PEH:Emulsion Treating

Publication Information

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume III – Facilities and Construction Engineering

Kenneth E. Arnold, Editor

Chapter 3 – Emulsion Treating*

Kenneth W. Warren PhD, SPE, Natco Group Inc.

Pgs. 61-122

ISBN 978-1-55563-116-1
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Most of the world’s oil reservoirs now produce a mixture of oil and water. The liquids are subjected to shear forces through pumps or other lifting methods, or are sheared as they pass through pressure-reducing devices in the production line. The shear forces disperse one liquid into the other with variations in drop size and stability that are related to the shear force encountered and the physicochemical nature of the production stream. Such dispersions commonly are referred to as emulsions, although many are not true emulsions.

In a true emulsion, either the drop size must be small enough that forces from thermal collisions with molecules of the continuous phase produce Brownian motion that prevents settling, or the characteristics of the interfacial surfaces must be modified by surfactants, suspended solids, or another semisoluble material that renders the surface free energy low enough to preclude its acting as a driving force for coalescence.

Even in fields where there is essentially no initial water production, water cuts eventually might increase enough to make emulsion treatment necessary. Water content of the untreated oil varies from < 1 to > 90 vol%. Salt and basic-sediment-and-water (BS&W) contents are important crude-purchasing requirements. Purchasers limit these contents in the oil they purchase to reduce transportation costs, water treatment and disposal costs, and equipment corrosion.

Removing water from the stream decreases the salt content, but additional steps might be required to meet salt specifications. BS&W content limits vary according to local conditions, practices, and contractual agreements, but typically range from 0.2 to 3.0%. BS&W usually is predominantly water, but might contain solids, some of which are sand, silt, mud, scale, and precipitates of dissolved solids from the producing formation. Other sources of solids are corrosion products, bacterial debris, and precipitated petroleum fractions such as asphaltenes. Solids are troublesome and vary widely among producing fields, zones, and wells.

When water forms a stable emulsion with crude oil and cannot be removed in conventional storage tanks, emulsion-treating methods must be used. This chapter covers the procedures and equipment that are used in treating emulsions. See the chapter on Crude Oil Emulsions in the General Engineering volume of this Handbook for detailed explanations of emulsions and their chemical treatment.

*

This chapter in the previous edition of the Handbook^[1] was written by H. Vernon Smith (Meridian Corp.) and Kenneth E. Arnold (brgon Engineering Services Inc.). Portions of their original material are retained in this edition.

Emulsions

Definition of an Emulsion

Strictly speaking, an emulsion is a heterogeneous liquid that consists of two immiscible liquids, one of which is intimately dispersed as droplets in the other. In oilfield parlance, though, an emulsion is any liquid/liquid dispersion that does not readily separate. This latter definition is the one used in this chapter, with apologies to the purists who would call these fine dispersions, rather than emulsions.

The stability of the emulsion is controlled by the types and amounts of surface-active agent and/or finely divided solids, which commonly act as emulsifying agents, or emulsifiers. Emulsifying agents form interfacial films around the droplets of the dispersed phase and create a barrier that slows or prevents coalescence of the droplets.

The matrix of an emulsion is called the external (or continuous) phase. The portion of the emulsion that is in the form of small droplets is called the internal (or dispersed or discontinuous) phase. This chapter considers emulsions of crude oil and the water or brine that is produced with it.

In most crude-oil/water emulsions, the water is finely dispersed in the oil. Such a water-in-oil emulsion is referred to as a "normal" emulsion. The oil can be dispersed in the water to form an oil-in-water emulsion, which is known as an "inverse" or "reverse" emulsion.

Emulsions sometimes are interrelated in a more complex form. The emulsion might begin as either water-in-oil or oil-in-water, but become multistage with additional agitation. If it is water-in-oil initially, a water-in-oil-in-water emulsion can be formed if a small volume of the original water-in-oil emulsion is enveloped in a film of water. Multistage emulsions usually add appreciably to the problem of separating the emulsion into oil and water. The more violent the agitation, the more likely multistage emulsions are to form.

How Crude-Oil Emulsions Form

For an emulsion to form, the two liquids forming the emulsion must be immiscible, there must be sufficient agitation to disperse one liquid as droplets in the other, and an emulsifying agent must be present.

Most crude-oil emulsions are the water-in-oil type, although oil-in-water emulsions are encountered in some heavy-oil production (e.g., in areas of Canada; in Venezuela; and in California, U.S.A.). Oil-in-water emulsions generally are resolved in the same way as are water-in-oil emulsions, except that electrostatic treaters cannot be used on them.

The agitation that is needed to form an emulsion may result from the bottomhole pump; flow through the tubing, wellhead, manifold, or flowlines; the surface transfer pump; pressure drop through chokes, valves, or other surface equipment; or any combination of these. The more agitation present, the smaller the water droplets that are dispersed in the oil. Studies of water-in-oil emulsions have shown that water droplet sizes vary widely, from < 1 to approximately 1,000 μm. Emulsions with smaller water droplets usually are more stable and difficult to treat than are those with larger droplets.

Crude oils vary considerably in emulsifying tendency. Some form very stable emulsions that are difficult to separate. Others do not emulsify or form loose emulsions that separate quickly. In an untreated emulsion, the density difference between the oil and the water will cause a certain amount of water to separate from the oil by natural coalescence and settling; however, unless some form of treatment is used to accomplish complete separation, a small percentage of water probably will remain in the oil, even after extended settling. The remaining water will be in minute droplets that have extremely low settling velocities. These droplets also will be widely dispersed, so that they have little chance to collide, coalesce into larger droplets, and settle.

The amount of water that emulsifies with crude oil in most production systems can vary widely, ranging from < 1 to > 60 vol% (in rare cases). The most common range of emulsified water in light crude oils (i.e., above 20°API) is from 5 to 20 vol%, and in crude oils that are heavier than 20°API is from 10 to 35 vol%.

Emulsifying Agents

Emulsifying agents are surface-active compounds that attach to the water-droplet surface and lower the oil/water interfacial tension. Adding energy to the mixture by agitation breaks the dispersed-phase droplets into smaller droplets. The lower the interfacial tension, the smaller the energy input that is required for emulsification (i.e., the smaller the droplets that will form with a given amount of agitation). Some emulsifiers are asphaltic. Barely soluble in oil and strongly attracted to water, they come out of solution and attach themselves to the droplets of water as these droplets are dispersed in the oil. Asphaltic emulsifiers form thick films around the water droplets and prevent droplet surfaces from contacting when they collide, thus preventing coalescence.

Oil-wet solids (e.g., sand, silt, shale particles, crystallized paraffin, iron hydroxides, zinc compounds, aluminum sulfate, calcium carbonate, iron sulfide, and similar materials that collect at the oil/water interface) can act as emulsifiers. These substances usually originate in the oil formation, but can form because of an ineffective corrosion-inhibition program.

Most crude-oil emulsions are dynamic and transitory. The interfacial energy per unit of area is fairly high in petroleum emulsions compared to that in emulsions commonly encountered in other industries; therefore, they are thermodynamically unstable in that the total free energy will decrease if the dispersed water coalesces and separates. The interfacial film introduces an energy barrier that prevents the "breaking," or separation, process from proceeding.

An emulsion’s characteristics change continually from the time of formation to the instant of complete resolution. Accordingly, aged emulsions can exhibit very different characteristics from those that fresh samples do. This is because any given oil contains many types of adsorbable materials and because the adsorption rate of the emulsifier and its persistence at the interface can vary. The emulsion characteristics also change when the liquid is subjected to changes in temperature, pressure, and degree of agitation.

Prevention of Emulsions

Excluding all water from the oil while the oil is produced and/or preventing all agitation of well fluids would prevent emulsion from forming; however, because these both are impossible, or nearly so, emulsion production must be expected from many wells. Sometimes, however, poor operating practices increase emulsification.

Operating practices that involve the production of excess water because of poor cementing or reservoir management can increase emulsion-treating problems, as can a process design that subjects the oil/water mixture to excess turbulence. Unnecessary turbulence can be caused by overpumping and poor plunger and valve maintenance in rod-pumped wells, by use of more gas lift gas than is needed, and by pumping the fluid where gravity flow could be used. To minimize turbulence, some operators use progressive cavity pumps, as opposed to reciprocating, gear, or centrifugal pumps. Other operators have found that some centrifugal pumps actually can cause coalescence if they are installed in the process without a downstream throttling valve. Wherever possible, pressure drop through chokes and control valves should be minimized before oil/water separation.

Stability of Emulsions

Generally, crude oils with low API gravity (high density) form more stable and higher-percentage-volume emulsions than do oils of high API gravity (low density). Asphaltic-based oils tend to emulsify more readily than do paraffin-based oils. High-viscosity crude oil usually forms a more stable emulsion than low-viscosity oil does. Emulsions of high-viscosity crude oil usually are very stable and difficult to treat because the viscosity of the oil hinders movement of the dispersed water droplets and thus retards their coalescence. In addition, high-viscosity/high-density oils usually contain more emulsifiers than do lighter oils.

Effect of Emulsions on Fluid Viscosity

Emulsions always are more viscous than the clean oil in the emulsion. In oilfield emulsions, the ratio of the viscosity of an emulsion to that of the clean crude oil depends on the shear rate to which the emulsion has been subjected. For many emulsions and for the shear rates normally encountered in piping systems, this ratio can be approximated using Eq. 3.1,^[1] if no other data are available.

....................(3.1)

where μ_e = viscosity of emulsion, cp; μ_o = viscosity of clean oil, cp; and f = fraction of the dispersed phase.

Sampling and Analyzing Crude-Oil Emulsions

Crude-oil purchasers have established specifications that limit the amount of BS&W in the oil. These limits usually are strictly applied; if the amount of BS&W in an oil exceeds the specified limit, a purchaser might not accept the oil from the producer. The seller and buyer must agree on the procedure for sampling and analyzing the oil to provide consistent and mutually acceptable data.

Emulsion-treating unit or system performance can be monitored by periodically and regularly withdrawing and analyzing samples of the contents at multiple levels in the vessel or multiple points in the system. This is particularly beneficial when treating emulsions that involve viscous oils. Emulsion samples should be representative of the liquid from which they are taken, so emulsification should not be allowed to occur when the sample is extracted. For example, for samples obtained at the wellhead, manifold, or oil-and-gas separator, emulsification can occur because of the turbulence created while the sample is removed from the pressure zone to the sample container. Although such a sample might show a high percentage of emulsion, the oil and water in the system actually might not be emulsified.

Samples from a pressure zone can be taken without further emulsification of the liquids if the velocity of the discharging liquid is controlled. One method is to use a piece of small-diameter tubing that is 10 to 15 ft long. One end of the tubing is connected to a bleeder valve on the line or vessel from which the sample is to be extracted, and the other end is connected to the sample container. The bleeder valve is opened fully, and the sample is allowed to flow through the small-diameter tubing into the container. Emulsification caused by pressure differential may be largely eliminated by flow through small-diameter tubing; however, contact with the tubing walls might produce coalescence, or perturbations to the flow caused by the passage of solids or large water drops might produce emulsification.

Another method for withdrawing representative emulsion samples is to use a sample container that initially is filled with water and is equipped with valves at the top and bottom, with the top valve connected to the point from which the sample is to be extracted. The top valve of the container is opened first, and the container is pressured from the line. The valve at the bottom of the container then is opened, and the water is discharged into the atmosphere as the sample enters the container. No emulsification will occur in the container because there is no pressure drop between the source and sample container to cause turbulence. After the sample has been taken, pressure can be bled off through a third valve with little effect on the sample.

The BS&W content of crude oil is determined using small centrifuges that are driven by hand or by electric motor. A small measured volume of sample is diluted with solvent and placed in graduated glass containers that then are inserted into the centrifuge and spun for a few minutes at speeds of 2,000 to 4,000 rev/min. The oil, water, and solids are separated by centrifugal force, and the percentages of each can be read directly from the graduated containers in which the sample is centrifuged.

These methods are described in the American Standards for Testing and Measurement publication ASTM D-96 for field measurements^[2] and ASTM D-4007 for laboratory procedures.^[3] Methods for taking and analyzing samples of crude oil for custody transfer are included in the API Manual of Petroleum Measurement Standards.^[4]

Separating a crude-oil/water emulsion into its bulk phases of oil and water usually involves three basic steps: destabilization (coagulation), coalescence (flocculation), and gravity separation (sedimentation). Operation and design parameters such as proper chemical selection, chemical-injection rate, treating temperature and pressure, continuous-phase viscosity, flow rate, vessel size and design, and fluid levels can affect separation and can be adjusted to optimize the separation process.
Step 1: Destabalization (Coagulation). Counteracting the stabilizing effect of the emulsifier destabilizes an emulsion. To increase the probability of coalescence of dispersed water droplets on contact, the tough skin or film surrounding the dispersed water droplets must be weakened and broken. This usually is accomplished by adding heat and/or a properly selected, interfacially active chemical compound to the emulsion. (This primarily is the task of the chemical treatment program.)
Step 2: Coalescence (Flocculation). After the films that encase the dispersed droplets have been broken or sufficiently weakened, the droplets must coalesce into drops that are large enough to settle out of the continuous phase of oil. The rate of contact of dispersed water droplets needs to be high, but without creating high shear forces. This usually is accomplished by mechanically inducing collisions between drops or by subjecting the destabilized emulsion to an electrostatic field.
Step 3: Gravity Separation (Sedimentation). Next, there must be a quiet period of settling to allow the coalesced drops to settle out of the oil by gravity. This requires a sufficient residence time and a favorable flow pattern in a tank or vessel that will allow the coalesced drops of water to separate from the oil.

Emulsion-Treating Methods

An emulsion-treating unit or system will use one or more of the methods listed in Table 3.1 to aid in destabilizing, coalescence, and/or gravity separation. Each of these treating methods is discussed separately below.

Table 3.1

Heating

Using heat to treat crude-oil emulsions has four basic benefits:

Heat reduces the viscosity of the oil, which allows the water droplets to collide with greater force and to settle more rapidly. The chart in Fig. 3.1 can be used to estimate crude-oil viscosity/temperature relationships. Crude-oil viscosities vary widely, and the curves on this chart should be used only in the absence of specific data. If a crude oil’s viscosity is known at two temperatures, it can be approximated at other temperatures by drawing a straight line along those temperature/viscosity points on the chart. Viscosity that is known at one temperature can be approximated at other temperatures by drawing a straight line parallel to the curves already on the chart. If the viscosity is unknown at any temperature, the chart’s curves may be used. API Spec. 12L^[5] recommends that crude oil be heated so that its viscosity is 50 cSt for dehydration. Viscosity should be < 7 cSt for desalting.
Heat increases the droplets’ molecular movement, which helps coalescence by causing the dispersed-phase droplets to collide more frequently.
Heat might deactivate the emulsifier (e.g., dissolve paraffin crystals), or might enhance the action of treating chemicals, causing the chemical to work faster and more thoroughly to break the film around the droplets of the dispersed phase of the emulsion.
Heat also might increase the density difference between the oil and the water, thus accelerating settling. In general, at temperatures below 180°F, adding heat will increase the density difference. Because most light oils are treated below 180°F, the effect of heat on gravity is beneficial. For heavy crudes ( < 20°API), which normally are treated above 180°F, heat might have a negative effect on the density difference. In special cases, increased heat might cause the density of water to be less than that of oil. This effect is shown in Fig. 3.2.

Fig. 3.1—Approximate viscosity/temperature relationships for crude oil. (Reprinted, with permission copyright ASTM International).
Fig. 3.2—Relationship of density with temperature for three crude oils.^[1]

Heating well fluids is expensive. Adding heat can cause a significant loss of the lower-boiling-point hydrocarbons (light ends). This causes "shrinkage" of the oil, or loss of volume. Because the light ends are boiled off, the remaining liquid has a lower API gravity and thus might have less value. Figs. 3.3 and 3.4 illustrate typical gravity and volume losses, respectively, vs. temperature for 33°API crude. The vapor leaving the oil phase can be vented to a vapor recovery system or compressed and sold with the gas. Either way, there probably will be a net income loss.

Fig. 3.3—API-gravity loss vs. temperature for 33^o API crude oil.^[1]
Fig. 3.4—Percent loss by volume vs. temperature for 33^o API crude oil.^[1]

The gas that is liberated when crude oil is treated also might create a problem in the treating equipment if the equipment is improperly designed. In vertical emulsion treaters and gun barrels, some liberated gas could rise through the coalescing section, creating enough turbulence and disturbance to inhibit coalescence. Perhaps more importantly, the small gas bubbles are attracted to surface-active material and, hence, to the water droplets; thus, they tend to keep the water droplets from settling and might even cause them to be discharged with the oil.

Fuel is required to provide heat, and so the cost of fuel must be considered. If the oil is above inlet-fluid temperature when it is discharged from the treating unit, it can be flowed through a heat exchanger with the incoming well fluid to transfer the heat to the cooler incoming well fluid. This will minimize evaporation losses and reduce fuel cost; however, it also will increase the vapor pressure of the crude, which might be limited by contract.

If properly done, heating an emulsion can greatly benefit water separation. Using less heat and a little more chemical, agitation, and/or settling space can obtain the most economical emulsion treatment.

In some geographic areas, emulsion-heating requirements vary in accordance with daily and/or seasonal atmospheric temperatures. Emulsions usually are more difficult to treat when the air is cooler—e.g., at night, during a rain, or in winter months. On the other hand, treatment, especially heating, might not be required in the warmer summer months. When the treating problem is seasonal, some emulsions can be resolved successfully by adding more chemical demulsifiers during winter months. The proper economic balance of heat and chemicals requires evaluation.

Crude-oil emulsions with similar viscosity ranges do not always require the same type of treating equipment or the same treating temperature. Emulsions that are produced from different wells on the same lease or from the same formation in the same field might require different treating temperatures. For this reason, treating temperatures should be tested so that the lowest practical treating temperature for each emulsion and treating unit or system can be determined by trial.

The heat input and thus the fuel required for treating depends on the temperature rise, the amount of water in the oil, and the flow rate. Because heating a given volume of water requires approximately twice the energy needed to heat the same volume of oil, it is beneficial to separate free water from the emulsion to be treated. Often this is done in a separate free-water-knockout (FWKO) vessel upstream of where heat is added. Sometimes it is accomplished in a separate section of the same vessel.

The required heat input for an insulated vessel (heat loss is assumed to be 10% of heat input) can be approximated using Eq. 3.2^[1]:

....................(3.2)

where Q = heat input, Btu/hr, ΔT = temperature increase, °F, q_o = oil flow rate, B/D, q_w = water flow rate, B/D, γ_o = specific gravity of oil, and γ_w = specific gravity of water.

Chemical Demulsifiers

Dehydration chemicals, or demulsifiers, are chemical compounds that are widely used to destabilize, and assist in coalescence of, crude-oil emulsions. This treatment method is popular because the chemicals are easily applied, usually are reasonable in cost, and usually minimize the amount of heat and settling time required.

The chemical counteracts the emulsifying agent, allowing the dispersed droplets of the emulsion to coalesce into larger drops and settle out of the matrix. To work, demulsifiers must be injected into the emulsion; must mix intimately with the emulsion and migrate to all the protective films surrounding all the dispersed droplets; and must displace or nullify the effect of the emulsifying agent at the interface. For the oil and water to separate, there must also be a period of continual, moderate agitation of the treated emulsion to produce contact between and coalescence of the dispersed droplets, as well as a quiet settling period.

Four actions are required of a chemical demulsifier:

Strong attraction to the oil/water interface. The demulsifier must be able to migrate rapidly through the oil phase to reach the droplet interface where it must counteract the emulsifying agent.
Flocculation. The demulsifier must have an attraction for water droplets with a similar charge and bring them together. In this way, large clusters of water droplets gather, which under a microscope look like bunches of fish eggs.
Coalescence. After flocculation, the emulsifier film remains continuous. If the emulsifier is weak, the flocculation force might be enough to cause coalescence; however, this usually is not true, and the demulsifier must enable coalescence by neutralizing the emulsifier and promoting rupture of the droplet interface film. In the flocculated emulsion, the film rupture causes increasing water-drop size.
Solids wetting. Iron sulfides, clays, and drilling muds can be made water-wet, which causes them to leave the interface and be diffused into the water droplets. paraffins and asphaltenes can be dissolved or altered by the demulsifier to make their films less viscous, or they can be made oil-wet so that they will be dispersed in the oil.

The demulsifier should be selected with all functions of the treating system in mind. If the process is a settling tank, a relatively slow-acting demulsifier can be applied with good results. On the other hand, if the system is an electrostatic process in which some of the flocculation and coalescence is accomplished by the electric field, a quick-acting demulsifier is needed or the demulsifier might need to be added farther upstream (preferable). The time required for demulsifier action in a vertical emulsion treater normally is between that in a settling tank and that in an electrostatic treater.

As field conditions change and/or the treating process is modified, the chemical requirements might change. Seasonal changes can cause paraffin-induced emulsion problems. Well workovers might change solids content, which can alter emulsion stability. Thus, no matter how satisfactory a demulsifier is, it cannot be assumed to be satisfactory over the life of the field.

Applying heat to an emulsion after a demulsifier has been mixed with it increases the chemical’s effectiveness by reducing the emulsion viscosity and facilitating more intimate chemical/emulsion mixing. Chemical reaction at the oil/water interface happens more rapidly at higher temperatures.

Where the demulsifier is injected into the emulsion is important. It should be injected into the emulsion and mixed so that it is evenly and intimately distributed throughout the emulsion when the emulsion is heated, coalesced, and settled in the treating system. It also should be injected in a continuous stream, with the chemical volume directly proportional to the emulsion volume.

Turbulence accelerates the diffusion of the demulsifier throughout the emulsion and increases the number and intensity of impacts between water droplets. Turbulence must persist long enough to permit the chemical to reach the interface between the oil and all the dispersed water droplets, but the intensity and duration of the turbulence must be controlled so that it will not cause further emulsification. Turbulence is the dynamic factor for emulsion formation; however, a moderate level of controlled turbulence causes the dispersed droplets to collide and coalesce. Usually, this turbulence is provided by normal flow in surface lines, manifolds, and separators and by flow through the emulsion-treating unit or system.

One way to help disperse the chemical throughout the emulsion is to mix a small volume of chemical with a diluent and then to inject and mix the diluted chemical with the emulsion. The larger volume of the mixture can help to mix the chemical more uniformly and intimately with the emulsion.

Usually, the chemical is injected into a coupling that is welded in the side of the pipe, but when flow rates are low ( < 3 ft/sec) or when laminar flow is encountered, this is not recommended. In such cases, an injection quill (which injects the chemical in the stream at a location that is removed from the wall), a chemical distributor (Fig. 3.5), and/or a static mixer (Fig. 3.6) are recommended. The static mixer is a series of staggered, helically convoluted vanes that use the velocity of the fluid to accomplish mixing.

Fig. 3.5—Chemical distributor for flowlines 10 in. or larger.^[1]
Fig. 3.6—Kinetic (static) mixer for mixing chemical demulsifier with emulsion. (Courtesy of Chemineer-Kenics, Dayton, Ohio.)

When a tank of wet oil (oil that contains more than the permissible amount of water) accumulates, the tank contents can be treated by adding a small proportion of demulsifier, agitating or circulating the tank contents, and then allowing time for the water to settle in the tank. Trailer-mounted units that include a heater, circulating pump, and chemical injector are sometimes used for this method of tank treating. This batch-treatment method normally is used as an emergency measure.

Using too much treating chemical not only wastes the money spent on its purchase, handling, and injection, but also can increase the stability of the water-in-oil emulsion or of the oil-in-water emulsion in the produced water and increase the stability or the volume of the interfacial emulsion and/or sludge. Using too little treating chemical can fail to break the emulsion and can allow a quick buildup of emulsion and/or sludge. It also can cause an excessive need for heat to break the emulsion and for settling time to resolve the emulsion; can reduce the capacity of the treating equipment; can cause high water content in the crude oil and, therefore, the accumulation of unsalable oil and the resultant cost of retreating the crude; and can increase the difficulty of removing oil from the produced water.

Agitation

Agitation or turbulence is necessary to form a crude-oil emulsion. When turbulence is controlled, however, it can assist in resolving the emulsion. Agitation increases the number of collisions of dispersed particles of water and increases the probability that they will coalesce and settle from the emulsion. Be careful to prevent excessive agitation that will cause further emulsification instead of resolving the emulsion. Keeping the turbulence to moderate Reynolds numbers of 50,000 to 100,000 usually achieves good coalescing conditions.

The flow of emulsions at moderate Reynolds numbers through long pipelines has been shown to cause coalescence and to develop droplets > 1,000 μm in diameter. Using a tortuous flow path as in the serpentine-pipe flow-coalescing device shown in Fig. 3.7 can decrease the pipeline length required for coalescence. Other devices that are described below have largely supplanted this technology.

Fig. 3.7—The serpentine-pipe coalescing pack grows a larger drop size on the inlet separator of a gravity settler. (Courtesy of Natco Group Inc.)

Coalescing Plates

Properly designed and placed baffle plates can assist demulsification by evenly distributing emulsion in a vessel and causing gentle agitation that helps to coalesce the droplets by causing dispersed water particles to collide. Using too much baffling, however, can cause excessive turbulence, which might increase emulsification and impede water-droplet settling. Special perforated baffle plates that are properly placed inside treating vessels provide surfaces on which water droplets can coalesce. The emulsion flowing through the perforations creates slight agitation in the form of eddy currents, which causes coalescence. If the perforations are too small, however, shearing of the water droplets can occur, yielding a tighter emulsion.

Other baffle-plate designs also provide surfaces for water coalescence. The design shown in Fig. 3.8 allows laminar flow through the plates, but provides directional changes to enable the water droplets to contact the plates and coalesce with a film on the surface of the plates. This type of plate can become plugged if used in situations with high paraffin deposition.

Fig. 3.8—Corrugated-plate pack, a special coalescing medium for crude-oil emulsions. (Courtesy of Natco Group Inc.)

Electrostatic Coalescence

The small water drops that are dispersed in the crude oil can be coalesced by subjecting the water-in-oil emulsion to a high-voltage electrical field. When a nonconductive liquid (oil) that contains a dispersed conductive liquid (water) is subjected to an electrostatic field, one of three physical phenomena causes the conductive particles or droplets to combine:

The water droplets become polarized and tend to align themselves with the lines of electric force. In so doing, the positive and negative poles of the droplets are brought adjacent to each other. Electrical attraction brings the droplets together and causes them to coalesce.
An induced electric charge attracts the water droplets to an electrode. In a direct current (DC) field, the droplets tend to collect on the electrodes or bounce between the electrodes, forming larger and larger droplets until eventually they settle by gravity.
The electric field distorts and thus weakens the film of emulsifier surrounding the water droplets. Water droplets dispersed in oil that are subjected to a sinusoidal alternating-current (AC) field become elongated along the lines of force as voltage rises during the first half-cycle. As the droplets are relaxed during the low-voltage part of the cycle, the surface tension pulls them back toward a spherical shape. This effect repeats with each cycle, weakening the film so that it breaks more easily when droplets collide.

Whatever the actual mechanism, the electrical field causes the droplets to move about rapidly, which increases the probability of collision with other droplets. Droplets coalesce when they collide at the proper velocity. The greater the voltage gradient, the greater the forces that cause coalescence; however, experimental data have shown that at some voltage gradient, rather than coalescing, the water droplets can be pulled apart, tightening the emulsion. For this reason, electrostatic treaters normally are equipped with a mechanism for adjusting the voltage gradient in the field.

In oil that contains a large quantity of water, there is a tendency toward "chaining"—the formation of a chain of charged water particles—which might form links between the two electrodes, causing short-circuiting. Chaining has been observed in emulsions that contain 4% or less water. If chaining causes excess power consumption, the voltage gradient is too large (i.e., the electrical grids of the electrostatic treater are too close together or the voltage is too high) for the amount of water being handled. The breaking out of solution of small amounts of gas also can create sufficient turbulence to impede sedimentation.

Water Washing

In some emulsion-treating vessels, separation of liquids and vapors takes place in the inlet diverter, flume, or gas boot that is located at the top of the vessel. The liquids flow by gravity through a large conduit to the bottom of the vessel. A spreader plate on the lower end of the conduit spreads the emulsion into many rivulets that move upward through the water, accomplishing a water wash. After passing through the water wash, the emulsion flows to the upper portion of the vessel, where the coalesced water droplets settle out of the oil.

When an emulsion is flowed through an excess of its internal phase, the droplets of its internal phase tend to coalesce with the excess of the internal phase and thus be removed from the continuous phase. This is the principle on which a water wash operates. The water wash is more beneficial if the emulsion has been destabilized by a demulsifier and if the water is heated. The effectiveness of a water wash greatly depends on the ability of the spreader plate or distributor to divide the emulsion into rivulets, causing the emulsion to have maximum intimate contact with the water bath, so that its small drops of water can coalesce with the bulk water.

There is some danger of multiphase emulsion formation if the stream passes through an interface "rag" (unresolved emulsion and solids) layer.

If an emulsion-treating system or unit uses a water wash, it should be charged with water to facilitate initial operation. Water from the emulsion to be treated should be used if available; if not, extraneous water may be used.

Filtering

A filtering material with the proper pore-space size and the proper ratio of pore space to total area can be used to filter out the dispersed water droplets of a crude-oil emulsion by preferentially wetting the filtering material with oil and keeping it submerged in oil. A pack used in this manner is correctly called a filter because it filters out the liquid that it prevents from passing through. Filtering is not a widely used crude-oil-emulsion treatment method, however, because of the difficulty in obtaining and maintaining the desired filtering effect and because filtering materials easily become plugged by foreign material.

One filtering material, excelsior, is wood that has been cut into small shreds or fibers (and so frequently is referred to as "hay"). It formerly was used as a filter in emulsion treaters, but now is largely obsolete. Excelsior should be used at < 180°F treating temperature. Higher temperatures will delignify and deteriorate the excelsior and make it difficult to remove from the vessel.

When its fibers are properly sized and compacted, glass wool also can serve as a filtering material. Coating the glass wool with silicone enhances its filtering effect because the silicone-coated glass-wool fibers are more wettable by oil than are untreated ones. Glass wool is not widely used for filtering, however, because of its initial expense and its fouling problems. Likewise, other available plastic and metal porous filtering materials are not widely used because of the difficulty of obtaining and maintaining the proper pore size and because they easily become inoperable because of fouling.

Fibrous Packing

Fibrous coalescing packs are not commonly used in oil treating, but are discussed here for completeness and to differentiate between filtering and coalescence. A coalescing pack is a section or compartment in an emulsion-treating tank or vessel that is packed with a water-wetted material, causing the water in the emulsion to coalesce into larger drops. A coalescing pack works on the principle that two immiscible liquids with different surface tensions cannot simultaneously take possession of a given surface. When the dispersed droplets of water contact the water-wet coalescing material, they coalesce and adhere to the coalescing surfaces. Oil will pass through the pore spaces of the coalescing material. Separation of the two liquids in a coalescing pack, then, is caused not by filtering, but by the greater affinity of the water-wet coalescing material for the water droplets.

The film of oil that contains the emulsifying agent that surrounds the dispersed water particles must be broken before these droplets will adhere to a coalescing medium. This is done with demulsifying chemicals and/or heat and by repeated contact between the water particles and the surface of the coalescing materials while the emulsion flows through the pack. When this film has been broken, the water particles will adhere to the surface of the coalescing material until they combine into drops that are large enough to settle out of the oil.

Glass wool can be used as coalescing material in emulsion-treating vessels, but it fouls easily and might cause channeling. Woven-wire mesh also can be used, but tends to be more expensive than glass wool.

Gravity Settling

Gravity settling is the oldest, simplest, and most widely used method for treating crude-oil emulsions. The density difference between the oil and the water causes the water to settle through and out of the oil by gravity. The gravitational force is resisted by a drag force from their downward movement through the oil. When these two forces are equal, a constant velocity is reached that can be computed from Stokes’ law, Eq. 3.3^[1]:

....................(3.3)

where v = the downward velocity of the water droplet relative to the oil, ft/sec; d = the diameter of the water droplet, μm; Δγ_ow = the specific-gravity difference between the water and the oil (water/oil); and μ_o= dynamic viscosity of the oil, cp.

Several conclusions can be drawn from Eq. 3.3:

The larger the water droplet is, the greater is its downward velocity (i.e., the larger the droplet, the less time it takes to settle to the bottom of the vessel, and thus the easier it is to treat the oil).
The greater the density difference between the water droplet and the oil, the greater is the downward velocity (i.e., the lighter the oil, the easier it is to treat the oil). For example, if the oil gravity is 10°API and the water is fresh, the settling velocity will be zero because there is no gravity difference.
The higher the temperature, the lower the oil viscosity, and thus the greater the downward velocity of the water droplets. It is easier to treat the oil at high temperatures than at low temperatures (assuming a small effect on gravity difference because of increased temperature).

Gravity settling can be used alone only to treat loose, unstable emulsions; however, for stronger emulsions, gravity settling separates water from oil only when used with other treating methods that increase water droplet size by destabilizing the emulsion and creating coalescence.

Retention Time

In a gravity settler (e.g., an oil-treating tank or the coalescing section of an oil-treating vessel), coalescence will occur, but because of the small forces at work, the rate of contact between water droplets is low, and colliding droplets seldom coalesce immediately. Thus, the coalescence process occurs over time, but it follows a steep exponential curve in which successive doubling of retention time yields small, incremental increases in droplet size.

Adding retention time alone (beyond a small amount for initial coalescence) might not significantly affect the size of the water droplets that must be separated by gravity to meet the desired oil quality. Using a taller tank increases the retention time, but does not decrease the upward velocity of the oil or might not significantly increase the size of the water drops. Thus, the additional retention time gained by using the taller tank might not materially affect the water content of the outlet oil.

Using a larger-diameter tank also will increase the retention time and, more importantly, will slow the upward velocity of the oil, allowing smaller droplets of water to settle out by gravity. In this case, it might not be the increase in retention time that improves the oil quality, but rather the reduction in flow velocity, which decreases the size of the water droplets that can be separated from the oil by gravity.

Centrifugation

Because of the density difference between oil and water, centrifugal force can be used to break an emulsion and separate it into oil and water. Small centrifuges are used to determine the BS&W content of crude-oil emulsion samples. A few centrifuges have been installed in oil fields to process emulsions, but centrifuges have not been widely used for treating emulsions because of high initial cost, high operating and maintenance costs, low capacity, and their tendency to foul.

Distillation

Distillation can be used to remove water from crude-oil emulsions. Along with lighter oil fractions, the water can be distilled by heating and then separated by appropriate means. The lighter oil fractions usually are returned to the crude oil.

The only current use of distillation is in the "flash system" that is used in 15°API and lower oil. Flash systems use the excess heat in the oil that is received from the treater or treating system and convert it to latent heat at or near atmospheric pressure. A surface condenser condenses the flashed steam in the cooler, incoming stream of raw crude, thus scavenging the excess heat that ordinarily would be wasted.

Fig. 3.9 shows a typical flash-distillation system for dehydrating emulsions of heavy viscous crude oils. It is very important in a flash system that the operating pressure be maintained high enough to keep the boiling temperature of the water in the emulsion at least 40°F above the bulk temperature. This will help prevent scale deposition on the heating elements.

Fig. 3.9—Typical flash-distillation system for dehydrating emulsions of heavy viscous crude oils. (Courtesy of Hydrocarbon Research Inc., Long Beach, California.)

The disadvantages of distillation are that it is expensive and that all the dissolved and suspended solids in the water remain in the oil when the water is removed by evaporation. For these reasons, flash treating systems usually are limited to heavy crudes that must meet low BS&W pipeline specifications, as might be the case in cold climates.

Desalting

Most produced water contains salts that can cause problems in production and refining, when solids precipitate to form scale on process equipment. The salts also accelerate corrosion in piping and equipment.

The salt content of crude oil almost always consists of salt dissolved in small droplets of water that are dispersed in the crude. Sometimes the produced oil contains crystalline salt, which forms because of pressure and temperature changes and because of stripping of water vapor as the fluid flows up the wellbore and through the production equipment.

The salinity of produced brine varies widely, but for most produced water, it ranges from 5,000 to 250,000 ppm of equivalent NaCl. (See the chapter on Properties of Produced Water in the General Engineering volume of the Handbook.) Crude oil that contains only 1.0% water with a 15,000-ppm salt content has 55 lbm of salt per 1,000 bbl of water-free crude. The chemical composition of these salts varies, but nearly always is mostly NaCl, with lesser amounts of calcium and magnesium chloride. Salt content limits might be set by transportation requirements in the production field or shipping terminal, or by concerns over corrosion, fouling, or catalyst degradation in the refinery.

The purpose of a desalting system is to reduce the salt content of the treated oil to acceptable levels. When the salinity of the produced brine is not too high, merely ensuring that there is a low fraction of water in the oil can reduce salt content. In that case, the terms desalting and emulsion treating effectively have the same meaning, and the concepts and equipment described previously can be used.

The required maximum concentration of water in oil to meet a known salt specification can be derived from Eq. 3.4:

....................(3.4)

where C_so = the salt content of the oil, lbm/1,000 bbl; C_sw = the concentration of salt in produced water, ppm; γ_w = the specific gravity of produced water; and f_w = the volume fraction of water in crude oil.

In produced brine with a high salt concentration, it might not be possible to treat the oil to a low enough water content ( < 0.2% is difficult to guarantee). A desalting system such as the one shown schematically in Fig. 3.10 consists of a mixing device (in which fresh water is used to wash the crude oil) and any of the electrostatic treating systems described below (which then are used to dehydrate the oil to a low water content). Mixing dilution water with the produced water lowers the effective value of C_sw in Eq. 3.4. If a single-stage desalting system requires too much dilution water or is unable to reach the desired salt concentration, then a two-stage system is used, such as the one shown schematically in Fig. 3.11.

Fig. 3.10—Typical flow diagram for a single-stage desalter. (Courtesy of Natco Group Inc.)
Fig. 3.11—Typical flow diagram for a two-stage desalter. (Courtesy of Natco Group Inc.)

Mixing Efficiency

The mixing efficiency is the fraction of wash water that actually mixes with the produced water. In effect, the remainder of the water bypasses the desalting stage and is disposed of as free water. A mixing efficiency of 70 to 85% is considered the highest attainable. Because mixing efficiency depends on the probability of contact between the dilution water and entrained brine, it varies with the drop population in the crude oil. The effectiveness of this dilution reaction is determined by a variety of influences (e.g., mixing intensity and duration, diffusional transport, and interdrop-collision frequency).

Dilution Water

Enough dilution water must be available to satisfy mass-balance requirements for diluting the dispersed brine enough that the salt specification can be met while considering the residual BS&W in the oil. Dilution-water quality also must be considered and can be a problem because of high pH, the presence of surfactants, and other conditions that can lead to increased emulsion stability.^[6]

Obviously, to remove salt, the dilution water must have low enough salt content to achieve the required equilibrium concentration in the residual entrained water. Less obvious but also important is the need for dilution water to be of sufficient quality to avoid contributing to emulsification. Streams that contain considerable amounts of coke particles, suspended solids, iron sulfide, and/or emulsified oil should not be used. Neither should streams contain traces of surfactant chemicals or excess caustic soda. Limiting ammonia to < 200 ppm avoids fouling and corrosion in the crude-distillation unit overhead and limits pH excursions. Preferably, the pH of the dilution water should be < 9.0, and provision for acid injection for pH control should be made if higher values are expected. High pH might enhance the formation of stable emulsions, whereas pH values < 6.5 might raise concerns about corrosion within the desalter vessel. The dilution water should contain < 0.02 ppm oxygen and < 1 ppm fluoride and should be low in sodium salts, suspended solids, and hardness ions.

Water Recycle

Contact efficiency, or collision frequency, between drops of dispersed brine and dilution water is proportional to the drop populations. Increasing the number of dilution-water drops yields more efficient contact. Because quantities of available dilution water usually are limited, the effluent water often is recycled to increase drop population. Effluent water from the second-stage desalter is much less saline than the dispersed brine, so that it can be used for dilution water for the first stage, as shown in Fig. 3.11. This is known as interstage recycling.

Another recycle scheme, intrastage recycling, previously was limited because it requires mixing of the recycle water and the fresh water, thereby lessening the effectiveness of the fresh water; however, the advent of counterflow desalting made it feasible to inject recycle water ahead of the mixing valve of a single-stage desalter and to inject the fresh water into the counterflow distributors, thereby increasing the drop population without raising the salinity of the fresh dilution water. With all recycle streams, be careful as to the quality of the water: if interface sludge or mud-wash solids are allowed to recycle, they might produce stable emulsions and cause rapid buildup of the interface-sludge layer. If this problem appears likely to occur, the recycle should be taken after an effluent water-cleaning device.

Effluent-Water Quality

The effluent water from a properly operating desalter, exclusive of mud-wash cycles, frequently is < 250 ppm oil in water. Field dehydrators might carry more oil in their effluent water, depending on the conditions of the crude oil being treated. Further clarifying the water requires additional retention time and different chemical treatment, both of which are more economically provided externally to the desalter vessel.

Water Solubility in Crude Oil

Water exhibits an appreciable solubility in crude oil at elevated temperatures. A rule of thumb is that approximately 0.4% water might be dissolved at temperatures of approximately 300°F, as shown in Fig. 3.12 for a variety of crude oils. A desalter or dehydrator can separate only dispersed water and has no effect on water that is soluble at operating conditions; however, a significant quantity of soluble water can precipitate when the output is sampled through a sample cooler and the sample is further cooled while awaiting analysis. This precipitated water might be erroneously assumed to be dispersed water in the effluent oil.

Fig. 3.12—Solubility of water as a function of temperature in various crude oils. (Courtesy of Natco Group Inc.)

A more insidious aspect of water solubilization occurs in the preheat train ahead of a desalter. As the oil is heated to operating temperature, water from the dispersed brine is solubilized into the oil phase while leaving behind precipitated salts. This can cause the formation of crystalline salt, which is very difficult to remove from the oil. Injecting fresh water ahead of the preheat train can help offset this problem and can alleviate heat exchanger fouling.

Incompatibilities of Oils

Crude oils might contain semisoluble organic materials (e.g., waxes and asphaltenes), which can precipitate during processing and cause the production of troublesome sludges or the stabilization of emulsions. Wax precipitation can be controlled through temperature and chemicals, but asphaltenes are more troublesome. By definition, asphaltenes precipitate in hydrocarbons of the molecular weight of pentane; therefore, if light hydrocarbons are recycled as slop oil into a vessel that is processing asphaltic crude oil, serious sludge precipitation might result.

Analytical Methods

Several procedures currently are in use, depending on the values to be measured, the accuracy required, and the equipment available. BS&W measurements usually are done by centrifugation, as discussed in Sec. 2.7 above and as described in ASTM D-96^[2] and ASTM D-4007.^[3] Salt analysis by conductivity, as described in ASTM D-3230,^[7] is a widely used technique for process monitoring and quality control. It is reliable at salt concentrations > 5 lbm/1,000 bbl and, with care, can be used at concentrations of from 2 to 5 lbm/1,000 bbl. At low salt levels, oil conductivity becomes a function of water content and pH, as well as of salt content. Because the ions responsible for pH changes are 2.6 to 4.6 times as conductive as chloride, the effects of minor pH changes far outweigh those of chloride-concentration changes. Other problems (e.g., variation in the composition of the salt mix in oils) also help to preclude the use of this method as a reliable indicator of absolute desalter performance at low effluent salt contents unless exacting calibration procedures are followed.

Laboratory results usually are obtained by analyzing total chloride ion, converting it to equivalent sodium chloride, and reporting it in lbm/1,000 bbl. At salt levels of 2 lbm/1,000 bbl and below, achieving meaningful and reproducible results requires great care. Of the several available salt-analysis methods, extraction and analysis of soluble salts has proved to be the most reliable, the one least subject to interference from other constituents.

Extraction and analysis of soluble salts involves diluting an oil sample with xylene and extracting the mixture with boiling deionized water. The extraction funnels then are placed in a water bath at 140 to 160°F for phase separation. If necessary, acidification, electrostatic cells, or chloride-free emulsion breaker may be used to enhance separation. The aqueous layer is removed and filtered if it is cloudy or if entrained oil is present. Then it is titrated with dilute silver nitrate (0.01N), using a chromate indicator under incandescent lighting. The titration procedure is known as the Mohr method and is described in API RP 45.^[8] Endpoint recognition requires a practiced eye when using dilute titrant. If available, ion chromatography also may be used for chloride determination. Ion chromatography is extremely accurate for determining small quantities of chloride, but its equipment is more expensive than titration equipment. Because of the widespread occurrence of chloride in nature and the very small quantity being measured in this method, take care to avoid contaminating the sample during handling.

Another commonly used method is the spectrophotometric determination of the metals sodium, calcium, and magnesium. These techniques use atomic absorption or inductively coupled plasma and are accurate and highly automated; however, they do not distinguish between water-soluble salts and those that exist primarily in the oil phase (e.g., metal-organic compounds or mineral precipitates), so their results might relate poorly to desalter performance.

Emulsion-Treating Equipment

Designing equipment or a system for treating crude-oil emulsions and sizing each piece of equipment for a specific application requires experience and engineering judgment. Unfortunately, no ideal procedure so far exists to infer from measured properties of the emulsion the most economical treating process, taking into account treating temperature, chemical usage, and the physical size of the treating equipment. For now, an engineer must rely on experience and empirical data from other wells or fields in the area and on laboratory experiments.

For example, it is difficult to predict the economic balance between the amounts of chemical and heat to use to destabilize the emulsion and aid in coalescence. Almost all emulsion-treating systems use demulsifying chemicals. Generally, the lower the treating temperature, the more chemical that is required to treat the emulsion. In many areas of west Texas, U.S.A., and in the Gulf of Mexico, some operators do not add heat to treat the relatively light crudes that are produced, whereas other operators under the same conditions do add heat when treating similar crudes, to minimize chemical cost and the size of the emulsion-treating equipment.

Another economic balance to consider involves coalescence-promoting factors (e.g., chemicals, water wash, heat, and coalescing plates) and treating-vessel size. The larger the treating vessel, the smaller are the water droplets that are sebrble from the emulsion. Thus, using coalescing aids might reduce the required equipment size by increasing the size of the water droplet that must be separated from the oil to meet the required quality. Of course, the vessel-cost savings must be weighed against the increased capital and operating cost (e.g., fuel and increased maintenance because of plugging) of the coalescing aids.

For design purposes, bottle tests in the laboratory are useful for estimating treating parameters such as treating-temperature ranges, demulsifier volume, settling time, and retention time. Unfortunately, bottle tests are static in nature and do not model closely the dynamic effects of water droplet dispersion and coalescence that occur in the actual equipment because of flow through control valves, pipes, inlet diverters, baffles, and water-wash sections.

When evaluating empirical data from similar wells or fields, the designer should recognize that the emulsion-treatment temperature might not be as important as the viscosity of the crude oil at that temperature. By observing an existing system, knowing the viscosity of the crude oil at treating temperature, and calculating from the flow geometry and Stokes’ law the minimum size of water droplet that can be settled from the crude oil, an oil-treating system can be designed that will heat the emulsion to the temperature required to obtain the same viscosity that exists in the sample field. Then the equipment described in the next section can be selected and sized so that all water droplets that are larger than the calculated minimum diameter can be separated from the oil.

Because of the uncertainties in scaling up from laboratory data and inferring designs from empirical data from similar wells or fields, a new treating system should be designed with either larger equipment or more heat-input capacity than is calculated to be necessary. How much "overdesign" should be built into the treating system depends on how the cost of the extra capacity weighs against the risk of not being able to treat the design throughput.

Several types of equipment or systems might resolve an emulsion satisfactorily, but one might be superior to others because of design, operation, initial cost, maintenance cost, operating cost, and performance considerations. Of course, selecting the fewest pieces of equipment needed and/or the simplest design for each treating system will optimize initial and operating costs. In essence, use the combination of emulsion-treating methods that will provides the lowest chemical use, treating temperature, loss of light hydrocarbons, and overall treating cost, and the best performance. Furthermore, experience and empirical data are a guide as to the optimum combination, but field testing is required to confirm the selections.

Below are described emulsion-treating equipment and systems—FWKOs, storage tanks, settling tanks, vertical and horizontal emulsion treaters, and electrostatic coalescing treaters. Each treating system and its components are available in a wide variety of types, configurations, sizes, component selections and designs, and usages. The design and selection of all the components of a treating system should be made at the time of initial purchase and installation; however, because of the modular design of most emulsion-treating systems, if the selected equipment does not perform as desired or if operating conditions change, additional features usually can be added and/or operating procedures altered to obtain the desired results.

FWKOs

Where large quantities of water are produced, it usually is desirable to separate the free water before attempting to treat the emulsion. This is done using a separator known as an FWKO.

When oil and water are agitated moderately and then allowed to settle, three distinct phases normally will form: a top layer of essentially clean oil with a small amount of water dispersed as very small droplets, a bottom layer of relatively clean water (free water) with a small amount of oil dispersed as very small droplets, and a layer of emulsion in between. As coalescence occurs over time, the amount of emulsion will approach zero. The free water is the water that separates out in three to ten minutes. Free water still might contain small droplets of dispersed oil that might require treatment before disposal. (Equipment for that is discussed in the chapter on Water-Treating Facilities in Oil and Gas Operations in the Facilities Engineering section of the Handbook.)

FWKOs are designed as either horizontal or vertical pressure vessels, but predominantly horizontal. Fig. 3.13 shows a horizontal FWKO. The fluid enters the vessel and flows against an inlet diverter. The sudden change in momentum causes an initial separation of liquid and gas, which prevents the gas from disturbing the settling section of the vessel. In some designs, the separating section contains a downcomer that directs the liquid flow to below the oil/water interface to aid in water-washing the emulsion.

Fig. 3.13—Typical horizontal FWKO. (Courtesy of Energy Recovery Div., Daniel Industries Inc., Houston.)

The liquid-collecting section of the vessel provides time for the oil and emulsion to form a layer of oil at the top while the free water settles to the bottom. When there is appreciable gas in the inlet stream, a three-phase separator can be used as an FWKO. See the chapter on Oil and Gas Separators in this section of the Handbook for a description of vertical and horizontal three-phase separators.

A cone-bottom vertical three-phase separator is used when sand production is anticipated to be a major problem. The cone normally is at a 45 to 60° angle to horizontal. The cone can be the bottom head of the vessel or, for structural reasons, can be installed internally in the vessel. In the latter case, a gas-equalizing line must be installed to ensure that the vapor behind the cone always is in pressure equilibrium with the interior of the vessel. Water jets can be used to dislodge and flush the sand from the vessel.

Oil and water usually separate more quickly and completely in an FWKO when the liquid travels through the vessel horizontally rather than vertically. With vertical flow, the upward-moving stream of oil and emulsion retards the water’s downward movement through it. Horizontal flow permits less-restricted downward movement of the water droplets.

It is possible to add a fire tube to an FWKO (Fig. 3.14) or to add heat upstream of the FWKO. In such cases, although the vessel might be called an FWKO, it actually performs the function of an emulsion treater.

Fig. 3.14—Schematic View of FWKO with heating element in each end.^[1]

Many configurations can provide baffles and maintain levels in an FWKO. A well-designed FWKO will perform the functions described above (i.e., degassing, water washing, and providing sufficient retention time and correct flow pattern for free water to be removed from the emulsion).

Once the free water has been removed, the oil might need further treatment. In many fields that produce light oil, a well-designed FWKO with ample settling time and an effective chemical-treating program can provide pipeline-quality oil; however, further emulsion treatment usually is required downstream of the FWKO.

Storage Tanks

Oil generally should be water-free before it is flowed into lease-storage tanks; however, if the oil contains only a small percentage of water and/or if the water and oil are loosely emulsified, the water could be allowed to settle to the bottom of the oil-storage tank and then be drawn off before oil shipment. This practice generally is not recommended or followed, but for small volumes of free or loosely emulsified water on small leases or for low-volume marginal wells, it might be a practical and economical procedure.

When a storage tank is used for dehydration, the oil is flowed into the tank and allowed to settle. When the tank is full of liquid, flow into the tank is stopped or switched to another tank, and the full tank remains idle while water settles out of the oil. When the water has separated, it is drained from the bottom of the tank and the oil is gauged, sampled, and pumped or drained to a truck or pipeline. No water wash is used with the standard storage tank because its shallowness and the absence of a proper spreader would make a water wash of little or no benefit.

Settling Tanks

Settling tanks that are used to treat oil go by various names. Some of the most common names are gun barrel (named for the protrusion of its central flume), wash tank, and dehydration tank. Their design details differ from field to field and from company to company, but all contain most or all of the basic elements shown in Fig. 3.15.

Fig. 3.15—Typical settling tank with internal downcomer (central flume) and emulsion spreader.^[1]

In the separation tank, the emulsion enters a gas-separation chamber or gas boot where a momentum change causes separation of gas from the emulsion. Gas boots can be as simple as the piece of pipe shown in Fig. 3.15, or they can contain more-elaborate nozzles, packing, or baffles to help separate the gas. If there is much gas in the well stream, using a two- or three-phase separator upstream of the settling tank usually is preferable. In that case, the gas boot must separate only the gas that is liberated while the pressure decreases during flow from the separator to the settling tank.

A downcomer directs the emulsion below the oil/water interface to the water-wash section. Most large tanks minimize short-circuiting by using a spreader to distribute the flow over the entire cross section of the tank. The more the upward-flowing emulsion spreads out and approaches plug (or uniform) flow, the slower will be its average upward velocity and the smaller will be the water droplets that settle out of the emulsion.

There are many types of spreader design. Spreaders can be made by cutting slots in plate, using angle iron, or punching holes in pipe. By separating it into many small streams, the spreader increases the emulsion’s intimate contact with the water and so promotes coalescence in the water-wash section (Figs. 3.16 and 3.17).

Fig. 3.16—Proper design of well-fluid inlet distributor for wash or gun-barrel tank, showing use of small holes in distributor.^[1]
Fig. 3.17—Improper design of well-fluid inlet for wash or gun-barrel tank.^[1]

Most spreaders contain small holes or slots to divide the oil and emulsion into small streams. Large holes (3 to 4 in. in diameter) are much less effective at dividing the stream than small holes are (3/8 to 1 in. in diameter); however, a spreader should be designed so that it does not agitate the fluid so much that shearing of the water droplets in the emulsion takes place, causing the emulsion to become harder to separate. In addition, small holes become plugged with solids more easily and are difficult to clean.

As the emulsion rises above the oil/water interface, water droplets settle out from the oil by gravity. Because there might be very little coalescence above the oil/water interface, increasing the height of the oil-settling section above some minimum to help spread out the flow might not materially affect the outlet oil quality.

Sometimes oil collectors that are similar in design to oil spreaders are used to help establish plug flow. An oil collector must prevent vortexing and should collect oil from the top of the tank in a way that minimizes horizontal movement of the oil.

Some tanks discharge the water through a water collector that is designed to cause the flow of water to more nearly approach plug-flow conditions. The water outlet collector must prevent vortexing of the water and minimize horizontal movement of the water. The water outlet collector should be located near the tank bottom. There must be enough vertical distance between it and the inlet spreader to allow sufficient clarification of the water, and it should be 6 to 12 in. above the tank bottom to allow for accumulation of sand.

Some tanks have elaborate sand-jetting and drain systems that sometimes are part of the water-collector system. Making these drains operate satisfactorily can be difficult because the water flow to each drain must be on the order of 3 ft/sec to suspend the sand. Sand drains might lengthen the time between tank cleanings, but the additional cost of sand drains in tanks might not be warranted.

In Fig. 3.15, the oil/water interface is established by an external adjustable weir, sometimes called a water leg. The height of the interface is determined by the fluid properties and by the difference in height between the oil outlet and weir. It may be calculated from Eq. 3.5:

....................(3.5)

where h_wd = the height of water draw-off overflow nipple in the weir box above the tank bottom, ft; h_oo = the height of the clean oil outlet above the tank bottom, ft; h_ww = the desired height of the water wash in the tank above the tank bottom, ft; γ_o = the specific gravity of the oil; and γ_w = the specific gravity of the water.

Water legs are used successfully for emulsions where the gravity is above 20°API and there is sufficient difference in gravity between the oil and water. Marginal performance is obtained on oil between 15 and 20°API. Below 15°API, water legs normally are not used.

It also is common to control the oil/water interface with internal weirs or with an interface liquid-level controller and a water-dump valve. In heavy oils, electronic probes most often are used to sense the interface and operate a water-dump valve. In lighter oils, interface floats that sink in the oil and float in the water are more common.

Not all settling tanks contain all the sections and design details described so far. Which ones are used depends on the overall process selected for the facility, the emulsion properties, the flow rates, and the desired effluent qualities. Fig. 3.15 is representative of the majority of settling tanks currently in use, but some tanks have a different flow pattern. A series of parallel vertical baffles from the bottom of the vertical tank to above the oil level (Fig. 3.18) cause the flow of the emulsion to be largely horizontal rather than vertical, so that the water droplets fall at right angles, rather than countercurrent, to the oil flow. Some settling tank designs use a vortex or swirling motion at the inlet of the tank to aid in coalescence and settling and to minimize short-circuiting. Many settling tanks help the treatment process by adding heat to the liquid using a direct heater, an indirect heater, or a type of heat exchanger.

Fig. 3.18—Plan view of vertical tank with horizontal flow settling pattern.^[1]

A direct-fired heater, sometimes referred to as a "jug" heater, is one in which the fluid to be heated comes in direct contact with the immersion-type of fire tube or heating element. Direct-fired heaters generally are used to heat low-pressure, noncorrosive liquids. These units normally are constructed so that the fire tube can be removed for cleaning, repair, or replacement.

An indirect-fired heater is one in which the fluid passes through pipe coils or tubes that are immersed in a bath of water, oil, eutectic salt, or another heat-transfer medium that, in turn, is heated by an immersion-type fire tube that is similar to the one used in the direct-fired heater. Convection currents cause the contents of the bath of an indirect-fired heater to circulate. The immersion-type fire tube heats the bath, which heats the fluid that is flowing through coils that are immersed in the bath. When water is used as the bath, using water that is free of impurities will prolong the heater’s life and prevent fouling of the surface of the fire tube and coils.

Indirect-fired heaters are less likely to catch fire than are direct-fired heaters and generally are used to heat corrosive and high-pressure fluids. They usually are constructed so that the fire tube and pipe coil are individually removable for cleaning and replacement. Indirect-fired heaters tend to be more expensive than direct-fired heaters.

Heat exchangers normally are used where waste heat is recovered from an engine, turbine, or other process stream or where fired heaters are prohibited. In complex facilities, especially offshore, a central heat-transfer system recovering waste heat and supplying it through heat exchangers to all process heat demands sometimes is more economical and might be the only way to meet established safety regulations.

Heating the entire stream of emulsion before it enters the settling tank is advantageous because:

After the fluid is heated, it flows through piping and into the flume pipe or gas boot of the gun-barrel tank. This moderate agitation of the heated fluid can help water droplets to coalesce.
The emulsion is heated before it reaches the gun barrel, which aids in removing gas from the oil in the gas boot. This helps maintain quiescence in the settling portion of the gun barrel.
The heater and gun barrel can be sized independently, which allows flexibility in sizing the system.
Water-wash volume in the gun barrel can be adjusted over a wide range, providing additional flexibility.
Continuous flow of fresh fluids through the heater tends to prevent coking and scaling and helps to keep the heating surface clean, which will prolong the heater’s life.

Heat can also be supplied to the system by circulating the water in the water-wash section to a heater and back to the tank. The hot-water-wash section warms the incoming emulsion. A thermosiphon caused by density differences between the hot and the cold water can serve as the driving force for the circulation if the heat source is not far from the tank.

The water also may be pumped to the heater and circulated back through the flume, as shown in Fig. 3.19. In this system, the settling space in the gun barrel might be disturbed by gas released from the oil when it contacts the hot water. It has two advantages. First, the oil will not be overheated because it is heated by the water bath in the gun barrel and never contacts the heating element in the heater. This minimizes vapor losses from the oil and helps to maintain maximum oil gravity. It also minimizes coking and scaling. Second, this system is as safe from fire hazards as a system involving a fired vessel can be because only water flows through the heater. There is no oil or gas in the fired vessel.

Fig. 3.19—Heater and gun barrel in forced-circulation heating method. (Courtesy of Energy Recovery Div., Daniel Industries Inc., Houston.)

Gun-barrel tanks also can be heated directly with a fire tube, as shown in Fig. 3.20, or with internal heat exchangers, using steam or other heat media. A fire tube is a U-tube direct-heating device that is inserted into a liquid to heat it. Heat exchangers can be either pipe coils or plate-type heating elements.

Fig. 3.20—Heated gun-barrel emulsion treater. (Courtesy of Natco Group Inc.)

Most plate-type heating elements are 18 to 32 in. wide and 5 to 8 ft long. They usually are preferred over pipe coils because when they are immersed in oil, their heat-transfer coefficient is 10 to 20% higher than that of a corresponding area of pipe. Further, the gentle agitation from the convection flow of the oil up the surface of the plate-type element assists in coalescence. Plate-type heating elements are available with a wide range of pressure ratings. They can be purchased for steam service or hot-water service, but the same unit should not be used for both because the construction of the cells is different for these two heating media.

Pipe coils are popular because the materials used in their construction usually are available locally; however, they normally cost slightly more than plate-type exchangers, especially in larger installations.

When heated directly, settling tanks operate in a fashion similar to vertical and horizontal emulsion treaters.

Vertical Emulsion Treaters

The vertical unit is the most commonly used one-well-lease emulsion treater. In a typical vertical design (Fig. 3.21), flow enters into a gas separation section near the top of the treater. This section must be sized adequately to separate the gas from the liquid. If the treater is downstream of a separator, this section can be very small. The gas separation section should have an inlet diverter and a mist extractor.

Fig. 3.21—Schematic view of typical vertical emulsion treater. (Courtesy of Natco Group Inc.)

The liquid flows through a downcomer to the bottom portion of the treater, which serves as an FWKO and water-wash section. If the treater is downstream of an FWKO, the bottom section can be very small. If the total wellstream is to be treated, the bottom section should be sized for sufficient retention time to allow the free water to settle out. This will minimize the amount of fuel gas needed to heat the liquid that rises through the heating section.

The oil and emulsion flows upward around the fire tubes to a coalescing section that provides sufficient retention time to allow the small water droplets to coalesce and to settle to the water section. Treated oil flows out the oil outlet. Any gas that is flashed from the oil because of heating flows through the equalizing line to the gas space above. Pneumatic or lever-operated dump valves maintain the oil level. An interface controller or an adjustable external water leg controls the oil/water interface.

Steam must be prevented from forming on the fire tubes. This can be done by using the "40° rule" (i.e., keeping the operating pressure equal to the pressure of saturated steam at a temperature that is equal to the operating temperature plus 40°F). In most treaters, the normal full-load temperature difference between the fire tube wall and the surrounding oil is approximately 30°F. The 40° rule, then, is desirable because it prevents flashing of steam on the wall of the fire tube and provides a 10°F safety margin.

Baffles and spreader plates may be placed in the coalescing section of the treater above the fire tubes. Originally, many treaters were equipped with excelsior or "hay" packs. In most applications, these might not be needed, but a manway may be provided in case a hay pack needs to be added in the field. Excelsior packs largely have been replaced with other coalescing media because of difficulties with disposal of the used excelsior.

Fig. 3.21 shows a treater with a fire tube, but it also is possible to use an internal heat exchanger to provide the required heat or to heat the emulsion before it enters the treater. For safety reasons, some offshore operators prefer a heat-transfer fluid and a pipe or plate heat exchanger inside the treater, rather than a fire tube.

Horizontal Emulsion Treaters

For most multiwell leases, horizontal treaters normally are preferred. Fig. 3.22 shows a typical horizontal treater design. Flow enters the front section of the treater where gas is flashed. The liquid flows downward to near the oil/water interface, where it is water-washed and the free water is separated. Oil and emulsion rise past the fire tubes and flow into an oil-surge chamber. The oil/water interface in the inlet section of the vessel is controlled by an interface-level controller, which operates a dump valve for the free water.

Fig. 3.22—Typical horizontal emulsion treater with vertical flow.^[1]

The oil and emulsion flow through a spreader into the back, or coalescing, section of the vessel, which is liquid-packed. The spreader distributes the flow evenly throughout the length of this section. Treated oil is collected at the top through a collection device that is used to maintain uniform vertical flow of the oil. Coalescing water droplets fall through the rising oil. The oil/water interface level is maintained by a level controller and dump valve for this section of the vessel.

A level controller in the oil surge chamber operates a dump valve on the oil-outlet line, regulating the flow of oil out the top of the vessel and maintaining a liquid-packed condition in the coalescing section. Gas pressure on the oil in the surge section allows the coalescing section to be liquid-packed.

The inlet section must be sized to handle separation of the free water and the heating of the oil. The coalescing section must be sized to provide adequate retention time for coalescence to occur and for the coalescing water droplets to settle through the upward-flowing oil.

Fig. 3.23 shows another design of a horizontal emulsion treater with a different flow pattern, one that minimizes vertical flow of the emulsion. In this treater design, oil, water, and gas enter the top of the treater at the left side (facing the burners) and travel frontward and downward. Gas remains at the top, and oil and water are heated as required. Some heat is applied to the water in this section, but because this section has its own temperature controller, its temperature can be adjusted for optimum performance.

Fig. 3.23—Horizontal emulsion treater with horizontal flow. (Courtesy of Hydrocarbon Research Inc., Long Beach, California.)

The cross section in Fig. 3.23 shows that the emulsion flows under a longitudinal baffle and through a large slot in the partition plate near the front of the treater at the bottom of the fire tube, where it is water-washed. In the right-side compartment of Section A-A, the oil and emulsion flow longitudinally up across the fire tube.

The separation baffle between the heating and settling sections blocks the passage of foam at the top and of emulsion at the bottom. Heated oil travels through a slot in a partition at approximately the centerline of the top fire tube. Free water is allowed to travel under the baffle. Accumulating emulsion at the interface rises to touch the fire tube, which is only 6 in. above the interface. The fire tube heats the emulsion pad, enhancing its coalescence, thereby maintaining a uniform emulsion-pad thickness.

Applying louvered or perforated baffles reduces channeling, skimming, and stratifying. Louvered baffles are stainless-steel sheets that are punched with a louvered pattern that ranges from 15 to 60% open area. They are solid at the top to prevent foaming, or skimming, and extend downward almost to the water. All the emulsion goes through the openings, which impede flow slightly to develop even flow distribution and help coalescence.

A weir and an oil box maintain the oil level in the treater. Water level in the treater is critical; thus, a weir is placed approximately 5 ft from the rear head seam to maintain the oil/water-interface level upstream of it. Adjusting the water-level controller that is downstream of this weir has no effect on the water level in the main treater body upstream of the weir.

Because the emulsion flow path in this design is essentially horizontal, the water particles are not opposed by the upflowing oil, as they are in a treater with a vertical flow pattern. This is especially important in heavy crudes, where the differential specific gravity between oil and water is small and where the settling velocity is low.

Other flow patterns are available if different baffle designs are used in horizontal treaters. The vertical and horizontal flow patterns described above are examples that illustrate the most generally applied concepts. Other methods for heating the emulsion can be used if it is desirable to eliminate the fire tubes.

Electrostatic Coalescing Treaters

AC Field Devices. The first applications of electrically induced flocculation used AC fields in the 12- to 23-kV range. The rapid reversal of polarity in an AC system (every 8.3 milliseconds with 60 Hz power) causes electrically induced corrosion reactions to remain reversible because the reaction products do not have time to diffuse away from the reaction site; however, the rapid reversal of the electrical field also precludes significant drop travel because of electrical forces. The flocculating effect of an AC field is caused by the stretching deformation from the polarization of the water drops. Because adjacent ends of two water drops are oppositely polarized, an attractive force exists that can cause coalescence if the drops are very close together (Fig. 3.24). The dipolar attractive force between drops of equal size can be expressed as follows after simplifying by incorporating typical values for the dielectric constants of water and oil:^[9]

Fig. 3.24—Response of a water drop to an electrostatic field when (A) no field is applied, (B) a moderate field is applied, and (C) an intense field is applied with some drop shattering produced. (Courtesy of Natco Group Inc.)

....................(3.6)

where F = the force of attraction, N; ε = dielectric constant, C²/N•m²; E = the electric field gradient; V/m; r = the drop radius, m; and d_i = the interdrop distance, m.

This equation illuminates the advantages and the weaknesses of an AC field in electroflocculation. Note that the dipolar attractive force depends highly on drop size (as the sixth power exponent testifies), with limited benefit in the coalescence of small drops. Also note the rapid decline in dipolar force with interdrop distance. In an AC field, the efficacy of electroflocculation depends on the ability of diffusion and fluid flow to bring dispersed water drops into close proximity. The AC field is most effective at removing large drops that are close together, and does not significantly affect very small drops; therefore, the AC field is most effective on the high-water-content emulsion at the inlet of a separation vessel and on the collection of large drops that accumulate at the oil/water interface. The oscillating elongation of the drops produced by the AC field also ruptures whatever stabilizing films might have formed, which is particularly advantageous for resolving slowly condensing dispersions in the zone of hindered settling at the oil/water interface.

AC treaters usually use an arrangement of charged horizontal bar gratings or grids to establish the electric field within the vessel. A two-grid system, known as "single hot" AC, uses a lower, charged grid and an upper, grounded grid that are separated by 6 to 8 in. (sometimes adjustable) (Fig. 3.25). The incoming oil is introduced near the oil/water interface and flows upward through the grids to an outlet collector. The water layer also is grounded through the shell of the vessel. An AC field then is established between the water and the charged grid and between the charged grid and the grounded grid. Oil flows across both of these fields as it transits the vessel.

Fig. 3.25—A conventional AC electrostatic dehydrator. (Courtesy of Natco Group Inc.)

Newer designs, known as "double hot" and "triple hot" AC systems, use multiple charged grids to improve efficiency and throughput. A technique known as "high-velocity" AC also is used to spread the incoming emulsion between the energized electrodes. All these variations serve to increase the retention time of the dispersion within the most intense zone of the electric field, and they depend on diffusion to carry polarized drops within the range of dipolar forces (Fig. 3.26).

Fig. 3.26—Improved AC dehydrators that incorporate increased field depth. (Courtesy of Natco Group Inc.)

There is a limit to the usable field strength for coalescence. At very high field strengths, enough energy is imparted to the drops to induce shattering rather than coalescence. This instability limit is described by the following proportionality^[10]:

....................(3.7)

where E_c = the critical voltage gradient, V/m; ε = the dielectric constant, C²/N•m² ; σ = the interfacial tension, N/m; and d = the droplet diameter, m.

Transformers for AC treating usually are built with at least 16 and 23 kV secondary taps (connections to the secondary coil to allow the use of different output voltages). Single-phase transformers usually are used with multiple transformers that are wired for load balancing on large installations. In some cases, three-phase transformers are used with multiple grids that are wired to accept different phases. To protect the transformers during process upsets, an internal reactor equal to 100% of the transformer reactance is placed in series with the primary winding. As the load on the transformer increases, the voltage across the inductor increases, limiting the current to the transformer. A transformer with 100% reactance can tolerate a short circuit on its secondary output without overheating. An unfortunate side effect of this protection scheme is that when the process is most in need of power, the reactor prevents the transformer from delivering it.

Extended retention time in the high-intensity field also can be achieved by using an electrode array of vertically hung parallel plates with alternate plates that are charged and grounded (plate AC). Another benefit of this geometry is that it reduces electrical retardation of the settling water drops because the electrostatic field is perpendicular to the fluid flow. This technique has proved useful as the first stage of multistage systems in which the feed stream contains high levels of dispersed water.

Table 3.2 summarizes AC configurations and applications.

Table 3.2

Fig 3.27

Combination AC/DC Treaters. In a DC field, the electrical forces are sustained and unidirectional, so that polarized drops can move along the lines of force of the field. For many years, the potential for galvanic corrosion when a DC field is impressed across a conductive liquid made DC fields applicable only to treatment of refined oils with high resistivity. In an AC field, the rapid reversal of polarity causes corrosion reactions to remain reversible, with no resultant net corrosion. In the early 1970s, a system was developed for combining the freedom from galvanic corrosion of the AC coalescer with the advantages of drop transport of the DC system.^[11]

This device’s electrodes are parallel plates that are connected to oppositely oriented diodes, so that alternate plates are oppositely charged. Because both diodes are connected to the same end of the transformer secondary winding, the plates are charged on alternate half cycles of the AC power supply (Fig. 3.27). The other end of the secondary winding is connected to ground, so that the electric field that is projected from the electrode array to the vessel remains AC. Also, the AC field still is available at the oil/water interface to assist in condensation of the settling dispersion, as well as to provide coalescence and settling of the loosely dispersed water fraction of the incoming crude oil.

Fig. 3.27—Combination AC/DC dehydrator. (Courtesy of Natco Group Inc.)

The DC field then is available to supply translational energy to the very small drops, which approach the nearest plate, become charged, and are either coalesced onto the film on the electrode or repelled toward the opposite plate, to collide with its oppositely charged drops. Rapid coalescence ensues. Because the plates can only charge on alternate half cycles, the current between them is limited to discharge of capacitively stored energy and is unable to produce significant electrolysis. These plates also are operating in relatively dry oil, which further limits current dissipation from them. This system is used widely for dehydration and desalting.

Transformers for AC/DC treaters are like those used for AC treaters, but also have an oil-filled secondary junction box that houses the diode packs.

Table 3.3 summarizes AC configurations and applications.

Table 3.3

Combination Electrostatic/Mechanical Dehydrators. Fig. 3.28 shows a combination electrostatic/mechanical dehydrator that uses electrostatic and mechanical coalescing mechanisms. The electrostatic section is constructed like an AC/DC coalescer, but with two major differences: the flow through the electrodes is downward, and the flux is higher than with normal sizing criteria. These changes cause a downward acceleration on the settling water drops and a residual electrostatic charge on the drops after they move out of the electrode area. The liquids then flow horizontally through a matrix-plate coalescing section. The residual charge on the drops causes an attraction between the drops and the coalescing medium, thereby producing rapid coalescence.^[12]

Table 3.2—Summary of AC/DC Configuration and applications

Fig. 3.28—An electromechanical heater-treater (dehydrator). (Courtesy of Natco Group Inc.)

Table 3.4 summarizes available electrostatic/mechanical dehydrator configurations and applications.

Table 3.4

Pulsed Field Treaters. Treaters may be fitted with a power supply that has a voltage controller. The controller combines a 35% reactance transformer with an electronic device that senses the load being drawn and adjusts the power to the transformer accordingly.^[13] The power adjustment is made by silicon-controlled rectifiers (SCRs), which switch the power on and off rapidly so that very short bursts of high power are interspersed with "off" periods. Therefore, the transformer does not exceed its average heat dissipation rating. This allows power to be delivered to the process under upset conditions without compromising the integrity of the power supply. The controller also can be programmed to modulate power to the process.

This controller’s action differs from a 100% reactor in that it reduces power on the basis of time rather than by variation of maximum voltage. Short bursts of high-intensity energy are applied to the emulsion with the duration of the pulses limited to maintain an average power output within the rating of the transformer. Research^[14] indicates that much of the coalescing action of an electric field occurs during the rapid change of voltage with time (high dV/dt) during an electrical pulse; therefore, much of the electric field’s coalescing ability is preserved during this pulsing action. The controller also allows programming of various electric-field vs. time profiles for cyclical operations.

Counterflow Desalters. Manipulating the drop-size/field-strength relationship allows the electric field to be used both to mix and to separate. Drops of dilution water that have been subjected to high field strength can be sheared to uniform sizes by the combination of translational shear and shattering because of charge-density instability. Then, as the field strength is lowered, they coalesce with the entrained brine and settle out (Fig. 3.29).

Fig. 3.29—Counterflow desalter showing the effect of the field on dilution water drops. (Courtesy of Natco Group Inc.)

Because most of the contact between the brine and the dilution water occurs while they are coalesced together, multiple coalescence events contribute much more to contact efficiency than does greater shear in a mechanical device. Cycling the field strength allows the process to be repeated many times during the retention time of the drops within the electric field. As a result, the contact efficiency of a multistage mixer/settler can be realized using a single vessel.^[15] Because the electrical force is concentrated on the dispersed phase, loss of energy because of shear of the continuous phase is reduced. Turndown and low dilution-water flow rates are readily accommodated.

Unlike conventional systems, which are restricted to concurrent flow by the nature of the mixing device, the electrostatic mixing system operates with countercurrent contact between the dilution water and the crude oil. Countercurrent flow provides contact between the freshest water and the cleanest oil, which ensures maximum effectiveness of the dilution water. This flow pattern also places fresh water near the outlet, so that inadvertent carry-over will be free of salt.

A counterflow desalter such as the one in Fig. 3.30 incorporates field-strength control, electrostatic mixing, and countercurrent flow. It uses composite electrodes and a voltage controller, both of which have been used effectively and reliably in oilfield dehydration systems for many years.

Fig. 3.30—Cut-away diagram of a counterflow desalter, showing the overhead dilution-water distributor. (Courtesy of Natco Group Inc.)

Using composite electrodes of varying conductivity is one of several approaches to controlling field strength. High field strength exists across zones of high electrode surface conductivity, and reduced field strength is found in the regions of low electrode surface conductivity. The desired conductivity patterns can be produced by using electrodes constructed of composite materials the surface composition of which can be adjusted in manufacture to provide these patterns. Such electrode plates have the advantage of maintaining a graduated field strength under a range of operating conditions. They also are self-limiting under arcing conditions. A metal grid array will be completely discharged by an arc, with loss of field in the entire vessel. Because an arc on a composite grid must be fed through a surface resistance, it is quickly quenched, and only the plate area in the immediate vicinity of the arc is discharged. Slippage because of temporary loss of field is largely eliminated.

Another method for controlling field strength is to vary the transformer output voltage to create a time-based field decay, rather than a spatial variation in strength. Because this method is time-based, it easily can be tailored to the kinetic needs of the process. It also can be used to eliminate excessive "hold-up" of small drops in the zones of high field intensity, which could lead to arcing if unchecked. The electrostatic mixing process is most successful when both the composite plate technology and the modulating controller are used. The mixing and coalescing process has four stages, each of which has unique field-strength requirements for optimum performance (Fig. 3.31):

Dispersing: A fast voltage ramp-up to the mixing voltage. This rapidly reduces the large drop population and coalesces small drops.
Mixing: Sustained high-intensity field for maximum drop subdivision and dispersal.
Coalescing: Voltage ramp-down permits optimum growth of drops. It is in this stage that most of the contact between the dilution water and the entrained brine occurs.
Settling: Sustained low-intensity field for drop growth and sedimentation and for control of aqueous phase hold-up between the electrodes.

Fig. 3.31—Voltage modulation in counterflow desalting, showing drop breakup (mixing), drop growth (coalescence), and drop sedimentation (settling). (Courtesy of Natco Group Inc.)

A voltage controller can be used to adjust these stages for optimum intensity and duration. Often it is necessary to effect a small compromise between dehydration (coalescing and settling) and contact efficiency (dispersal and mixing). The compromise is small because in the presence of countercurrent flow, the water carry-over that is produced by intense mixing is mostly fresh water, so that desalting efficiency is undiminished.

Countercurrent flow is essential for realizing the full benefit of multiple mixing and coalescing stages. Achieving this benefit requires introducing dilution water above the electrodes in the dry-oil zone. The water must remain as coarse drops in this area to prevent carry-over. Uniform distribution is desirable, although the electric field produces some distribution and will overcome mild maldistribution.

The simplest way of spreading the dilution water above the electrodes is through a system of laterals that have orifices sized to produce a small pressure drop at design flow rates. This system usually requires less dilution water because of increased contact efficiency. Injecting excess water into the feed stream sometimes provides other benefits (e.g., reduced upstream heat-exchanger fouling, satisfaction of solubility requirements of water in oil as the temperature increases, and crystalline-salt removal).

Power Consumption. The power expended in electrostatic coalescence is consumed largely by current flow through the conductive liquids. This power mostly is converted to resistive heating; little of it actually is used in the coalescence reaction. Transformers are sized according to power-flux criteria, and adjustments are made for known characteristics of the oil to be treated and the operating temperature. Remember, though, that dehydrator and desalter transformers are sized conservatively to allow them to operate in the lower 30% of their capacity to accommodate reactive losses associated with the transformer protection scheme. The operating load therefore is roughly 30% of the connected load.

Table 3.5 summarizes available counterflow-desalter configurations and applications.

Table 3.5

Operational Parameters

Chemical Treatment. Chemical treatment with demulsifiers is used to counteract the natural surfactants present, and wetting agents or other chemicals sometimes are used to carry the suspended solids into the water layer. The presence of a band of emulsion in centrifuged samples indicates that further chemical treatment might be needed.

Operating Temperature. Operating temperature is used as the primary control of viscosity in an oil dehydrator or desalter. The lower the viscosity, the better the performance because drag on the settling drops is reduced. As a rule of thumb, the maximum viscosity for effective dehydration usually is assumed to be approximately 20 cSt, whereas the maximum viscosity for effective desalting is approximately 7 cSt. The temperatures at which these viscosities are obtained, therefore, are the minimum operating temperatures for these operations. Lower viscosities are desirable, but care should be taken not to adversely affect differential density between the phases, which also is a function of temperature.

Process Flux. The process flux is the volume of oil per unit of time that passes through a unit area as measured at the horizontal longitudinal plane through the vessel centerline. Because in most treaters the settling water drops must fall through the rising oil, the minimum drop size that is capable of achieving a net downward velocity increases as process flux increases; therefore, achieving high process flux (minimum vessel size) requires coalescing the drops to larger sizes, reducing the viscosity, and maximizing differential density to produce high sedimentation rates.

Subsytems

Power Supplies

Transformers. Transformers used in dehydrator and desalter power supplies must be capable of sustaining a short-circuited output without damage or overheating. This protection normally is derived by including a saturable core reactor sized commensurately to the reactance of the transformer winding in series with the primary winding of the transformer. As the primary current increases, the voltage drop across the reactor increases; therefore, failures in the vessel electrical components or process upsets causing high conductivity will not damage the transformer. Transformers in this service also experience high mechanical stresses from rapidly fluctuating loads and must be constructed with cores and windings that are mechanically solid and highly resistant to vibration.

Controllers. A weakness of electrostatic coalescers has been their means of protecting the electrical system in the event of excessive power requirements during short-term upsets. Unfortunately, the reactor-based protection scheme described above effectively reduces power input to the vessel precisely when it is most needed.

To counteract this, an electronic controller was developed that can sense the load demand and modify the power input to the transformer. This voltage controller differs from the reactor in that it reduces power on the basis of time rather than by uniformly diminishing output. Short bursts of high-intensity energy are applied to the emulsion, and the duration of the pulses is limited to maintain an average power output within the rating of the transformer. This action continues to provide coalescing energy even during times of process upset.

The voltage controller also assists with the necessary compromise between field strength required for adequate translation of small drops and field strength sufficient to produce subdivision of large drops. As drop size increases and the surface-to-bulk ratio decreases, surface tension becomes unable to maintain rigidity of the drop, and viscous drag on the moving drop causes deformation. As velocity or drop size increases, this deformation, in concert with electrically induced perturbations, becomes sufficient to cause the drop to shatter. At any given field strength, there is a range of stable drop sizes that is limited at the lower end by the ability of the field to transport the drop, and at the upper end by what drop size can be transported without shattering. An ideal arrangement would be a field with a high-intensity zone for coalescence of very small drops, followed by gradually decreasing field strength for shifting the equilibrium drop size range to large values. To accomplish this, the controller varies the transformer output voltage to create time-based field decay. In addition to providing optimum field strength for coalescence of a wide range of drop sizes, the controller also can be used to provide high-intensity fields that are suitable for both mixing (in the case of counterflow desalters) and dehydration.

Insulators

Entrance Bushings. Entrance bushings are insulated pressure-sealing devices that conduct high voltage into the desalter vessel. Bushings are constructed of perfluorocarbon because of its superior resistance to fouling by foreign substances such as suspended solids or precipitated organic materials. If such materials collect on the surface of the insulator, a resistive electrical path will form that will conduct a small current and produce localized heating. This heating can cause the formation of a carbonized track along the insulator surface that ultimately will cause insulator failure. The perfluorocarbon portion of the bushings must remain submerged during operation to avoid plasma erosion of the insulator material.

Electrode Hangers. Electrode hangers are insulating devices that mechanically support the electrostatically charged elements inside the treater or desalter vessel. They are available in two designs: standard hangers and high-temperature hangers.

Standard hangers use a 1-in. diameter perfluorocarbon rod with threaded end caps that are attached to swivels and J-hooks. They are widely used on oilfield treaters and desalters that operate at temperatures < 250°F. Loading is adjusted on the basis of temperature. Cast virgin perfluorocarbon is strongly recommended for this service. If extruded rod is used, ensure that "poker chip" discontinuities in density do not occur in the rod.

High-temperature hangers are used in applications with temperatures of up to 300°F. These are made of 2-in.-diameter cast virgin perfluorocarbon rod.

Electrodes

Electrodes are devices that provide direct contact between the electrical system and the process fluids. Often these are referred to as "grids" because of the nature of the electrodes that originally were used in AC field treaters and desalters. Several types of electrodes now are in general use.

Bar Grating, or Grids. Electrodes made of rectangular arrays of perpendicular steel rods or small-diameter pipes were the original grids of electrostatic treaters, and they remain in widespread use in AC field devices. Generally, several of these are hung in vertically separated horizontal planes above the longitudinal centerline of the vessel to increase liquid retention time in the most intense electrostatic field. The spacing between electrodes might be adjustable. These electrodes are inexpensive to construct and easy to carry into the vessel through a manway; however, the openings that are required to provide sufficient electrical clearance through each grid for the supports for the underlying grids can allow a portion of the process flow to bypass the intense area of the electrostatic field.

Steel Plates. Arrays of vertically hung, parallel plates with a plate-to-plate spacing of approximately 6 in. and a plate height of 6 to 10 in. may be used in an electrostatic vessel to achieve high retention time in the intense zone of the electrostatic field. Similar plates also are used to provide the combination AC/DC field.

Composite Plates. Electrostatic coalescence generally proceeds through a mechanism of drop polarization, alignment of the polarized drops, and chaining of these drops along the lines of force of the electrostatic field. These conductive chains lead to frequent electrical discharges or arcing between the electrodes. The arcs are a normal part of the process and, because they are submerged in oil, do not produce any damage; however, a steel electrode array is momentarily discharged by an arc, and if the arcs occur frequently enough (as in a wet emulsion), the electrodes might be discharged long enough to allow slippage of process fluids that have not had adequate exposure to the field.

Composite plate electrodes may be used to increase the water tolerance of the system under such conditions. These electrodes consist of plates of composite (fiber-reinforced plastic) construction with graphite fibers embedded in the central portion of the plate to impart conductivity along the length of the plate. The remainder of the plate contains filler materials that adsorb a layer of water on the plate surface. This adsorbed water layer then becomes the conductive medium along the height of the plate. Because such an adsorbed layer is highly resistive, any arcing that occurs is quenched quickly. As a result, only the immediate vicinity of the arc is discharged, and slippage is almost eliminated. Composite plates are used in all counterflow desalters, as well as on AC/DC processes for increased water tolerance.

Liquid Distribution Systems

Inlet Spreaders. A common type of inlet spreader is an inverted trough with distributor holes in the upper part of the trough (Fig. 3.32). Flow into the trough depresses the oil/water interface inside the trough to provide a hydrostatic head for creating uniform flow distribution. Changes in flow are reflected in changes in hydrostatic head, allowing for uniform distribution over a wide range of flow rates. Another advantage of the inverted trough is its ability to discharge free water and heavy solids directly out the bottom, without passing them through the shear of the orifices. The spreader is designed according to Eq. 3.8:

Fig. 3.32—Typical box-type inlet distributor in (a) a heater-treater and (b) an unheated dehydrator. (Courtesy of Natco Group Inc.)

....................(3.8)

where q = flow, ft³/sec; A = the area of diffuser holes, ft²; C_o = the orifice factor (0.6 to 0.7); g = gravitational constant = 32.2 ft/sec²; h = head, ft; γ_w = the specific gravity of brine; and γ_o = the specific gravity of oil.

Another common spreader configuration uses perforated pipes as the inlet distributor (Fig. 3.33). Pipe spreaders are preferable when vessel motion might be a factor (e.g., in floating production systems). The number, size, and distribution of the orifices are chosen so as to achieve uniform distribution across the vessel. In recent years, application of computational-fluid-dynamics (CFD) techniques to spreader design have enabled the design of highly efficient spreaders. Commonly used pressure drop across distributor orifices is 5 to 6 in. of water column for inverted troughs and 0.5 to 1.0 psi for perforated pipes.

Fig. 3.33—Typical perforated-pipe inlet distributor and oil outlet collector. (Courtesy of Natco Group Inc.)

Outlet Collectors. Most vessel designs provide for a treated-oil collector in the upper part of the vessel. This collector is either a perforated pipe or a channel with perforations, and is designed according to Eq. 3.9:

....................(3.9)

where D = hole diameter, in., and n = number of holes.

Dilution-Water Spreaders. Counterflow desalters incorporate a header/lateral spreader system for injecting dilution water above the electrodes. The electrostatic field provides some distribution of the counterflowing dilution water, and the size and spacing of the orifices are adjusted to assure uniform distribution.

Instrumentation and Safety Systems

Safety Grounding Floats. Safety grounding floats are floats that are mechanically linked to grounding switches inside the electrostatic-treating vessel. These devices ground the electrical systems inside the vessel upon loss of liquid level. They ensure that no electrically energized components are exposed to the gas phase and that the electrodes are not energized accidentally during personnel entry into the vessel.

Low-Level Shutdowns. Shutdown switches may be installed to shut off transformer power in the event of liquid-level loss, or to shut down the process in the event of high or low interface level. These switches may be located in external cages or inserted through nozzles.

Interface Controls. Several types of interface control are available, including weighted floats, capacitance probes, conductivity probes, and radio frequency (RF) probes. What control is selected for an application depends on crude oil characteristics, compatibility with central control systems, and operator preference. Many installations now use the RF probes. They can be used for interface control, high- and low-level interface alarms, bottom-sediment detection, and upstream anticipation of feed-stream changes.

Solids-Removal Systems

Because dehydrator and desalter vessels are designed to promote sedimentation, suspended solids in the feed stream also tend to settle out of the liquid stream. If the solids are water-wetted and heavy, they tend to settle through the interface and collect on the bottom of the vessel. In an oilfield situation, these solids often consist primarily of fine sand, whereas in a refinery, they usually are fine silts. Corrosion products might be present in both. If the solids are oil-wetted or are of a density between that of oil and water, they tend to collect as a sludge layer at the oil/water interface and usually are accompanied by poorly resolved emulsions. Either case eventually requires removal of the solids from the vessel to prevent process upsets. These solids could consist of mud, silt, sand, salts, asphaltenes, paraffin, and other impurities that are produced with crude oil and accompanying water. When present in small quantities, these impurities add little to the treating problem; however, when present in appreciable quantities, they might make the treating problem difficult and expensive, and might require the use of special equipment and techniques.

It is good practice to equip all treating vessels with cleanout openings and/or washout connections so that the vessels can be drained and cleaned periodically. Larger vessels should be equipped with manways to facilitate cleaning them. Steam cleaning might be required periodically, and acidizing may be necessary to remove calcium carbonate or similar deposits that cannot be removed by hot water or by steam cleaning.

One of the most likely causes of difficulty in operating fired emulsion-treating vessels is the deposition of solids on fire tubes and nearby surfaces. If such deposits cannot be prevented, these surfaces should be cleaned periodically. The deposits insulate the fire tube, reducing heating capacity and efficiency. They also can cause accelerated corrosion and failure of the heater tubes.

Of the salts commonly found in oilfield waters, the chlorides, sulfates, and bicarbonates of sodium, calcium, and magnesium are predominant. The most prevalent of the chlorides is NaCl, followed by calcium and magnesium chloride. These salts can be found in nearly all water associated with crude oil. Salts seldom are found in the crude oil; when they are present, they are mechanically suspended, not dissolved, in it. An exception to this is organic salts (e.g., naphthenates).

Emulsion-heating equipment is particularly susceptible to scaling and coking. These depositional processes are distinct, but might occur simultaneously. Also, one can hasten the other.

Calcium and magnesium carbonates and calcium and strontium sulfates readily precipitate on heating surfaces in emulsion-treating equipment by decomposition of their bicarbonates and the resultant reduced solubility in the water carrying them. They are deposited in pipes, tubes, and fittings, and on the inside surface of treating vessels. Maximum deposition occurs on the hottest surfaces (e.g., heating coils and fire tubes).

Scale deposition also might occur when pressure on the fluid is reduced. This is the result of release of CO₂ from the bicarbonates in salt water, which forms insoluble salts that tend to adhere to surfaces of equipment that contain the fluid.

Coke generally is not a primary fouling material; however, when deposits of salt, scale, or any other fouling material build up, coking begins as soon as the insulating effect of the fouling material causes the skin temperature of the heating surface (fire tube or element) to reach 600 to 650°F. The coke that forms aggravates fouling and reduces heat transfer. Once coking starts, a burnout of the fire tube might follow quickly.

In areas where fluids cause considerable scaling or coking, such deposits can be minimized by decreasing the treating temperature or by using chemical inhibitors, properly designed spreader plates, and favorable fluid velocities through the equipment. Arranging the internals of the equipment so that all surfaces are as smooth and continuous as possible also will reduce such deposits. For trouble-free operation of equipment over a long time, the operator periodically should inspect the equipment internally and clean its surfaces as required.

Mud-Was or Sand-Jet Systems. It is common to shut down and drain vessels periodically for cleaning. Sand can be removed from the unit with rakes and shovels or with a vacuum truck. The use of sand pans, automated water jets, and drain systems can eliminate or minimize the problem of sand and silt in emulsion-treating vessels, but it is very difficult to eliminate sand buildup in large-diameter tanks.

A sand pan is a special perforated or slotted box or enclosure that is located in the bottom portion of a vessel or tank. Sand pans are designed to cover the area of the vessel that the flow of discharging water will clean. Often they are designed to work with a set of water jets. The sand pans for horizontal vessels usually consist of elongated, inverted V-shaped troughs that are parallel with and on the bottom of the vessels and that straddle the vertical centerline of the vessel. In the design in Fig. 3.33, the sand pans have sides that make a 60° angle with the horizontal. The bottom edges of the sloping sides are serrated with 2-in. V-shaped slots and are welded to the interior of the shell of the treater. Most sand pans used in horizontal vessels are 5 to 10 ft long.

Sand pans without a water-jet system might satisfactorily remove sand from some vessels; however, vessels should be equipped with a water-jet system, in addition to sand pans, to assist sand removal from the vessel. Fig. 3.34 illustrates typical sand pans with a water-jet system.

Fig. 3.34—Sand pans and water-jet system in a horizontal vessel. (Courtesy of Natco Group Inc.)

In vertical vessels, the sand pan can be a flanged and dished head approximately one-third the diameter of the vessel in which it is concentrically located. The sand pan usually is serrated around the periphery, where it is welded to the bottom head of the vertical vessel concentric with the water outlet.

Water jets usually are designed to flow 12 to 20 U.S. gal/min of water through each jet with a differential pressure of 35 to 100 psi. Standard jets are available for this service that have a 60° flat fan jet pattern. The jets usually are spaced on 12- to 24-in. centers. The water jet header is U-shaped so that the vessel is cleaned on both sides of the sand pan simultaneously. The water jets and sand-dump valves can be programmed to operate all at the same time or in sequential cycles.

One problem in removing sand from vessels is that very few, if any, water-discharge-control valves can withstand for long the abuse of sand-cutting during the water-discharge period. A partial solution is to arrange the instrumentation to open and close the water-discharge control valve on clean, sand-free water and to use special slurry-type valves.

The most sophisticated sand-removal systems use programmable logic controllers to select the proper time intervals between dumps and to automatically control the length of the water/sand-discharge period. The timing must be coordinated with the water-jet system and the normal water-dump controller. A properly designed sand-removal system with proper water jetting and water/sand dumping can operate for many years without needing to be shut down to clean out sand or to repair or replace the dump valve.

Most emulsion-treating systems that handle large volumes of sand should not rely on hand or nonprogrammed operation for sand removal. If the operator fails to activate the dump valve often enough, sand will cover the sand pans and plug or partially plug the water outlet, and the drains will become inoperative. With sand pans in the treater but without a programmer, large volumes of sand usually will cause trouble by plugging or partially plugging the water outlets and/or by cutting or wearing away the drain valve.

Because the amount and type of sand vary greatly, the length and frequency of the water jetting and dumping cycles must vary to suit local conditions. Most of the coarser sand will settle out in the inlet end of the treater; the fine sand will settle out near the outlet end of the treater. It might be necessary to cycle the water jets and drain valves near the inlet end of the treater three to four times more frequently than those near the outlet end. Many timers are set for 30 minutes between jetting and dumping cycles and for 20- to 60-second jetting and dumping periods.

In refinery settings, sand jets usually are referred to as mud-wash systems.

Interface-Sludge Drains. Interfacial buildup, sometimes referred to as sludge, is material that can collect at or near the oil/water interface of emulsion-treating tanks and vessels. Interfacial buildup can contain paraffin, asphaltenes, bitumen, water, sand, silt, salt, carbonates, oxides, sulfides, and other impurities mixed with unresolved emulsion. It can be removed from the vessel through a drain installed at the interface or by closing the water-dump valve and floating it out to a bad-oil tank for further processing or disposal. Interfacial buildup also can be discharged with the water by opening the water-drain valve, but this can create problems in the water-treatment plant.

Interface-sludge drains are collectors at the oil/water interface that are connected to discharge valves. Interface sludge tends to collect irregularly and often reaches an equilibrium depth that does not impair operation seriously; therefore, the need for draining interface sludge is best determined by regular monitoring of the interface depth and condition, using samples from the trycocks. The presence of a continuously increasing interface layer or one that contains a high concentration of suspended solids indicates a need for draining.

Draining must be done very slowly and must be carefully monitored to avoid drawing excess oil or water into the collectors. For this reason, it is best done manually. Properly used, interface-sludge drains can reduce the load on the downstream water-treatment facilities by redirecting the high-oil- and high-solid-content material into a slop-oil system, where it can be batch treated more effectively with heat and chemicals.

Mixing Devices

An important facet of desalting is achieving contact between the entrained water in the crude oil and the dilution water that is used to wash the oil.

Mixing Valves. Typically, the dilution water is added to the oil upstream of a valve. The water is injected into the oil flow line through a distributor. The differential pressure across the valve then is used to shear the water drops and mix the two phases.

Typical differential pressures are 5 to 20 psi. Although mixing valves generally are satisfactory, they do have some disadvantages. Mixing efficiency generally is low at extremes of phase ratio, so that using small quantities of dilution water (< 2%) might not be feasible; likewise, turndown in flow rate will require adjustment of the valve to maintain contact efficiency. More serious disadvantages include the requisite compromise between mixing efficiency and excessive emulsification and the energy wasted on shear of the continuous phase. Because very small drops act as rigid spheres following flow streamlines, it is unlikely that they will achieve sufficient energy to participate in mechanically induced collisions; therefore, their contribution to the salt content of a crude oil represents a fraction unreachable by means of mixing valves.

Static Mixers. Mixing efficiency can be improved by adding static-mixer elements downstream of the mixing valve to achieve a more homogeneous blend of brine drops and dilution-water drops (Fig. 3.6). Static mixers are series of short, helical baffles mounted in a pipe, with adjacent baffles that have reverse twists. They continually blend the stream at low shear. Because increasing mixing efficiency by increasing the shear rate can lead to emulsification problems, the use of low-shear devices for blending the stream can be an asset, particularly with difficult crude oils. At best, a mixing valve/desalter combination can function as a single-stage mixer/settler.

Electrostatic Mixing. As discussed previously, the electrostatic field also can be used as a mixing device if it is programmed to exceed the critical voltage gradient during a portion of the treating cycle. This is the technique used to achieve mixing under counterflow conditions in the counterflow desalter.

Level Controllers and Gauges

Many liquid-level controllers are available for liquid/gas control and for oil/water-interface control in light-crude-oil ( > 20°API) systems. For interfacial controllers in light crude oils, floats that sink in the oil but float in the water normally are used.

For heavy crude oils, electronic interface controllers have been used very successfully. They operate on the principle of the differences between oil and water electrical conductivity, electrical capacitance, or RF absorption. The most common type, capacitance probes, use the dielectric strength of the fluid in which they are immersed.

Standard-gauge glasses (reflex or transparent) are used on 20°API and higher crude oil. Reflex gauges normally are used for liquid/gas levels, and transparent gauges are used for oil/water levels. Pressure vessels normally use armored-gauge glasses, and tanks use tubular-gauge glasses. Some operators use the tubular-gauge glasses on low-pressure treating equipment. Tubular-gauge glasses normally are furnished on standard low-pressure vessels unless armored gauges are specified.

For API gravities below 20°API, gauge glasses are not recommended, particularly for interfacial service, because they are difficult or impossible to read. In lieu of gauge glasses, a system of sample valves (often called trycocks) is used, with the sample lines all piped to a single point just above a sample box. Generally, the lines are insulated to keep them warm. A nameplate clamped on each sample valve designates the elevation it represents in the treater. The sample box is fitted with a drain line piped to the sump.

Water-in-Oil Detectors (BS&W Monitors)

Several companies manufacture BS&W monitors, devices for detecting and measuring the water content of crude oil. BS&W monitors typically are analog instruments that measure dielectric strength and are designed specifically for determining the water content of crude oil that contains a low percentage of water. They do not operate satisfactorily on streams that contain free water. The monitor provides a water reading that corresponds to the water content of the oil. It can be made to alert the operator, record the reading, and control the BS&W content level if the detected percentage exceeds the field-selectable preset limit.

Operational Considerations

Treating Emulsions From Enhanced Oil Recovery (EOR) Projects

Standard emulsion-treating procedures, equipment, and systems used during primary and secondary oil production might be inadequate for treating the emulsions encountered in EOR projects. EOR methods of oil production [ e.g., in-situ combustion and steam, CO₂, caustic, polymer, and micellar (surfactant/polymer) floods] might cause the production of emulsions that do not respond to treatment that normally is used in primary- and secondary-oil-production operations.

The emulsions from EOR projects usually are treated independently of the primary and secondary emulsions from the same fields. Emulsion-treating procedures, equipment, and systems have been and continue to be developed for use in these EOR projects.

Clarification of Water That Is Produced With Emulsions

Even though a normal (water-in-oil) emulsion exists in the oil-production system, produced water that is separated from crude oil usually contains small quantities of oil. This oil has been divided into small particles and dispersed in the water by agitation and turbulence caused by flow in the formation, into the wellbore, and through equipment; by reciprocation of sucker rods; and by surface transfer pumps. These small particles of oil are suspended in the water by mechanical, chemical, and electrical forces. In most systems, the amount of oil in the untreated produced water varies from an average low of 5 ppm to an average high of 2,000 ppm; however, in some water systems, oil contents as high as 20,000 ppm (2.0%) have been observed. These oil particles usually are between 1 and 1,000 μm in diameter, with most ranging between 5 and 50 μm.

Various methods can be used to remove oil from the produced water: chemicals, heat, gravity settling (skim tanks, API separators, etc.), coalescence (plate, pipe/free flow), tilted plate (corrugated) interceptors, hydrocyclones, flotation, flocculation, and/or filtering. The chapter on Water-Treating Facilities in Oil and Gas Operations in the Facilities Engineering section of the Handbook discusses the details of deoiling the produced water.

Burners and Fire Tubes

The design of burners and fire tubes is important because of the high cost of fuel and the operating problems that can occur when they malfunction. The burner should provide a flame that does not impinge on the walls of the fire tube, but that is almost as long as and is concentric with the fire tube. If the flame touches the fire-tube wall, hot spots can develop, which can lead to premature failure.

Burners should not be allowed to cycle on and off frequently because thermal stresses caused by temperature reversals can damage the fire tube. The combustion controls should be accessible and designed so that the operator can adjust the air and gas easily to achieve the optimum flame pattern and peak combustion efficiency.

A reliable pilot burner is required. Many operators and regulatory agencies require burner safety-shutdown valves that will shut off fuel to the burner in case of pilot failure.

API RP 14C^[16] contains a basic description of recommended safety devices needed for fire- and exhaust-heated units. Consideration should be given to installing safety devices on onshore and offshore fired treaters. Such safety devices include process high-temperature shutdown devices, burner-exhaust high-temperature shutdown devices, low-flow devices and check valves for heat exchangers, high- and low-pressure shutdown sensors, pressure-relief valves, flame arresters, fan-motor-starter interlocks on forced-draft burners, etc.

Every gas-fired crude-oil heating unit should use fuel gas from which liquids have been "scrubbed." In large facilities, a central fuel-gas scrubber or filter can provide such fuel gas to all fired units. Many small facilities are equipped with individual fuel-gas-scrubber vessels for each fired unit. These individual scrubbers typically are 8 to 12 in. in diameter and 2 to 4 ft tall, and contain a float-operated shutoff valve. If liquid enters the scrubber, the float closes a valve and stops gas flow to the burners of the heating unit, thus preventing oil from entering the combustion chamber and thus possibly preventing a fire.

Most fire tubes that transfer heat to crude oil or emulsion are sized to transfer 7,500 Btu/hr per ft², although some manufacturers use heat-transfer rates as high as 10,000 Btu/hr per ft². Fire tubes that transfer heat to the water-wash section of a treater, such as in a vertical treater, are sized for 10,000 Btu/hr per ft², although some manufacturers use heat-transfer rates as high as 15,000 Btu/hr per ft². These higher rates should be used with caution, though, because they can be overly optimistic and thus might lead to undersizing of the required fire-tube area.

The temperature controller, fuel-control valve, pilot burner, main burner, combustion-safety controls, and fuel-gas scrubber should be on a schedule of preventive maintenance, including periodic inspection and cleaning as required.

Deposits of soot, carbon, sulfur, and other solids should be removed from the combustion space periodically to prevent heating-capacity reduction and combustion-efficiency loss. On oil-fired units, the combustion controls, burner nozzles, combustion refractory, air/fuel-control linkages, oil pump, oil preheater, pressure and temperature gauges, and O₂ and/or CO₂ analyzers should be inspected and maintained periodically.

Corrosion

Emulsion-treating equipment that handles corrosive fluids should periodically be inspected internally to determine whether remedial work is required. Extreme cases of corrosion might require a reduction in the working pressure of the vessel, or repair or replacement of vessel and piping. Ultrasonic tests can measure the wall thickness of vessels and piping to detect the existence and extent of corrosion.

Mitigating or controlling corrosion of emulsion-treating equipment usually is accomplished by excluding oxygen, using corrosion inhibitors, applying internal coating, and/or using special metallurgy.

Exclusion of Oxygen. Corrosion rates in most oilfield applications can be kept low if O₂ is excluded from the system. Take care in the process design to install and maintain gas blankets on all tanks and to exclude rainwater from the system. Recycled water from sump systems and storage tanks is a prime source for O₂ entry into the process.

Corrosion Inhibitors. Corrosion inhibitors are materials that, when added in small amounts to an environment that potentially is corrosive to a metal or alloy, effectively reduce the corrosion rate by diminishing the tendency of the metal or alloy to react with the solution. As liquid solutions or compounds, inhibitors can be injected into the flow stream in the flowline, manifold, or production system. The potential for corrosion inhibitors to act as emulsifying agents should be recognized when they are applied.

Cathodic Protection. Sacrificial galvanic anodes commonly are used for cathodic protection. They are made of a metal the relative position of which in the galvanic series causes it to provide sacrificial protection to the steel vessel. Most galvanic anodes that are used in emulsion treaters are 3 to 6 in. in diameter and 3 to 4 ft long, and usually are sized to last 10 to 20 years. Multiple anodes usually are installed in each vessel. They are considered expendable and always are installed in the vessel through a flange or quick coupling so that they can be replaced easily when expended.

The galvanic anodes must be installed so that they are immersed in the water, which serves as an electrolyte. They will not protect the treater if they are immersed in the oil. The anodes must "see" all metal surfaces that are to be protected (i.e., there must be no obstructions between the anodes and the surfaces they are to protect). Each anode should be located as near as is practical to the center of the compartment or area they are to protect.

An impressed-electric-current cathodic-protection system also can be used to inhibit corrosion. It is a direct electric current that is supplied by a device that uses a power source external to the electrode system. The DC current can be obtained by rectifying an AC current. When resistivity of the electrolyte is > 25 Ω•cm, an impressed-current system should be considered; however, impressed-current systems are difficult and costly to maintain and usually require skilled technicians.

Electrical current-density requirements for cathodic protection of emulsion-treating vessels usually range from 5 to 40 mA/ft² of bare-water-immersed steel.

Internal Coating. Emulsion-treating vessels can be coated internally for protection from corrosion. It is important that the internal surfaces and the welds of the vessels be properly prepared to receive the coating. A coating system must be able to withstand the physical and chemical environment to which it will be exposed. Coating specifications, application techniques, and final inspection also are very important considerations. Coating alone should not be relied on to prevent corrosion, though, because most coating systems contain some "holidays" (breaks in the coating) or are damaged in shipping or installation.

Steel tanks can be galvanized or lined in the field with fiberglass or other coatings. Some operators use fiberglass tanks in their emulsion-treating process, whereas others feel that using fiberglass creates an unnecessary fire hazard.

Special Metallurgy. In particularly severe environments, such as where large quantities of CO₂ are expected and where O₂ cannot be eliminated from the system practically, corrosion can be minimized by using stainless-steel vessels or an internal stainless cladding in carbon-steel vessels. In most low-pressure applications, stainless-steel vessels are less expensive than clad vessels. It might also be less expensive to use a stainless-steel vessel than one that is internally coated because of the labor required to prepare and coat the internal surfaces of the vessel.

Economics of Treating Crude-Oil Emulsions

The objective of operating oil-producing properties is consistently to deliver the maximum volume of highest-API-gravity oil to the pipeline at the lowest possible cost. Emulsions should be prevented wherever feasible and, when unpreventable, should be treated at the lowest cost.

Implementing the following nine directives can minimize the occurrence and treatment cost of emulsions:

Eliminate production of water with oil where possible and practical.
Minimize the investment in emulsion-treating equipment by studying the treating problem and selecting appropriate treating methods, equipment, and procedures. The emulsion-treating system should be as small as possible, yet capable of adequately handling treating requirements on the lease. A treating system may be oversized initially to allow for future development, lease expansion, and/or increased water production. Such future needs may be anticipated when purchasing treating equipment; however, a needlessly oversized system incurs unnecessary expense and accomplishes nothing more than a properly sized system does.
Where feasible, minimize the amount of oil that is lost with discharged water, and salvage oil from interfacial sludge and tank bottoms. Oil might be discharged with the water as it flows from FWKOs, emulsion treaters, gun barrels, and other treating vessels. The fraction of oil is low, and the oil usually is dispersed in small droplets. Sometimes this oil is pumped with the water to disposal wells or delivered to operators of water disposal companies without recovery or without being credited to the lease. Such oil loss can be minimized by maintaining proper operating variables with adequately sized and maintained vessels and controls and by properly designed water-treating systems.
Minimize chemical-treating costs by using the most appropriate chemical demulsifier compound(s), the optimum quantity of chemical, the proper location and method of injection of chemical, the proper means of intimately mixing chemical with emulsion, and the proper use of heat. Treatment chemicals are not recoverable and are an ongoing expense. Some crude oil can be adequately treated by use of chemical injection with coalescence and/or settling without heat; however, some emulsions require an increased temperature during the coalescing and settling period. A proper balance of chemical and heat helps to provide the most economical and efficient treating system. The chemicals must be intimately mixed with emulsion so that a minimum amount of chemical will provide maximum benefit. Chemicals can be wasted by being injected into the oil in large slugs, rather than being intimately mixed with the emulsions.
Ensure that chemicals added to the produced fluids are compatible. Some corrosion inhibitors can cause emulsions or affect the action of oil-treating chemicals. Chemicals used in produced-water-treating systems might be recycled to the oil-treating system with the skimmed oil and cause emulsion-treating problems there.
Conserve gravity and volume of oil by using the optimum treating temperature, cooling the oil before discharging it to storage, discharging vent gases from treating vessels through cooler oil in stock tanks, maintaining slight gas pressure on treating-system and storage tanks, and using vapor-recovery equipment on vessels and tanks. Resolve crude-oil emulsions at the lowest effective temperature. Excessive heat drives condensable vapors from the oil, and they are discharged with the gas. Loss of these light ends lowers the API gravity of the oil and simultaneously reduces the oil volume. A further disadvantage of overheating is the increased maintenance on treating systems that is caused by hot spots, salt deposition, scaling, and increased corrosion rate, especially of the fire tubes.
Use all treating equipment to the best advantage. Constant and careful observation, testing, supervision, and record keeping will allow emulsion-treating equipment to be used to maximum efficiency. Transferring equipment and making alterations or additions to the treating system can enable more effective use of existing equipment.
Practice preventive maintenance to minimize irretrievable loss of oil production because of downtime for equipment repairs. The more complex the treating system, the greater is the possibility of mechanical failure. Oversized and overly complex systems have a greater failure frequency than do more-appropriately designed, simpler, and more-compact systems.
Exchange information on treating methods and results among company personnel and with other operators, engineering firms, vendors, and chemical-treating companies. Sharing such experience among personnel who are responsible for handling treating problems will lead to lower treating costs.

Cost records are important in oil emulsion-treating operations. Achieving optimum operation of emulsion-treating equipment at minimum cost requires keeping proper records of operating temperatures, pressures, fuel and/or power consumption, chemical usage, performance, etc. Such records should be kept on a daily, weekly, or monthly basis, and should be reviewed regularly and made available for supervisory personnel.

Cost records are important for determining whether an existing system should be modified or should be replaced. Which of these is justified will depend on the efficiency of the system, which is determined using accurate and reliable cost and performance records. Cost records on existing methods or systems assist in determining the type and size of treating systems for new leases. Treatment cost records should make it possible to determine current operating costs, probable installation costs for new systems, and probable future operating costs of similar systems.

Each operator determines what is to be charged to emulsion-treating costs. Table 3.6 outlines items that may be considered part of the database for a cost-accounting system. Some of these items will not apply to all treating systems, and some operators will elect to group some of the categories. A comprehensive general listing is given for those who wish to consider all items of cost. Special systems and conditions might require additional cost items.

Table 3.6

Complete and accurate treatment cost records must consider all factors listed in Table 3.6.

Equipment-investment costs must include the initial cost of all equipment used, including the costs of transporting it to the location and erecting and installing it, and of readying the system for operation. It also includes such items as pipe and pipefittings, valves, grade work, foundations, and fencing.

The labor costs should include supervisory personnel, cost of company and contract labor, and other labor required to obtain, install, and put the treating system into operation. Operating costs should be kept separately from maintenance costs and should include such items as supervisory labor, operating labor, chemicals, fuel, and miscellaneous supplies. Maintenance costs should include the cost of maintaining and repairing all treating equipment (e.g., cleaning, repairing, and painting).

The overall-system-performance section of the record should include an accurate record of the volume of oil treated and the volume of water separated, treated, and handled. This part of the record also should include reference to troubles experienced with the system, as well as a commentary on day-to-day performance of the unit or system.

Nomenclature

A	=	area of diffuser holes, L², ft²
C_o	=	orifice factor (0.6 to 0.7), dimensionless
C_so	=	salt content of the oil, m/L³, lbm/1,000 bbl
C_sw	=	concentration of salt in produced water, ppm
d	=	droplet diameter, L, m or μm
d_i	=	interdrop distance, L, m
D	=	diameter of distributor holes, L, in.
E	=	electric field gradient, mL/qt², V/m
E_c	=	critical voltage gradient, mL/qt², V/m
f	=	fraction of the dispersed phase, dimensionless
f_w	=	volume fraction of water in crude oil, dimensionless
F	=	force of attraction, mL/t², N
g	=	gravitational constant, L/t², 32.2 ft/sec²
h	=	head, L, ft
h_oo	=	height of the clean oil outlet above the tank bottom, L, ft
h_wd	=	height of water draw-off overflow nipple in the weir box above the tank bottom, L, ft
h_ww	=	desired height of the water wash in the tank above the tank bottom, L, ft
n	=	number of holes
q	=	flow rate, L³/t, ft³/sec
q_o	=	oil flow rate, L³/t, B/D
q_w	=	water flow rate, L³/t, B/D
Q	=	heat input, m/T/t, Btu/hr
r	=	drop radius, L, m
t	=	time, t, sec
v	=	downward velocity of the water droplet relative to the oil, L/t, ft/sec
V	=	voltage, mL²/qt², V
γ_o	=	specific gravity of oil, dimensionless
γ_w	=	specific gravity of water, dimensionless
ε	=	dielectric constant, q²/mL³/t², C2/N•m²
μ_e	=	viscosity of emulsion, m/Lt, cp
μ_o	=	viscosity of clean oil, m/Lt, cp
σ	=	interfacial tension, m/t², N/m
ΔT	=	temperature increase, T, °F
Δγ_ow	=	specific gravity difference between the oil and water (water-oil), dimensionless

References

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General References

Al-Muaibid, H. 1995. .Dual Polarity Desalter Testing. Saudi Aramco J. of Technology (Summer): 54.

API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems 1991. Dallas, Texas: API.

API Spec. 12K, Specification for Indirect-Type Oil Field Heaters. 1989. Dallas, Texas: API.

API Std. 1104, Standard for Welding Pipelines and Related Facilities. 1999. Dallas, Texas: API.

Arnold, K. and Stewart, M. 1986. Surface Production Operations, Volume 1: Design of Oil-Handling Systems and Facilities. Houston, Texas: Gulf Publishing Co.

Bailes, P.J. 1981. Solvent extraction in an electrostatic field. Ind. Eng. Chem. Process Des. Dev. 20 (3): 564-570. http://dx.doi.org/10.1021/i200014a030.

Bailes, P.J. and Larkai, S.K.L. 1981. An Experimental Investigation into the Use of High Voltage D.C. Fields for Liquid Phase Separation. Chemical engineering Research and Design 59: 229-237.

Bailes, P.J. and Larkai, S.K.L. 1990. Design Factors Affecting the Performance of Electrostatic Coalescers. Proc., p. 1411–1416. International Solvent Extraction Conference, Kyoto, Japan, 16–21 July, .

Bansback, P.L. and Bessler, D.U. 1975. Cold Treating of Oilfield Emulsions. Presented at the Southwestern Petroleum Short Course, Dept. of Petroleum Engineering, Texas Tech U., Lubbock, Texas, April.

Barnett, J.W. 1988. Desalters Can Remove More Than Salts and Sediment. Oil & Gas J. (11 April).

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SI Metric Converstion Factors

°API		141.5/(131.5+°API)		=	g/cm³
bbl	×	1.589 873	E – 01	=	m³
Btu/hr	×	2.930 711	E – 01	=	W
Btu/hr•ft²	×	3.154 591	E – 03	=	kW/m²
cSt	×	1.0*	E + 00	=	mm²/s
cp	×	1.0*	E – 03	=	Pa•s
ft	×	3.048*	E – 01	=	m
ft²	×	9.290 304*	E – 02	=	m²
ft³	×	2.831 685	E – 02	=	m³
°F		(°F + 459.67)/1.8		=	K
in.	×	2.54*	E + 00	=	cm
lbm	×	4.535 924	E – 01	=	kg
mA	×	1.0*	E – 03	=	A
psi	×	6.894 757	E + 00	=	kPa
rev/min	×	1.666 667	E – 02	=	rev/s
rev/min	×	1.047 198	E – 01	=	rad/s
U.S. gal	×	3.785 412	E – 03	=	m³

Conversion factor is exact.

</div>

[r1-1] 1.00 ^1.01 ^1.02 ^1.03 ^1.04 ^1.05 ^1.06 ^1.07 ^1.08 ^1.09 ^1.10 ^1.11 ^1.12 ^1.13 _

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[r3-3] 3.0 ^3.1 _

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