Energy & Fuels 2000, 14, 31-37
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Emulsion Resolution in Electrostatic Processes Gary W. Sams† and Moshen Zaouk* NATCO, A Division of National Tank Company, 10910 East 55th Place, Tulsa, Oklahoma Received June 7, 1999. Revised Manuscript Received October 8, 1999
Many oil production processes present a significant challenge to the primary separation and dehydration equipment designer and operator. Such processes include innovative production techniques, long pipelines, high-pressure transfer pumps, high shear mixers, gas-lift techniques, submersible production pumps, intermediate oil storage, batch processing methods, flow line pigging, and well treatment chemicals. Any combination of these production and processing techniques can produce an oil history that the equipment designer cannot and should not ignore. Furthermore, the nature of petroleum emulsions changes continuously as the producing field depletes and production methods change. Timely laboratory analysis can be used by the operator to effectively define the stability of the petroleum emulsion and determine the most significant destabilizing variables such as chemicals, viscosity, and shear energy. Numerous techniques are available to the equipment designers and operators to destabilize and resolve petroleum emulsions. These techniques include the traditional application of demulsifiers, temperature, and retention time as well as electrostatics including nontraditional methods of modulated or pulsed voltage control. Optimizing these numerous variables and techniques presents a significant and perpetual challenge for the designer and operator. This paper describes the characteristics of water-in-oil emulsions typically handled and resolved by electrostatic processes, including dehydrating and desalting. This overview describes the upstream production parameters affecting the nature and characteristics of crude oil emulsions and the processing variables influencing the effectiveness of traditional and nontraditional electrostatic processes. Several unique examples are presented to support the conclusions of this paper.
Introduction Every day the complex petroleum industry faces the challenge of resolving several types of emulsions. Oil companies routinely rely on a variety of techniques to “break” these emulsions. Production techniques result in stable crude oil/water emulsions that require aggressive treatment methods. The stability of the emulsion depends on a variety of factors including production history such as thermal and pressure cycles and energy input. Oil gravity, contaminants, water content, water salinity, and pH also determine its nature. Common resolution methods include time, temperature, and chemical treatment, while aggressive techniques include centrifugal force, sonic treatment, and high-voltage electrostatics. This paper discusses the nature of the emulsions routinely experienced by the petroleum industry and several essential parameters. It focuses on the use of high-voltage electrostatic methods to accelerate the water droplet coalescence and separation. Electrostatic treatment is effective in dehydrating crude oil from its connate sediments and corrosioninducing salts, thereby reducing corrosion and fouling of downstream production equipment. In refinery applications, the removal of catalyst poisons such as sodium, iron, and arsenic is achieved by first dispersing freshwater. These dispersions are necessary for efficient * Corresponding author. Phone: 918/660-7150. Fax: 918/622-8058. E-mail:
[email protected]. E-mail:
[email protected].
salt removal but may result in stable, finely dispersed water droplets. The removal of these droplets by electrostatic coalescence is essential to achieve efficient salt removal. Production History The process of recovering crude oil from beneath the earth begins by forcing a blend of oil and water through a vertical casing to the surface. The resulting shear energy and pressure decline produces a “tight” oil/water emulsion once at the surface.1 En route to the production equipment, where primary separation and dehydration take place, many emulsions are heated, pressurized, and pumped as they are pushed through pipelines. Once at the production facility, the emulsion is generally a homogenized blend of oil, water, gas, and contaminants. An understanding of this production history can provide the separator, dehydrator, and desalter designer with some valuable insight into the nature of the crude oil and water emulsion. Lift Techniques. These techniques include primary production, gas-lift, beam pumps, steam flooding, CO2 flooding, polymer flooding, and submersible pumps. Each of these techniques produces a different oil/water emulsion for the production equipment to process. Examples include gas-lift (high GOR wells) which may dehydrate a crude oil leaving crystalline salts (1) Taylor, S. E. Colloids Surfaces 1988, 29, 29-51.
10.1021/ef990109w CCC: $19.00 © 2000 American Chemical Society Published on Web 11/25/1999
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suspended in the oil. Current desalting processes cannot remove these salt crystals. In addition, steam flooding used with heavy, viscous crude oils produces high water cuts of relatively freshwater. The resulting small density differential between the oil and water produces slow separation rates. Finally, multi-stage centrifugal pumps, whether submerged or not, deliver extreme shear energies resulting in tight emulsions. As lift-techniques change toward higher production rates the degree of oil/water emulsification also changes. Thus aggressive lift-techniques mandate aggressive emulsion resolution methods. Several resolution methods are routinely combined to provide the operator with the most cost-effective treatment method. Shear Energy. Perhaps the most damaging variable is the energy input into the emulsion to move it to the production equipment. Most of the energy moves the oil/ water/gas mixture through the pipeline overcoming elevation changes and frictional losses. However, some fraction of the energy produces shear between the oil and water phases. As the shear energy (i.e., pressure drop across orifices and valves) increases so does the interfacial area. For a water-in-oil dispersion, the interfacial area increases by forming smaller water droplets. As these water droplets decrease in diameter, the emulsion coalescence and separation rates slow significantly. Even in light crude oil installations, high shear forces may result in a fine water dispersion that may be difficult to resolve. Photomicrographs of crude oils as light as 38 API, subjected to pressure drops in excess of 100 psig, show water droplet diameters less than 5 µm. Emulsion damage created by droplet shear is cumulative, in other words, a single 100-psi pressure does the equivalent damage of two stages with pressure drops of 50 psi each. Pressure Cycles. In conjunction with shear energy, pressure cycling produces a shift in the droplet distribution to smaller diameters resulting in tighter, more difficult emulsions. As with shear energy, the droplet response is cumulative, thus multi-stage centrifugal pumps produce a more difficult emulsion than a singlestage centrifugal of the same capacity. Detrimental shear produced by high-speed centrifugal pumps can be avoided by the use of progressive cavity or positive displacement pumps. It is also possible to reduce droplet shear by using larger, slow-speed centrifugal pumps, whenever possible. Thermal Cycles. The application of heat has several benefits. It lowers the oil viscosity, increases the density difference between the oil and water, to temperatures of 177 °F, and increases the mobility rate and final dispersion of the demulsifying chemical. It also reduces the precipitation of waxes, reduces pipeline pressure drops, and saves pumping horsepower. However, heating and cooling cycles may also promote a variety of undesirable effects, including oil dehydration accompanied by salt crystallization, wax or asphaltene precipitation accompanied by emulsion stabilization, bacteria formation accompanied by corrosion,2 and loss of lightends accompanied by increasing oil-specific gravity and viscosity. (2) Bass, C.; Lappin-Scott, H. Oilfield Rev. 1997, 17-25.
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While thermal cycles may be unavoidable, these undesirable effects are mitigated with proper precautions. For example, process pressure should be high enough to prevent boiling of the dispersed water and the formation of salt crystals; during heating sufficient water must be present to account for an increase in soluble water; sustained temperatures below 140 °F should be avoided to reduce bacteria growth; temperatures should remain above the cloud point to prevent the precipitation of paraffins which may increase the oil viscosity and stabilize the emulsion; and cooling may condense as much as 0.3%-dissolved water forming a fine dispersion of water droplets. Chemical Demulsifiers. The injection of the optimum demulsifier chemical and dosage can greatly improve the destabilization and final resolution of the emulsion.3 The most effective demulsifier is often “tailored” in the laboratory to meet the needs of each particular crude oil type. Properly designed chemical blends interact with the interfacial film in an orderly way to promote complete coalescence. Only rarely is the coalescence of an oil-water emulsion actually hindered by the introduction of demulsifying chemicals. Final chemical selection and evaluations based on widely accepted “bottle test” methods may fail to select the proper chemical demulsifier for electrostatic coalescence and separation. Just as the chemical demulsifier acts at the water droplet interface, so does electrostatic coalescence. If demulsifiers are not properly selected they may interfere with the coalescence and separation induced by the applied electrostatic field. However, properly selected demulsifiers augment the electrostatic activity at the droplet interface and significantly increase the coalescence and separation rates. Water Cut. Water production typically increases during the life of an oil field. Historically, the produced water fraction is low early in the producing cycle and increases late in the life of the field. In many fields, the water eventually becomes the continuous phase and the oil the dispersed phase. At some point, the economics become unsuitable as revenue from a declining oil supply fails to cover the costs of processing the high water fraction. Fortunately, high water content emulsions are generally easier to process than emulsions with lower water cuts. In other words, the less water in the oil, the smaller the water droplets and the slower the coalescence and separation rate. As the water content approaches the “inversion point” (water-continuous emulsion) the larger the water droplets, the faster the coalescence and separation rates. Once the inversion point is achieved in the production cycle, it might be advantageous to revise the processing method to further improve the separation rate, lower the water content of the oil, and improve the water quality. Crude Characteristics Traditionally, the fundamental physical properties used to evaluate emulsion stability and resolution have been limited to the oil-specific gravity and viscosity. While these properties are principally responsible for the separation rates of a water-in-oil emulsion, in some (3) Meijs, F. H.; Mitchell, R. W. J. Pet. Technol. 1974, 563-568.
Emulsion Resolution in Electrostatic Processes
instances other variables including interfacial tension and conductivity are equally important. Whole crude oils, in addition to a mixture of hydrocarbon fractions, also contain a nonhomogeneous blend of a variety of compounds, such as surfactants, anions, cations, clay, sand, silt, and bacteria. These compounds, ranging in concentrations from trace to percentage levels, contribute in varying degrees to the emulsion stability, coalescence, and separation rates. Several important characteristics define a stable emulsion, and this degree of emulsion stability depends on most of the following factors: the size of the dispersed water droplets, the age of the emulsion, the viscosity of the oil, the difference in the density of the two liquids, the volume percentage of the water cut, the interfacial tension, and the asphaltenes, paraffin, and suspended solids content. Additionally, although not as predominant, several water properties are also important and contribute to the emulsion stability. These water properties are discussed later. Oil Gravity. Generally, a high gravity differential between the oil and water results in rapid separation of the dispersed water phase from an oil phase. Unfortunately, heavy specific gravity oils are associated with relatively freshwaters resulting in low gravity differentials. On the other hand, lighter oils are normally associated with highly saline waters resulting in a high gravity differential. Improved oil quality can be achieved by electrostatic coalescence, which promotes droplet growth and higher separation rates. Viscosity. In conjunction with the apparent gravity differential, the continuous phase viscosity is inversely proportional to the separation rate. It is well-known that increasing the water content in a water-in-oil emulsion results in a significant increase in the mixture viscosity up to the inversion point. An accepted industry standard for the empirical determination of oil viscosity is the ASTM D-2669 double-log model. While this model is suitable for viscosities ranging from 60 to 800000 mPa s and includes the temperature dependence, it is limited to dry oils. Richardson (1958), Mooney (1946, 1961), and Benayoune, Khezzar and Al-Rumhy4 developed viscosity models to predict the effect of water content on the dry oil viscosity.4 The Richardson and Mooney models require the viscosity at the desired temperature to be determined first. With the known dry viscosity, the Richardson or Mooney methods calculate the water-dependent viscosity. Benayoune et al. chose to modify the ASTM D-2669 double-log model to include the water content while maintaining the temperature dependence of the method. Unfortunately, their study included only one oil. Although these correlations provide suitable viscosities in the absence of laboratory data, avoid using them if accurate lab data is available. Conductivity. While it is doubtful that oil conductivity is related to emulsion stability, it is critical to the electrostatic treatment of water-in-oil emulsions in DC fields. Refined oils with extremely low conductivity (4000 ps/m) do not respond well to DC electrostatic (4) Benayoune, M.; Khezzar, L.; Al-Rumhy, M. Pet. Sci. Technol. 1998, 16, 767-784.
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treatment methods. The lack of dissolved charge carriers limits the oil’s ability to establish adequate surface charges at the water droplet interface. Crude oils typically have moderate to high conductivity (4800080000 ps/m) and respond well to DC electrostatic methods. However, oils with extremely high conductivity (200000 ps/m), such as slop oils, require larger power supplies to promote coalescence. Tests conducted by Taylor found the conductivity of the emulsion increased rapidly when the emulsion was subjected to an AC voltage field.5 Taylor attributed this increase to the formation of water chains between electrodes. This emulsion conductivity is dependent on water content, oil viscosity, temperature, and water cut. On the other hand, the ability to promote droplet charging by a DC field is dependent on the conductivity of the continuous oil phase. This dry oil conductivity is dependent on the nature and concentration of the ionic species dissolved in the crude oil and the suspended solids. Asphaltene/Paraffin. It is a well-known fact that the presence of polar asphaltene and resin fractions serves to stabilize the crude oil emulsion.6 Precipitated asphaltene and paraffin can significantly increase the stability of a water-in-oil emulsion. Solids, scale, and corrosion products may stabilize an emulsion when wetted by the adsorption of these fractions from the crude oil. Since asphaltene is soluble in an aromatic solvent, its presence tends to be more significant in medium, highly aromatic oils. Once oil-wetted, solid particles including asphaltene and paraffin accumulate at the droplet interface, it is difficult for an electrostatic field to either polarize or charge droplets through this barrier. Solids. Solids include such minerals as clay, sand, oxides, sulfates, and sulfides. Although some researchers see no detrimental effects due to the presence of solids, there is anecdotal data suggesting that high solid levels may contribute to emulsion stability. Other researchers have reported a thin stabilizing film that forms at the interface around the dispersed water droplets. While flocculation may continue to occur, coalescence and separation fail due to the tough outer layer surrounding and protecting the water droplets. As reported by Alston the presence of solids may limit the ability to sustain a high electrostatic voltage field due to shorting between electrodes.7 When solid concentrations are higher than 100 ppm, oilfield chemical companies have reported difficulty in determining the optimum dfemulsifying chemical. Both the solids and chemical compete for the droplet interface. Interfacial Tension. It is well understood that interfacial tension between the oil and water phases determines droplet stability. However, quantifying the interfacial tension is difficult because of numerous dependencies including temperature, water-soluble organic compounds, fine solids, and water-soluble chemical additives. Additionally, the salinity and pH of the water and chemical additives will alter the interfacial (5) Taylor, S. E. Inst. Phys. Conf. Ser. No. 118: Section 3. 1991, 185190. (6) McLean, J. D.; Kilpatrick, P. K. J. Colloid Interface Sci. 1997, 196, 23-34. (7) Alston, L. L., Ed.; Oxford University Press: New York, 1968.
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Figure 1. The effect of increasing the temperature on the interfacial tension.
tension. Typically, the interfacial tension, reported as dynes/cm, varies from a high of 50 to 0.5 for a wide range of oils and waters. The presence of contaminants such as silts, clay, or production fines can accumulate at the droplet interface and increase the emulsion stability. High interfacial tension promotes rapid flocculation but hinders coalescence due to the rigid nature of the interface. However, as the interfacial tension decreases, the ability for the emulsion to be resolved increases. Then below an interfacial tension of one dy/cm, the oil and water mixture may emulsify spontaneously. Furthermore, an electrostatic charge (i.e., 23000 V) used by crude oil treaters may provide a net droplet charge (DC field) or polarization (AC field) to accelerate droplet coalescence; however, an imbalance of electrical charge created at the water droplet surface may create additional droplet instability resulting in dispersion. Effect of Increasing the Dosage of Demulsifier Chemical on Interfacial Tension. Data collected on interfacial tension by the addition of demulsifier shows that the interfacial tension decreases as the chemical demulsifier concentration increases. This phenomenon was observed and illustrated by Gramme.8 In general, Gramme states that the rate of sedimentation increases and more water separates as the interfacial tension decreased, and the emulsion destabilized due to the injection of demulsifier chemicals. The theoretical fact that demulsifier chemicals are readily adsorbed at the oil/water interface significantly lower the interfacial tension, and promote the coalescence of the aqueous phase can help explain and justify this principle. Gramme also agrees that demulsifiers “tailored” to a specific, crude oil-water emulsion and the behavior is very difficult to predict. Lindemuth of NALCO/EXXON Energy Chemicals stated that emulsion breakers destabilize the emulsion by structurally affecting the interfacial properties.9 He also discussed the direct influence of emulsion breakers on the interfacial tension due to their ability to dissolve the asphaltene content of the crude oil and destabilize the emulsion. Tests conducted in our laboratory clearly indicated that incremental injections of demulsifier chemical to the water-in-oil emulsion decreased the interfacial tension force and destabilized the emulsion. Effect of Increasing the Temperature on the Interfacial Tension. Studies performed at NATCO’s laboratory showed that an increase in temperature reduced the interfacial tension of water-in-oil emulsions (Figure 1). (8) Gramme, P. E. Inter. Conf. Pet. Phase Behavior Fouling. 1999, 196-217. (9) Lindermuth, P. M. Inter. Conf. Pet. Phase Behavior Fouling. 1999, 249-257.
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Figure 2. The effect of the increase in salinity on the interfacial tension.
Figure 3. The effect of pH on the interfacial tension.
Sjoblom of the University of Bergen noted that, among other things, the increase in temperature helped reduce the critical electric field required to break the emulsion.10 He also indicated that an increase in temperature accelerated the solubility of resins and asphaltenes present in the crude oil and significantly decreased the interfacial tension between the two phasessoil and water. Effect of the Increase of Salinity on the Interfacial Tension. NATCO studies showed that increases in the produced water salinity lowered the interfacial force, helped reduce the interfacial tension, and destabilized the water-in-oil emulsion (Figure 2). Again, Sjoblom stated that the increase in salinity reduced the electrostatic field required and broke the emulsion more rapidly. Wasan of ITT also pointed out that higher concentrations of salt helped lower the interfacial tension and improved coalescence of the entrained aqueous phase.11 Effect of the Water Cut on the Stability of the Emulsion. Gramme confirmed our findings that the applied voltage field decreases as the amount of water increases. He goes on to discuss that a critical water cut exists for each crude oil below which little or no water separates. This water cut, which varies with different oils, seems to be an important factor in the separation process. Effect of pH on the Interfacial Tension. Testing conducted in NATCO’s laboratory confirms the findings presented by Marquez of Intevep.12 (See Figure 3.) She states that the interfacial tension of some heavy crude oils depends on the pH of the contained produced water. Strassner concluded that emulsions with pH < 6 are highly stable, while those at pH > 10 exhibited low stability or were highly unstable.13 However, at pH 13 the emulsion was again highly stable. (10) Sjoblom, J. Inter. Conf. Pet. Phase Behavior Fouling. 1999. (11) Wasan, D.; Kumar, K.; Nikolov, A. Inter. Conf. Pet. Phase Behavior Fouling. 1999. (12) Marquez, M. L. Inter. Conf. Pet. Phase Behavior Fouling. 1999, 189-195. (13) Strassner, J. E. J. Pet. Technol. 1968, 303-312.
Emulsion Resolution in Electrostatic Processes
Effect of Oil Aging. The length of time between production and treatment may promote emulsion stability. This stabilization or aging is the result of solids accumulation at the droplet interface, loss of light ends and demulsiofier activity, oxidation and gas stripping etc... Water Characteristics Not only do these crude oil properties contribute to emulsion stability, but several produced brine water properties also contribute to the stability of any emulsion. The important water properties include pH, gravity, salinity and solids content. Water pH. Generally, low-pH brine produces better water quality by neutralizing the naturally occurring basic surfactants. However, low brine pH may hinder the overall performance of a dehydrator or desalter since the pH contributes to the stability of the emulsion by chemically altering the water droplet interface. For example, a rigid interfacial film formed by the presence of asphaltenes are strongest in acid pH (8). The injection of an acid or base to optimize the pH of the produced water can aid most dehydration processes. However, the optimum pH for maximum emulsion instability depends on crude oil and brine composition, fine solids, and crude oil aging. Laboratory evaluation of the oil/water behavior can provide useful guidelines for proper pH control to achieve optimization of an emulsion treating system. Unfortunately, pH adjustment typically is used for corrosion control, rarely to improve dehydration performance. Brine Salinity. Generally, produced water salinity varies directly with oil gravity and inversely with oil viscosity. In other words, fresh, low-salinity brines accompany heavy, high-viscosity oils and high-salinity brines accompany light, low-viscosity oils. This unfortunate anomaly results in a density difference between heavy oils and their produced brines that is very low. Increases in emulsion temperature to about 177 °F generally increase the difference in density. The most common mineral salts found in the produced brine are chlorides, bicarbonates, and the sulfates of sodium, calcium, and magnesium. Salinity ranges from a few parts per million to nearly 240000 ppm (or 24 wt %). Total Suspended Solids. Solids are either lifted with the oil and water or formed in the pipeline and production equipment. Solids may consist of sand produced with the oil, scale products formed in the casing, pipeline, or production equipment, bacteria growth in the production equipment, and corrosion products formed throughout the production system. Generally, water-wet solids should not interfere with the coalescence and separation processes. However, oilwetted solids tend to hinder separation by accumulating at the droplet interface. Generally, demulsifier selection is more difficult when the suspended solid concentration is greater than 100 ppm (0.01%). Electrostatic Resolution Methods Electrostatics cannot completely replace tried and true emulsion resolution methods such as time, tem-
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perature, and chemical. However, when properly applied, electrostatic methods may relax process dependence on them. A variety of electrostatic treatment techniques available to the designer and operator include AC, DC, AC/DC, modulated and pulsed voltage fields.14 Whichever electrostatic method is selected, an understanding of the water droplet behavior within a voltage field will aid the designer to optimize the treatment rate, temperature, chemical dosage, and applied voltage.15 Water Dipole. In an AC type electrostatic field, the driving force for droplet coalescence is based on the dipole of the water molecule. Applying voltage to an AC electrode aligns the water molecules creating a chain of water droplets with positive and negative poles. Droplets that are close together will migrate toward each other and coalesce. However, a 60 Hz AC field alters polarity up to 120 times per second limiting the droplet mobility. Since the droplet interface is not charged, the AC field cannot promote film rupture to expose a clean water surface to adjacent droplets. Charging. In a DC electrostatic field, a sustained movement of electrons charges the water droplet interface. The ability to charge the droplet interface is primarily dependent on the voltage magnitude and the oil conductivity. Studies have shown that higher DC voltage levels are capable of delivering a significant charge to even the smallest water droplets and thereby promoting coalescence. Furthermore, the DC field promotes droplet stretching that ruptures the outer film and enhances the droplet coalescence rate. However, pure DC fields are rarely used in processing since they can promote rapid corrosion due to induced DC current flows. Conductivity. In general, for electrostatic treatment processes, crude oil is considered a nonconductive continuous phase. Pure organic components may be treated electrostatically; however, the low conductivity generally reduces the droplet charge and hinders droplet movement, coalescence, and separation. In highly refined oils where the conductivity is extremely low, AC and DC electrostatic fields rely on the dipole of the dispersed water to promote droplet coalescence. However, in DC treatment processes, the oil conductivity is essential to deliver a charge to the dispersed water droplets. The DC field transfers a charge to dispersed water droplets proportional to the voltage gradient and the oil conductivity. Small-scale lab studies have shown that a limited increase in the oil conductivity can improve water droplet coalescence by a significant amount in some crude oils. Unfortunately, high oil conductivity requires an increase in the connected power supply and limits the voltage gradient developed between electrodes. Coalescence/Separation. As a water droplet progresses through the electrostatic field while coalescence and separation occur,16 the characteristics of the dispersed aqueous phase change. These changes tend to (14) Bailes, P. J.; Freestone, D.; Sams, G. W. The Chem. Eng. 23 October 1997, 34-39. (15) Von Phul, S. A.; Hewitt, M.; Wallum, J. Proc. Laurance Reid Gas Conf. University of Okla., College of Continuing Education, Engineering and Geosciences. 1997, 239-261. (16) Waterman, L. C. Chem. Eng. Prog. 1965, 61 (10), 51-57.
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slow the coalescence and separation rate leaving a small percentage of untreated water. The following changes occur to the dispersed phase. Coalescence of the dispersed phase will increase the droplet diameters, increase the droplet spacing, reduce the droplet population, increase the attractive forces between droplets, reduce the total interfacial area, and reduce droplet mobility. Separation of the dispersed phase will reduce the droplet volume percentage, reduce the interfacial surface area, increase the droplet spacing, decrease the attractive force between droplets, and reduce droplet mobility. Water droplet separation without coalescence accumulates an unresolved emulsion at the vessel interface between the oil and water phases.17 This accumulation of emulsion forms a hindered settling zone that, if unresolved, will “short” the electrical field, limit the voltage gradient, and slow further droplet coalescence. Coalescence rates have been shown to improve when the applied voltage is pulsed or modulated, this technique aids in destabilizing the water droplets and reducing the unresolved emulsion by as much as 50%. Mobility. For effective coalescence and separation in vertical flow, oil dehydrators. Failure to achieve sufficient droplet coalescence results in excessive upward movement of the water droplets resulting in water carry-over and poor process performancwater Water droplet mobility must be achieved in both the horizontal and vertical directions. Enhancing horizontal movement promotes rapid coalescence of the dispersed water droplets. e. Since AC fields rely solely on the water dipole to promote coalescence, droplet mobility is limited. However, in a DC field, once a net droplet charge exists droplet mobility increases significantly. Higher electrostatic voltages improve the horizontal droplet mobility. However, higher voltages may overcome the interfacial tension resulting in a dispersion of the water droplets rather than coalescence. Dispersion. Droplet dispersion created by highvoltage gradients is not always detrimental. In desalting processes, increasing the droplet dispersion improves the contact efficiency between the produced brine water and the injected dilution water. Techniques used to achieve high levels of dispersion are pressure drop across static mixers or valves and high-voltage gradients. Either dispersion technique produces smaller, finely dispersed water droplets. These smaller droplets increase the interfacial surface area for better contact efficiency. However, a fine dispersion is only effective at increasing the desalter performance when coalescence occurs between the brine and dilution water. Laboratory Observations When proper field-treatment methods are difficult to optimize, a lab study is useful to determine the nature of the emulsion and possible treatment remedies. The following examples provide an overview to the type of treatment methods required to resolve some difficult emulsions. (17) Renjilian, A. Filtration Soc. Mtg. Saddle Brook, NJ, 15 April 1975.
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pH Adjustment. The dehydration of a light crude oil from Brunei, which consisted of 70-80% water at a pH of 12.5 in a very stable emulsion, finally resolved by the addition of a large dosage of acid.to achieve a neutral pH. Biocide Interference. It was determined that a medium gravity oil from the Middle East with a low water cut was stabilized by biocides used in the produced water. These added chemicals interfered with the coalescence of the dispersed phase. Shipping Contamination. Nigerian oil, shipped to our lab for analysis, arrived contaminated by a strong caustic solution with which the shipping container was cleaned prior to loading the “chemical-free” oil. Without proper diagnosis, the lab would have recommended an erroneous treatment method. Highly Conductive Crude. A refinery operating with multiple crude feedstocks was having difficulty with highly conductive Chinese crude. This oil created intolerable problems in the existing AC electrostatic desalters by preventing the desalters from maintaining adequate treating voltage in both the first and second treatment stages. The overall desalting and dehydration performance was poor. After modification of the second stage desalter, this oil was desalted to specification by a combination AC/ DC field in conjunction with a modulated voltage field and proprietary composite electrodes. Low Interfacial Tension. An attempt to dehydrate refrigeration oil was hindered by an extremely high water pH (12.5-13) and a low interfacial tension (
