PEH:Crude Oil Emulsions

Publication Information

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume I – General Engineering

John R. Fanchi, Editor

Copyright 2007, Society of Petroleum Engineers

Chapter 12 – Crude Oil Emulsions

Sunil L. Kokal, Saudi Aramco

Pgs. 533-570

ISBN 978-1-55563-108-6
Get permission for reuse

Introduction

Crude oil is seldom produced alone because it generally is commingled with water. The water creates several problems and usually increases the unit cost of oil production. The produced water must be separated from the oil, treated, and disposed of properly. All these steps increase costs. Furthermore, sellable crude oil must comply with certain product specifications, including the amount of basic sediment and water (BS&W) and salt, which means that the produced water must be separated from the oil to meet crude specifications.

Produced water may be produced as "free" water (i.e., water that will settle out fairly rapidly), and it may be produced in the form of an emulsion. A regular oilfield emulsion is a dispersion of water droplets in oil. Emulsions can be difficult to treat and may cause several operational problems in wet-crude handling facilities and gas/oil separating plants. Emulsions can create high-pressure drops in flow lines, lead to an increase in demulsifier use, and sometimes cause trips or upsets in wet-crude handling facilities. The problem is usually at its worst during the winter because of lower surface temperatures. These emulsions must be treated to remove the dispersed water and associated inorganic salts to meet crude specifications for transportation, storage, and export and to reduce corrosion and catalyst poisoning in downstream processing facilities.

Emulsions occur in almost all phases of oil production and processing: inside reservoirs, wellbores, and wellheads; at wet-crude handling facilities and gas/oil separation plants; and during transportation through pipelines, crude storage, and petroleum processing. The chapter on emulsion treating in the Facilities section of this handbook deals with the hardware of emulsion-treating equipment. This chapter is limited to the produced oilfield emulsions at the wellhead and in the wet-crude handling facilities. The primary focus is on the fundamentals and the application of available technologies in resolving emulsions. The chapter looks at the characteristics, occurrence, formation, stability, handling, and breaking of produced oilfield emulsions. There are several good general references available for more detailed and diversified discussions on crude oil emulsions. A comprehensive presentation and further basic information can be found in an encyclopedia of emulsion technology, Becher’s classic book on the subject, and recent books on petroleum emulsions.

This chapter covers four aspects of produced oilfield emulsions. [CD edition includes video .]

• Sec. 12.1 provides a brief introduction to the occurrence, types, and characteristics of emulsions. It deals with the fundamental nature of emulsions including their definitions, how they form, and their physical properties. It also includes a subsection on viscosities of emulsions.
• Sec. 12.2 discusses the stability of emulsions including the formation of films or "skins" on the droplets. Factors that affect emulsion stability include heavy polar material in the oil (asphaltenes, waxes), very fine solids, temperature, droplet size, pH, and brine composition. This section also discusses how to measure emulsion stability.
• Sec. 12.3 visits the mechanisms of demulsification. The factors that destabilize emulsions include temperature, shear, removal of solids, and control of emulsifying agents. This section also discusses the practical aspects of demulsification and highlights methods of emulsion breaking including thermal, mechanical, electrical, and chemical.
• Sec. 12.4 discusses field applications and special topics that should be useful for the practicing engineer dealing with emulsions, either regularly or on a limited basis. A method to sample oilfield emulsions is included. A field emulsion treatment program is discussed and, more importantly, methods to prevent emulsion problems are highlighted. Finally, the practical aspects of demulsifier selection and optimization are included.

Definition

An emulsion is a dispersion (droplets) of one liquid in another immiscible liquid. The phase that is present in the form of droplets is the dispersed or internal phase, and the phase in which the droplets are suspended is called the continuous or external phase. For produced oilfield emulsions, one of the liquids is aqueous and the other is crude oil. The amount of water that emulsifies with crude oil varies widely from facility to facility. It can be less than 1% and sometimes greater than 80%.

Types of Emulsions

Produced oilfield emulsions can be classified into three broad groups: water-in-oil, oil-in-water, and multiple or complex emulsions. Water-in-oil emulsions consist of water droplets in a continuous oil phase, and oil-in-water emulsions consist of oil droplets in a water-continuous phase. Figs. 12.1 and 12.2 show the two basic (water-in-oil and oil-in-water) types of emulsions. In the oil industry, water-in-oil emulsions are more common (most produced oilfield emulsions are of this kind); therefore, the oil-in-water emulsions are sometimes referred to as "reverse" emulsions.

• 

  Fig. 12.1 – Photomicrograph of a water-in-oil emulsion.

• 

  Fig. 12.2 – Photomicrograph of an oil-in-water emulsion.

Multiple emulsions are more complex and consist of tiny droplets suspended in bigger droplets that are suspended in a continuous phase. For example, a water-in-oil-in-water emulsion consists of water droplets suspended in larger oil droplets that, in turn, are suspended in a continuous water phase. Fig. 12.3 shows an example of a multiple emulsion.

• 

  Fig. 12.3 – Photomicrograph of a water-in-oil-in-water emulsion.

Given the oil and water phases, the type of emulsion formed depends on several factors. As a rule of thumb, when the volume fraction of one phase is very small compared with the other, the phase that has the smaller fraction is the dispersed phase and the other is the continuous phase. When the volume-phase ratio is close to 1 (a 50:50 ratio), then other factors determine the type of emulsion formed.

Emulsions are also classified by the size of the droplets in the continuous phase. When the dispersed droplets are larger than 0.1 μm, the emulsion is a macroemulsion. Emulsions of this kind are normally thermodynamically unstable (i.e., the two phases will separate over time because of a tendency for the emulsion to reduce its interfacial energy by coalescence and separation). However, droplet coalescence can be reduced or even eliminated through a stabilization mechanism. Most oilfield emulsions belong in this category. In contrast to macroemulsions, there is a second class of emulsions known as microemulsions. These emulsions form spontaneously when two immiscible phases are brought together because of their extremely low interfacial energy. Microemulsions have very small droplet sizes, less than 10 nm, and are considered thermodynamically stable. Microemulsions are fundamentally different from macroemulsions in their formation and stability.

Formation of Emulsions

Crude oil emulsions form when oil and water (brine) come into contact with each other, when there is sufficient mixing, and when an emulsifying agent or emulsifier is present. The amount of mixing and the presence of emulsifier are critical for the formation of an emulsion. During crude oil production, there are several sources of mixing, often referred to as the amount of shear, including flow through reservoir rock; bottomhole perforations/pump; flow through tubing, flow lines, and production headers; valves, fittings, and chokes; surface equipment; and gas bubbles released because of phase change. The amount of mixing depends on several factors and is difficult to avoid. In general, the greater the mixing, the smaller the droplets of water dispersed in the oil and the tighter the emulsion. Emulsion studies have shown that the water droplets can vary in size from less than 1 μm to more than 1000 μm.

The second factor important in emulsion formation is the presence of an emulsifier. The presence, amount, and nature of the emulsifier determines, to a large extent, the type and "tightness" of an emulsion. The natural emulsifiers in a crude are resident in the heavy fraction. Because there are different types of crudes and because these crudes have different amounts of heavy components, the emulsifying tendencies vary widely. Crude with a small amount of emulsifier forms a less stable emulsion and separates relatively easily. Other crudes contain the right type and amount of emulsifier, which lead to very stable or tight emulsions.

Emulsifying Agents

Produced oilfield water-in-oil emulsions contain oil, water, and an emulsifying agent. Emulsifiers stabilize emulsions and include surface-active agents and finely divided solids.

Surface-Active Agents. Surface-active agents (surfactants) are compounds that are partly soluble in both water and oil. They have a hydrophobic part that has an affinity for oil and a hydrophilic part that has an affinity for water. Because of this molecular structure, surfactants tend to concentrate at the oil/water interface, where they form interfacial films. This generally leads to a lowering of the interfacial tension (IFT) and promotes dispersion and emulsification of the droplets. Naturally occurring emulsifiers in the crude oil include higher boiling fractions, such as asphaltenes and resins, organic acids, and bases. These compounds have been shown to be the main constituents of interfacial films that form around water droplets in many oilfield emulsions. The stabilizing effects of asphaltenes are discussed in Sec. 12.2.2. Other surfactants that may be present are from the chemicals injected into the formation or wellbores (e.g., drilling fluids, stimulation chemicals, corrosion inhibitors, scale inhibitors, wax, and asphaltene-control agents).

Finely Divided Solids. Fine solids can act as mechanical stabilizers. These particles, which must be much smaller than emulsion droplets (usually submicron), collect at the oil/water interface and are wetted by both oil and water. The effectiveness of these solids in stabilizing emulsions depends on factors such as particle size, interparticle interactions, and the wettability of the particles. Finely divided solids found in oil production include clay particles, sand, asphaltenes and waxes, corrosion products, mineral scales, and drilling muds. Fig. 12.4 shows the photomicrograph of an emulsion showing the presence of solids.

• 

  Fig. 12.4 – Photomicrograph of an emulsion showing the presence of solids.

Characteristics and Physical Properties

Oilfield emulsions are characterized by several properties including appearance and color, BS&W, droplet size, and bulk and interfacial viscosities.

Appearance and Color. Color and appearance is an easy way to characterize an emulsion. The characterization becomes somewhat easy if the emulsion is transferred into a conical glass centrifuge tube. The color of the emulsion can vary widely depending on the oil/water content and the characteristics of the oil and water. The common colors of emulsions are dark reddish brown, gray, or blackish brown; however, any color can occur depending on the type of oil and water at a particular facility. Emulsion brightness is sometimes used to characterize an emulsion. An emulsion generally looks murky and opaque because of light scattering at the oil/water interface. When an emulsion has small diameter droplets (large surface area), it has a light color. When an emulsion has large diameter droplets (low total interfacial surface area), it generally looks dark and less bright. Understanding the characteristics of an emulsion by visual observation is an art that improves with experience.

Basic Sediment and Water. BS&W is the solids and aqueous portion of an emulsion. It is also referred to as BSW, bottom settlings and water, or bottom solids and water. Several methods are available to determine the amount of water and solids in emulsions. Standard methods have been proposed by several organizations including the Institute of Petroleum, American Petroleum Institute, and the American Society for Testing Materials. The most common technique for the determination of oil, water, and solids consists of adding a slight overdose of a demulsifier to an emulsion, centrifuging it, and allowing it to stand. The amount of solids and water separated is measured directly from specially designed centrifuge tubes. When only the water content is desired, Karl-Fischer titration can also be used. It is very accurate at low contents of water (<2%) but can also be used for determining higher content (>10%). Other, less common methods are based on electrical properties (conductance and dielectric constants), gamma-ray attenuation, and microwave-based meters.

Droplet Size and Droplet-Size Distribution. Produced oilfield emulsions generally have droplet diameters that exceed 0.1 μm and may be larger than 100 μm. Emulsions normally have a droplet size range that can be represented by a distribution function. Fig. 12.5 shows the drop-size distributions of typical petroleum emulsions. The droplet-size distribution in an emulsion depends on several factors including the IFT, shear, nature and amount of emulsifying agents, presence of solids, and bulk properties of oil and water. Droplet-size distribution in an emulsion determines, to a certain extent, the stability of the emulsion and should be taken into consideration in the selection of optimum treatment protocols. As a rule of thumb, the smaller the average size of the dispersed water droplets, the tighter the emulsion and, therefore, the longer the residence time required in a separator, which implies larger separating plant equipment sizes. The photomicrographs in Figs. 12.1 through 12.4 show the droplet-size distribution for several emulsions.

• 

  Fig. 12.5 – Droplet-size distribution of petroleum emulsions.

The droplet-size distribution for oilfield emulsions is determined by the following methods.

• Microscopy and image analysis. For example, the emulsion photomicrographs in Figs. 12.1 through 12.4 can be digitized and the number of different-sized particles measured with image analysis software.
• By the use of electrical properties such as conductivity and dielectric constants.
• By the use of scattering techniques such as light scattering, neutron scattering, and X-ray scattering. These techniques cover droplet sizes from 0.4 nm to more than 100 μm.
• Physical separation including chromatographic techniques, sedimentation techniques, and field-flow fractionation.

Rheology. Viscosity of Emulsions. Emulsion viscosity can be substantially greater than the viscosity of either the oil or the water because emulsions show non-Newtonian behavior. This behavior is a result of droplet crowding or structural viscosity. A fluid is considered non-Newtonian when its viscosity is a function of shear rate. At a certain volume fraction of the water phase (water cut), oilfield emulsions behave as shear-thinning or pseudoplastic fluids (i.e., as shear rate increases, viscosity decreases). Fig. 12.6 shows the viscosities of tight emulsions at 125°F at different water cuts. The constant values of viscosity for all shear rates, or a slope of zero, indicate that the emulsions exhibit Newtonian behavior up to a water content of 40%. At water cuts greater than 40%, the slope of the curves deviate from zero, which indicate non-Newtonian behavior. The non-Newtonian behavior is pseudoplastic or shear-thinning behavior. The very high viscosities achieved as the water cut increase up to 80% (compared with viscosities of oil approximately 20 cp and water <1 cp). At approximately 80% water cut, an interesting phenomenon is observed. Up to a water cut of 80%, the emulsion is a water-in-oil emulsion; at 80%, the emulsion "inverts" to an oil-in-water emulsion, and the water, which was the dispersed phase, now becomes the continuous phase. In this particular case, multiple emulsions (water-in-oil-in-water) were observed up to very high water concentrations (>95%).

• 

  Fig. 12.6 – Viscosities of very tight emulsions at 125°F.

Temperature also has a significant effect on emulsion viscosity. Fig. 12.7 shows an example of the effect of temperature on emulsion viscosity. Emulsion viscosity decreases with increasing temperature (the data have been plotted on a semilog scale). The viscosity of emulsions depend on several factors: viscosities of oil and water, volume fraction of water dispersed, droplet-size distribution, temperature, shear rate, and amount of solids present.

• 

  Fig. 12.7 – Viscosities of very tight emulsions at a shear rate of 0.1 (1/s).

Figs. 12.6 and 12.7 show that the viscosity of the emulsion can be substantially higher than the viscosity of the oil or water at a given temperature. The ratio of the viscosity of an emulsion to the viscosity of the virgin crude oil at the same temperature can be approximated by the following equation.

....................(12.1)

where a is the factor for the type of emulsion, μ_e is the viscosity of emulsion, μ_o is the viscosity of clean oil at same temperature, and Φ is water cut or fraction of water. The value of a varies depending on the type of emulsion: 7.3 for very tight emulsion, 5.5 for tight emulsion, 4.5 for medium emulsion, 3.8 for loose emulsion, and 3.0 for very loose emulsion.

Fig. 12.8 shows viscosities calculated with Eq. 12.1. Emulsion viscosity depends on several factors, and Eq. 12.1 provides an estimate only. For more precise values, experimental data must be used. Emulsion viscosity is measured by standard viscometers, such as capillary tube and rotational viscometers (concentric cylinder, cone and plate, and parallel plate). It is important that temperature is constant and quoted with the viscosity data. Special procedures must be adopted for measuring the rheology of emulsions.

• 

  Fig. 12.8 – Relative viscosities of emulsions.

Interfacial Viscosity. The previous discussion on viscosity was limited to bulk emulsion viscosity. A closely related and very important property, especially for demulsification, is the interfacial viscosity, or the viscosity of the fluid at the oil/water interface. As mentioned previously, water-in-oil emulsions form rigid interfacial films encapsulating the water droplets. These interfacial films stabilize an emulsion by lowering IFT and increasing interfacial viscosity. These films retard the rate of oil-film drainage (see Sec. 12.2.2) during the coalescence of water droplets, thereby greatly reducing the rate of emulsion breakdown. The oil-drainage rate depends on the interfacial shear viscosity. High interfacial viscosities significantly slow the liquid drainage rate and thus have a stabilizing effect on the emulsion. Emulsion interfacial viscosity plays a very important role in demulsification and is discussed in Sec. 12.2.1. Several Sources provide a detailed discussion of measurement techniques and application to emulsion stability.

Stability of Emulsions

From a purely thermodynamic point of view, an emulsion is an unstable system because there is a natural tendency for a liquid/liquid system to separate and reduce its interfacial area and, hence, its interfacial energy. However, most emulsions demonstrate kinetic stability (i.e., they are stable over a period of time). Produced oilfield emulsions are classified on the basis of their degree of kinetic stability. Loose emulsions separate in a few minutes, and the separated water is free water. Medium emulsions separate in tens of minutes. Tight emulsions separate (sometimes only partially) in hours or even days.

Water-in-oil emulsions are considered to be special liquid-in-liquid colloidal dispersions. Their kinetic stability is a consequence of small droplet size and the presence of an interfacial film around water droplets and is caused by stabilizing agents (or emulsifiers). These stabilizers suppress the mechanisms involved (sedimentation, aggregation or flocculation, coalescence, and phase inversion) that would otherwise break down an emulsion. Sedimentation is the falling of water droplets from an emulsion because of the density difference between the oil and water. Aggregation or flocculation is the grouping together of water droplets in an emulsion without a change in surface area. Coalescence is the fusion of droplets to form larger drops with reduced total surface area. Sec. 12.3 discusses the mechanisms of emulsion breakup.

Surface Films and Stability to Coalescence

As mentioned previously, produced oilfield emulsions are stabilized by films that form around the water droplets at the oil/water interface. These films are believed to result from the adsorption of high-molecular-weight polar molecules that are interfacially active (surfactant-like behavior). These films enhance the stability of an emulsion by increasing the interfacial viscosity. Highly viscous interfacial films retard the rate of oil-film drainage during the coalescence of the water droplets by providing a mechanical barrier to coalescence, which can lead to a reduction in the rate of emulsion breakdown. Figs. 12.9 and 12.10 show the persistent film in a water-in-oil emulsion. The presence of fine solids can also strengthen the interfacial film and further stabilize emulsions.

• 

  Fig. 12.9 – Photomicrograph of an emulsion showing interfacial films.

• 

  Fig. 12.10 – Photomicrograph of an emulsion showing interfacial films (magnified).

The properties of interfacial films depend on the type of crude oil (asphaltic, paraffinic, etc.), composition and pH of the water, temperature, the extent to which the adsorbed film is compressed, contact or aging time, and the concentration of polar molecules in the crude oil. A good correlation exists between the presence of incompressible interfacial film and emulsion stability. These films are classified into two categories on the basis of their mobilities. Rigid or solid films are like an insoluble, solid skin on water droplets characterized by very high interfacial viscosity. There is considerable evidence that very fine solids stabilize these films. They provide a structural barrier to droplet coalescence and increase emulsion stability. These films also have viscoelastic properties. Mobile or liquid films are characterized by low interfacial viscosities. Liquid films are formed, for example, when a demulsifier is added to an emulsion. They are inherently less stable than rigid or solid films, and coalescence of water droplets is enhanced.

Emulsion stability has been correlated with the mobility of interfacial films. Surfactants that modify the rigidity of the film can affect demulsification considerably. Sec. 12.3 discusses this topic further.

Factors Affecting Stability

It is evident from the previous discussion that interfacial films are primarily responsible for emulsion stability. In this section we discuss the factors that affect interfacial films and, therefore, the emulsion stability. Important factors are heavy polar fractions in the crude oil; solids, including organic (asphaltenes, waxes) and inorganic (clays, scales, corrosion products, etc.) materials; temperature; droplet size and droplet-size distribution; pH of the brine; and brine composition.

Heavy Polar Fraction in Crude Oil. Naturally occurring emulsifiers are concentrated in the higher-boiling polar fraction of the crude oil. These include asphaltenes, resins, and oil-soluble organic acids (e.g., naphthenic, carboxylic) and bases. These compounds are the main constituents of the interfacial films surrounding the water droplets that give emulsions their stability.

Asphaltenes. Fig. 12.11 shows that asphaltenes are complex polyaromatic molecules defined to be soluble in benzene/ethyl acetate and insoluble in low-molecular-weight n-alkanes. They are dark brown to black friable solids with no definite melting point. Asphaltenes are considered to consist of condensed aromatic sheets with alkyl and alicyclic side chains and heteroatoms (nitrogen, oxygen, sulfur, and trace metals like vanadium and nickel) scattered throughout. Fig. 12.12 shows the hypothetical structure of a petroleum asphaltene and Fig. 12.13 shows a 3D representation. Asphaltene molecules can have carbon numbers from 30 and over and molecular weights from 500 to more than 10,000. They are characterized by a fairly constant hydrogen/carbon ratio of 1.15 with a specific gravity near one. [Note: Fig. 12.12 can be found in the printed volume of the Petroleum Engineering Handbook, or the original source - J.G. Speight and S.E. Moschopedis: “On the Molecular Nature of Asphaltenes,” Advances in Chemistry Series, J.W. Bunger and N.C. Li (eds.), American Chemical Society (1981) 195, 1-15. Copyright 1981 American Chemical Society. ACS did not provide permission for its use in PetroWiki.]

• 

  Fig. 12.11 – Definition chart of petroleum asphaltenes.

• 

  Fig. 12.13 – 3D representation of a Venezualan asphaltene molecule (courtesy of J. Murgich and A. Mansoori).

The nature of asphaltenes in the crude oil is still a subject of debate (see the chapter on asphaltenes in this section of the Handbook). The asphaltenes are believed to exist in the oil as a colloidal suspension and to be stabilized by resins adsorbed on their surface. In this regard, the resins act as peptizing agents for asphaltenes and together form clusters called micelles (Fig. 12.14). These micelles or colloids contain most of the polar material found in the crude oil and possess surface-active properties (interfacially active material). The surface-active properties are the result of the sulfur, nitrogen, oxygen, and metal containing entities in asphaltenes molecules that form polar groups such as aldehydes, carbonyl, carboxylic, amine, and amides.

• 

  Fig. 12.14 – Asphaltene-resin micelle.

It is this surface-active behavior of asphaltenes that makes them good emulsifiers. Surfactants are compounds that have a polar part with an affinity to water and a nonpolar part with an affinity to oil (Fig. 12.15). This dual affinity is satisfied when they are positioned (or adsorbed) at the oil/water interface with the polar part immersed in water and the nonpolar part in oil. This orientation results in a decrease in the thermodynamic free energy of the system. The accumulation of high-molecular-weight substances at the interface results in the formation of the rigid film. Fig. 12.16 shows an asphaltene-stabilized water droplet. When such a film forms, it acts as a barrier to drop coalescence. For two drops to coalesce, the film must be drained and ruptured. The presence of the asphaltenes can naturally retard the drainage of this film. The primary mechanism involved in this retardation is the steric repulsion or hindrance caused by the high-molecular-weight materials in the film. Fig. 12.17 shows the steric repulsion produced by the interaction between the nonpolar or hydrophobic groups of the surfactant molecules. With asphaltenic-surfactant molecules, the side chains can extend considerably into the oil phase and steric repulsion can maintain the interface at a distance sufficient to inhibit coalescence. The molecules at the oil/water interface result in an increase in both the interfacial viscosity and the apparent viscosity of the oil in the film between the droplets. Both of these effects oppose film drainage and inhibit coalescence.

• 

  Fig. 12.15 – Schematic of a surfactant molecule and formation of micelles.

• 

  Fig. 12.16 – Mechanism of emulsion stabilization by asphaltenes.

• 

  Fig. 12.17 – Steric repulsion between two water droplets, which retards film drainage and coalescence.

The state of asphaltenes in the crude oil has an effect on its emulsion-stability properties. While asphaltenes stabilize emulsions when they are present in a colloidal state (not yet flocculated), there is strong evidence that their emulsion-stabilizing properties are enhanced significantly when they are precipitated from the crude oil and are present in the solid phase. The effect of polar fractions (primarily asphaltenes) on the film properties was investigated by Stassner. In a series of tests, it was demonstrated that the removal of asphaltenes (deasphalting) from the crude oil resulted in a very loose emulsion characterized by mobile films. Adding the precipitated asphaltenes back to the deasphalted oil in increasing quantities resulted in the formation of rigid or solid films and increasingly stable emulsions. Fig. 12.18 shows the effect of asphaltenes (when added to deasphalted oil) on emulsion stability. Another study examined the effect of asphaltenes on emulsion stabilization and showed that the extent of emulsification was related to the aromatic/aliphatic ratio of the crude oil. This was further substantiated by Bobra. Both studies reported that two factors control emulsion stability: the amount of asphaltenes and the aromatic/alkane ratio in the crude oil. Emulsification tendencies reduce with increasing aromatic content of the crude oil. Asphaltenes, apart from stabilizing emulsions themselves, alter the wettability of other solids present and make them act as emulsifying agents for water-in-oil emulsions.

• 

  Fig. 12.18 – Effect of asphaltenes, added to deasphalted oil, on emulsion stability.

Resins. Resins are complex high-molecular-weight compounds that are not soluble in ethyl¬acetate but are soluble in n-heptane (Fig. 12.11). They are heterocompounds, like asphaltenes, that contain oxygen, nitrogen, and sulfur atoms. Molecular weights of resins range from 500 to 2,000. As Fig. 12.14 shows, resins have a strong tendency to associate with asphaltenes, and together they form a micelle. As Figs. 12.16 and 12.17 illustrate, the asphaltene-resin micelle plays a key role in stabilizing emulsions. It appears that the asphaltene-resin ratio in the crude oil is responsible for the type of film formed (solid or mobile) and, therefore, is directly linked to the stability of the emulsion.

Waxes are high-molecular-weight alkanes naturally present in the crude oil that crystallize when the oil is cooled below its "cloud point." They are insoluble in acetone and dichloromethane at 30°C. There are two types of petroleum waxes: paraffin and microcrystalline. Paraffin waxes are high-molecular-weight normal alkanes, and microcrystalline waxes are high-molecular-weight iso-alkanes that have melting points greater than 50°C.

Waxes by themselves are soluble in oil and, in the absence of asphaltenes, do not form stable emulsions in model oils. However, the addition of a nominal amount of asphaltenes (an amount insufficient by itself to produce emulsions) to oils containing wax can lead to the formation of stable emulsions. Therefore, waxes can interact synergetically with asphaltenes to stabilize emulsions. The physical state of the wax in the crude oil also plays an important role in emulsion stabilization. Waxes are more apt to form a stable emulsion when they are present as fine solids in the emulsion; thus, waxy emulsions are more likely at lower temperatures. Waxes, being oil-wet, have a tendency to stabilize water-in-oil emulsions. Crudes that have a high cloud point generally have a greater tendency to form stable and tight emulsions than crudes with low cloud points. Similarly, lower temperatures generally enhance the emulsion-forming tendencies of crude oils.

Solids. Fine solid particles present in the crude oil are capable of effectively stabilizing emulsions. The effectiveness of these solids in stabilizing emulsions depends on factors such as the solid particle size, interparticle interactions, and the wettability of the solids. Solid particles stabilize emulsions by diffusing to the oil/water interface, where they form rigid films that can sterically inhibit the coalescence of emulsion droplets. Furthermore, solid particles at the interface may be electrically charged, which may also enhance the stability of the emulsion. Particles must be much smaller than the size of the emulsion droplets to act as emulsion stabilizers. Typically these solid particles are submicron to a few microns in diameter.

The wettability of the particles plays an important role in emulsion stabilization. Wettability is the degree to which a solid is wetted by oil or water when both are present. Fig. 12.19 shows the three cases of wettability in terms of the contact angle. When the contact angle, δ, is less than 90°, the solid is preferentially oil-wet. Similarly, when the contact angle is greater than 90°, the solid is preferentially water-wet. Contact angles close to 90° result in an intermediately wetted solid that generally leads to the tightest emulsions. If the solid remains entirely in the oil or water phase, it will not be an emulsion stabilizer. For the solid to act as an emulsion stabilizer, it must be present at the interface and must be wetted by both the oil and water phases. In general, oil-wet solids stabilize a water-in-oil emulsion. Oil-wet particles preferentially partition into the oil phase and prevent the coalescence of water droplets by steric hindrance. Similarly, water-wet solids stabilize a water-continuous or an oil-in-water emulsion. Examples of oil-wet solids are asphaltenes and waxes. Examples of water-wet solids are inorganic scales (CaCO₃, CaSO₄), clays, sand, and corrosion products. Water-wet particles can be made oil-wet with a coating of heavy organic polar compounds.

• 

  Fig. 12.19 – Wetting behavior of solids at the oil/water interface.

When solids are wetted by the oil and water (intermediate wettability), they agglomerate at the interface and retard coalescence. These particles must be repositioned into either the oil or water for coalescence to take place. This process requires energy and provides a barrier to coalescence.

The role of colloidal solid particles in emulsion stability and the mechanisms involved are summarized in the following points.

• The particles must be present at the oil/water interface before any stabilization can take place. The ability of the particles to diffuse to the interface and adsorb at the interface depends on its size, wettability, and the state of dispersion of the solids (whether flocculated or not).
• The ability of the solids to form a rigid, protective film encapsulating the water droplets is important for stabilizing these emulsions.
• Water-wet particles tend to stabilize oil-in-water emulsions, and oil-wet particles stabilize water-in-oil emulsions.
• Some degree of particle interaction is necessary for effective stabilization.

The effectiveness of colloidal particles in stabilizing emulsions depends largely on the formation of a densely packed layer of solid particles (film) at the oil/water interface (Fig. 12.20). This film provides steric hindrance to the coalescence of water droplets. The presence of solids at the interface also changes the rheological properties of the interface that exhibits viscoelastic behavior. This affects the rate of film drainage between droplets and also affects the displacement of particles at the interface. It has also been demonstrated that for asphaltenes and waxes to be effective emulsifiers, they must be present in the form of finely divided submicron particles.

• 

  Fig. 12.20 – Droplet stabilization by solids.

Temperature. Temperature can affect emulsion stability significantly. Temperature affects the physical properties of oil, water, interfacial films, and surfactant solubilities in the oil and water phases. These, in turn, affect the stability of the emulsion. Perhaps the most important effect of temperature is on the viscosity of emulsions because viscosity decreases with increasing temperatures (Fig. 12.7). This decrease is mainly because of a decrease in the oil viscosity. When waxes are present (the temperature of the crude is below its cloud point) and are the source of emulsion problems, application of heat can eliminate the problem completely by redissolving the waxes into the crude oil. Temperature increases the thermal energy of the droplets and, therefore, increases the frequency of drop collisions. It also reduces the interfacial viscosity, which results in a faster film-drainage rate and faster drop coalescence.

The effect of temperature on crude oil/water interfacial films was studied in some detail by Jones et al., who showed that an increase in temperature led to a gradual destabilization of the crude oil/water interfacial films. However, even at higher temperatures, a kinetic barrier to drop coalescence still exists. Temperature influences the rate of buildup of interfacial films by changing the adsorption rate and characteristics of the interface. It also influences the film compressibility by changing the solubility of the crude oil surfactants in the bulk phase.

Slow degassing (removal of light ends from the crude oil) and aging lead to significant changes in the interfacial film behavior at high temperatures. The films generated by this process remain incompressible and nonrelaxing (solid films) at high temperatures at which emulsion resolution is not affected by heating.

Drop Size. As mentioned earlier, emulsion droplet sizes can range from less than a micron to more than 50 microns. Fig. 12.5 shows the typical droplet-size distributions for water-in-crude oil emulsion. Droplet-size distribution is normally represented by a histogram or by a distribution function.

Emulsions that have smaller size droplets will generally be more stable. For water separation, drops must coalesce—and the smaller the drops, the greater the time to separate. The droplet-size distribution affects emulsion viscosity because it is higher when droplets are smaller. Emulsion viscosity is also higher when the droplet-size distribution is narrow (i.e., droplet size is fairly constant).

pH. The pH of water has a strong influence on emulsion stability. The stabilizing, rigid emulsion film contains organic acids and bases, asphaltenes with ionizable groups, and solids. Adding inorganic acids and bases strongly influences their ionization in the interfacial films and radically changes the physical properties of the films. The pH of water affects the rigidity of the interfacial films. It was reported that interfacial films formed by asphaltenes are strongest in acids (low pH) and become progressively weaker as the pH is increased. In alkaline medium, the films become very weak or are converted to mobile films. The films formed by resins are strongest in base and weakest in acid medium. Solids in the emulsions can be made oil-wet by asphaltenes, an effect that is stronger in an acidic than in a basic medium. These partially oil-wet solids tend to stabilize water-in-oil emulsions.

pH also influences the type of emulsion formed. Acid or low pH generally produces water-in-oil emulsions (corresponding to oil-wetting solid films), whereas basic or high pH produces oil-in-water emulsions (corresponding to water-wetting mobile soap films). Fig. 12.21 shows the effect of pH on emulsion stability for a Venezuelan crude. Optimum pH for demulsification is approximately 10 in the absence of a demulsifier.

• 

  Fig. 12.21 – Effect of pH and demulsifier concentration on emulsion stability.

Brine composition also has an important effect (in relation to pH) on emulsion stability. Fig. 12.22 shows the effect of a bicarbonate brine and distilled water on emulsion stability as a function of pH. Optimal pH for water separation changes from approximately 10 for distilled water to between 6 and 7 for the brine solution because of an ionization effect (association/interaction of ions present in the brine with the asphaltenes). The study suggests that for most crude oil/brine systems an optimum pH range exists for which the interfacial film exhibits minimum emulsion-stabilizing or maximum emulsion-breaking properties. The optimum pH for maximum emulsion stability depends on both the crude oil and brine compositions. The latter seems to be more important.

• 

  Fig. 12.22 – Effect of brine and pH on emulsion stability.

Frequently, severe emulsion upsets occur in surface-treating facilities following acid stimulation. It has also been linked to formation damage. Following acid treatment, wells can be very slow to clean up, often resulting in partial or complete plugging of the well. This plugging and formation damage generally occurs because of solid precipitates or sludges forming on contact of the crude oil with the acid. These precipitates are mainly asphaltenes, resins, and other high-molecular-weight hydrocarbons. These materials are apparently precipitated from the crude oil by the reduction in pH and are among the tightest emulsions produced. Proper design of the acid treatment is necessary to avoid well productivity decline and emulsion upsets caused by acidization.

Brine Composition. Specific ions present in the brine can also influence interfacial film behavior. The effect of brine composition on interfacial film and emulsion stability has been reported. Waters from petroleum formations generally contain many ions. Sodium and chloride ions are usually present in high concentrations, while other ions are present in wide-ranging quantities. At the interface, these ions may react chemically with the hydrophilic groups to form insoluble salts. In the studies cited, an insufficient number and variety of crude oil/brine systems were tested to draw any concrete conclusions regarding the effect of brine and its composition on interfacial film and emulsion-stabilizing properties. However, the following general trends are noted.

• Brine composition (alkalinity in particular because of a buffering effect) is intimately tied to the pH in determining the stabilizing properties of the interfacial films.
• Brines with high Ca⁺⁺ ions and a high Ca⁺⁺/Mg⁺⁺ ratio form nonrelaxing, rigid films around the water droplets, resulting in stable emulsions.
• Higher concentration of divalent ions and high pH result in reduced emulsion stability.

Many species of polar molecules are present at the interface, and each species responds differently. Synergistic effects may occur when several different cations are present at the same time.

Stability Measurement

From a practical point of view, measurement of stability is one of the most important tests that can be performed on an emulsion. It determines the ease with which the oil and water separates in an emulsion. There are numerous methods available for determining emulsion stability, and the most common is the simple bottle test.

The bottle test involves diluting the emulsion with a solvent, mixing in a demulsifier, shaking to disperse the demulsifier, and observing the phase separation as a function of time. The tests are normally done at elevated temperature and may involve centrifugation to speed up the separation. While different methods and procedures are followed by various laboratories, there is a standard ASTM method (ASTM 4007) for determining the bottom sediments and water in an emulsion. The stability of the emulsion is generally related to the ease of water separation with time and demulsifier dosage. For example, at a given demulsifier concentration, emulsions can be rated on their stability by the amount of water separated in a given period of time. Alternatively, for a fixed length of time and a given demulsifier concentration, different demulsifiers can be graded in terms of their demulsification qualities. The bottle test is used regularly as a screening test for potential demulsifiers.

While a standard method is available for determining BS&W, no standard method is available in the literature for determining the stability of the emulsion with the bottle test. Recently, a method was proposed for measuring the stability of an emulsion quantitatively. The concept of an emulsion separation index was proposed to measure the tightness of an emulsion. The fraction of the total water separated in a regular bottle test at different demulsifier dosages is averaged to determine a separation index for the emulsion. The separation index measures from zero (no separation) to 100% (full separation). The separation index thus provides a measure of emulsion tightness (or stability): the lower the index, the greater the tightness or stability. The index must be quoted at the temperature of the test and for a given demulsifier. The index is very useful for comparing the stability of emulsions from different sources (for example, different wells or wet-crude handling facilities). Appendix A briefly describes the procedure, and Kokal and Wingrove provides additional details.

Other techniques also have been used for the measurement of emulsion stability. A technique based on light scattering in crude-oil emulsions was used to measure the coalescence of water droplets (and, hence, emulsion stability). The method can be used to monitor the coalescence action of demulsifiers. Another technique suggests the measurement of dielectric constant of oilfield emulsions as a measure of their stability. The dielectric constant, which can be measured readily, can be used to characterize emulsions. A change in dielectric constant with time or demulsifier dosage can be used as a measure of the emulsion stability. This technique may be used for screening, ranking, and selecting demulsifiers for emulsion resolution. Recently, electroacoustical techniques have shown promise for electrokinetic measurement of colloidal phenomena in emulsions and the rate of flocculation and coalescence of water droplets in water-in-oil emulsions. The technique, based on the ultrasound vibration potential, which involves the application of a sonic pulse and the detection of an electric field, was used successfully in monitoring coagulation in a water-in-oil emulsion. Another technique developed recently used critical electric field measurements for emulsion stability.

Demulsification

Demulsification is the breaking of a crude oil emulsion into oil and water phases. From a process point of view, the oil producer is interested in three aspects of demulsification: the rate or the speed at which this separation takes place, the amount of water left in the crude oil after separation, and the quality of separated water for disposal. A fast rate of separation, a low value of residual water in the crude oil, and a low value of oil in the disposal water are obviously desirable. Produced oil generally has to meet company and pipeline specifications. For example, the oil shipped from wet-crude handling facilities must not contain more than 0.2% BS&W and 10 pounds of salt per thousand barrels of crude oil. This standard depends on company and pipeline specifications. The salt is insoluble in oil and associated with residual water in the treated crude. Low BS&W and salt content is required to reduce corrosion and deposition of salts. The primary concern in refineries is to remove inorganic salts from the crude oil before they cause corrosion or other detrimental effects in refinery equipment. The salts are removed by washing or desalting the crude oil with relatively fresh water.

Destabilizing Emulsions

As mentioned previously, produced oilfield emulsions possess some kinetic stability. This stability arises from the formation of interfacial films that encapsulate the water droplets. To separate this emulsion into oil and water, the interfacial film must be destroyed and the droplets made to coalesce. Therefore, destabilizing or breaking emulsions is linked directly to the removal of this interfacial film. The factors that affect the interfacial film and, consequently, the stability of the emulsions were discussed earlier. The factors that enhance or speed up emulsion breaking are discussed here.

Temperature. Application of heat promotes oil/water separation and accelerates the treating process. An increase in temperature has the following effects.

• Reduces the viscosity of the oil.
• Increases the mobility of the water droplets.
• Increases the settling rate of water droplets.
• Increases droplet collisions and favors coalescence.
• Weakens or ruptures the film on water droplets because of water expansion and enhances film drainage and coalescence.
• Increases the difference in densities of the fluids that further enhances water-settling time and separation.

All these factors favor emulsion destabilization and oil/water separation; however, heat by itself is not a cure-all and even has some disadvantages (e.g., loss of light ends from the crude oil). An economic analysis should be performed that takes into consideration factors such as heating costs, reduced treating time, and residual water in the crude. An increase in temperature also can be achieved by burying crude-oil pipelines or by insulating them. These factors should be evaluated carefully during development, especially at facilities where emulsion problems are anticipated.

Agitation or Shear. Generally, reducing agitation or shear reduces emulsion stability. Very high shear is detrimental and should be avoided. High shear causes violent mixing of oil and water and leads to smaller droplet sizes. Smaller droplets are relatively more stable than larger droplets; therefore, measures that increase shearing of the crude oil (for example, mechanical chokes, valves, flow obstructions, and pressure drops) should be avoided or minimized where possible. However, a certain amount of shear is required for mixing the chemical demulsifier into the bulk of the emulsion.

Residence or Retention Time. The period of time that the emulsion is held at the treating temperature is the residence, retention, or treating time. This typically is between 10 to 30 minutes for normal crude oil production; however, it may need to be much longer to treat tight emulsions effectively. An increase in residence time increases the separation efficiency and reduces the residual amount of water in the crude. Increasing residence time, however, comes at the expense of high separator-equipment costs.

Solids Removal. Solids have a strong tendency to stabilize emulsions, especially if they are present as fines or when they are wetted by both oil and water. Removing the solids or their source is sometimes all that is required for eliminating or reducing the emulsion problem. Oil-wet solids stabilize water-in-oil emulsions. Water-wet solids can also be made oil-wet with a coating of heavy polar materials and can participate effectively in the stabilization of water-in-oil emulsions. The presence of solid asphaltenes and waxes has a definite detrimental effect on the emulsion problem, and every effort should be made to eliminate their presence in the crude oil. The solids can be removed by dispersing them into the oil or can be water-wetted and removed with the water.

Control of Emulsifying Agents. Because emulsifying agents are necessary in the stabilization of emulsions, controlling them allows for their destabilization and resolution. Some of the ways to control emulsifiers include the following processes.

• Careful selection of chemicals that are injected during oil production. The chemicals include, for example, acids and additives during acidization, corrosion inhibitors for corrosion protection, surfactants and dispersants for organic- and inorganic-deposition control, and polymers and blocking agents for water-production control. Laboratory compatibility testing of these chemicals should be conducted before field injection to avoid tight emulsions.
• Avoiding incompatible crude-oil blends. A crude-oil blend is incompatible if it results in the precipitation of solids (organic and inorganic). This occurs, for example, when an asphaltic crude oil is mixed with a paraffinic crude oil, resulting in the precipitation of asphaltenes. Again, laboratory testing can identify incompatible crudes.
• Use of dispersants for controlling the precipitation of asphaltenes and the use of pour-point depressants for controlling waxes. Alternatively, emulsion stability can be controlled by raising the temperature of the crude above its cloud point.
• Neutralizing the effect of stabilizing film encapsulating the water droplets by demulsifiers. These chemicals promote coalescence of water droplets and accelerate water separation.

Retrofitting. Additional water separation can be achieved by retrofitting the existing equipment. Invariably, emulsion problems increase after the separation equipment has been installed because of field aging, increased watercuts, improper design, or several other reasons. Additional equipment (for example, free-water knockout drums and heater treaters) can be installed to assist in the breaking of oilfield emulsions. Internals can also be installed or retrofitted in production-separation traps. The most common retrofitting is the installation of a coalescer section that assists in coalescing water droplets. There are several options available, and re-engineering is generally required on a case-by-case basis. The chapter on emulsion treating in the Facilities section of this Handbook provides further information.

Mechanisms Involved in Demulsification

Demulsification, the separation of an emulsion into its component phases, is a two-step process. The first step is flocculation (aggregation, agglomeration, or coagulation). The second step is coalescence. Either of these steps can be the rate-determining step in emulsion breaking.

Flocculation or Aggregation. The first step in demulsification is the flocculation of water droplets. During flocculation, the droplets clump together, forming aggregates or "floccs." The droplets are close to each other, even touching at certain points, but do not lose their identity (i.e., they may not coalesce). Coalescence at this stage only takes place if the emulsifier film surrounding the water droplets is very weak. The rate of flocculation depends on the following factors.

• Water content in the emulsion. The rate of flocculation is higher when the water cut is higher.
• Temperature of the emulsion is high. Temperature increases the thermal energy of the droplets and increases their collision probability, thus leading to flocculation.
• Viscosity of the oil is low, which reduces the settling time and increases the flocculation rate.
• Density difference between oil and water is high, which increases the sedimentation rate.
• An electrostatic field is applied. This increases the movement of droplets toward the electrodes, where they aggregate.

Coalescence. Coalescence is the second step in demulsification. During coalescence, water droplets fuse or coalesce together to form a larger drop. This is an irreversible process that leads to a decrease in the number of water droplets and eventually to complete demulsification. Coalescence is enhanced by the following factors.

• High rate of flocculation increases the collision frequency between droplets.
• The absence of mechanically strong films that stabilize emulsions.
• High interfacial tension. The system tries to reduce its interfacial free energy by coalescing.
• High water cut increases the frequency of collisions between droplets.
• Low interfacial viscosity enhances film drainage and drop coalescence.
• Chemical demulsifiers convert solid films to mobile soap films that are weak and can be ruptured easily, which promotes coalescence.
• High temperatures reduce the oil and interfacial viscosities and increase the droplet collision frequency.

Sedimentation or Creaming. Sedimentation is the process in which water droplets settle down in an emulsion because of their higher density. Its inverse process, creaming, is the rising of oil droplets in the water phase. Sedimentation and creaming are driven by the density difference between oil and water and may not result in the breaking of an emulsion. Unresolved emulsion droplets accumulate at the oil/water interface in surface equipment and form an emulsion pad or rag layer. A pad in surface equipment causes several problems including the following.

• Occupies space in the separation tank and effectively reduces the retention or separation time.
• Increases the BS&W of the treated oil.
• Increases the residual oil in the treated water.
• Increases arcing incidences or equipment upset frequency.
• Creates a barrier for water droplets and solids migrating down into the bulk water layer.

Emulsion pads are caused or exacerbated by ineffective demulsifier (unable to resolve the emulsion); insufficient demulsifier (insufficient quantities to break the emulsion effectively); other chemicals that nullify the effect of the demulsifier; low temperatures; and the presence of accumulating solids. Because emulsion pads cause several operational problems, their cause should be determined and appropriate actions taken to eliminate them.

Methods of Emulsion Breaking or Demulsification

In the oil industry, crude-oil emulsions must be separated almost completely before the oil can be transported and processed further. Emulsion separation into oil and water requires the destabilization of emulsifying films around water droplets. This process is accomplished by any, or a combination, of the following methods:

• Adding chemical demulsifiers.
• Increasing the temperature of the emulsion.
• Applying electrostatic fields that promote coalescence.
• Reducing the flow velocity that allows gravitational separation of oil, water, and gas. This is generally accomplished in large-volume separators and desalters.

Demulsification methods are application specific because of the wide variety of crude oils, brines, separation equipment, chemical demulsifiers, and product specifications. Furthermore, emulsions and conditions change over time, which adds to the complexity of the treatment. The most common method of emulsion treatment is the application of heat and an appropriate chemical demulsifier to promote destabilization, followed by a settling time with electrostatic grids to promote gravitational separation.

Thermal Methods. Heating reduces the oil viscosity and increases the water-settling rates. Increased temperatures also result in the destabilization of the rigid films because of reduced interfacial viscosity. Furthermore, the coalescence frequency of water droplets is increased because of the higher thermal energy of the droplets. In other words, heat accelerates emulsion breaking; however, it very rarely resolves the emulsion problem alone. Increasing the temperature has some negative effects. First, it costs money to heat the emulsion stream. Second, heating can result in the loss of light ends from the crude oil, reducing its API gravity and the treated oil volume. Finally, increasing the temperature leads to an increased tendency toward some forms of scale deposition and an increased potential for corrosion in treating vessels.

The application of heat for emulsion breaking should be based on an overall economic analysis of the treatment facility. The cost-effectiveness of adding heat should be balanced against longer treatment time (larger separator), loss of light ends and a resultant lower oil-product price, chemical costs, and the costs of electrostatic grid installation or retrofitting.

Mechanical Methods. There is a wide variety of mechanical equipment available for breaking oilfield emulsions including free-water knockout drums, two- and three-phase separators (low- and high-pressure traps), desalters, settling tanks, etc. See the chapter on emulsion treating in the Facilities section of this Handbook for a detailed description of emulsion-treating equipment.

Free-Water Knocout Drums. Free-water knockout drums separate the free water from the crude oil/water mixture. Some of the associated gases may be separated in these drums. Free-water knockout drums are supplementary equipment that aid in the treatment of produced crude oil emulsions.

Production Traps or Three-Phase Separators. Three-phase separators or production traps are used to separate the produced fluids into oil, water, and gas. These separators can be either horizontal or vertical in configuration. Each separator is sized with a set retention time to provide adequate separation at a given throughput rate. The separator may include a heater section, wash water, a filter section, a coalescing or stabilizing section, and electrostatic grids. Fig. 12.23 shows a typical three-phase separator. There is a large variety of separators in use today. For example, a separator may have a large heater section or may have no coalescer packing. Selecting the right separator for any given set of conditions is a complex engineering task that depends on several factors.

• 

  Fig. 12.23 – Three-phase emulsion separator.

Oil/water separation is usually based on a gravitational separation. Because water has a higher density than oil, water droplets have a tendency to settle down. Stokes’ Law approximates the settling rate of water droplets.

....................(12.2)

where v is the settling velocity of the water droplets, g is the acceleration caused by of gravity, r is the radius of the droplets, (ρ_w - ρ_o) is the density difference between the water and oil, and μ is the oil viscosity. Stokes’ Law suggests that the settling velocity is increased by increasing the density difference between water and oil, reducing the viscosity, and increasing the drop size. However, Stokes’ Law should be applied to emulsions with caution. Increasing the coalescence rate increases the droplet size and has the strongest effect on the settling velocity. While it is true that larger diameter droplets settle faster, emulsifiers prevent droplet coalescence in an actual treating system. Another important consideration is that Stokes’ Law applies only to a static system with nondeforming droplets. Both these assumptions are not true in complex emulsion-treating equipment. It is a dynamic system, and where the motion is vigorous, re-emulsification is possible. Stokes’ Law also applies only to isolated particles or, in this application, to dilute emulsions.

A degree of flexibility in the separator design, with options to modify, is the best strategy when designing emulsion-treatment separators. Operating conditions (such as pressures, temperatures, water cuts, and oil/brine compositions) change during the life of the field, and the equipment should be able to handle these changes or be modified to account for them.

One way to improve the efficiency of separators is to install coalescer packs. These packs increase the travel of the fluid through the separator. The wiping or rolling action of the emulsion as it passes through the packing or baffles causes the water droplets to coalesce. Spreaders also can be installed to increase the collision frequency between droplets.

Desalters. The oil from the separator is generally "off-spec" (i.e., it still contains unacceptably high levels of water and solids). It must be further treated to meet crude specifications. For the refinery, the salt level must be further reduced. Refinery crude should contain no more that a specified amount of inorganic solids (salts). This is generally expressed in pounds per thousand barrels. The industry standard is 1 pound per thousand barrels. The removal of the salts, along with the remaining water, is the process of desalting.

Desalters are normally designed as either one-stage or multistage desalters. Fig. 12.24 shows a schematic of a one-stage desalter. Generally, desalters use a combination of chemical addition, electrostatic treating, and settling time. The retention time is based on a certain oil specification for a given product rate. Also, fresh water (wash water) is added with the chemicals to reduce the concentrations of dissolved salt (by diluting) in the treated water and, hence, the outgoing crude.

• 

  Fig. 12.24 – One-stage desalter.

Desalter performance is generally optimized by a careful manipulation of system parameters. Operational data are obtained by altering the system parameters and monitoring their effect on the quality of oil (or water/salt removal). Optimum set points can be obtained for operating temperatures, interface level, treating chemicals, wash-water rates and injection points, and mix valves settings.

Electrical Methods. Electrostatic grids are sometimes used for emulsion treatment. High-voltage electricity (electrostatic grids) is often an effective means of breaking emulsions. It is generally theorized that water droplets have an associated net charge, and when an electric field is applied, the droplets move about rapidly and collide with each other and coalesce. The electric field also disturbs the interfacial film by rearranging the polar molecules, thereby weakening the rigid film and enhancing coalescence. Fig. 12.23 shows a cross section of a typical electrostatic treater (a three-phase separator, in this case). The electrical system consists of a transformer and electrodes that provide high-voltage alternating current. The electrodes are placed to provide an electric field that is perpendicular to the direction of flow. The distance between the electrodes is often adjustable so that the voltage can be varied to meet the requirement of the emulsion being treated.

Electrostatic dehydration generally is used with chemical and heat addition. Invariably, the use of electrostatic dehydration results in reduced heat requirements. Lower temperatures result in fuel economy, reduced problems with scale and corrosion formation, and reduced light-end loss. Electrostatic grids can also lead to a reduction in the use of emulsion-breaking chemicals. The one limitation of electrostatic dehydration is shorting/arcing, which generally happens when excess water is present. Recent designs in electrostatic grids have eliminated shorting/arcing.

Chemical Methods. The most common method of emulsion treatment is adding demulsifiers. These chemicals are designed to neutralize the stabilizing effect of emulsifying agents. Demulsifiers are surface-active compounds that, when added to the emulsion, migrate to the oil/water interface, rupture or weaken the rigid film, and enhance water droplet coalescence. Optimum emulsion breaking with a demulsifier requires a properly selected chemical for the given emulsion; adequate quantity of this chemical; adequate mixing of the chemical in the emulsion; and sufficient retention time in separators to settle water droplets. It may also require the addition of heat, electric grids, and coalescers to facilitate or completely resolve the emulsion.

Chemical Selection. Selection of the right demulsifier is crucial to emulsion breaking. The selection process for chemicals is still viewed as an art rather than a science. However, with the increasing understanding of emulsion mechanisms, the availability of new and improved chemicals, and new technology, research, and development efforts, selection of the right chemical is becoming more scientific. Many of the failures of the past have been eliminated.

Demulsifier chemicals contain the following components: solvents, surface-active ingredients, and flocculants. Solvents, such as benzene, toluene, xylene, short-chain alcohols, and heavy aromatic naptha, are generally carriers for the active ingredients of the demulsifier. Some solvents change the solubility conditions of the natural emulsifiers (e.g., asphaltenes) that are accumulated at the oil/brine interface. These solvents dissolve the indigenous surface-active agents back into the bulk phase, affecting the properties of the interfacial film that can facilitate coalescence and water separation.

Surface-active ingredients are chemicals that have surface-active properties characterized by hydrophilic-lipophilic balance (HLB) values. For a definition and description of HLB, see the literature. The HLB scale varies from 0 to 20. A low HLB value refers to a hydrophilic or water-soluble surfactant. In general, natural emulsifiers that stabilize a water-in-oil emulsion exhibit an HLB value in the range of 3 to 8. Thus, demulsifiers with a high HLB value will destabilize these emulsions. The demulsifiers act by total or partial displacement of the indigenous stabilizing interfacial film components (polar materials) around the water droplets. This displacement also brings about a change in properties such as interfacial viscosity or elasticity of the protecting film, thus enhancing destabilization. In some cases, demulsifiers act as a wetting agent and change the wettability of the stabilizing particles, leading to a breakup of the emulsion film.

Flocculants are chemicals that flocculate the water droplets and facilitate coalescence. A detailed process for selecting the appropriate demulsifier chemicals, described in the literature, includes the following steps.

• Characterization of the crude oil and contaminants includes the API gravity of the crude oil, type and composition of oil and brine, inorganic solids, amount and type of salts, contaminant type and amounts.
• Evaluation of operational data includes production rates, treating-vessel capabilities (residence time, electrostatic grids, temperature limitations, etc.), operating pressures and temperatures, chemical dosage equipment and injection points, sampling locations, maintenance frequency, and wash-water rates.
• Evaluation of emulsion-breaking performance: past experience and operating data including oil, water, and solids content during different tests; composition and quality of interface fluids; operating costs; and amounts of water generated and its disposal.

Testing procedures are available to select appropriate chemicals. These tests include bottle tests, dynamic simulators, and actual plant tests. All test procedures have limitations. Hundreds of commercial demulsifier products are available that may be tested. Changing conditions at separation facilities result in a very slow selection process, especially at large facilities; therefore, it is important at such facilities to maintain a record of operational data and testing procedures as an ongoing activity.

Mixing/Agitation. For the demulsifier to work effectively, it must make intimate contact with the emulsion and reach the oil/water interface. Adequate mixing or agitation must be provided to thoroughly mix the chemical into the emulsion. This agitation promotes droplet coalescence; therefore, the point at which the demulsifier is added is critical. Once the emulsion has broken, agitation should be kept to a minimum to prevent re-emulsification. There should be sufficient agitation in the flow stream to allow the chemical to mix thoroughly, followed by a period of gentle flow inside the separator to promote gravity separation.

Dosage. The amount of chemical added is also important. Too little demulsifier will leave the emulsion unresolved. Conversely, a large dose of demulsifier (an overtreat condition) may be detrimental. Because demulsifiers are surface-active agents like the emulsifiers, excess demulsifier may produce very stable emulsions. The demulsifier simply replaces the natural emulsifiers at the interface.

It is difficult to prescribe standard or typical dosage rates for treating emulsions because of the wide variety of demulsifier chemicals available, the different types of crude being handled, the choice of separation equipment, and the variations in product qualities. Furthermore, some of the chemicals come in different concentrations (active ingredient in a carrier solvent). The amount or dosage of demulsifier required is very site-specific and depends on several factors, some of which are discussed in this chapter. On the basis of an evaluation of the literature, the demulsifier rates quoted vary from less than 10 to more than 100 ppm (based on total production rates). These numbers are provided for primary or secondary oil-recovery emulsions. During tertiary oil recovery (especially during surfactant or micellar flooding), demulsifier rates typically can be in the hundreds of ppm and even higher in extreme cases.

Factors Affecting Demulsifier Efficiency. Several factors affect demulsifier performance including temperature, pH, type of crude oil, brine composition, and droplet size and distribution. As described previously, an increase in temperature results in a decrease in emulsion stability, and, hence, a lower dosage of demulsifier is required. pH also affects demulsifier performance. Generally, basic pH promotes oil-in-water emulsions and acidic pH produces water-in-oil emulsions. High pH, therefore, helps in destabilizing water-in-oil emulsions. It has also been reported that basic pH reduces demulsifier dosage requirements (see Fig. 12.21).

Demulsifiers that work for a given emulsion may be completely ineffective for another. Demulsifiers are typically formulated with polymeric chains of ethylene oxides and polypropyl¬ene oxides of alcohol, ethoxylated phenols, ethoxylated alcohols and amines, ethoxylated resins, ethoxylated nonylphenols, polyhydric alcohols, and sulphonic acid salts. Fig. 12.25 shows typical demulsifier molecular formulas. Commercial demulsifiers may contain one or more types of active ingredient. There is a wide variation within the active ingredient type as well. For example, the molecular weight and structure of the ethylene or propylene oxides can be changed to effect a complete range of solubilities, HLBs, charge neutralization tendencies, solids-wetting characteristics, and costs.

• 

  Fig. 12.25 – Typical demulsifier molecular formulas.

Mechanisms Involved in Chemical Demulsification. Chemical demulsification is very complex. There are several hypotheses and theories regarding the physicochemical mechanism for the action of a chemical demulsifier. The only clear generalization regarding demulsifiers is that they have a high molecular weight (about the same as natural surfactants) and, when used as emulsifying agents, they tend to establish an emulsion opposite in type to that stabilized by natural surfactants. There are thousands of products that have been patented as crude oil demulsifiers. A detailed knowledge of the functionality of demulsifiers and their effectiveness in breaking emulsions is still lacking; however, there are a few general rules for chemical demulsifiers and their ability in breaking emulsions.

Several studies have been conducted on certain aspects of the chemical demulsification process. It has been suggested that demulsifiers displace the natural stabilizers present in the interfacial film around the water droplets. This displacement is brought about by the adsorption of the demulsifier at the interface and influences the coalescence of water droplets through enhanced film drainage.

Fig. 12.26 shows the film drainage process schematically. When two droplets approach each other, the thickness of the interfacial film decreases as the liquid flows out of the film. This sets up an IFT gradient with high IFT inside the film and low IFT outside the film. The interfacial viscosity is very high because of the adsorbed natural surfactants (asphaltenes). Demulsifier molecules have a higher surface activity than natural surfactants and, therefore, replace them at the interface. When demulsifier molecules are adsorbed in the spaces left by the natural surfactants, the IFT gradient is reversed, film drainage is enhanced, and the interfacial viscosity is reduced. This causes the film to become very thin and collapse, resulting in droplet coalescence. The efficiency of the demulsifier thus depends on its adsorption at the droplet surface. There is competition for adsorption when other surface-active species are present. The indigenous surfactants, like asphaltenes, present in the crude oil are only weakly adsorbed and are readily displaced by the demulsifier.

• 

  Fig. 12.26 – Film drainage in the presence of a demulsifier. The demulsifier displaces the indigenous surfactants in the interfacial film.

Because of the large variety of components in the crude oil, it is not surprising that the effectiveness of a given demulsifier is sensitive to the crude oil type. In addition, the adsorption and displacement processes and, hence, the demulsifier effectiveness also depend on pH, salt content, and temperature. The best demulsifiers are those that readily displace preformed rigid films and leave mobile films (films that exhibit little resistance to coalescence) in their place.

Besides displacing the natural surfactants at the interface (breaking the rigid film), many chemical additives reduce or inhibit the rate of buildup of interfacial films. The best demulsifiers should possess both types of film modifying behavior: displacement of components in rigid interfacial films and inhibition of the formation of the rigid films.

The demulsifier effectiveness also depends on its dosage. An increase in demulsification rate is generally observed with increasing demulsifier concentration up to a critical concentration (the critical aggregation concentration). This is attributed to a monolayer adsorption of the demulsifier at the interface (simultaneously displacing the indigenous crude oil surfactant film). Higher concentrations beyond this critical concentration (overdosing) result in two different types of behavior. Type I behavior is the leveling of the demulsification rate with increased demulsifier concentration. This type of behavior is attributed to the formation of a liquid crystalline phase. Type II behavior is a reduction in demulsification rate with increased demulsifier concentration. This type of behavior is attributed to steric stabilization of grown water droplets and is detrimental to demulsification because it retards the separation rate during overdosing. The type of behavior observed depends on the concentration and type of demulsifier. Some demulsifiers form aggregates in water or oil to give a viscous phase, while others may stabilize the emulsion sterically.

The solubility of the demulsifier in oil and water, or its partitioning, is also very crucial in determining the effectiveness of the demulsifier. The partitioning of the surfactant is measured either by the partition coefficient or by its HLB value. Several studies have tried to link the demulsifier effectiveness to its partition coefficient. For the demulsifier to be fairly active, it must be an amphiphile with a partition coefficient of unity (i.e., the demulsifier should partition equally between the oil and water phases). The surface adsorption rate is faster when the demulsifier has a partition coefficient of close to one. Because of this criterion and the fact that demulsifiers are added to the continuous oil phase, demulsifiers that are soluble in water only (low partition coefficient or low HLB) are not very effective in breaking water-in-oil emulsions. Oil solubility is important because oil forms the continuous phase, permits a thorough distribution of the demulsifier in the emulsion, and affects its diffusion to the oil/water interface. When this demulsifier reaches the interface, it must partition into the water phase (droplets) to displace the natural stabilizers at the interface effectively. This results in a reduction of interfacial viscosity and a change in the IFT gradient, both of which enhance film thinning and water droplets coalescence.

To ensure good overall performance, a demulsifier should meet the following criteria.

• Dissolve in the continuous oil phase.
• Have a concentration large enough to diffuse to the oil/water interface. However, it should not be higher than the critical aggregate concentration.
• Partition into the water phase (partition coefficient close to unity).
• Possess a high rate of adsorption at the interface.
• Have an interfacial activity high enough to suppress the IFT gradient, thus accelerating the rate of film drainage and promoting coalescence.

Special Topics in Crude Oil Emulsions

Emulsion Sampling

Samples of the emulsion may be required for several reasons including crude specification verification, performance evaluation of the emulsion-treating system, or simply for laboratory testing. Invariably, the emulsion to be sampled is under pressure, and special procedures must be used to obtain representative samples. For crude specification testing, it is not important to maintain the integrity of the water droplets; however, the sample location point may be critical. In general, samples should not be withdrawn from the bottom of the pipe or vessel. Free water may be present and accumulate at the bottom of the pipe or vessel, affecting the BS&W reading. Neither should the sample be withdrawn from the top of the vessel because it primarily will be oil. The best position in the pipe to take an emulsion sample is on the side, preferably with a quill. Turbulence and high fluid velocity in the pipe may also ensure that the sample is homogenous and representative.

Every effort should be made to obtain a sample that closely represents the liquid from which it is taken. This is especially true of liquids under pressure. Emulsification should not occur during the sampling itself. For example, samples obtained at the wellhead or production headers may show a high percentage of emulsion, whereas the actual oil and water inside the piping may or may not be in the form of an emulsion. This indicates that the emulsification was a consequence of the sampling because the sample was depressurized into the sample container.

A special procedure is used to obtain representative samples from pressurized sources without further emulsification of the liquids. Fig. 12.27 shows a floating piston cylinder used in the procedure. The cylinder is first evacuated and filled with a pressurizing fluid (for example, glycol or a synthetic oil) on one side of the floating piston. The top of the cylinder (evacuated side) is then connected to the sampling location from which the sample is to be taken. The bottom valve on the cylinder is closed and the top valve slowly opened to pressurize the fluid in the cylinder. This is usually a small amount because of the low compressibility of the liquid in the cylinder. Once the top valve is completely open, the bottom valve is opened very slowly to drain the pressurizing liquid while allowing the sample liquid to be taken in from the top into the cylinder. The procedure should be performed slowly to obtain the sample without a pressure drop between the cylinder and the sampling location. Another variation of the method is to charge the sample into a simple cylinder, without a floating piston, filled with water or mercury. Once the sample is captured, the cylinder can be depressurized extremely slowly with little effect on the sample. In situations in which this procedure is not possible, the best sampling method is to bleed the sample line very slowly into the sample container. The idea is to minimize shear and reduce emulsification that may be caused by the sampling procedures.

• 

  Fig. 12.27 – Sampling of a high-pressure emulsion.

Field Emulsion-Treatment Program

There is a lack of specific case studies on emulsion treatment in the open literature for the following reasons.

• An emulsion treatment program is very site-specific. Each producing system is unique and is reviewed individually for solutions.
• Traditionally, demulsifier selection has been conducted by the chemical service companies, who have been reluctant to part with the information. This has also been, in part, because of the lack of understanding of emulsion treatment.
• Chemical selection has been viewed as a "black art" that has produced as many failures as successes.
• The scope of emulsion treatment is very broad, and it is usually difficult to address the complexities in generalized studies. Parts of the specifics have been reported extensively.
• Most of the operating oil companies have some sort of optimization programs for emulsion treatment. In general, this includes addition of chemicals, heat, and retrofitting.

The design of emulsion-treating equipment and procedures for a given field or application requires experience and engineering judgment. The engineer must rely on laboratory data, data from nearby wells or fields, and experience. There is no standard solution available for striking a balance between, for example, the amount of chemical and heat to resolve emulsions. The greater the treatment temperature, the lower the amount of demulsifier needed. In general, economic analysis dictates the type and size of equipment used and the balance between the amount of chemical used and heating requirements. In some cases, crude oil specifications may decide the system to be used for emulsion treatment. Other factors include internal packing and the size of the equipment. The savings in equipment cost must be balanced against the increased capital and operating costs of the packing or coalescing grids.

Laboratory bottle tests can provide an estimate of treating temperatures and retention times that can be used for design and operation; however, these tests are done under static conditions, and field usage is dynamic. Demulsifier dosages, for example, generally are much greater in the static bottle tests than during field conditions. However, laboratory testing is excellent for screening different emulsion samples for relative tightness, evaluating prospective demulsifiers, and evaluating the effects of different variables on emulsion resolution.

General guidelines for an emulsion-treatment program in the field include the following points.

• Each producing stream is unique and must be evaluated individually to determine the best separation strategy. Laboratory tests should be conducted with actual samples to determine the tightness of the emulsions; however, data from nearby wells and fields can be used as estimates.
• During the early design of the separation facility, planning for future emulsion treatment should begin. For example, if water cuts are anticipated to increase, appropriate measures should be taken in the design phase of the equipment or handling facilities for increased water handling.
• Operational experience and laboratory work are needed to substantiate emulsion concerns and identify solutions. Pilot and plant tests should determine the actual treatment requirements. As noted previously, bottle tests have limitations in determining dosage but are good for screening and trend analysis.
• Treatment capacities can be increased for existing separator trains by re-engineering and retrofitting. For example, internal packing can be installed in the separator for improving emulsion resolution. See the chapter on emulsion treating in the Facilities section of this Handbook for additional details.
• For existing systems, demulsifier and other relevant operational data (production rates, water cuts, temperatures, and costs) should be recorded over time. These data can be useful for analyzing demulsifier dosages (for example, during summer and winter) and unit demulsifier costs and can pinpoint certain activities that may be responsible for emulsion upsets and underlying problems. These data are also very useful for optimization of emulsion-treatment programs.
• The emulsion-treatment program should be reviewed periodically because conditions change. The frequency of evaluation depends on many factors including the relative cost of the demulsifier usage, heating costs, capacity limitations, and manpower requirements.

Emulsion Prevention

Emulsions are always a drain on the operating budget. It is almost impossible to eliminate emulsions during crude production; however, emulsion problems can be reduced and optimized by following good operating practices. The following points should be included in operating practices.

• Solids management. Fine solids stabilize emulsions, and efforts should be made to reduce solid contaminants during production. These solids include asphaltenes, which can be controlled by effective asphaltene management, dispersants, etc.; scales, which should be reduced by scale inhibitors; and waxes, which should be controlled with pour-point depressants or heating.
• Reduction of corrosion products. These products can be reduced with effective corrosion inhibitors.
• Acidization. Stimulation with acids can cause very tight emulsions; consequently, acid jobs should be designed with care, and their field performance should be reviewed. To avoid emulsion upsets, the acid job design should incorporate effective demulsifiers at relatively high concentrations, use mutual solvents, and minimize fines and precipitates during acidization.
• Mixing or turbulence. Chokes and other devices such as pumps should be controlled to optimize shear and mixing. While a moderate amount of mixing is necessary and beneficial, severe mixing leads to tight emulsions or even re-emulsification after water separation. Another place to control mixing is in gas lift operations by injecting the optimum amount of gas.
• Compatibility of chemicals. Increasingly, more chemicals are being used for improved oil recovery and crude processing. The chemical may be the source of the emulsion problem. Compatibility studies should be performed with the chemicals that are used during crude oil production (from the reservoir to the separation facilities), and their emulsion-forming tendencies should be evaluated.

Demulsifier Selection and Optimization

For an existing facility, important questions include, "Are we using the best demulsifier?" and, "Is my demulsifier usage optimized?" Demulsifier selection is still considered an art that improves with experience; however, there are methods now available to eliminate some of the uncertainties involved in demulsifier screening and selection. The properties of a good demulsifier were addressed previously. How to select the best demulsifier and to optimize its usage is addressed here.

Demulsifier selection should be made with the emulsion-treatment system in mind. Some of the questions to be asked include the following.

• What is the retention time of the emulsion in the equipment?
• What type of emulsion is to be treated?
• What is the water cut?
• Is the system heated, or can it be heated if necessary?
• What is the range of operating temperatures during the summer and winter months?
• Is the feed constant or changing in composition?

As field conditions change, demulsifier requirements also change. Lower temperatures in the winter can induce wax-related and other problems. Well treatments can upset the treatment plant. For example, acidizing a well can result in asphaltenic sludges that may form tight and stable emulsions. Similarly, well workovers and chemical treatments can lead to emulsion-related problems at the treatment facility. The consequences of well treatments and other activities should be anticipated, and the operator should be ready to increase the demulsifier dosage, if necessary. It cannot be expected that the same demulsifier or the same demulsifier dosage will be capable of resolving emulsions when conditions change.

To select a demulsifier for a given system, one generally starts with the bottle tests. Representative emulsion samples are taken and transferred into several centrifuge tubes. Several demulsifiers, usually from different demulsifier vendors, are added to the centrifuge tubes in various amounts, and water-dropout data are collected and analyzed to determine the best demulsifier. Before the tests, the demulsifier vendors can be invited to provide one or two of their demulsifiers. Most vendors would want to test their chemicals with emulsions from the field before submitting their best candidates. A quantitative method for demulsifier testing was developed recently, and the calculation procedures are described in the Appendix. For selecting the best demulsifier, several sets of tests may be necessary at different concentrations, temperatures, water cuts, etc. The demulsifier dosages obtained in the lab are generally greater than what will be needed in the field. It is highly recommended that the bottle test be conducted with fresh emulsions (i.e., within a few minutes of sampling), because sample aging has a significant effect on demulsifier dosages. During the bottle tests, other factors should be noted: color and appearance of the emulsion, clarity of the water, sediments in the water, presence of a rag layer, and loose solids hanging at the interface. These factors can provide information that may be important during demulsifier selection.

After the bottle tests, two or three promising demulsifiers are selected for field testing. During the field trials, the screened chemicals should be tested at various concentrations, operating temperatures, and settling times and tested for clarity of separated water and, most importantly, the amount of water and salt remaining in the produced crude. It is also a good idea to test the chemicals over a period of time (minimum of 1 to 2 days and longer, if possible) to evaluate the performance and compare it with the incumbent chemical performance. The best demulsifier is the one that produces the fastest, cleanest separation at the lowest possible cost per unit barrel of crude.

The demulsifier concentrations generally range from less than 5 ppm (approximately 1 gal/5,000 bbl) to more than 200 ppm (approximately 8 gal/1,000 bbl). The most common range is between 10 and 50 ppm. Whatever the demulsifier dosage and range, it may be possible to reduce and optimize the demulsifier usage by evaluating various components in the treatment program.

Proper Demulsifier Mixing. For the demulsifier to be effective, it must mix intimately with the emulsion and migrate to the film surrounding the water droplets. If the mixing is poor, the demulsifier will be ineffective. Ideally, the demulsifier should be injected in a continuous stream through inline mixers that are sufficiently upstream so that the demulsifier has time to mix thoroughly with the emulsion. Demulsifier slugging should be avoided because it creates localized high concentration regions (an overtreat condition) and promotes re-emulsification. One way to enhance the mixing is to dilute the demulsifier with sufficient quantities of a diluent, generally a solvent, and inject the diluted demulsifier/solvent mixture into the emulsion. The larger quantity of the mixture makes it possible for the chemical to be mixed more uniformly with the emulsion.

Similarly, turbulence enhances the diffusion and dispersion of demulsifier into the emulsion and increases the probability of collisions between water droplets. This turbulence must persist long enough to allow the chemical to reach the interface between the oil and water, but the intensity should not be so severe that it causes further tightening of the emulsion. This level of turbulence is usually provided by normal flow through the emulsion-treating unit that occurs in the pipes, manifolds, valves, and separators. When the flow rates are too low for proper mixing, special care must be taken for mixing the chemical. Special mixers, such as mixing valves, injection quills, kinetic mixers, and vortex mixers, may be installed to ensure proper demulsifier mixing.

The point at which the demulsifier is injected is also important. In general, the further upstream the demulsifier is injected, the better. However, if there is considerable turbulence and shear between the point where the demulsifier is injected and the point where water is removed, it may be worthwhile to reconsider that decision. Another problem with very far upstream injection is the separation of water in the pipes, which can lead to other problems, such as corrosion. In many instances, demulsifier is injected at multiple points to optimize its overall usage; however, this is an option for high-volume treatment facilities and, here again, the demulsifier-split ratio (between different points) should be optimized by trial and error.

Another problem sometimes ignored is the settling characteristics of the demulsifier. The active ingredients in some demulsifiers tend to settle at the bottom of demulsifier tanks because of insolubility, incomplete mixing, and density differences. If this happens, the surface-active ingredient injection into the treatment facility is erratic. During the first few days of the tank charge and injection, the demulsifier may work satisfactorily; however, subsequent performance may deteriorate as the active ingredients are exhausted and only the carrier solvent is injected. If this cycle is observed, the culprit is the settling of the active ingredients of the demulsifier in the tank. Steps to eliminate settling include installing a mixer in the demulsifier tank or replacing the demulsifier.

Demulsifier Overdosing. Overdosing of the chemical can result in enhanced stability of the emulsion, leading to rag layers or pads inside the separators. This is a severe problem because it worsens with increased demulsifier costs. It can be difficult to determine that there is demulsifier overdosing at a treatment facility. One way to reduce overdosing is to conduct field-optimization tests periodically to determine optimum demulsifier rates. These tests are done by going through a series of demulsifier rates at the treatment facility and monitoring the product crude and water characteristics. These trials provide the best demulsifier rates for the facility. A better way to optimize demulsifier rates is by installing automated or semiautomated demulsifier control systems. The control systems receive input from sensors in the treatment facility and take action to increase or decrease the demulsifier rates. The sensors monitor grid voltages in the dehydrator and desalter, emulsion layer inside the separator (monitoring through interface levels), crude and water quality, and operating temperature. The controller can also inject additional demulsifier into the separator inlet during upset conditions to minimize their impact. An automatic controller should always be searching for the minimum demulsifier usage.

Understanding the Causes of Emulsions. For larger facilities it may be worthwhile to understand the causes of tight emulsions. Some of the factors that stabilize emulsions, such as fine solids, asphaltenes and waxes, temperature, size of water droplets, pH, brine composition, etc., were highlighted earlier. Some of the factors, such as brine composition and water cuts, cannot be controlled; however, other factors can be controlled. The temperature can be increased by heating the crude or burying/insulating the flowlines. Water droplet sizes can be increased by reducing mixing or shearing. Organic precipitates can be eliminated with dispersants and specialty chemicals. The first task is to diagnose the causes. Understanding the causes leads to better decisions for controlling the demulsifier usage. Several investigative case studies have been reported for understanding the causes of tight emulsions and optimizing demulsifier usage.

Evaluating the Process. A thorough evaluation of the emulsion-treatment facility may be worthwhile for optimizing costs. Some of the factors to explore include the extent of agitation, wash-water rates, electrostatic grid voltages, retention times, and separator internals.

Agitation. Some agitation is necessary to mix the demulsifier into the bulk of the emulsion. Agitation is also necessary for the water droplets to collide, increasing the probability of their coalescence. However, every effort should be taken to prevent excessive agitation because this may lead to further emulsification. In other words, a moderate level of agitation is required, and excessive turbulence should be avoided. Demulsification can be assisted by the use of plate packing or baffles inside the separators. These baffle plates distribute the emulsion evenly and cause gentle agitation, which assists in the coalescing of droplets. The surface of the plates also helps in drop coalescence.

Retention Time. The gentle agitation necessary after the mixing of the demulsifier should be followed by a period of quiescent settlement to enhance coalescence, generally by gravity settling. This relates to the retention time of the fluid in the separator and the dimensions of the vessel.

Electrostatic Coalescing. Drop coalescence can be assisted by the application of a high-voltage electric field to the emulsion. This is particularly beneficial for polishing the oil and reducing the oil’s water content to very low levels (less than 0.5%). Electrostatic coalescing works by charging the water droplets and increasing the frequency of their collision, which improves their chance of coalescence.

Maintaining a Database on Usage and Costs. Experience and demulsifier data are important because they can be used to optimize usage. Typical data to maintain in a database include oil and water rates, temperatures, demulsifier rates, demulsifier costs, and comments regarding any changes that were made in the treatment facilities. Table 12.1 provides typical data for an operating wet-crude handling facility. Such data can be analyzed to diagnose demulsifier-usage problems. They can also be used as a base to compare the results for new and experimental demulsifiers. Furthermore, they provide a quick, easy reference for understanding the seasonal variation in consumption, causes of upsets, or increased demulsifier usage.

• 

  Table 12.1

Nomenclature

a	=	factor for the type of emulsion
e	=	exponential function
g	=	acceleration caused by of gravity, L/t2, m/s2
I	=	emulsion separation index, %
n	=	number of experiments
r	=	radius of the droplets, L, m
T	=	temperature, T, °F
v	=	settling velocity of the water droplets, L/t, m/s
W	=	water separation at a given demulsifier concentration/time as a percentage of BS&W
δ	=	contact angle, degrees
μ	=	viscosity, m/Lt, cp
μe	=	viscosity of emulsion, m/Lt, cp
μo	=	viscosity of clean oil at same temperature, m/Lt, cp
ρw	=	density of water, m/L3, lbm/ft3
ρo	=	density of oil, m/L 3 , lbm/ft 3
Φ	=	water cut or fraction of water

Acknowledgements

This chapter is based on a literature review conducted at Saudi Aramco as part of a Ghawar Emulsion Study Team with contributions from Mohammad Abdulmoghini, Bob Hintermeier, and Edward Chen. Review of the chapter by Henry Halpern and Martin Wingrove of Saudi Aramco is also acknowledged.

References

Appendix A – Emulsion Separatation Index (ESI) Test

The emulsion bottle test is a quantitative method for demulsifier testing and involves the following procedure.

• The crude oil emulsion sample is tested as soon as possible after it is received in the lab. The pressurized method for sampling the emulsion is recommended. The samples are remixed with a standard bottle shaker for approximately a minute. The same amount of shaking should be used in all tests.
• The mixed emulsion sample is added to 100-ml standard centrifuge tubes.
• The centrifuge tubes are placed in a water bath for a minimum of 30 minutes to reach the desired temperature.
• The required dosage of the chemical is added to the centrifuge tubes. The amount of chemical is based on the total amount of emulsion (oil and water).
• The tubes are shaken by hand a given number of times (approximately 20 shakes) and placed in the water bath at the desired temperature.
• The amount of water separated is measured with time (5, 10, 15, and 20 minutes).
• After 20 minutes, the tubes are centrifuged for another 20 minutes at the desired temperature, and the final amounts of water and emulsion or rag layer are measured.
• Generally, these experiments should be done in sets to investigate the effect of certain variables. All efforts should be made to keep all the variables constant except the one under investigation.

The ESI is then calculated from the measured oil/water separation data.

....................(A-1)

where I = emulsion separation index, W = water separation at a given demulsifier concentration/time as a percentage of BS&W, and n = number of experiments.

Notes

• Direct comparison of demulsifier dosage obtained in the laboratory with field observations should always be made with caution because the laboratory experiments are made under static conditions, and field usage observations are made under dynamic conditions. Furthermore, ESI tests are done on dead crude, while field usage tests are on live (gas dissolved) crudes. However, laboratory testing is excellent for screening wellhead samples for relative emulsion tightness; evaluating prospective demulsifiers; and evaluating the effects of different variables on emulsion resolution because all the conditions are kept constant except the variable under investigation.
• Although ESI quantifies the bottle tests, it has a qualitative edge and has a range of reproducibilities because of several possible errors. These possible errors include sampling error, operator error, inability to read the level of water separated properly because the oil has a tendency to stick to the glass, and temperature error.
• There is a definite effect of aging. The longer an emulsion (oil/water mixture) stays in the lab before testing, the higher the demulsifier dosage required to break it; therefore, for best results, ESI tests should be done on fresh emulsion samples.

---

Example 12.A.1

Given the data in Tables A-1 and A-2, calculate the ESI for Demulsifier C.

• 

  Table A-1

• 

  Table A-2

Solution. Eq. A-1 can be used to give

---

SI Metric Conversion Factors

cp	×	1.0*	E−03	=	Pa•s
ft3	×	2.831 685	E−02	=	m3
°F		(°F−32)/1.8		=	°C
lbm	×	4.535 924	E−01	=	kg

*

Conversion factor is exact.