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Oil demulsifier selection and optimization

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For an existing facility, important questions include:

  • "Are we using the best demulsifier?"
  • "Is my demulsifier usage optimized?"

Demulsifier selection is still considered an art that improves with experience; however, there are methods now available to eliminate some of the uncertainties involved in demulsifier screening and selection. The properties of a good demulsifier were addressed previously. How to select the best demulsifier and to optimize its usage is addressed here.

Demulsifier selection criteria

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

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

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

To select a demulsifier for a given system, one generally starts with the bottle tests. Representative emulsion samples are taken and transferred into several centrifuge tubes. Several demulsifiers, usually from different demulsifier vendors, are added to the centrifuge tubes in various amounts, and water-dropout data are collected and analyzed to determine the best demulsifier. Before the tests, the demulsifier vendors can be invited to provide one or two of their demulsifiers. Most vendors would want to test their chemicals with emulsions from the field before submitting their best candidates. A quantitative method for demulsifier testing was developed recently,[1] and the calculation procedures are described in the Appendix. For selecting the best demulsifier, several sets of tests may be necessary at different concentrations, temperatures, water cuts, etc. The demulsifier dosages obtained in the lab are generally greater than what will be needed in the field. It is highly recommended that the bottle test be conducted with fresh emulsions (i.e., within a few minutes of sampling), because sample aging has a significant effect on demulsifier dosages. During the bottle tests, other factors should be noted:

  • Color and appearance of the emulsion
  • Clarity of the water
  • Sediments in the water
  • Presence of a rag layer
  • Loose solids hanging at the interface

These factors can provide information that may be important during demulsifier selection.

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

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

Proper demulsifier mixing

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

Similarly, turbulence enhances the diffusion and dispersion of demulsifier into the emulsion and increases the probability of collisions between water droplets. This turbulence must persist long enough to allow the chemical to reach the interface between the oil and water, but the intensity should not be so severe that it causes further tightening of the emulsion. This level of turbulence is usually provided by normal flow through the emulsion-treating unit that occurs in the:

  • Pipes
  • Manifolds
  • Valves
  • Separators

When the flow rates are too low for proper mixing, special care must be taken for mixing the chemical. Special mixers may be installed to ensure proper demulsifier mixing. Such mixers include:

  • Mixing valves
  • Injection quills
  • Kinetic mixers
  • Vortex mixers

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

Another problem sometimes ignored is the settling characteristics of the demulsifier. The active ingredients in some demulsifiers tend to settle at the bottom of demulsifier tanks because of:

  • Insolubility
  • Incomplete mixing
  • Density differences

If this happens, the surface-active ingredient injection into the treatment facility is erratic. During the first few days of the tank charge and injection, the demulsifier may work satisfactorily; however, subsequent performance may deteriorate as the active ingredients are exhausted and only the carrier solvent is injected. If this cycle is observed, the culprit is the settling of the active ingredients of the demulsifier in the tank. Steps to eliminate settling include installing a mixer in the demulsifier tank or replacing the demulsifier.

Demulsifier overdosing

Overdosing of the chemical can result in enhanced stability of the emulsion, leading to rag layers or pads inside the separators. This is a severe problem because it worsens with increased demulsifier costs. It can be difficult to determine that there is demulsifier overdosing at a treatment facility. One way to reduce overdosing is to conduct field-optimization tests periodically to determine optimum demulsifier rates. These tests are done by going through a series of demulsifier rates at the treatment facility and monitoring the product crude and water characteristics. These trials provide the best demulsifier rates for the facility. A better way to optimize demulsifier rates is by installing automated or semiautomated demulsifier control systems. The control systems receive input from sensors in the treatment facility and take action to increase or decrease the demulsifier rates. The sensors monitor:

  • Grid voltages in the dehydrator and desalter
  • Emulsion layer inside the separator (monitoring through interface levels)
  • Crude and water quality
  • Operating temperature

The controller can also inject additional demulsifier into the separator inlet during upset conditions to minimize their impact. An automatic controller should always be searching for the minimum demulsifier usage.

Understanding the causes of emulsions

For larger facilities it may be worthwhile to understand the causes of tight emulsions. Some of the factors that stabilize emulsions were highlighted earlier, such as:

  • Fine solids
  • Asphaltenes and waxes
  • Temperature
  • Size of water droplets
  • pH
  • Brine composition
  • etc.

Some of the factors, such as brine composition and water cuts, cannot be controlled; however, other factors can be controlled. The temperature can be increased by heating the crude or burying/insulating the flowlines. Water droplet sizes can be increased by reducing mixing or shearing. Organic precipitates can be eliminated with dispersants and specialty chemicals. The first task is to diagnose the causes. Understanding the causes leads to better decisions for controlling the demulsifier usage. Several investigative case studies have been reported for understanding the causes of tight emulsions[1][2][3] and optimizing demulsifier usage.

Evaluating the process

A thorough evaluation of the emulsion-treatment facility may be worthwhile for optimizing costs. Some of the factors to explore include the extent of:

  • Agitation
  • Wash-water rates
  • Electrostatic grid voltages
  • Retention times
  • Separator internals


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

Retention time

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

Electrostatic coalescing

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

Maintaining a database on usage and costs

Experience and demulsifier data are important because they can be used to optimize usage. Typical data to maintain in a database include:

  • Oil and water rates
  • Temperatures
  • Demulsifier rates
  • Demulsifier costs
  • Comments regarding any changes that were made in the treatment facilities

Table 1 provides typical data for an operating wet-crude handling facility. Such data can be analyzed to diagnose demulsifier-usage problems. They can also be used as a base to compare the results for new and experimental demulsifiers. Furthermore, they provide a quick, easy reference for understanding:

  • The seasonal variation in consumption
  • Causes of upsets
  • Increased demulsifier usage

Chemical demulsifiers

Dehydration chemicals, or demulsifiers, are chemical compounds that are widely used to destabilize, and assist in coalescence of, crude-oil emulsions. This treatment method is popular because the chemicals are easily applied, usually are reasonable in cost, and usually minimize the amount of heat and settling time required.

The chemical counteracts the emulsifying agent, allowing the dispersed droplets of the emulsion to coalesce into larger drops and settle out of the matrix. To work, demulsifiers:

  • must be injected into the emulsion
  • must mix intimately with the emulsion and migrate to all the protective films surrounding all the dispersed droplets
  • must displace or nullify the effect of the emulsifying agent at the interface

For the oil and water to separate, there must also be a period of continual, moderate agitation of the treated emulsion to produce contact between and coalescence of the dispersed droplets, as well as a quiet settling period.

Actions of a chemical demulsifier

The mechanisms to consider for a chemical demulsifier:

  • Strong attraction to the oil/water interface. The demulsifier must be able to migrate rapidly through the oil phase to reach the droplet interface where it must counteract the emulsifying agent.
  • Flocculation. The demulsifier must have an attraction for water droplets with a similar charge and bring them together. In this way, large clusters of water droplets gather, which under a microscope look like bunches of fish eggs.
  • Coalescence. After flocculation, the emulsifier film remains continuous. If the emulsifier is weak, the flocculation force might be enough to cause coalescence; however, this usually is not true, and the demulsifier must enable coalescence by neutralizing the emulsifier and promoting rupture of the droplet interface film. In the flocculated emulsion, the film rupture causes increasing water-drop size.
  • Solids wetting. Iron sulfides, clays, and drilling muds can be made water-wet, which causes them to leave the interface and be diffused into the water droplets. paraffins and asphaltenes can be dissolved or altered by the demulsifier to make their films less viscous, or they can be made oil-wet so that they will be dispersed in the oil.


The demulsifier should be selected with all functions of the treating system in mind. If the process is a settling tank, a relatively slow-acting demulsifier can be applied with good results. On the other hand, if the system is an electrostatic process in which some of the flocculation and coalescence is accomplished by the electric field, a quick-acting demulsifier is needed or the demulsifier might need to be added farther upstream (preferable). The time required for demulsifier action in a vertical emulsion treater normally is between that in a settling tank and that in an electrostatic treater. As field conditions change and/or the treating process is modified, the chemical requirements might change. Seasonal changes can cause paraffin-induced emulsion problems. Well workovers might change solids content, which can alter emulsion stability. Thus, no matter how satisfactory a demulsifier is, it cannot be assumed to be satisfactory over the life of the field. Applying heat to an emulsion after a demulsifier has been mixed with it increases the chemical’s effectiveness by reducing the emulsion viscosity and facilitating more intimate chemical/emulsion mixing. Chemical reaction at the oil/water interface happens more rapidly at higher temperatures.


Where the demulsifier is injected into the emulsion is important. It should be injected into the emulsion and mixed so that it is evenly and intimately distributed throughout the emulsion when the emulsion is heated, coalesced, and settled in the treating system. It also should be injected in a continuous stream, with the chemical volume directly proportional to the emulsion volume.


Turbulence accelerates the diffusion of the demulsifier throughout the emulsion and increases the number and intensity of impacts between water droplets. Turbulence must persist long enough to permit the chemical to reach the interface between the oil and all the dispersed water droplets, but the intensity and duration of the turbulence must be controlled so that it will not cause further emulsification. Turbulence is the dynamic factor for emulsion formation; however, a moderate level of controlled turbulence causes the dispersed droplets to collide and coalesce. Usually, this turbulence is provided by normal flow in surface lines, manifolds, and separators and by flow through the emulsion-treating unit or system.


  1. 1.0 1.1 Kokal, S. and Wingrove, M. 2000. Emulsion Separation Index: From Laboratory to Field Case Studies. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 1-4 October 2000. SPE-63165-MS.
  2. Kokal, S. and Al-Juraid, J. 1999. Quantification of Various Factors Affecting Emulsion Stability: Watercut, Temperature, Shear, Asphaltene Content, Demulsifier Dosage and Mixing Different Crudes. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-56641-MS.
  3. Kokal, S., Al-Yousif, A., Meeranpillai, N.S. et al. 2001. Very Thick Crude Emulsions: A Field Case Study of a Unique Crude Production Problem. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 September-3 October 2001. SPE-71467-MS.

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.

Alsayed, B., Mahgoub, I., & Allegro, N. (2011, January 1). Production Enhancement By Demulsified Injection Through Gas Lift System - Field Case Study. Offshore Mediterranean Conference.

Berger, P. D., Hsu, C., & Arendell, J. P. (1988, November 1). Designing and Selecting Demulsifiers for Optimum Field Performance on the Basis of Production Fluid Characteristics. Society of Petroleum Engineers.

Dalmazzone, C., & Noïk, C. (2001, January 1). Development of New “green” Demulsifiers for Oil Production. Society of Petroleum Engineers.

Dalmazzone, C., Noik, C., & Komunjer, L. (2005, March 1). Mechanism of Crude-Oil/Water Interface Destabilization by Silicone Demulsifiers. Society of Petroleum Engineers.

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.

Dosunmu, A., Otikiri, A. E., & Fekete, P. O. (2012, January 1). Evaluation of Emulsion Treatment Using Different De-emulsifiers. Society of Petroleum Engineers.

Gong, C., & Towner, J. W. (2001, January 1). Study of Dynamic Interfacial Tension for Demulsification of Crude Oil Emulsions. Society of Petroleum Engineers.

Graham, D. E., & Stockwell, A. (1980, January 1). Selection of Demulsifiers for Produced Crude Oil Emulsions. Society of Petroleum Engineers.

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.

Kaiser, A. (2013, April 8). Environmentally Friendly Emulsion Breakers: Vision or Reality? Society of Petroleum Engineers.

Kokal, S., & Wingrove, M. (2000, January 1). Emulsion Separation Index: From Laboratory to Field Case Studies. Society of Petroleum Engineers.

Kokal, S. L. (2005, February 1). Crude Oil Emulsions: A State-Of-The-Art Review. Society of Petroleum Engineers.

Kokal, S. L., & Al Ghamdi, A. (2005, January 1). Oil-Water Separation Experience From A Large Oil Field. Society of Petroleum Engineers.

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.

MacConnachie, C. A., Mikula, R. J., Kurucz, L., & Seoular, R. J. (1993, January 1). Correlation Of Demulsifier Performance And Demulsifier Chemistry. Petroleum Society of Canada.

MacConnachie, C., Mikula, R. J., Scoular, R. J., & Kurucz, L. J. (1994, January 1). Optimizing Demulsifier Performance: A Fundamental Approach. Petroleum Society of Canada.

Manek, M. B. (1995, January 1). Asphaltene Dispersants as Demulsification Aids. Society of Petroleum Engineers.

Nguyen, D. T., & Sadeghi, N. (2011, January 1). Selection of the Right Demulsifier for Chemical Enhanced Oil Recovery. Society of Petroleum Engineers.

Nguyen, D. T., Sadeghi, N., & Houston, C. W. (2011, January 1). Emulsion Characteristics and Novel Demulsifiers for Treating Chemical EOR Induced Emulsions. Society of Petroleum Engineers.

Opawale, A. O., Osisanya, S. O., Dulu, A., & Otakoro, S. E. (2011, January 1). An Integrated Approach to Selecting and Optimizing Demulsifier Chemical Injection Points using Shearing Energy Analysis: A Justification for Downhole Injection in High Pressured Well. Offshore Technology Conference.

Paulis, J. B., & Sharma, M. M. (1997, January 1). A New Family of Demulsifiers for Treating Oilfield Emulsions. Society of Petroleum Engineers.

Phukan, M., Koczo, K., Falk, B., & Palumbo, A. (2010, January 1). New Silicon Copolymers For Efficient Demulsification. Society of Petroleum Engineers.

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.

Staiss, F., Bohm, R., & Kupfer, R. (1991, August 1). Improved Demulsifier Chemistry: A Novel Approach in the Dehydration of Crude Oil. Society of Petroleum Engineers.

Wilson, N., Temple-heald, C., Readman, N., & Davies, C. (2013, April 8). The Development and Field Application of New Surfactant Chemistries for Application to Heavy Oils. Society of Petroleum Engineers.

Wylde, J. J., Coscio, S. E., & Barbu, V. (2010, February 1). A Case History of Heavy-Oil Separation in Northern Alberta: A Singular Challenge of Demulsifier Optimization and Application. Society of Petroleum Engineers.

Yang, Y., Dismuke, K. I., Penny, G. S., & Paktinat, J. (2009, January 1). Lab and Field Study of New Microemulsion-Based Crude Oil Demulsifiers for Well Completions. Society of Petroleum Engineers.

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See also

Oil demulsification