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Stability of oil 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 that would otherwise break down an emulsion. Such mechanisms include:
- Aggregation or flocculation
- Phase inversion
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. Oil demulsification discusses the mechanisms of emulsion breakup.
Surface films and stability to coalescence
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. 1 and 2 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.
- Type of crude oil (asphaltic, paraffinic, etc.)
- Composition and pH of the water
- Extent to which the adsorbed film is compressed
- Contact or aging time
- Concentration of polar molecules in the crude oil
- 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.
Factors affecting oil emulsion stability
- Heavy polar fractions in the crude oil
- Solids, including organic (asphaltenes, waxes) and inorganic (clays, scales, corrosion products, etc.) materials
- Droplet size and droplet-size distribution
- pH of the brine; and brine composition
Heavy polar fraction in crude oil
- 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.
Fig. 3 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 scattered throughout. The heteroatoms include:
- Trace metals like vanadium and nickel
Fig. 4 shows a 3D representation of the structure of an asphaltene molecule. 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.
The nature of asphaltenes in the crude oil is still a subject of debate (see Asphaltenes and waxes for more details). 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. 5). 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:
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. 6). 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. 7 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. 8 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.
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. 9 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.
Resins are complex high-molecular-weight compounds that are not soluble in ethyl¬acetate but are soluble in n-heptane (Fig. 3). They are heterocompounds, like asphaltenes, that contain:
- Sulfur atoms
Molecular weights of resins range from 500 to 2,000. As Fig. 6 shows, resins have a strong tendency to associate with asphaltenes, and together they form a micelle. As Figs. 7 and 8 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 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.
- Solid particle size
- Interparticle interactions
- 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. 10 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:
Examples of water-wet solids are:
- Inorganic scales (CaCO3, CaSO4)
- Corrosion products
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. 11). 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.
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. 9). 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.
Emulsion droplet sizes can range from less than a micron to more than 50 microns. Fig. 5 in Oil emulsions 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).
- Organic acids and bases
- Asphaltenes with ionizable groups
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 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 – Effect of pH and demulsifier concentration on emulsion stability.
Brine composition also has an important effect (in relation to pH) on emulsion stability. Fig. 13 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. 13 – 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:
- 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.
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.
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). Sampling and analyzing emulsions 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:
- 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. 5 Another technique developed recently used critical electric field measurements for emulsion stability.
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Noteworthy papers in OnePetro
Alboudwarej, H., Muhammad, M., Shahraki, A. K., Dubey, S., Vreenegoor, L., & Saleh, J. M. (2007, August 1). Rheology of Heavy-Oil Emulsions. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/97886-PA
Al-Ghamdi, A. M., Noik, C., Dalmazzone, C. S. H., & Kokal, S. L. (2007, January 1). Experimental Investigation of Emulsions Stability in GOSPs. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/106128-MS
Al-Ghamdi, A. M., Noik, C., Dalmazzone, C. S. H., & Kokal, S. L. (2007, January 1). Experimental Investigation of Emulsions Stability in GOSPs, Part II: Emulsion Behaviour. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/109888-MS
Al-Ghamdi, A. M., Noïk, C., Dalmazzone, C. S. H., & Kokal, S. L. (2009, December 1). Experimental Investigation of Emulsion Stability in Gas/Oil Separation Plants. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/109888-PA
Dalmazzone, C., Noïk, C., Glénat, P., & Dang, H.-M. (2010, September 1). Development of a Methodology for the Optimization of Dehydration of Extraheavy-Oil Emulsions. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/121669-PA
Ersoy, G., Yu, M., & Sarica, C. (2009, June 1). Modeling of Inversion Point for Heavy Oil-Water Emulsion Systems. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/115610-PA
Jones, T. J., Neustadter, E. L., & Whittingham, K. P. (1978, April 1). Water-In-Crude Oil Emulsion Stability And Emulsion Destabilization By Chemical Demulsifiers. Petroleum Society of Canada. http://dx.doi.org/doi:10.2118/78-02-08
Kang, W., & Wang, D. (2001, January 1). Emulsification Characteristic and De-emulsifiers Action for Alkaline/Surfactant/Polymer Flooding. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/72138-MS
Kokal, S., & Al-Juraid, J. (1999, January 1). Quantification of Various Factors Affecting Emulsion Stability: Watercut, Temperature, Shear, Asphaltene Content, Demulsifier Dosage and Mixing Different Crudes. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/56641-MS
Kokal, S., Al-Yousif, A., Meeranpillai, N. S., & Al-Awaisi, M. (2001, January 1). Very Thick Crude Emulsions: A Field Case Study of a Unique Crude Production Problem. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/71467-MS
Kokal, S. L. (2005, February 1). Crude Oil Emulsions: A State-Of-The-Art Review. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/77497-PA
Kokal, S. L., Al-Ghamdi, A., & Meeranpillai, N. S. (2007, March 1). An Investigative Study of Potential Emulsion Problems Before Field Development. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/102856-PA
Kokal, S. L., & Al-Dokhi, M. (2008, August 1). Case Studies of Emulsion Behavior at Reservoir Conditions. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/105534-PA
Poindexter, M. K., Chuai, S., Marble, R. A., & Marsh, S. C. (2003, January 1). Classifying Crude Oil Emulsions Using Chemical Demulsifiers and Statistical Analyses. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/84610-MS
Poindexter, M. K., Chuai, S., Marble, R. A., & Marsh, S. (2006, August 1). The Key to Predicting Emulsion Stability: Solid Content. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/93008-PA
Selves, J. L., & Burg, P. (1999, June 1). Predictions of Water-in-crude Oil Emulsion Stability From Chromatographic Data. Petroleum Society of Canada. http://dx.doi.org/doi:10.2118/99-06-02
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