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Oil 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:

  • Rate or the speed at which this separation takes place
  • Amount of water left in the crude oil after separation
  • 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% basic sediment and water (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

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. Factors that affect the interfacial film are discussed in Stability of oil emulsions. 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 of 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
  • 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 should be avoided or minimized where possible. Such measurees include:

  • Mechanical chokes
  • Valves
  • Flow obstructions
  • Pressure drops

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.[1][2] 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. Emulsion treating 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.[3]

  • 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.[3][4]

  • 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
  • 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

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. See Heating oil emulsions for more information. Heat accelerates emulsion breaking; however, it very rarely resolves the emulsion problem alone. Increasing the temperature has some negative effects.

  1. It costs money to heat the emulsion stream.
  2. Heating can result in the loss of light ends from the crude oil, reducing its API gravity and the treated oil volume.
  3. 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
  • The costs of electrostatic grid installation or retrofitting

See also Economics of treating emulsions.

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

See Emulsion treating subsystems for a detailed description of emulsion treating equipment.

Free-water knockout 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:

  • Heater section
  • Wash water
  • Filter section
  • Coalescing or stabilizing section
  • Electrostatic grids

Fig. 1 shows a typical three-phase separator.[5] 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.

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.

RTENOTITLE....................(1)

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
  • (ρw - ρo) is the density difference between the water and oil
  • 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
  • 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. 2 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.

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
  • Mix valves settings

Electrical methods

Electrostatic grids are sometimes used for emulsion treatment. When a nonconductive liquid (oil) that contains a dispersed conductive liquid (water) is subjected to an electrostatic field, one of three physical phenomena causes the conductive particles or droplets to combine:

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

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

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. 1 shows a cross section of a typical electrostatic treater[5] (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
  • 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.

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

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.[6][7][8][9][10] 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
  • 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[4]. 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.[4] 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[4], 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.[6] These tests include:

  • Bottle tests
  • Dynamic simulators
  • 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.

For more on chemical demulsifiers see Oil demulsifier selection and optimization.

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:

  • Wide variety of demulsifier chemicals available
  • Different types of crude being handled
  • Choice of separation equipment
  • 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.

When injection is not recommended

Usually, the chemical is injected into a coupling that is welded in the side of the pipe, but when flow rates are low ( < 3 ft/sec) or when laminar flow is encountered, this is not recommended. In such cases, the following are recommended:

  • Injection quill (which injects the chemical in the stream at a location that is removed from the wall)
  • Chemical distributor (Fig. 3)
  • Static mixer (Fig. 4)

The static mixer is a series of staggered, helically convoluted vanes that use the velocity of the fluid to accomplish mixing.

Factors affecting demulsifier efficiency

Several factors affect demulsifier performance including:

  • Temperature
  • pH
  • Type of crude oil
  • Brine composition
  • 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[11] requirements (see Fig. 5).

Demulsifiers that work for a given emulsion may be completely ineffective for another. Demulsifiers are typically formulated with polymeric chains of:

  • Ethylene oxides and polypropylene oxides of alcohol
  • Ethoxylated phenols
  • Ethoxylated alcohols and amines
  • Ethoxylated resins
  • Ethoxylated nonylphenols
  • Polyhydric alcohols
  • Sulphonic acid salts

Fig. 6 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
  • Costs

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.[12] 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.[13]

Several studies have been conducted on certain aspects of the chemical demulsification process.[7][8][9][10][12][13][14][15][16][17][18][19][20][21][22] It has been suggested[9] 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. 7 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.[19][20] 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.[9] The indigenous surfactants, like asphaltenes, present in the crude oil are only weakly adsorbed and are readily displaced by the demulsifier.

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
  • 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.[9][17]

  • 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[8][13][19][20][23] 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[19][20] (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
  • 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.[19]

  • 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.

Nomenclature

g = acceleration caused by of gravity, L/t2, m/s2
r = radius of the droplets, L, m
v = settling velocity of the water droplets, L/t, m/s
μ = viscosity, m/Lt, cp
ρw = density of water, m/L3, lbm/ft3
ρo = density of oil, m/L 3 , lbm/ft 3

References

  1. 1.0 1.1 Menon, V.B. and Wasan, D.T. 1987. Particle—fluid interactions with applications to solid-stabilized emulsions Part III. Asphaltene adsorption in the presence of quinaldine and 1,2-dimethylindole. Colloids Surf. 23 (4): 353-362. http://dx.doi.org/http://dx.doi.org/10.1016/0166-6622(87)80276-7.
  2. Kokal, S. and Al-Juraid, J. 1998. Reducing Emulsion Problems By Controlling Asphaltene Solubility and Precipitation. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 27-30 September 1998. SPE-48995-MS. http://dx.doi.org/10.2118/48995-MS.
  3. 3.0 3.1 Bobra, M. 1990. A Study of the Formation of Water-in-Oil Emulsions. Proc., 1990 Arctic and Marine Oil Spill Program Technical Seminar, Edmonton, Canada.
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  21. Manek, M.B. 1995. Asphaltene Dispersants as Demulsification Aids. Presented at the SPE International Symposium on Oilfield Chemistry, San Antonio, Texas, 14-17 February 1995. SPE-28972-MS. http://dx.doi.org/10.2118/28972-MS.
  22. Singh, B.P. 1994. Performance of Demulsifiers: Prediction Based on Film Pressure Area Isotherm and Solvent Properties. Energy Sources 16 (3): 377-385. http://dx.doi.org/10.1080/00908319408909084.
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Noteworthy papers in OnePetro

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

Boudi, A. A., Linga, H., Al-Johar, Z., & Al-Yousef, K. (2011, January 1). New Mixer System Enhances Saudi Aramco GOSP Crude-Water Separation Performance. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/147736-MS

Bruning, I. M. de A. (1992, January 1). The Determination of Polarity for Crude Oil Demulsification. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/23751-MS

Castro, L. U. (2001, January 1). Demulsification Treatment and Removal of In-Situ Emulsion in Heavy-Oil Reservoirs. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/68852-MS

Dalmazzone, C., & Noïk, C. (2001, January 1). Development of New “green” Demulsifiers for Oil Production. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/65041-MS

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

Dutta, B. K., & Ahmed, H. H. (2003, January 1). Production Improvement by Downhole Demulsification - A Simple and Cost Effective Approach. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/81568-MS

Feng, J., Zhou, X., & He, Q. (1982, January 1). Daqing Crude Oil Dehydration. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/10575-MS

Fjeldly, T. A., Hansen, E. B., & Nilsen, P. J. (2008, June 1). Novel Coalescer Technology in First-Stage Separator Enables Single-Stage Separation and Heavy-Oil Separation. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/118891-PA

Gramme, P. E., Dybdahl, B., Holt, Ø., Friedemann, J. D., & Riise, B. (1999, January 1). MTU - The Multi Test Unit for Investigating Offshore Separation Problems and Optimizing the Gas/Oil/Water Separation Process. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/56847-MS

Islam, M. R., Genyk, R., & Malik, Q. (2000, January 1). Experimental and Mathematical Modelling of Ultrasonic Treatments for Breaking Oil-Water Emulsions. Petroleum Society of Canada. http://dx.doi.org/doi:10.2118/2000-087

Jiachao, F., Jiansen, Z., & Shaobing, C. (1994, January 1). Water/Oil Separation Characteristics of Daqing Oilfield Polymer Flooding Production Fluid. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/28540-MS

Lagerlef, D. L., Sindelar, S. T., McLelland, W. G., & Blumer, D. J. (1995, January 1). Downhole Emulsion Breaker Injection into the Lift Gas Stream. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/29487-MS

Manek, M. B. (1995, January 1). Asphaltene Dispersants as Demulsification Aids. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/28972-MS

Manuel, B., Sellman, E. L., & Murtagh, T. (2013, June 11). Effective Dehydration of Canadian Heavy Crude Oil and DilBit. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/165464-MS

Mead, S. L., & Navarrete, R. C. (2003, January 1). Water Wetting of Solids During the Field Demulsification Process. Petroleum Society of Canada. http://dx.doi.org/doi:10.2118/2003-069-EA

Nahmad, D. G., Kmiec, I., Nasir, A., & Udau, I. (2008, January 1). X-O-T Technology For The Treatment Of Crude Oil Emulsions. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/115222-MS

Nguyen, D. T., & Sadeghi, N. (2012, January 1). Stable Emulsion and Demulsification in Chemical EOR Flooding: Challenges and Best Practices. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/154044-MS

Noik, C., Dalmazzone, C. S. H., & Glenat, P. (2008, January 1). Pre-electrocoalescer Unit Adapted to the Extra-heavy Oil Characteristics. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/117563-MS

Noik, C., Chen, J., & Dalmazzone, C. S. H. (2006, January 1). Electrostatic Demulsification on Crude Oil: A State-of-the-Art Review. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/103808-MS

Oriji, A. B., & Appah, D. (2012, January 1). Suitability of Local Demulsifier as an Emulsion Treating Agent in Oil and Gas Production. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/162989-MS

Phukan, M., Koczo, K., Falk, B., & Palumbo, A. (2010, January 1). New Silicon Copolymers For Efficient Demulsification. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/128553-MS

Ranganathan, R., Kurucz, L., Mourits, F., & Parker, R. J. (1985, January 1). Characterization And Treatment Of Saskatchewan Heavy Oil Emulsions. Petroleum Society of Canada. http://dx.doi.org/doi:10.2118/SS-85-11

Renouf, G., Scoular, R. J., & Soveran, D. (2003, January 1). Treating Heavy Slop Oil With Variable Frequency Microwaves. Petroleum Society of Canada. http://dx.doi.org/doi:10.2118/2003-020-EA

Renouf, G., Kurucz, L., & Soveran, D. (2007, May 1). Produced Fluids Separation Using a Coalescer Column. Petroleum Society of Canada. http://dx.doi.org/doi:10.2118/07-05-04

Salleh, I. K., Nadeem, M. N., Aziz, K. M. A., Alwi, N., Hamid, P. A., & Manap, A. A. A. (2009, January 1). Remediation of Naphthenate Stable Emulsion for Malaysian Oil Fields. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/121630-MS

Sams, G., Gopeesingh, H., Sellman, E. L., Zheng, F., Blackman, N., Mandewalkar, S. P. K., Zaouk, M. (2013, July 2). Electrostatic Dehydration of Heavy Oil from Polymer Flood with Partially Hydrolyzed Polyacrylamide. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/165269-MS

Sellman, E., Sams, G. W., & Mandewalkar, S. P. K. (2013, March 10). Improved Dehydration and Desalting of Mature Crude Oil Fields. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/164289-MS

Shvetsov, V., & Yunusov, A. (2010, January 1). New methods and treating units for electrical dehydration and desalting of oil. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/135974-MS

Soffian, R. M., & Niven, T. L. (1993, January 1). Emulsion Treatment Program. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/25346-MS Walsh, J. M., Sams, G. W., & Lee, J. M. (2012, April 30). Field Implementation of New Electrostatic Treating Technology. Offshore Technology Conference. http://dx.doi.org/doi:10.4043/23200-MS

Wiggett, A. J., & Ricza, T. (2013, March 10). Enhancement of Heavy oil Demulsification. Society of Petroleum Engineers. http://dx.doi.org/doi:10.2118/164335-MS

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Emulsion treating methods

Oil emulsions

Oil demulsifier selection and optimization

Separating emulsions

PEH:Crude_Oil_Emulsions

Category