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Difference between revisions of "Oil emulsions"
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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%.
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
- Disposed of properly
All these steps increase costs. Furthermore, crude oil must comply with certain product specifications for sale, 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.
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
- Recent books on petroleum emulsions.
Crude oils vary considerably in emulsifying tendency. Some form very stable emulsions that are difficult to separate. Others do not emulsify or form loose emulsions that separate quickly. In an untreated emulsion, the density difference between the oil and the water will cause a certain amount of water to separate from the oil by natural coalescence and settling; however, unless some form of treatment is used to accomplish complete separation, a small percentage of water probably will remain in the oil, even after extended settling. The remaining water will be in minute droplets that have extremely low settling velocities. These droplets also will be widely dispersed, so that they have little chance to collide, coalesce into larger droplets, and settle.
The amount of water that emulsifies with crude oil in most production systems can vary widely, ranging from < 1 to > 60 vol% (in rare cases). The most common range of emulsified water in light crude oils (i.e., above 20°API) is from 5 to 20 vol%, and in crude oils that are heavier than 20°API is from 10 to 35 vol%.
Types of emulsions
Produced oilfield emulsions can be classified into three broad groups:
- 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. 1 and 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.
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. 3 shows an example of a multiple 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.
In a true emulsion, either the drop size must be small enough that forces from thermal collisions with molecules of the continuous phase produce Brownian motion that prevents settling, or the characteristics of the interfacial surfaces must be modified by surfactants, suspended solids, or another semisoluble material that renders the surface free energy low enough to preclude its acting as a driving force for coalescence.
An emulsion’s characteristics change continually from the time of formation to the instant of complete resolution. Accordingly, aged emulsions can exhibit very different characteristics from those that fresh samples do. This is because any given oil contains many types of adsorbable materials and because the adsorption rate of the emulsifier and its persistence at the interface can vary. The emulsion characteristics also change when the liquid is subjected to changes in the following:
- Degree of agitation
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
- 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.
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 (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
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 Oil emulsions stability. 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
- 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
- Wettability of the particles
Finely divided solids found in oil production include:
- Clay particles
- Asphaltenes and waxes
- Corrosion products
- Shale particles
- Mineral scales that collect at the oil/water interface
- Drilling muds
Fig. 4 shows the photomicrograph of an emulsion showing the presence of solids.
Characteristics and physical properties
Oilfield emulsions are characterized by several properties including:
- Appearance and color
- Droplet size
- 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:
- Oil/water content
- 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
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
- 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
- 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
- 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. 5 shows the drop-size distributions of typical petroleum emulsions. The droplet-size distribution in an emulsion depends on several factors including the:
- Interfacial tension (IFT)
- Nature and amount of emulsifying agents
- Presence of solids
- 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. 1 through 4 show the droplet-size distribution for several 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. 1 through 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.
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. 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%).
Temperature also has a significant effect on emulsion viscosity. Fig. 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
- Shear rate
- Amount of solids present
Figs. 6 and 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.
- a is the factor for the type of emulsion
- μe is the viscosity of emulsion
- μo is the viscosity of clean oil at same temperature
- 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
- 3.0 for very loose emulsion
Fig. 8 shows viscosities calculated with Eq. 1. Emulsion viscosity depends on several factors, and Eq. 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
- 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.
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 Stability of oil emulsions ) 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. Several sources provide a detailed discussion of measurement techniques and application to emulsion stability.
|a||=||factor for the type of emulsion|
|μe||=||viscosity of emulsion, m/Lt, cp|
|μo||=||viscosity of clean oil at same temperature, m/Lt, cp|
|Φ||=||water cut or fraction of water|
- Becher, P. ed. 1983. Encyclopedia of Emulsion Technology, Vol. 1 Basic Theory. New York: Dekker.
- Becher, P. ed. 1985. Encyclopedia of Emulsion Technology, Vol. 2 Applications. New York: Dekker.
- Becher, P. ed. 1988. Encyclopedia of Emulsion Technology, Vol. 3 Basic Theory, Measurement and Applications. New York: Dekker.
- Becher, P. 1966. Emulsions: Theory and Practice, second edition, Advances in Chemistry Series No. 162. Washington, DC: American Chemical Soc.
- L.L. Schramm ed. 1992. Emulsions: Fundamentals and Applications in the Petroleum Industry, Advances in Chemistry Series No. 231. Washington, DC: American Chemical Society.
- Manning, F.S. and Thompson, R.E. 1994. Water-in-Crude-Oil Emulsions. Oilfield Processing 2.
- Schubert, H. and Armbroster, H. 1992. Principles of Formation and Stability of Emulsions. Intl. Chem. Eng. 32 (1): 14.
- Tambe, D.E. and Sharma, M.M. 1993. Factors Controlling the Stability of Colloid-Stabilized Emulsions: I. An Experimental Investigation. J. Colloid Interface Sci. 157 (1): 244-253. http://dx.doi.org/http://dx.doi.org/10.1006/jcis.1993.1182
- I.B. Ivanov ed. 1988. Thin Liquid Films, Surfactant Science Series. New York: Dekker.
- Mohammed, R.A., Bailey, A.I., Luckham, P.F. et al. 1994. The effect of demulsifiers on the interfacial rheology and emulsion stability of water-in-crude oil emulsions. Colloids Surf., 91 (3 November): 129-139. http://dx.doi.org/http://dx.doi.org/10.1016/0927-7757(94)02840-0
- Chen, G. and Towner, J.W. 2001. Study of Dynamic Interfacial Tension for Demulsification of Crude Oil Emulsions. Presented at the SPE International Symposium on Oilfield Chemistry, Houston, Texas, 13-16 February 2001. SPE-65012-MS. http://dx.doi.org/10.2118/65012-MS
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