Demulsification is a general term used to describe the separation of water from crude oil. As crude oil is produced from a reservoir it tends to become mixed with either natural formation water or mixed formation and injection water. This produced mixture of crude oil and water is termed an oil and water emulsion. It is critical to topsides process operations that the crude oil is efficiently and quickly separated from the water to allow dry oil to be exported and clean water to be discharged within consent, thus maximizing crude oil value and minimizing operating costs.


Typically, the emulsions formed are water in oil with the continuous phase being oil and the dispersed phase being water. The severity of the emulsion formed and thus the ease at which it can be broken is dependent on many factors including:
• physical and chemical properties of the crude oil
• production temperature
• distance between reservoir and topsides
• degree of agitation experienced between reservoir and separator, turbulent flow
• presence of solids (sand, clay, bacteria, scale, asphaltenes, corrosion product, naphthenates) and/or natural surfactants which act to stabilize the emulsion


The most common method of breaking emulsions is with the use of demulsifying / desalting chemicals. Demulsifying and desalting chemicals tend to act on the emulsion by:

• flocculation of the oil droplets
• dropping of the water
• coalescence of the water droplets

The speed and efficiency at which this occurs can be improved by process equipment design and operating conditions e.g. increasing the temperature, separator design etc.

Demulsifiers are generally injected on a continuous basis upstream of the 1st stage production separator but in certain circumstances, they can be injected subsea.


Demulsifier selection is best performed on live crude oil thus the selection process must be performed in the field and is generally performed using the “bottle test” method. Using this method numerous base chemicals can be tested on fresh emulsions and at the exact operating conditions thus a product can be formulated which is specific to the field and the emulsion. As field conditions change over its lifetime it is essential to optimize demulsifier performance on a regular basis


1. Obtain the appropriate, chemical-free sample for testing purposes. For slop oils, etc., representative sampling may be the most difficult step in this procedure. Viscosity and stratification of the waste may require sampling from various tank levels and testing on a composite of these samples.
2. Fill test bottles to the 100 ml mark with the sample and place in the water bath. Bath temperature should correspond to that used in the system. NOTE: if heat will not be available in the system, heating the samples can be omitted; however, usually heat is a necessary step for the most effective demulsification, and should be considered whenever practical.
3. While the samples are heating, take a sample of the untreated emulsion, dilute it 50/50 with a solvent, such as xylene or toluene, and centrifuge to determine the amount of solids, water, and oil present.
4. After the samples are heated, inject the appropriate amount of demulsifier and shake the samples to insure even distribution of the chemical. The amount of agitation can be varied in order to better duplicate that expected in the system or vessel. If dosage rates are not known, start al 60-150 ppm.
5. After the chemical and emulsion have been mixed, return the samples to the water bath (or allow to sit at room or system temperature, if heat will not be used in the system).
6. Periodically record the amount of oil, water and interface in each sample. Suggested times would be 15 and 30 minutes, 1, 2, 4, 8, and 24 hours, depending on the time available.
7. Depending upon the particular waste oil being tested and the amount of time available in the system, settling times will range from as little as 1-2 hours to as long as 48 hours.
8. After selecting those demulsifiers which exhibit the best activity, rescreen them at several dosages (e.g., 60, 75, 100, 150, 200 ppm) to determine their treating plateau as well as optimum dosage.


o The amount of water, “rag”**, oil, and the quality of the oil should be considered when selecting the best demulsifier. The latter point can best be determined by diluting a portion of the top oil with solvent and centrifuging to determine residual BS&W (basic sediment and water).
o If a demulsifier alone is unable to effectively resolve the emulsion, investigate the addition of acid or caustic along with the chemical. Oftentimes a pH adjustment can have a dramat ic effect on emulsion stability. In such instances, it is advisable to rescreen all the demulsifiers to determine the best product.
o Careful thought should be given to the quality of water that is dropped from the emulsion. Very oily water will often create big problem further downstream.

Ideally, the best demusifier should result in the driest oil with the least amount of interface and the cleanest water when bottle tests are run under system temperatures and retention times.

A typical bottle test will consist of one blank and a set of samples that contain individual products of choice that are best suited for the given set of system conditions at hand. A blank sample must be run with each set of test bottles. Typical injection rates for water clarifiers will range between 20 ppm to 45 ppm.


1. Fill each test bottle with lOOml of produced water.
2. Inject and label test bottles with products of choice at desired concentration (30 ppm is a good stm1ing point).
3. Shake samples vigorously for 30 seconds or approximate produced water residence time from injection point to the point of downstream separation.
4. Allow bottles to rest in place for approximate retention time of downstream vessel.
5. Compare water clarity of each test bottle to the blank and rate from 1-10.
6. Evaluate the amount, buoyancy and oil solubility of the generated floe for each sample bottl e. Rate and record floe properties from 1-10.
7. Repeat steps 1-5 until a product is chosen.

A bench top floatation cell should be utilizeD to finalize product selection and recommended injection rate. The benchtop floatation cell can essentially simulate the mechanical lifting action of a full-scale single-cell floatation unit. Effluent samples can be analyzed for % efficiency of the product of choice at various injection rates. The most efficient full-scale units employed offshore have three or more segmented floatation cells that will individually reduce effluent O&G concentrations from 20-40%

To identify what is happening in the system, daily samples should be analyzed at each vessel in the treatment stage to ensure emulsion is not building in the system. Initial shakeout samples taken at the oil outlets and interface levels of vessels should not be preheated or “slugged” with knock out drops when identifying an emulsion. Doing so can distort the true fluid properties.


1) Fill sample tube to 100% level with mineral spirits.
2) Flush sample point for 1 min. and fill sample tube to 200% level with oil sample.
3) Centrifuge sample for 30 seconds. This will determine the amount of Free Water and Basic Sediment (BS) in the sample. Record these values.
4) Slug sample with 1drop of demulsifier; shake well and heat to 140 F. Centrifuge sample for an additional 2 minutes. This will determine any residual BS&W. Record these values.


 No BS observed in initial shakeout: Continue to monitor system.
 Excess Free Water in the initial shakeout. Usually indicates insufficient retention time and/or heat or other mechanical problems.
 High BS levels before and after the chemical injection point look the same in initial shakeouts. Usually indicates a chemical under treatment. Check pumps and vessels for proper operation. Slightly increase chemical rates.
 More BS observed in the treated sample than in the un-treated sample normally indicates a chemical over treatment. Check pumps and vessels for proper operation. Blend untreated fluid with over treated fluid. Decrease chemical rates.


Initial shakeout contains emulsion but emulsion is not present after addition of heat and chemical slug in sample:

 Increase demulsifier rate slightly; monitor system until emulsion does not appear in initial shakeout. If emulsion is still present, contact Coastal representative for discussion.
 If no emulsion is present and total BS&W is still high after rate adjustments, the problem may be caused by other sources than fluid from separators. When no emulsion is found from other sources, the problem may be mechanical (See Below).


Normally, emulsion will build at the oil and water interface in all vessels. Most BS&W upsets can be attributed to sudden and sometimes subtle changes in system dynamics. Identification of the problem source is the most important stage in upset elimination.

Most BS&W problems are caused by three mechanisms:
1) Mechanical or Equipment Problems
2) Produced Fluid Problems
3) Chemical Problems


  • Changes in vessel temperature and/or pressure.
  • Malfunctioning or improperly set level controllers.
  • Malfunctioning BS&W probes.
  • Corrosion and/or scaling of vessel internals.
  • Accumulation of high tank bottoms


• Changed chokes on any wells
• Any well making sand
• Acidized or any worked over wells
• Corrosion treating of wells
• Newly drilled wells
• Chemical, soap or motor oil dumping into the sump
• Paraffin cutting
• Change in daily production


• Chemical over treatment or under treatment
• Moved chemical injection points
• Exceeded chemical shelf life

In most cases, eliminating the problem source will remedy the upset. However, pads caused by these scenarios may have to be batch treated with slugging compounds or in some cases, isolated and removed mechanically.

Contact Coastal Chemical to learn how we can assist with demulsifiers / desalters.