December 6, 2023

Emulsions, Oil Desalting, Dehydration Process

This study covers only the treatment of water/oil emulsions. Emulsion breaking procedures can be classified in three categories:

  • Chemical processes:

 By adding active molecules (demulsifiers) at a very low concentration (from a few ppm to a few dozen ppm).

  • Physical processes:

 which mainly make use of the temperature and/or electrostatic field effect.

  • Mixed processes:

 Procedures to break tight water-oil emulsion involve usually a combination of chemical and physical processes.





 A demulsifying agent should have the following characteristics:

  • A strong interfacial

This property is a function of the migration speed of the demulsifier in the continuous phase in the direction of the oil water interface and of its capacity to become adsorbed preferentially at the interface or to interact with the emulsifier present.

Hence, a demulsifier which is intended to break a water-in-oil emulsion must be soluble in oil.

  • To favour the grouping of water droplets (flocculation).
  • To wet the solids present in order to disperse these particles in one of the
  • To destroy the interfacial films (which means increasing the water-oil interfacial tension) so that the water droplets can coalesce and then

The chemicals most frequently used are a combination of high molecular weight synthetic polymerics and surfactant detergent.

The long chain macromolecule adsorbed a the surface of a drop of water can, for instance, extend its action to the mass of the solution, which will allow the demulsifier to connect up with another drop. If this “bridging” effect takes place, it explains the flocculation of water droplets. If, moreover, the interfacial films are destroyed by the surfactant, coalescence can occur.


The “bridging” theory was developed by LAMER, MICHAELS, HEALY to explain the flocculation of colloidal solids, and it would appear logical to extend this idea to cover emulsions.


 In general, an additive consists of one or several active elements and one or more solvents. To our knowledge, there are a dozen groups of active chemicals for demulsification:

  • ethylene oxide – propylene oxide copolymers,
  • polyoxypropylate and polyoxyethylate diamines,
  • polyoxypropylate, polyoxyethylate phenol-formol resins,
  • certain glycols,
  • polyoxyethylate polyols,
  • silicones,
  • sulfonates,
  • pyridinic organic bases,
  • ethylene oxide and propylene oxide copolymer esters,
  • ethylene oxide, propylene oxide copolymer carbonate derivatives,
  • polyurethanes,
  • epoxy derivatives,
  • oxyethylate

The solvents used are mainly of two types:

  • more or less aromatic hydrocarbons,

 The principle consists of injecting a determined quantity of additives at one or several points on the crude oil production system.

Three types of treatment can be considered:

  • Batch:

This very old method is rarely used nowadays. It may still be used if an out-of- specification crude, contained in a stock tank, has to be treated again following an incident during routine heating operations (injection pump break down, etc.).

  • Downhole treatment:

This system is usually applied on wells produced by hydraulic pumping with the purpose of preventing emulsion from forming due to turbulence.

  • Surface on-line treatment:

This is by far the most commonly used method. The demulsifier injection points are placed:

  • on the well head (s) or,
  • on the well manifold or,
  • on the production unit inlet manifold or,
  • on the separator(s) or electrostatic dehydrator

Additives are injected by a piston or diaphragm proportioning pumps. The injection rate will depend on:

  • effluent production in the pipe network,
  • the best dose of demulsifier determined after a bottle

The system can be driven by:

  • linkage with a beam pump,
  • electric motor,
  • gas

The latter is by far the most commonly used in the field. The gas used can be associated gas or even compressed air (see Fig. XIII.1).

The injection rate is controlled either by altering the piston stroke of the pump, or by adjusting the pulsation frequency.

The choice of the injection point(s) is very important:

  • the turbulence must be adequate to make sure the additive and the emulsion are thoroughly mixed,
  • the temperature at the injection point may be the determining factor in the case of the treatment of certain emulsions. In almost any set up, the hotter the effluent, the greater the saving of injected

There is an advantage in injecting the demulsifier well upstream of the transport and production system.

Indeed, one of the factors favouring emulsion stability is ageing. By injecting the additive at the wellhead, for instance, early action is assured when the emulsion is still young and less stable.

Moreover, the chemical has a longer active life before entering the treatment unit.


 The purpose of these tests is to determine the most active demulsifier for breaking the emulsion produced by a well or a group of wells, the best amount to inject (i.e. the lowest cost of additive needed to reach the required specifications) and temperature of utilisation.

4.1.  Basic principle


Under the action of the added demulsifier, the water in oil emulsion is broken, more or less thoroughly, and the water settles. The test consists of noting the amount of water settled as a function of time, the variables being the temperature and the amount of demulsifier injected.


4.2.  Sampling precautions

 The best sampling point is the first stage separator or test separator oil outlet, as long as there is no demulsifier injection upstream, otherwise sampling will be done at the well, or at any point on the line placed upstream the demulsifier injection

  • The sampling valve will be opened carefully to avoid shearing (cause of turbulence) and to allow the gas to
  • The sample will be taken in a plastic jerrican or drum fitted with a bleeding tap to eliminate free water). From the drum, the emulsion will be collected after eliminating the free
  • The sample taken must be representative of the emulsion to be treated; it is, in fact, usually preferable to prepare a compound sample (mixture of effluents from several wells).
  • Care should be taken not to allow the sample to

4.3. Main equipment

 Prescription bottles: 200 ml content graduated to 100

  • Thermostatic control water
  • Centrifuge fitted with cone-shaped

4.4.  Preparing the treating compounds

 Demulsifiers may be used pure or diluted. It may therefore be necessary to carry out a range of dilution in an appropriate solvent (e.g. a blend of 25 % methanol, 75 % xylène).

4.5.  Procedure


  • Once the free water has been drained from the jerrican, or directly from the emulsion sample taken in the drum, shake the sample and  share  it  out  between  the  prescription  bottles, 100 cm3 per bottle. Place them in a thermostatic control bath. When the bottles are at the desired temperature (any temperature between the extreme temperatures of the effluent on the field and when producing), shake all bottles by hand (100 times), add various quantities of demulsifiers (e.g. 20, 50 and 100 ppm).

Keeping an untreated witness bottle, place in the bath, wait for 10 minutes, read the amount of water settle, shake all bottles, whether treated or untreated, 20 times by hand; replace in the thermostatic bath.

  • Note the amount of water which has settled according to time, the appearance of the settled water and the volume of the interface, the presence of
  • Certain products may be effective in the laboratory, but not have the hoped results due to a tendency to reemulsify water in dynamic flow. After 2 hours, the sample is therefore shaken again hard (100 times) and the previous procedure is
  • Then add excess demulsifier, shake 20 times, leave to settle in the bath for 10
  • Note the volume of water settled, the volume of the interface, the presence of sediments.

This method makes it possible to short list a few products out of a fairly large range of additives. The best amount of compound to be used is then sought, rerunning the same tests, by varying the amount of demulsifier 5 vpm by 5 vpm or 10 vpm by 10 vpm as required (the choice of a 5 vpm or 10 vpm will depend on the first tests).

Instead of stages 4 and 5 the following procedure can be followed:

4b – Take 50 cm3 of crude from the upper part of the bottle. Measure the water content using the Dean-Stark method or by centrifuging or measuring the salinity.

5b –  Centrifuge the rest of the sample and note the parameters.


4.6. Results interpretation

 The results of the tests for product selection and the results of tests to find the best compound/effluent ratio are given on a table (see Fig. XIII.3).

The best product is that which gives the greatest water settling (at the same time the quantity of residual water in the top 50 cm3 must be as small as possible) for the smallest quantity of compound and in the shortest time, whilst maintaining the proper water and interface quality.

Check the effect on the effluent caused by any overdose (see Fig. XIII.4).


It should be noted that the results of these tests must be considered carefully, and should be followed by full scale tests on field.



 As can be seen from the above it is difficult to define an additive whose effectiveness is guaranteed, without previously running bottle tests on the field, followed by field tests.

It would, however, be interesting to try to establish a link between the characteristics of a crude oil, and the chemical nature of the active material likely to break the emulsions of which it is the source.

  • density,
  • asphalt content,
  • acid number (presence of naphtenates),
  • pour point (presence of paraffins).


The aim is to try to reveal the chemical matter of the active demulsifying elements for each “family” of crude oils (see table on Fig. XIII.5). Thus when studying a new reservoir, it would be easier to make a recommendation (formula) for an active demulsifier.


However, this study is only a preliminary approach. To simplify the problem, certain parameters, responsible for stabilizing an emulsion have not been considered:

  • the presence of sediments in the crude: their presence in the effluent depends on the nature of the reservoir rock, the production flowrates per well, ;
  • the wax appearance temperature (WAT).

However, the characteristics of the emulsion are beginning to be considered, in particular when sizing the water droplets dispersed in the oil: this is a function ot the quantity of associated water, of the hydraulic and/or mechanical energy in the water-oil effluent.




Below, we refer to the fact of withdrawing the water dispersed in the crude as:

  • “demulsion” or “dehydration”, stressing the water content rather than the salinity,
  • “desalting” the operations which make it possible to reach the specification in salt when this is not the direct result of complying with the “water”

Crude salinity is usually due to the presence of salt water. Thus to desalt the crude the main point is to eliminate this salt water, in fact, to dehydrate (primary dehydration).

However, dehydration cannot be complete, some water always remains. The salt dissolved in this residual water can give salt contents above specifications. It is therefore necessary to dilute the reservoir water with a softer water; and then dehydrate again (secondary dehydration).

In certain cases (very salty reservoir water, low water content, high GOR), salt cristals are present in the crude. These are eliminated by dissolving them in added soft or briny water followed by effluent dehydration.

Desalting a crude means dehydrating the effluent which has previously been diluted by water softer than the reservoir water.

 This shows how desalting processes, set up to treat the crude on the field, are dehydration processes associated with a previous dilution of the reservoir water by a softer water.

Below we will study, the joint physical dehydration desalting processes.


 Treatments implemented on the field consist in separating out the water (of varying salinity) from the crude, as thoroughly as possible.

When free water is present, simple settling or gravity separation will suffice. This operation can be done in a Free Water Knock Out such as the one shown on Fig. XIII.6. This apparatus operates on the same principle as the high pressure separators (the gas oultet is flanged). It is placed upstream the three-phase separators when the effluent to be treated contains a high proportion of free water. In the presence of emulsion more complex technologies are used possibly with demusifiers, amongst which:

  • Wash Tank (water wash and settling)
  • Heater Treater (hot wash and settling).


These processes are suitable for treating light or medium crudes, but are inapplicable for heavier crudes (API < 30). Electrostatic desalting becomes necessary in these cases, and also for offshore oil fields where the material must be compact (which eliminates certain traditional means, such as the “Wash Tank” offshore).




There are several type of “Wash Tank”:

  • traditional Wash Tanks (see Fig. 7),
  • Wash Tanks made by modifying a Stock Tank,
  • Wash Tanks with spiral tracks (see Fig. 8a).

2.1. Principle


Their operating principle is simple: the lower part of the tank is filled with water to a depth which varies both on the salinity and on the emulsifying tendency of the crude to be treated. This level is adjusted either by standard level adjustment, or by varying the water column of the drain trap.

The salinity of this water pad is kept constant by adding fresh water at the Wash Tank inlet.


The salty crude inlet is placed in the upper part of the tank and is dispersed at the bottom of the wash tank by a diffuser or a system of baffles which force the effluent through the water plug and favour the coalescence of the water droplets.

(The advantage of the diffuser is that it breaks the fluid velocity to prevent whirl pools from forming; it also allows the gases to escape before entering the Wash Tank. The spiral baffle system offers the advantage of increasing the distance covered by the effluent in the water pad).


The settle water is evacuated from the bottom of the container and a constant water level is maintained.


The crude is evacuated from the top part by an overflow device.


N.B.: The latter type of Wash Tank (see Fig. XIII.8b) is, in fact, an improved settling tank, with injection of wash water close to an internal mixer. All the effluent to be treated has to pass through the system. This process does not therefore use the passage into a water plug to coalesce.



2.2. Effectiveness of “Wash Tanks”


Washing with water in a Wash Tank is a means of primary dehydration or desalting.

The efficiency of wash tank treatment is governed by an essential parameter: the temperature of the crude to be treated. Usually crude is available at temperatures which are too low. Before feeding a wash tank, reheating is almost always necessary.

In spite of this precaution, the crude leaving the “Wash Tanks” still contains emulsified water. The water content of the oil on leaving the Wash Tank cannot be expected to be below 1 – 2 %. Settling must therefore continue in the stock tanks, in order to get a properly treated crude.


2.3. Operational parameters


The values of the various parameters to be displayed in the Wash Tank depend on:


  • the quality of the crude to be treated: water content, salt content, emulsion tendency, viscosity, etc. …


  • availability conditions: pressure, temperature, residual The main parameters are as follows:
  • Heating temperature:

For viscosities up to 50 Cst to 37.8°C, this temperature is in the order of 60°C; above this a specific study should be made.


  • Water injection:

The quantity of water to be injected should maintain the salt content of the water plug at a value below 20g/l.

When the crude is practically water free, the quantity of injected water should not be  below 5 % with respect to the quantity of crude to be treated for fear of making a stable emulsion, but it should not exceed 30 to 35 %, except in special cases.


  • Demulsifier injection

This injection is recommended and increases the treatment efficiency.


2.4. Typical installation


The Wash Tank desalting process can be used when an installation of crude storage is erected:

e.g. at the end of the processing chain on a field or at the terminals before loading. The figure

  • gives possible schematics for treating an effluent with wash

The first operation consists in eliminating free water through a free water separator or through a decanting tank. Then the emulsion is driven towards the wash tank either by its own pressure, or by a pump. The dilution fresh water is injected into the emulsion upstream of the wash tank. The intermingling of the two liquids is ensured by the pump, when there is one, or by a mixing valve; the pressure drop of which is adjusted to obtain the desired emulsion fineness (pressure drop



between 0.5 and 1.5 bar). In the wash tank, the water slug is maintained at a constant height (1/3 to 1/2 of the tank as a function of the stability of the emulsion to be treated). The bath salt content, (checked frequently), is maintained at the required concentration by an additional fresh water supply. If necessary, the wash tank includes a reheating coil. The treated oil is then stored in tanks where decanting is completed.





3.1. Principle


The main aims of reheating are as follows:


  • to accelerate coalescence increasing the Brownian movement of the water drops;
  • to reduce oil viscosity which reduces decanting


A heater treater combines several functions in a single device:


  • emulsion first enters a gas/oil separator;


  • partially degassed liquids are forced into a conduit leading up to the base of the heater treater through a spray nozzle. Water settles at the tank bottom;


  • then the emulsion crosses a water layer whose level is kept constant. Part of the water is decanted;


  • the lightened emulsion goes through the filtering section which is not always indispensable;


  • the treated oil overflows into the top part of the


3.2. Types of devices and operation


There are two types of heater treater:


  • vertical,


Operation of a vertical heater treater (see Fig. XIII.10).


  • Liquid / gas separator:

The effluent comes into a liquid gas separator placed on the heater treater. The separated cold gas is recycled in the upper chamber where it cools the steams released from the hot oil and causes the condensation of most liquefiable fractions. It is then either recovered or burnt at the flare.

  • Free water separator (FWKO):

Partially degassed liquids flow into a large diameter conduit leading to the base of the heater treater. A nozzle device sprays the liquids into very thin droplets and free water settles at the bottom of the tank.

  • Wash tank:

This is made up of a volume of water of about 40 to 60 % of the heater treater capacity. The bath is heated to the right temperature by an underwater fire tube. The bath height is maintained constant by an automatic device, siphon tube or valve, draining off the excess water brought by the effluent. The emulsion, pulverised at the base of the bath, heats up quickly at its contact. A large part of the water is left and the lightened emulsion rises towards the filtering section.

  • Filtering section:

The filtering section is not always necessary. Its use is reserved for the treatment of particularly stable emulsions. It is made with a lining (non resinous wood shavings such as aspen, cotton plant or poplar, glass fibres…) which can be changed through a manhole. It should be noted that this stuffing does not act as a filter, but rather as a coalescent, which helps to gather the disperse phase.

When the disperse phase of the emulsion is water, it is necessary to moisten the stuffing before starting operations.

When this material is compressed properly, the dispersed droplets, still trapped inside their skin of emulsifier have to deform themselves to get through the pores.

This causes the film to break and helps coalescence.


  • Recovery of the treated oil:

The treated oil accumulates in the top part of the treater, above the filtering section. It is withdrawn by a line with an escape head and carried off towards the storage tanks where settling ends. This unit is most often completed by an exchanger where the treated, hot oil yields its calories to the incoming fluid; loss by evaporation during storage is thus decreased and heating energy can be saved.


Operation of an horizontal heater treater (see Fig. XIII.11)

These devices operate in the same way as vertical heater treaters.


  • Advantages:


  • The plenum chamber is larger than that of the vertical heater treaters. They can therefore treat heavier


  • Internal partitioning diverts free water from the heating section, whence a gain in treatment capacity and energy


  • Drawbacks:


They need more ground space than vertical heater treaters. But in spite of that, the device remains more compact than the wash tank system.

3.3.  Heater treater efficiency

 The output of a heater treater is greatly improved by the downstream injection of a surfactant. Heater treaters are more compact than wash tanks, and:

  • oil residence time is considerably less than the wash tank

However, the oil residual water content at the outlet remains high, in the order of 0.5 %, which generally requires an additional treatment;

  • they can work under pressure which makes it possible to treat viscous crudes with a minimum of loss by


3.4. Typical installation


It is obvious that the schematics given in figure XIII.12 are not exhaustive, and different solutions, can be adopted if suitable.





The traditional dehydration-desalting processes recalled previously are suitable for the treatment of light or medium oils, but become ineffective when the crudes to be treated are heavier (API < 30).


An electrostatic treatment is therefore necessary in these specific cases.


Moreover, the development of offshore oil-fields means a demand for compact solutions, which tends to exclude certain traditional means such as wash tanks.




After the three-phase separators, the crude contains water and dissolved salts, but also possibly some salts in the form of crystals more or less protected from water by a coating of crude.


Water is often in the form of a stable emulsion requiring very long storage times. The electrostatic desalter contributes efficiently to destroy these emulsions.


For this a new emulsion is created with about 3 to 5 % of water, less salty than the reservoir water. This water can be fresh water if it is available or sea water in offshore productions. (In practice, water with a salt content of over 50 g/l cannot be used). This new emulsion thus created is destroyed in the desalter; the residual salt water of the treated crude presents a poorer salt content than the original water. For the same final water content the crude salt content has thus been reduced.



These basic operations take place in an electric desalter: the table below describes these operations as well as parameters governing them:



Operations Achievements of the operation Active parameters

Fresh water washing

Formation of a thin emulsion between the salt crude and fresh water –       quantity of water

–       adjustment of the mixing valve

–       presence  of  a      wetting agent


Coalescence of the water drops dispersed in the crude

The electric field develops some forces between drops and dipoles facilitating coalescence –       value of the electric field

–       quantity    of    water    and quality of the emulsion

–       residence time

–       surfactant



Drop settling

This begins at the same time as coalescence and takes place throughout the entire volume. –       Drop diameter (quantity of water)

–       difference      in      density between water and crude

–       crude viscosity

–       temperature    (action    on viscosity)



1.1.  Dissolution and dilution


The washing operation consists in carrying salts into the water phase. To ensure the best water/oil contact, the achieved emulsion should be thin enough (the size of the water drops thus formed varies from 1 to 10 microns).


The water and crude will be mixed through a mixing valve. The mixture will be adjusted so that the emulsion is as thin as possible without disturbing settling during the following stage.


1.2.  Coalescence in a field circuit



  • General


The water/crude stable emulsion is stabilised firmly by polar molecules such as asphaltenes, naphtenates and/or thinly divided solids.


These agents stabilise the emulsion, whence the necessity to use certain demulsifiers.


The difficulty of coalescence is therefore a function of the quantity of natural emulsifiers contained in the crude and also of the presence of thinly divided solids.



  • Coalescence mechanisms


The water molecule is formed with:


  • an oxygen atom carrying a negative potential d,
  • two hydrogen atoms each one carrying a positive d+





The water molecule configuration is given on the above figure. The angle formed by the two covalent bonds O-H (the oxygen atom being the top) is about 105°. A dipole moment results from this. In water, the H2O molecule distribution is random which means that a given volume has a nil dipole moment.


On the contrary, if water is placed in a high potential field circuit, the H2O molecules take their bearings according to their dipole moment. A given water volume, placed in a field circuit, presents an induced dipole moment.

Given a water emulsion in oil. Apply a field circuit to it and observe the behaviour of a water drop isolated in the continuous oil phase (see Fig. XIII.13). As long as the difference of potential is nil, the drop remains spherical. When a high difference of potential is applied, the water drop is distorted, becomes oval, and is transformed in induced dipole. All the drop positive charges move towards the end of the drop nearest the field negative potential; the negative charges going towards the field positive potential. The water drops thus polarised in a field circuit are submitted to a force as shown on figure XIII-13. The left column is a series of microscope photographs of water drops; the right column makes it possible to understand the polarisation effect. On the top photograph, there is no field circuit; a field circuit is imposed on the middle photograph (drop lengthening). On the bottom photograph, the field circuit gradient is considerably increased and the water drop breaks to form two drops after having stretched to maximum length.


If another water drop is located close to the first one, it also polarises. There is therefore an attraction between both water drops. The force of attraction between the two aligned droplets is given by the Gaussian formula:



æ aö 4

F  =  K E2 a2 ç   ÷

è dø

where:        a     =     water drop radius

d     = distance between the drop centres E     = electric gradient

F     = force of attraction


This formula is simplified and only remains valid in the case of water drops with the same diameter.

  • If a water drop acquires a permanent charge when contacting an electrode, it will be submitted to the attraction of the polarized drops coming up to the electrode and of the drops charged by the other electrode as well as to the first electrode repulsion. The forces of interaction between the drops are respectively in 1/d3 and 1/d2 which corresponds to a longer radius than the forces in 1/d4 between induced


  • In an alternating field, the charged drop is rather less “mobile” than the induced dipole as the field alternations lead to alternate movements close to the electrode where the drop became charged. In a direct field, the charged drops have a permanent group movement towards the opposite load plate which favours the grouping of drops with the opposite


  • Active parameters


To increase the coalescence force F, it is better to increase the field circuit E. It should, however, be noted that very high fields might distort the drops so much that they could be split into smaller drops. In practice, a unit field of 5 000 V/cm is not exceeded.


To increase F, “d” can be reduced, as distance between drops and “a” can be increased, as drop radius.


These two magnitudes are a function of the quantity of water added to form the secondary emulsion and of the quality of the achieved dispersion. The adjustment of the mixture valve is therefore a critical parameter of the installation, once the water proportion has been chosen.


The drops are generally between 0.75 µm and 7.5 µm in diameter. Assuming that drops are isometric and in compact hexagonal piling (when in contact):


d    = 2a


where x is the water content in percentage;



for x = 75 we get:     1 =    d


:      drops are in contact.



The coalescence force is therefore as follows:


F = K a2 x4/3


It is therefore in our interest to increase x (quantity of water in the emulsion) by injecting fresh water or sea water according to the case in hand (see Fig. XIII.14).

For x = 10%, the distance between drop contact (d – 2a) is about 1 diameter, and the force of attraction is very high, especially as coalescence is going to increase the drop size until turbulence and decantation reduce the local concentration and increase the distance between the drops.


For x = 1%, the distance between the drops is about 3 diameters, the force of attraction is divided by 21 with respect to 10%.


For x = 0.1%, the distance between the drops is about 8 diameters, the force of attraction is divided by 450 with respect to 10% and becomes increasingly inadequate as viscosity of the crude increases.




One cannot hope to reduce the undissolved water content of the crude to less than 0.1 – 0.2%.

The increase in the water content is limited by the increase of the emulsion conductivity and the lowering of the electric gradients implied up to the triggering risk.


  • Field circuits


An alternating electrostatic field is usually used to dehydrate a crude. The electrodes are suspended in the dehydrator oil phase by means of insulation. The electrode pattern usually adopted by the manufacturers is made up of grids (bars assembled to form a plane).


Two horizontal grids are usually used: the lower grid is connected to the transformer secondary, the upper grid is earthed.


The emulsion comes into the field near the bottom of the dehydrator and rises through the grids. Oil gathers at the top before being evacuated. The decanted water accumulates at the bottom of the dehydrator and creates a water-oil interface parallel to the grids (see the figure below).

The voltage applied to the electrodes varies from 16 000 volts to 25 000 volts; the electrical installed capacity, about three times the required capacity, varies according to capacity, the nature and conductivity of the crude and to operational conditions between 0.3 and 0.5 KVA/T/h.


The use of 50-60 hertz alternating current (see Fig. XIII.15a) implies that the field and the charges induced on the dipoles change direction 100-120 times per second, passing by 0. But the law of attraction between drops and dipoles is applicable at any moment.


Given Vm the field maximum potential.


The nominal potential Vn = Vm./ 2

Thus, the maximal potential of an electrode connected to a transformer secondary of 20 KV will be of 28.3 KV.


In such an alternating field, the water drops vibrate: there is a continuous variation of the geometric shapes of the drops passing from round to oval then back to round etc… (see Fig. XIII.15b). This phenomenon of vibrations facilitates the rupture of the stabilising film surrounding the drops; these drops are electrically neutral: only those located near the electrodes are momentarily charged. This explains why there is no important displacement of the drops under the effect of the alternating


field circuit except the vibrations “in situ” previously described which can be at the origin of a kind of “swimming”.



With very high frequencies (> 100 MHz) a phenomenon of relaxation appears. Dipoles can no longer follow the variations of the field circuit. The dipole – dipole attraction disappears with these frequencies.


It can also be noted (see Fig. XIII.15c) that the distance between the charged electrode (high potential) and the upper electrode (grounded) is smaller than that between the charged electrode and the interface level (also grounded through the desalter walls).


Such a distribution of the electrodes creates a primary field, between low electrode and interface level, of about 100 – 400 volts/cm and a secondary field between low and high electrodes of about 500 – 2 000 volts/cm, according to the transformer connection and the emulsion conductivity. (The field circuit is limited to less than 5 000 V/cm to avoid bursting the small 1 to 10 micron drops, or an arc forming from the charged electrode).


This explains why the water drops with an medium diameter are coalesced in the primary field. The thinner drops which are not affected by this low intensity field, continue to rise up to the secondary field where they coalesce before settling (as the water concentration is poorer, a higher field circuit can be established without any risk of breakdown denser than at the level of the primary field).


A variation consists in using at least two transformers to supply a high out of phase voltage (phase angle: 120°C). The desalter always includes two electrodes: the low electrode is charged by one of the transformers as before whereas the top electrode is also charged by the other transformer(s). The result is a greater difference in potential between the two grids. The primary field still exists, and a field circuit appears between the top electrode and the desalter walls which are earthed.




Transformers are designed to resist short-circuits without suffering any damage. To protect the transformer, a resistance coil is placed in series with the primary (see Fig. XIII.16a).

When the oil conductivity increases, the current crossing the primary increases the coil impedance which causes a drop in the voltage supplied by the transformer. In the example described on figure XIII.16, the supply voltage varies from 5 500 v to 0 v when the conductivity between the electrodes passes from i = 0 to the short-circuit intensity i = Icc (see Fig. XIII.16b).


The field circuit between the electrodes will therefore be all the weaker as the emulsion is more conductive and as a smaller transformer power margin is available. The coalescence quality, and therefore the quality of desalting will consequently be affected.


The possibility of using a direct electrostatic field to dehydrate a crude has also been considered. Here, there are two major problems:


  1. the technical difficulty to obtain high direct voltages with significant intensities, from an alternating current,


  1. the risks of corrosion connected with a “sacrificial” electrolysis of the electrodes and/or the walls of the device. In a direct field, the water drop behaviour is very different from that in an alternating field (see Fig. 17).

As in an alternating field, the water drops polarise, but this polarisation is permanent which makes it possible for them to move towards the nearest electrode. Reaching the electrode surface, the drop is electrically charged with the same sign (electron transfer) before being pushed away towards the opposite electrode. Reaching this one, the reverse mechanism begins again. Thus the drops move alternately from one electrode to the other.



During these displacements, coalescence takes place:


  • between polarised neutral drops moving towards the electrodes,
  • between opposite charge drops having already been in contact,
  • between polarised neutral drops and charged


However, when emulsion conductivity is sufficient, there is a considerable risk of electrolytic corrosion, which is why dehydration in the presence of a direct electric field is not used. To avoid corrosion problems, a recent technological development offers a dehydration system using a direct electrostatic field combined with an alternating electrostatic field.


1.3.  Decantation


Assuming that the water drops are spherical, they will settle in the desalter, under the effect of gravity, according to Stokes’ law:




V = 2


. a2 . g Dw

  • Do




V   =    gravity drop velocity g    =    gravity acceleration a = water drop radius

Dw:  =     density of the disperse phase (water) Do   =              density of the continuous phase (crude)

m = viscosity of the continuous phase (crude)


The gravity drop velocity should be higher than the crude rising velocity towards the desalter outlet (about 0.2 cm/sec). To improve settling, it should be a good thing to:


  • increase the water drop sizes (increasing the quantity of injected water and using demulsifiers),


  • operate at the highest possible temperature to decrease the continuous phase


In practice, the desalters are calculated for a viscosity of 2 to 5 centipoises and for a settling time of 20 to 30 minutes. As the residence time between the interface level and the top electrode is only 5 to 10 minutes, it demands a decanting velocity of about 0.25 cm/sec (consequence of a gravity drop velocity of 0.45 cm/sec and a crude upward velocity of 0.2 cm/sec.


In the case of heavy crudes, Stokes’ law shows that to reach an adequate gravity drop velocity, it is necessary to operate with a higher temperature. But this is not always sufficient, and the residence time in the desalter will have to be increased frequently.


With a very heavy crude a decrease in temperature has been known to cause a change of sign in the difference of density, with the result that oil appeared at the bottom of the dehydrator. Another time a dehydrator on very heavy crude was designed to separate water at the top and oil at the bottom (see Fig. XIII.18 and XIII.19).




2.1. One-stage desalting


  • General


The figure XIII.20 gives a cross-section of the schematic of field circuits usually used as well as the water/crude emulsion distribution.

  • The various technologies


Optimization of the desalting technique has been going on until recently.


The different solutions are as follows:


  • the electrode disposition (see Fig. 21).

Due to the presence of one, two or three transformers and the disposition of electrodes the field circuit distribution can be very sophisticated, which makes it possible to have a better field homogeneity and therefore better overall efficiency. H.T.I. (Hydrocarbon Technology Inc.) (manufacturer) uses a series of vertical electrodes supplied by an alternating current. This technology would be particularly well adapted to the treatment of heavy oils with long residence times.

  • The desalter emulsion supply system (see Fig. 22).

According to manufacturers, the emulsion inlet into the desalter is placed above or below the water/crude interface. The supply system between the electrodes has been dropped as there is a risk of short-circuits. Figure XIII-22 gives in detail a technique in which the supply is made above the interface level (Howmar) and a technique in which the water/crude emulsion crosses the water layer, washing and disolving part of the emulsion (Petrolite).


  • The type of current used (alternating or direct).

Most known technologies use an alternating field. A recent technology proposes a system of vertical electrodes supplied with direct current (rectified half-wave alternating current) combined with the alternating current (see Fig. XIII.23). This was patented in 1971 by the American company CE NATCO under the name of “dual polarity”.

It combines both the advantages of dehydration in the presence of a direct electrostatic field and those of an alternating electrostatic field. The transformer secondary splits up into two lines, each equipped with a current rectifier (see Fig. XIII.24 and 25). Both rectifiers work in opposition. Each of these lines passes the desalter wall and supplies one vertical grid out of two. Thus two adjacent electrodes are connected, each one, to one of these two lines.

During the positive half of the electric cycle, the electrodes connected to the line fitted with the corresponding rectifier are charged positively. The rectifier set on the other line prevents the second series of electrodes from being discharged. The latter will only be charged negatively during the next half of the electric cycle.


We will now see what occurs at the level of two adjacent electrodes: one carries a positive permanent charge; the other a negative permanent charge. There is therefore a field circuit with a variable intensity but a fixed direction between these two vertical electrodes.


Neutral drops form an induced dipole (with a fixed direction) and move towards the nearest electrode. During this trip a dipole-dipole attraction, as described above, is exerted. When contacting the electrode, the drops acquire a permanent charge; they are rejected by this electrode and attracted by the opposite electrode. The induced charge/dipole forces (in 1/d3) and opposite charge/charge forces (in 1/d2) cause



coalescence. Once out of the horizontal field, the drops are again submitted to the alternating field as with traditional equipment.


There is indeed a circulation of electrons between the charged plates on the one hand, the desalter walls and the interface on the other hand (both of which are at the 0 potential as they are earthed). During the positive half of the cycle the current flows from the positive plates to the earth. The current position is reversed during the negative half of the cycle. An alternative field therefore results from this which, as it superimposes the direct field, eliminates the risk of electrolytic corrosion.


“Dual polarity” process and performances: the initial emulsion (fairly conductive) gets under the vertical grids, in the alternating field circuit with a poor gradient. The biggest drops coalesce whereas the smallest ones are carried along into the denser direct field circuit, between the vertical electrodes. A weaker alternating field subsists above the grids which could complete the coalescence of certain drops.


In this type of technology, the presence of a direct current confers permanent charges to the drops. The coalescence therefore occurs between the opposite permanent charge drops or when the charged drop hit the opposite charge electrodes. The direct high voltage initiates drop migration until the size is sufficient to settle by gravity. This form of coalescence, according to the manufacturer, appears to give a higher dehydration rate than the alternating electrostatic coalescence acting by controlled turbulence of the spherical water droplets and induced dipole attraction.


Still according to the manufacturer, the explanation would be that the application of a rectified direct current makes it possible to avoid any cancellation of the electric forces with a frequency of 100-120 times per second as in the case for alternating voltage. It is obvious that all these effects are all the more measurable as the desalting temperature is lower, or as the crude viscosity is higher. According to these criteria with respect to the alternating system (see Fig. XIII.26):

  • Either a similar desalting efficiency with a lower temperature ( Dq = 15°F ) hence a

decrease in heating capacities (consumed energy saving; lower investment and maintenance costs) and a decrease in the light losses (decrease in its API degree).


  • Or a higher desalting efficiency with the same operational can be hoped for.

2.2. Two-stage desalting



  • Two different capacities


When oil-field water has a salt content over 30 g/l, two series desalters can generally be found on the production fields. Here too, there are several possible variations (see Fig. XIII.27).


Diagrams 1 and 2: two similar capacities are assembled in series and used as a desalter; in fact, the wash water is injected upstream of each of them. Moreover, the dilution fresh water can be injected upstream of the second stage using, at the first stage, a recycling of the water coming from the second stage.


Diagrams 3 and 4: two similar desalters assembled in series, one of which is used as dehydrator (without water injection). The diagram 3 is typical of an offshore production installation with oil-field water containing a lot of salt which is removed as well as possible, before inputing the wash water . In case of insufficient performances with this assembly, diagram 2 can be adopted and, in the last resort to diagram 1. Diagram 4 is in fact not very interesting. It comes down to increasing the residence time, which can also be obtained by putting the units in parallel.


  • Only one capacity (see Fig. 28)


A quite recent technique proposes to solve water emulsions in oil using two stages of coalescence in a single capacity. The stages are insulated hydraulically by vertical superposition and make it possible to have a succession of sequences in series. Each stage is characterized by flat and permeable electrodes.


This technology includes three electrodes, forming a series of field circuits each with its own distribution. A pump and pipe system makes it possible to supply the next stage with the coalesced liquid from the previous stage.




What degree of flexibility is there when seeking the best output from a desalter?


The design parameters used by manufacturers for sizing the equipment (settling time, electrode surface/crude flow, electrode technology…) are not considered. Only the parameters below, classified in descending order of magnitude are considered.


3.1. Water/crude interface level


In fact, the water level represents a potential 0 electrode of the primary field defined with the lowest electrode of the installation. Any significant variation of the water level alters the primary field and disturbs the field circuit. It is therefore a good thing to keep this level constant according to the manufacturer’s recommendations. In practice it may be difficult to respect this constraint (dirty level glass, float position disturbed by the presence of interface emulsions).


3.2. Desalting temperature



The decanting criterion Dw – Do


is an ascending function of temperature.



It is therefore necessary to desalt at the highest temperature possible compatible with the local stresses. The increase in temperature can be obtained either by heating the crude, or maintaining



the wellhead temperature by thermal insulation of the lines and capacities. There is a growing concern regarding the loss of lights hence exchangers are installed on the desalter outlets.


On the field, the operations are carried out at a low temperature compared with the temperatures reached in refineries. The crude is rarely heated to more than 60°C on a field.


One should however add that in most cases, the stresses are such that we do not have sufficient flexibility to adjust this parameter.


To provide protection from wash water aggressiveness, epoxy type internal coatings are used in the desalters or the wash water is treated (deaeration, inhibitors).


3.3. Wash water rate


It should be remembered that the force of electric coalescence is an increasing function of the wash rate. It would therefore be a good thing to increase the quantity of wash water; this is all the more true as the crude gets heavier.


3.4. Injection point of the wash water


Generally, water is injected upstream of the mixing valve. A “pre-wash” can be made, injecting part or all of the water upstream of the three-phase separators where part of the injected water will be decanted.


However, this practice should be avoided when treating medium crude (° API 35) owing a risk of stable emulsions forming at the separators.


3.5. Nature of the wash water


This problem is first and foremost a problem of availability. Fresh water is recommended whenever it is possible. However, on offshore platforms, the use of sea water, when it contains less salt than the oil-field water, is possible.


Generally, the wash water is deaerated to limit corrosion (residual oxygen < 0.05 mg/l).


Some problems of deposits by sea water/oil-field water incompatibility can also be encountered downstream of the wash water injection, and it may be necessary to adjust the wash water flow rate according to the precipitation limit or add antideposition agents.


3.6.  Pressure drop in the mixing valve


It is very difficult to recommend any strict rules in this field. An increase in the pressure drop tends to cause a very fine dispersion, and therefore emulsions which are difficult to break. Too slight a pressure drop means an unthorough washing. In practice, the optimum pressure drop is defined once all the other parameters have been adjusted. It varies between 0.2 and 2 bars according to the nature of the treated crude.



3.7.  Nature and rate of demulsifier


There are many demulsifiers on the market. Generally, they are injected upstream of the separators, sometimes even at the wellheads. The rate of injection varies from 5 to 50 ppm according to the nature of the crude to be treated.


The role of a demulsifier is to destabilise the film of emulsifier surrounding the water droplets and thus favour their coalescence.


The performance required from a good demulsifier is twofold:


  • improve the quality of the separation on the oil side,
  • improve the quality of the separation on the water





4.1.  Performance control


The performances of a desalter are assessed according to the three following criteria:


  • Salt content of the treated crude


The required performances mainly depend on the wash water characteristics and on the subsequent treatment (storage…). Measurements are made using traditional laboratory methods:


  • volumetric dosage of washed out chlorides,
  • measurement of the electric conductivity in a third


  • Water content of the treated crude


The required performances are usually 0.15 or 0.2 % (volume) of free water at the operating temperature.


The measuring methods used are as follows:


  • the centrifuge method (insoluble water),
  • Dean Stark method (total water)


  • Oil content of the discharged water


The required performances are a function of the local stresses. The manufacturers generally guarantee a water oil content at the outlet of desalters below 500 ppm (sometimes 200 ppm) at the operating temperature. These guarantees are completely unrealistic and cannot be used for designing oily water processing units. A 2 000 ppm specification appears to be more realistic.



Subsequent treatment is necessary to meet local requirements, particularly for offshore production. Desalter water is more difficult to treat than separator water.


The usual control methods are as follows:


  • the gravimetric method (complex and proposed as standard measurement),
  • the method by colorimetry (not very accurate),
  • the infrared method (quicker and more accurate)




Electrostatic desalting, the most recent technique used in desalting on oil fields, presents the advantage over traditional processes, such as wash tank and heater treater, of being applicable to all cases.


Electrostatic desalting is particularly well adapted to offshore fields where equipment must be compact. Moreover, it would appear to be the best technique for future treatment of heavy crudes and effluents produced by secondary or tertiary recovery techniques.




  • LAMER V.K. and HEALY K.

“Absorption – Floculation Reactions of Macromolecules at the Solid Liquid Interface”, Rev. Pure App. Chem. Vol 13, pp 112-132 (1963)


“Aggregation of Suspensions by Polyelectrolytes” Ind. Eng. Chem. Vol 46 pp 1485-1490 (1954)


“Iran has big desalting and pressure maintenance jog ahead” The Oil and Gas Journal Mar. 13, 1978 pp 65-70

  • Cours: C.E. NATCO

“Crude Oil Dehydration”


  • Corrosion Handbook



“Dessalage du pétrole brut sur le champ de production” Pétrole et Techniques n° 273 août septembre 1980



“Crude desalting: why and how”

Hydrocarbon Processing Feb. 1965, vol 44 n°2