12 shows three types of demisting cyclones: reverse flow, nonrecycling axial flow, and recycling axial flow. In the reverse flow cyclone, flow enters tangentially around the gas outlet tube. The flow travels down, with liquid being spun to the outer wall and draining out the bottom. The gas reverses direction and flows out the inner tube.

In axial flow cyclones, a stationary turbine in the tube spins the flow. Downstream of the turbine, the liquid film is removed through slits, along with some "secondary" purge gas. The liquid drops to the bottom of a box chamber enclosing the cyclone and flows out a drain tube. The main portion of the gas flows straight out of the cyclone. For nonrecycling axial flow cyclones, the secondary gas usually must be cleaned up by a mesh pad.

In the recycling cyclone, the purge gas is educed back into the center of the cyclone through the stationary turbine. (See Fig. 2.12.) A low-pressure region exists because of the spinning flow, similar to that in a tornado. In this way, the secondary purging gas is cleaned again, and there is no need for a mesh pad. The cyclone demisters have proprietary sizing rules. Typical drop size removal is approximately 5 to 10 μm.

In applying centrifugal force to separation, the separator size is determined by the flow capacity, among other factors. However, the amount of separating force that can be generated at a given rotational velocity decreases as the separator diameter increases. The result is that larger, higher-capacity centrifugal monotube units are less efficient than smaller ones for removing small-entrained mist droplets.

Fig. 2.13 shows a multitubular cyclone separator, in which the flowstream is processed through a bank of parallel cyclone tubes, each tube taking a fraction of the flow. Each tube keeps a small diameter to maintain high separation efficiency. The unit shown is a recycling separator; that is, a slipstream of the gas is extracted with the liquid from the tubes and recycled to the tube inlet.

Centrifugal force may be used in conjunction with other separation mechanisms for removing oil mist from gas. As previously discussed, Fig. 2.5 shows two types of cyclone/vortex tube clusters installed in an otherwise conventional separator. Each vertical vortex tube handles a portion of the flowing stream, performing primary separation of entrained mist by means of centrifugal force. The vortex tube device is followed by a disengagement space, where any droplets of oil that have been caught and coalesced, but carried through, will rapidly settle. A mist extractor may be installed in the disengagement space, if needed.

Turndown should be considered when selecting the demister. However, it is difficult to compare turndown of cyclones, vane packs, and mesh because drop size removal is affected differently at varying gas rates.

Coalescers and Fiber Beds. For scrubbing purposes, filter coalescers merge, or coalesce, small droplets of liquid into larger drops (Fig. 2.14). Gas is forced to flow through several layers of filter media, each layer having a progressively larger mean pore opening. As droplets compete for the open pores, they coalesce, and the process continues until the larger drops continually collect and drain into a collecting sump. In addition, some coalescers have a patented oleophobic/hydrophobic treatment. Stated removal size is approximately 0.3 μm.

Fiber-bed mist eliminators use small-diameter fibers (0.02 mm) to capture the small droplets. These fiber beds use Browning diffusion or an impaction mechanism to remove drops as small as 0.1 μm. The fiber beds are typically packaged in a cylindrical shape, as shown in Fig. 2.15.

Special Problems

Foaming. 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 in Callaghan et al.[2].

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 settling, agitation (baffling), heat, chemicals, and 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. 2.16 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. 2.17 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. 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. 2.18. 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 in this section of the Handbook.

Corrosion. 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 chapter on Water Treating in this section of the Handbook.

Sloshing. 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 2.4 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 in Roberts, Basurto, and Chen[3], highlights two main features of wave-damping internals: elimination of the gas/liquid interface and 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, vessel access, solids collection, and 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 2.5 highlights the differences between horizontal and vertical baffles.

Level Controls. 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 2.6. 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 are shown in Sec. 2.2.

Some schematics of typical two- and three-phase separators are shown in Figs. 2.19 through 2.26 in horizontal and vertical orientations. All figures listed are self-explanatory.
  • Fig. 2.19: Horizontal two-phase separator with inlet diverter, perforated distribution baffle, and demister.
  • Fig. 2.20: Horizontal two-phase separator enhanced for foam breaking with inlet cyclones, perforated distribution baffle, and cyclonic demisters.
  • Fig. 2.21: Horizontal double barrel two-phase separator for low liquid rates.
  • Fig. 2.22: Horizontal three-phase separator with flooded weir.
  • Fig. 2.23: Horizontal three-phase separator with oil bucket and water weir, requiring no active interface control.
  • Fig. 2.24: Horizontal three-phase separator with boot for low water rates.
  • Fig 2.25: Vertical two-phase separator with inlet diverter and demister.
  • Fig. 2.26: Vertical three-phase separator with inlet diverter and demister.
  • Fig. 2.27a: Schematic of a central inlet separator, dual outlet designed for floaters.
  • Fig. 2.27b: Dual-inlet, central-outlet separator. The liquid level in the center of the vessel is generally constant. Hence, the liquid level changes because platform tilt does not really affect the operation of the devices in the center of the vessel.
  • Fig. 2.28a: Two-stage, vertical scrubber with inlet diverter, mesh coalescer, and cyclone demisters. This unit has a high turndown capacity (that is, the ability to operate effectively at much less than the design capacity) and a small droplet capture range. The inlet diverter removes bulk liquids. At low rates, the mesh pad acts as a separator and removes the mist. At higher gas rates, the mesh acts as an agglomerator, coalescing small drops into larger ones. The larger drops are re-entrained but caught by the cyclone demisters. Typical turndown is ~8 to 10.
  • Fig. 2.28b: Single-stage cyclone scrubber for low liquid loading. The gas/liquid flows directly at the cyclones. This type of a scrubber is a compact unit with a three to five reduction in size and weight from a standard scrubber.
  • Fig. 2.29: A schematic of a Gasunie cyclone separator. The separator is a stand-alone inlet cyclone in which the vessel shell itself is the outer wall of the cyclone. This separator is mainly used as a scrubber but can be applied for higher liquid loadings on the order of 10%v.
  • Fig. 2.30: A gas/liquid cylindrical cyclone (GLCC) is a very simple and inexpensive centrifugal separation device. Rough separation is achieved under low- g conditions, the swirl being generated by the sloped tangential inlet. The slope helps keep the level down during small slug occurrence. It is often used for bulk separation in conjunction with well testing as shown. The streams are temporarily separated, measured and analyzed, then recombined. With this arrangement, no level control is necessary because the levels are maintained by hydraulic balance.
  • Fig. 2.31: A multitube cyclone inline separator, which causes a wet gas flowstream to be divided between a number of cyclone tubes. As the gas stream enters a tube, it encounters a spin generator. The spin generator is a stationary device consisting of a hollow core and a radial arrangement of curved blades that divert the gas stream into a rotating flow pattern. In the tube downstream of the spin generator, liquid is separated from the gas by being slung out against the tube wall by centrifugal force. Near the end of each tube, the liquid film encounters a peripheral gap in the tube wall. This gap allows the liquid to be pulled out of the tube into the annular space around the tubes, where it falls to the bottom and is discharged under level control. The demisted gas stream continues through the tube, then recombines with that of the other tubes.

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.

Separator Sizing


The basic steps in separator design are listed next:

  1. Estimate diameter and length on basis of liquid requirements. Considerations of design include drop size removal, retention time, coalescers (e.g., plate packs), surge volume, levels and alarms, and motion.
  2. Calculate the gas cross-sectional area and vessel length. Considerations of design include drop size, removal, mist eliminator requirements, and velocity requirements.
  3. Select vessel diameter and length to satisfy Steps 1 and 2.
  4. Select inlet device and iterate.
  5. Separators are typically sized by the droplet settling theory or retention time for the liquid phase. For the gas phase, the settling theory or requirements of the demister are used.

Settling Theory

In gravity settling, the dispersed phase drops/bubbles will settle at a velocity determined by equating the gravity force on the drop/bubble with the drag force caused by its motion relative to the continuous phase.

In horizontal vessels, a simple ballistic model can be used to determine a relationship between vessel length and diameter. In vertical vessels, settling theory results in a relation for the vessel diameter.

Horizontal Separators. Droplet settling theory, using a ballistic model, results in the relationship shown in Eq. 2.6. For liquid drops in gas phase

d = vessel internal diameter, in.;
dm = drop diameter, μm;
hg = gas-phase space height, in.;
Fg = fractional gas cross-sectional area;
Leff = effective length of the vessel where separation occurs, ft;
T = operating temperature, °R;
Qg = gas flow rate, MMscf/D;
P = operating pressure, psia;
Z = gas compressibility;
ρl = liquid density, lbm/ft3;
ρg = gas density, lbm/ft3;
CD = drag coefficient. (See Appendix A for calculation.)

For bubbles or liquid drops in liquid phase:

dm = bubble or drop diameter, μm;
hc = continuous liquid-phase space height, in.;
Fc = fractional continuous-phase cross-sectional area;
ρd = dispersed liquid-phase density, lbm/ft3;
ρc = continuous liquid-phase density, lbm/ft3;
Qc = continuous liquid-phase flow rate, B/D.

For low Reynolds number flow, Eq. 2.7 can be further reduced to

trc = continuous-phase retention time, minutes,
μc = continuous-phase dynamic viscosity, cp,
Δγ = specific gravity difference (heavy/light) of continuous and dispersed phases.

Vertical Vessels. Settling theory results in the following relationship. For liquid drops in gas phase,
For bubbles or liquid drops in liquid phase,
Assuming low Reynolds number flow, Eq. 2.10 can be further reduced to
Drop/Bubble Sizes. If drop or bubble removal is being used for sizing, consult Table 2.7 for guidelines. Sizing the water phase by oil-drop removal is usually not effective. The water effluent quality is more likely dictated by the added chemicals. Hence, the water-phase volume is typically determined by a retention time, based on experience.

The oil drops to be removed from the gas stream also depend upon the downstream equipment. Flare scrubbers are typically designed for removal of drops that are a few hundred microns in size.

Compressor scrubbers are typically designed large enough so that a mist extractor, which can remove 10- to 20-μm drops and smaller, can fit inside the shell. Because the gas has already been conditioned by passing through an upstream separator containing a mist extractor, there is no need during normal operations to precondition the gas for the scrubber mist extractor by removing large droplets. The scrubber serves as a safety function to trap slugs of liquid that can occur as a result of failure (liquid carryover) from the upstream separator. Thus, the separator should be able to separate a slug and provide a high liquid level, which will allow the compressor to shut down prior to ingesting liquid. Normally, this is accomplished by sizing the vessel shell for a 300- to 600-μm drop removal.

Retention Time

Horizontal Vessels. The relationship of vessel diameter and length is given by

tro = oil retention time, minutes,
trw = water-retention time, minutes,
Qo = oil flow rate, B/D,
Qw = water flow rate, B/D,
Fl = fraction of vessel cross-sectional area filled by liquid.

Vertical Vessels. Similarly for vertical vessels, the relationship of vessel diameter and liquid pad heights is given by

ho = oil pad height, in.
hw = water pad height, in.

Demister Sizing

As discussed previously, many types of demisters are limited by a maximum velocity given by

Kd = demister capacity factor, ft/sec and depends upon the demister type;
Vm = maximum velocity, ft/sec;
ρL = liquid density, lbm/ft3;
ρg = gas density, lbm/ft3.

For horizontal vessels, the required demister area (Ad) is given by
For vertical vessels, Eq. 2.1 is also valid. The vessel diameter is then obtained as
For demisters (horizontal or vertical vessels) sealed in a gas box, in addition to the demister area, some height must be maintained between the bottom of the demister and the highest liquid level for the demister to drain. A pressure drop exists across the demister. If the liquid level is too high, the demister will not drain, and liquid siphoning can occur. A small hole is sometimes drilled into the drainpipe as a siphon breaker.

When using settling theory or demister sizing in horizontal vessels, one should also consider the gas velocity for re-entrainment. Too high of a gas velocity will result in liquid re-entrainment from the liquid surface, which may flood the demister and cause carryover. Typical gas velocities for re-entrainment are shown in Table 2.8.

Seam-to-Seam Length

Horizontal Vessels. The seam-to-seam length, Lss, of the vessel should be determined from the geometry once a diameter and effective length have been determined. Length must be allotted for inlet devices, gas demisters, and coalescers. For screening purposes, the following approximations can be used.
The ratio of length to diameter is typically in the 3 to 5 range.

Vertical Vessels. The seam-to-seam length of the vessel should be determined from the geometry, once a diameter and height of liquid volume are known. Allowance must be made for the inlet nozzle, space above the liquid level, gas separation section, mist extractor, and for any space below the water outlet as shown in Fig. 2.31. For screening purposes, the following approximations can be used, where d is the vessel diameter).
The ratio of height to diameter is typically in the 3 to 5 range for two-phase separators. For three-phase separators, the ratio is in the 1.5 to 3 range.

Additional consideration should be given for installation of the internals as well as man-way access. In glycol dehydration towers, a man-way is typically installed above the packing/trays and the demister. Access space must be allotted for installation of the equipment.

Nozzle Sizing

Nozzles are generally sized by momentum or velocities. Table 2.9 gives guidelines that can be used for sizing nozzles, where ρm is the bulk density and Vm the bulk velocity.

In addition, the API RP14E[4] on erosion velocity should be included. This relationship is also given by an inlet momentum criterion as ρmVm2 = C2, where C is given as 100 for continuous service and 125 for intermittent service. The value of C can also vary with pipe material, solids loading, and service. See the chapter on Piping and Pipelines in this section of the Handbook. Vortex breakers are generally required on the liquid outlets. These are typically perpendicular plates, as shown in Fig. 2.32.

Examples of Separator Sizing

Example 2.1: Vertical Two-Phase Separator With a Mesh Pad Demister

Given Values. The given values for Example 2.1 are listed next.

Gas rate 10 MMscf/D
Gas-specific gravity 0.6
Gas z-factor 0.84
Gas Density 3.7 lbm/ft3
Oil rate 2,000 B/D
Oil density 50 lbm/ft3
Operating pressure 1,000 psia
Operating temperature 60oF
Mesh pad K-factor 0.35 ft/sec
Mesh pad thickness 6 in.
Liquid-retention time 1 minute
Inlet nozzle 4 in.

Step 1. Calculate the required mesh-pad area with Eq. 2.15. This mesh area will result in a vessel internal diameter of 15 in.
Step 2. Calculate the height for liquid retention time with Eq. 2.13. ho = 74 in.
Step 3. Compute seam-to-seam length with Eq. 2.18.

The Leff /D (D = d/12) is 9.2 and is larger than the typical 3 to 5 range. Therefore, the internal diameter must be increased to reduce the Leff /D ratio. Table 2.10 shows Leff /D for three different vessel IDs. A 24-in. ID vessel has the appropriate Leff/D ratio. The selected vessel would then be 24 in. × 8 ft SS tall (after rounding up the height).

The mesh pad can be installed in two ways, if the 1.15 ft 2 is to be maintained. One, a full-diameter mesh pad can be installed with a blanking annular plate on top. Two, a cylindrical box with a 15-in. diameter can be installed around the gas outlet.

Example 2.2: Horizontal Two-Phase Separator

Size a horizontal separator to remove 100 μm drops in the gas phase.
Given Values. The given values for Example 2.2 are listed next:

Gas rate 10 MMscf/D
Gas-specific gravity 0.6
Gas z-factor 0.84
Gas density 3.7 lbm/ft3
Gas viscosity 0.012 cp
Oil rate 2,000 B/D
Oil density 50 lbm/ft3
Operating pressure 1,000 psia
Operating temperature 60 °F
Mesh pad K-factor 0.35 ft/sec
Mesh pad thickness 6 in.
Liquid retention time 1 minute
Inlet nozzle 4 in.
Vessel fill 50% (Therefore, Fg = 0.5 and hg = 0.5d.)

Step 1. Calculate vessel diameter and length with Eq. 2.6 for gas capacity.
Assume hg = 0.5 d so that Fg = 0.5.
From Appendix A, using a gas viscosity of 0.012 cp, CD = 1.42.

Step 2. Calculate Leff and Lss = Leff + d/12 for different values of d.
Step 3. Calculate the vessel diameter and length for liquid retention time with Eq. 2.12.
Step 4. Calculate Leff and Lss = Leff + d/12 for different values of d.
Step 5. Select vessel that satisfies both gas and liquid capacity.
A comparison of Tables 2.11 and 2.12 shows that the liquid capacity is the dominant parameter. Hence, a 24-in. × 6.6-ft vessel is sufficient, as it has a slenderness ratio within the typical 3 to 5 range. This size should be rounded up to 24 in. × 7 ft.

Example 2.3: Vertical Three-Phase Separator

Given Values. The given values for Example 2.3 are listed next:

Gas rate 5 MMscf/D
Gas specific gravity 0.6
Gas z-factor 0.84
Gas density 3.7 lbm/ft3
Oil rate 5,000 B/D
Oil density 50 lbm/ft3
Oil viscosity 10 cp
Water rate 3,000 B/D
Water density 66.8 lbm/ft3
Operating pressure 1,000 psia
Operating temperature 60°F
Liquid-retention time 10 minutes each phase
Inlet nozzle 12 in.
Drop removal from gas 100 μm

Step 1. Calculate vessel diameter based on gas capacity from Eq. 2.9.
From the previous example:


Step 2. Calculate the vessel diameter based on water drop removal from Eq. 2.11 for a 500-μm drop.

At this point, we know that the water-drop removal is the dominant sizing parameter in comparison to the gas capacity.

Step 3. Calculate liquid levels for retention time based on Eq. 2.13.
Table 2.13 shows liquid levels for different vessel diameters.

Step 4. Calculate vessel height from Eq. 2.17. Vales for Lss are given in Table 2.4. Values for 12Lss /d should be in the 1.5 to 3 range.
Step 5. Select a vessel size that satisfies gas capacity, water-drop removal, and liquid-retention time requirements. An 84-in. × 13.4-ft separator satisfies the requirements, so you would round up to an 84-in. × 13.5-ft vessel. Similarly, a 90-in. × 12.5-ft separator would also be satisfactory.


Ad = required demister area
C = API RP14E erosion constant, (lbm/ft-sec2)1/2
CD = drag coefficient (see Appendix A for calculation)
d = vessel internal diameter, in.
dh = hydraulic diameter, in. (or consistent units for Eq. 2.1)
dm = bubble or drop diameter, μm
dpp = perpendicular spacing of plates, m
D = vessel diameter, ft
Do = drop diameter, cm (or consistent units for Eq. 2.3)
Fc = fractional continuous-phase cross-sectional area
Fg = fractional gas cross-sectional area
Fl = fraction of vessel cross-sectional area filled by liquid
g = gravitational acceleration, cm/sec2 (or consistent units for Eq. 2.3)
h = liquid height, in.
hc = continuous liquid-phase space height, in.
hg = gas-phase space height, in.
ho = oil pad height, in.
hw = water pad height, in.
K = mesh capacity factor, m/s or ft/sec
L = plate-pack length, m (or consistent units for Eq. 2.2)
Leff = effective length of the vessel where separation occurs, ft
Lss = seam-to-seam vessel length, ft
P = operating pressure, psia
Qc = continuous liquid-phase flow rate, B/D
Qg = gas flow rate, MMscf/D
Qo = oil flow rate, B/D
Qw = water flow rate, B/D
Re = Reynolds number
T = operating temperature, °R
trc = continuous-phase retention time, minutes
tro = oil-retention time, minutes
trw = water-retention time, minutes
V = bulk velocity, m/sec
Vc = continuous-phase velocity, m/s (or consistent units for Eq. 2.1 )
Vm = design velocity, m/s (or consistent units for Eq. 2.5 )
Vh = horizontal water velocity, m/s (or consistent units for Eq. 2.2 )
Vr = drop rise velocity, m/s (or consistent units for Eq. 2.2 )
Z = gas compressibility
α = inclination angle, degrees
Δγ = specific gravity difference (heavy/light) of continuous and dispersed phases
μc = continuous phase dynamic viscosity, cp
μw = water dynamic viscosity, Poise (or consistent units for Eq. 2.3 ), kg/m-sec or N∙sec/m2
π = constant, 3.14159
ρ = density, kg/m3 or lbm/ft3
ρm = bulk density, kg/m3 or lbm/ft3
ρc = continuous liquid-phase density, kg/m3 or lbm/ft3
ρd = dispersed liquid-phase density, kg/m3 or lbm/ft3
ρg = gas density, kg/m3 or lbm/ft3
ρl = liquid density, kg/m3 or lbm/ft3
ρo = oil density, kg/m3 or lbm/ft3
ρw = water density, kg/m3 or lbm/ft3


m = bulk properties


  1. _
  2. _
  3. _
  4. _

Appendix A – Drag Coefficients

The balance of drag and buoyancy is given as

VT = terminal velocity, cm/sec;
CD = drag coefficient of drop/bubble;
ρc = continuous phase density, g/cm3;
ρd = dispersed phase density, g/cm3;
g = gravitational constant, 981 cm/sec2;
dv = dispersed phase drop/bubble size, cm.

Eq. A-1 can be rewritten as

μc = continuous phase viscosity, g/(cm/sec) = poise,
Re = Reynolds number, VTdvρc/μc,
Ar = Archimedes number.

The drag coefficient is a function of the Reynolds number, Re, and is given by a curve-fit of data (up to a Reynolds number of 5,000) from Perry’s Chemical Engineers’ Handbook. [1]
The form of Eq. A-3 was chosen to allow for an easy solution of Eq. A-3 for the Reynolds number as outlined by Darby in Darby[2].
The procedure then to calculate the drag coefficient is to calculate the Archimedes number, Ar, as defined in Eq. A-2; solve Eq. A-4 for the Reynolds number, Re; and solve Eq. A-3 for the drag coefficient, CD.

Appendix Nomenclature

Ar = Archimedes number
CD = drag coefficient of drop/bubble
dv = dispersed phase drop/bubble size, cm
g = gravitational constant, 981 cm/sec2
Re = Reynolds number, VTdvρc/μc
VT = terminal velocity, cm/sec
μc = continuous phase viscosity, g/(cm/sec) = poise
ρc = continuous phase density, g/cm3
ρd = dispersed phase density, g/cm3

Appendix References

  1. _
  2. _

SI Metric Conversion Factors

°API 141.5/(131.5 + °API) = g/cm3
bbl × 1.589 873 E – 01 = m3
cp × .01* E – 03 = Pa•s
ft × 3.048* E – 01 = m
ft2 × 9.290 304* E – 02 = m2
ft3 × 2.831 685 E – 02 = m3
ft/sec × 3.048* E – 01 = m/s
°F (°F – 32)/1.8 = °C
gal × 3.785 412 E – 03 = m3
in. × 2.54* E + 00 = cm
lbm × 4.535 924 E – 01 = kg
lbm/ft3 × 1.601 846 E + 01 = kg/m3
psi × 6.894 757 E + 00 = kPa


Conversion factor is exact.