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Crude Oil Emulsions

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Chapter 19 Crude Oil Emulsions H. Vernon Smith, Meridian Corp. Kenneth E. Arnold, Paragon Engineermg Scr~icm Inc. Introduction Much of the oil produced worldwide is accompanied by water in an emulsion that requires treating. Even in those fields where there is essentially no initial water produc- tion. water cuts may increase in time to the point where it is necessary to treat the emulsion. Water content of the untreated oil may vary from a fraction of I % to over 90%. To prevent increased transportation costs, water treat- ment and disposal costs, and deterioration of equipment, purchasers of crude oil limit the basic sediment and water (BSSCW) content of the oil they purchase. Limits vary de- pending on local conditions, practices. and contractual agreements and typically range from 0.2 to 3.0%. BY&W is usually predominantly water but may contain solids. The solids contained in the BS&W come from the produc- ing formation and consist of sand. silt, mud, scale. and precipitates of dissolved solids. These troublesome solids vary widely from producing field to field. zone to zone, and well to well. Purchasers may also limit the salt content of the oil. Removing water from the stream decreases the salt con- tent. Salt content along with BS&W are the two impor- tsnt crude purchasing requirements. When water forms a stable emulsion with crude oil and cannot be removed in conventional storage tanks. emulsion-treating methods must be used. The methods. procedures, equipment, and systems generally used in treating crude oil emulsions are considered in this chap- ter, Space limitation does not permit the rigorous trcat- ment of crude oil emulsions. Many topics and sub-topics exist on which entire chapters can be written. This chap- tcr contains an abbreviated discussion of only a few of the most important and pertinent considerations of crude oil emulsions. More detailed and diversified discussions on crude oil emulsions can be found in the General Refer- ences at the end of the chapter. Theories of Emulsions Definition of an Emulsion An emulsion is a heterogeneous liquid system consisting of two immiscible liquids with one of the liquids intimately dispersed in the form of droplets in the second liquid. An emulsion is distinguished from a simple dispersion of one liquid in another by the fact that, in an emulsion, the prob- ability of coalescence of droplets on contact with one another is greatly reduced because of the presence of an emulsifier, which inhibits coalescence. Such inhibition is not present in a dispersion. The stability of the emulsion is controlled by the type and amount of surface-active agents and/or finely divid- ed solids. which commonly act as emulsifying agents or emulsifiers. As shown in Fig. 19.1, these emulsifying agents form interfacial films around the droplets of the dispersed phase and create a barrier that slows down or prevents coalescence of the droplets. The matrix of an emulsion is called the external or con- tinuous phase. The portion of the emulsion that is in the form of small droplets is called the internal, dispersed, or discontinuous phase. The emulsions considered in this chapter consist of crude oil and water or brine produced with it. In most emulsions of crude oil and water, the water is finely dispersed in the oil. The spherical form of the water globules is a result of interfacial tension (IFT). which com- pels them to present the smallest possible surface area to the oil. This is a water-in-oil emulsion and is referred to as a “normal” emulsion. The oil can be dispersed in the water to form an oil-in-water emulsion, which is referred to as an “inverse” or “reverse” emulsion. A typical reverse emulsion is shown in Fig. 19.2. Emulsions are sometimes interrelated in a more com- plex form. The emulsion may be either water-in-oil or oil-in-water to begin with, but additional agitation may

Chapter 19

Crude Oil Emulsions H. Vernon Smith, Meridian Corp.

Kenneth E. Arnold, Paragon Engineermg Scr~icm Inc.

Introduction Much of the oil produced worldwide is accompanied by water in an emulsion that requires treating. Even in those fields where there is essentially no initial water produc- tion. water cuts may increase in time to the point where it is necessary to treat the emulsion. Water content of the untreated oil may vary from a fraction of I % to over 90%.

To prevent increased transportation costs, water treat- ment and disposal costs, and deterioration of equipment, purchasers of crude oil limit the basic sediment and water (BSSCW) content of the oil they purchase. Limits vary de- pending on local conditions, practices. and contractual agreements and typically range from 0.2 to 3.0%. BY&W is usually predominantly water but may contain solids. The solids contained in the BS&W come from the produc- ing formation and consist of sand. silt, mud, scale. and precipitates of dissolved solids. These troublesome solids vary widely from producing field to field. zone to zone, and well to well.

Purchasers may also limit the salt content of the oil. Removing water from the stream decreases the salt con- tent. Salt content along with BS&W are the two impor- tsnt crude purchasing requirements.

When water forms a stable emulsion with crude oil and cannot be removed in conventional storage tanks. emulsion-treating methods must be used. The methods. procedures, equipment, and systems generally used in treating crude oil emulsions are considered in this chap- ter, Space limitation does not permit the rigorous trcat- ment of crude oil emulsions. Many topics and sub-topics exist on which entire chapters can be written. This chap- tcr contains an abbreviated discussion of only a few of the most important and pertinent considerations of crude oil emulsions. More detailed and diversified discussions on crude oil emulsions can be found in the General Refer- ences at the end of the chapter.

Theories of Emulsions Definition of an Emulsion An emulsion is a heterogeneous liquid system consisting of two immiscible liquids with one of the liquids intimately dispersed in the form of droplets in the second liquid. An emulsion is distinguished from a simple dispersion of one liquid in another by the fact that, in an emulsion, the prob- ability of coalescence of droplets on contact with one another is greatly reduced because of the presence of an emulsifier, which inhibits coalescence. Such inhibition is not present in a dispersion.

The stability of the emulsion is controlled by the type and amount of surface-active agents and/or finely divid- ed solids. which commonly act as emulsifying agents or emulsifiers. As shown in Fig. 19.1, these emulsifying agents form interfacial films around the droplets of the dispersed phase and create a barrier that slows down or prevents coalescence of the droplets.

The matrix of an emulsion is called the external or con- tinuous phase. The portion of the emulsion that is in the form of small droplets is called the internal, dispersed, or discontinuous phase. The emulsions considered in this chapter consist of crude oil and water or brine produced with it.

In most emulsions of crude oil and water, the water is finely dispersed in the oil. The spherical form of the water globules is a result of interfacial tension (IFT). which com- pels them to present the smallest possible surface area to the oil. This is a water-in-oil emulsion and is referred to as a “normal” emulsion. The oil can be dispersed in the water to form an oil-in-water emulsion, which is referred to as an “inverse” or “reverse” emulsion. A typical reverse emulsion is shown in Fig. 19.2.

Emulsions are sometimes interrelated in a more com- plex form. The emulsion may be either water-in-oil or oil-in-water to begin with, but additional agitation may


Fig. 19.1—Photomicrograph of water-in-oil emulsion. Observethe riqid-appearing film or skin that retardscoalescence.

cause it to become multistage. If it is a water-in-oil emul-sion initially, a water-in-oil-in-water emulsion can beformed if a small volume of the original water-in-oil emul-sion is enveloped in a film of water. It is also possibleto form multistage emulsions in an oil continuous phaseas shown in Figs. 19.3 and 19.4. This alternating external-phase/internal-phase/external-phase arrangement has beenknown to exist in eight stages. Multistage emulsions usual-ly add appreciably to the problem of separating the emul-sion into oil and water. The more violent the agitation,the more likely multistage emulsions are to form.

How Crude Oil Emulsions FormThe three conditions necessary for the formation of anemulsion are (1) the two liquids forming the emulsionmust be immiscible, (2) there must be sufficient agitationto disperse one liquid as droplets in the other, and (3) theremust be an emulsifying agent present. Crude oil and waterare immiscible. If gently poured into the same container,they will quickly separate. If the oil and water are vio-lently agitated, small drops of water will be dispersed inthe continuous oil phase and small drops of oil will bedispersed in the continuous water phase. If left un-disturbed, the oil and water will quickly separate intolayers of oil and water. If any emulsion is formed, it willbe between the oil above and the water below.

When considering crude oil emulsions, we are usuallyconcerned with water-in-oil emulsions because most emul-sions are this type. Oil-in-water emulsions are encoun-tered in some heavy oil production, however, such as that

Fig. 19.2—Photomicrograph of reverse emulsion. Uniformlysized oil particles are about 10 µm in diameter andare dispersed in the continuous water phase.

found in areas of Canada, California, Venezuela, andother areas. Oil-in-water emulsions are generally resolvedin the same way as water-in-oil emulsions, except elec-trostatic treaters cannot be used on oil-in-water emulsions.

The agitation necessary to form an emulsion may re-sult from any one or a combination of several sources:(1) the bottomhole pump, (2) flow through the tubing,wellhead, manifold, or flowlines, (3) the surface trans-fer pump, or (4) pressure drop through chokes, valves,or other surface equipment. The greater the amount ofagitation, the smaller the droplets of water dispersed inthe oil. Figs. 19.5 through 19.9 show common crude oilemulsions that demonstrate the range of droplet sizesnormally encountered. Studies of water-in-oil emulsionshave shown that water droplets are of widely varyingsizes, ranging from less than 1 to about 1,000 µm. Emul-sions that have smaller droplets of water are usually morestable and difficult to treat than those that have largerdroplets.

Crude oils vary widely in their emulsifying tendencies.Some may form very stable emulsions that are difficultto separate, while others may not emulsify or may forma loose emulsion that will separate quickly. The presence,amount, and nature of an emulsifying agent determineswhether an emulsion will be formed and the stability ofthat emulsion. If the crude oil and water contain no emul-sifying agent, the oil and water may form a dispersionthat will separate quickly because of rapid coalescenceof the dispersed droplets. On the other hand, if an emul-sifying agent is present in the crude oil, a very stable emul-sion can be formed.


Fig. 19.3—Photomicrograph of oil-in-water-in-oil emulsion. Oildroplets are shown dispersed in water droplets thatare dispersed in the continuous oil phase.

If an emulsion is not treated, a certain amount of waterwill separate from the oil by natural coalescence andsettling because of the difference in density of oil andwater. Unless some form of treatment is used to accom-plish complete separation, however, there probably willbe a small percentage of water left in the oil even afterextended settling. The water that remains in the oil willbe in minute droplets that have extremely slow settlingvelocities. They will be widely dispersed so that there willbe little chance for them to collide, coalesce into largerdroplets, and settle.

The amount of water that emulsifies with crude oil inmost production systems may vary from less than 1 tomore than 60% in rare cases. The most common rangeof emulsified water in light crude oil-i.e., oil above20° API-is from 5 to 20 vol%. The most common rangeof emulsified water in crude oil heavier than 20° API isfrom 10. to 35%.

Emulsifying AgentsEmulsifying agents are surface-active compounds that at-tach to the water-drop surface and lower the oil/water IFT.When energy is added to the mixture by agitation, thedispersed-phase droplets are broken into smaller droplets.The lower the IFT, the smaller the energy input requiredfor emulsification-i.e., with a given amount of agitation,smaller droplets will form.

There are many theories on the nature of emulsifyingagents in crude oil emulsions. Some emulsifiers arethought to be asphaltic in nature. They are barely soluble

Fig. 19.4—Photomicrograph of multiple-stage emulsion fromRocky Mountain field. The dispersed water phasecontains small oil particles.

Fig. 19.5—Photomicrograph of loose emulsion from westernKansas containing about 30% emulsified water in theform of droplets ranging in diameter from about 60µm downward.


Fig. 19.6—Photomicrograph of water-in-oil emulsion with dis-persed particles of water ranging in size from about250 to about 1 µm.

Fig. 19.8—Photomicrograph of tight emulsion with the dispersedwater particles varying in size from 1 to 20 µm.

Fig. 19.7—Photomicrograph of relatively tight water-in-oil emul-sion. Largest water droplets are about 60 µm,medium droplets are about 40 µm, and the smallestones are about 1 to 20 µm.

in oil and are strongly attracted to the water. They comeout of solution and attach themselves to the droplets ofwater as these droplets are dispersed in the oil. They formthick films that surround the water droplets and preventthe surfaces of the water droplets from contacting, thuspreventing coalescence when the droplets collide.

Oil-wet solids-such as sand, silt, shale particles, crys-tallized paraffin, iron, zinc, aluminum sulfate, calciumcarbonate, iron sulfide, and similar materials-that col-lect at the oil/water interface can act as emulsifiers. Fig.19.10 shows some of these solids removed from a crudeoil emulsion. These substances usually originate in theoil formation but can be formed as the result of an in-effective corrosion-inhibition program.

Many emulsions are prepared for commercial use. Anemulsion of kerosene and water is used for spraying fruittrees; soap is used as the emulsifying agent. Eggs supplythe emulsifying agent used in the preparation of mayon-naise from vegetable oil and vinegar: These are very stableemulsions.

Most but not all crude oil emulsions are dynamic andtransitory. The interfacial energy per unit of area in pe-troleum emulsions is rather high compared with familiarindustrial emulsions. They are therefore thermodynami-cally unstable in the sense that if the dispersed watercoalesced and separated, the total free energy woulddecrease. Only the presence of an emulsifier film in-troduces an energy barrier that prevents the “breaking”or separation process from proceeding.

The characteristics of an emulsion change continuallyfrom the time of formation to the instant of complete reso-lution. This occurs because there are numerous types of


Fig. 19.9—Photomicrograph of tight emulsion from HuntingtonBeach, CA; water content 20%, with the averagewater droplet diameter less than 5 µm.

adsorbable materials in a given oil. Also, the adsorptionrate of the emulsion and permanence of location at theinterface may vary as the fluid flows through the proc-ess. Furthermore, the emulsion characteristics are changedas the liquid is subjected to changes in temperature, pres-sure, and degree of agitation.

Prevention of EmulsionsIf all water can be excluded from the oil as it is producedand/or if all agitation of well fluids can be prevented, noemulsion will form. Exclusion of water in some wells isdifficult or impossible, and the prevention of agitation isalmost impossible. Therefore, production of emulsionfrom many wells must be expected. In some instances,however, emulsification is increased by poor operatingpractices.

Operating practices that include the production of ex-cess water as a result of poor cementing or reservoirmanagement can increase emulsion-treating problems. Inaddition, a process design that subjects the oil/water mix-ture to excess turbulence can result in greater treatingproblems. Unnecessary turbulence can be caused by over-pumping and poor maintenance of plunger and valves inrod-pumped wells, use of more gas-lift gas than is needed,and pumping the fluid where gravity flow could be used.Some operators use progressive cavity pumps as opposedto reciprocating, gear, or centrifugal pumps to minimizeturbulence. Others have found that some centrifugalpumps can actually cause coalescence if they are installed

Fig. 19.10—Photomicrograph showing a collection of inorganicsolids removed from an emulsion by filtering andwashing. These solids include calcite, silica, ironcompounds, obsidian, and black carbonaceous ma-terials.

in the process without a downstream throttling valve.Wherever possible, pressure drop through chokes andcontrol valves should be minimized before oil/water sepa-ration.

Color of EmulsionsThe color of a crude oil emulsion can vary widely, de-pending on the oil and water content of the emulsion andthe characteristics of the oil and water. The most com-mon color of emulsions is a dark reddish brown. How-ever, any color from light green or yellow to grey or blackmay be found. “Brightness” is an indicator of the pres-ence of an emulsion. Oil-free water and water-free oil areclear and bright. Emulsions are murky and opaque be-cause of reflection and scattering/of light at the oil/waterinterfaces of the dispersed phase. The greater the totalinterfacial area between the oil and water, the lighter thecolor of the emulsion. That is, an emulsion containingmany small droplets of water will tend to be lighter thanone containing an equal volume of water in larger dropletsbecause the latter has less total interfacial surface area.

Stability of EmulsionsGenerally, crude oils with low API gravity (high density)will form a more stable and higher-percentage volume ofemulsion than will oils of high API gravity (low density).Asphaltic-based oils have a tendency to emulsify morereadily than paraffin-based oils. High-viscosity crude oil


into bulk oil and water three things must be done:

will usually form a more stable emulsion than low- viscosity oil. Emulsions of high-viscosity crude oil usually are very stable and difficult to treat because the viscosity of the oil hinders or prevents movement of the dispersed water droplets and thus retards their coalescence. In ad- dition, high-viscosity/high-density oils usually contain more emulsifiers than lighter oils.

Effect of Emulsion on Viscosity of Fluids

Emulsions are always more viscous than the clean oil con- tained in the emulsion. The ratio of the viscosity of an emulsion to the viscosity of the clean crude oil in oilfield emulsions depends on the shear rate to which it has been subjected. The authors have found that for many emul- sions and the shear rates normally encountered in piping systems, this shear rate can be approximated by the fol- lowing equation if no other data are available.

~,/~~~=1+2.5f+l4.lJ”, . . . . . . . . . (1)


cc e = viscosity of emulsion.

PO = viscosity of clean oil, and

f = fraction of the dispersed phase.

Sampling and Analyzing Crude Oil Emulsions Purchasers of crude oil have established certain specifi- cations that must be met before they will accept oil from a producer. These specifications limit the amount of BS&W in the oil. The limitations are usually strict, and if the amount of ES&W in the oil exceeds the specified limit. the oil may not be accepted by the purchaser. The seller and buyer must agree on the procedure for sam- pling and analyzing the oil to provide consistent and mutu- ally acceptable data.

The performance of emulsion-treating units or systems can be observed and studied by the practice of regularly and periodically withdrawing and analyzing samples of the contents at multiple levels in the vessels or multiple points in the systems. This is particularly beneficial in treating emulsions involving viscous oils. Samples of emulsions should be representative of the liquid from which they are taken. Emulsification should not occur when the sample is extracted. Samples obtained at the wellhead. manifold, or oil and gas separator may show a high percentage of emulsion, but the oil and water in the system may actually not be emulsified. This indicates that emulsification occurred because of the turbulence created as the sample was removed from the pressure zone to the sample container.

It is possible to take a sample from a pressure zone without further emulsification of the liquids if the veloci- ty of the discharging liquid is controlled. One method is to use a piece of small-diameter tubing approximately 10 to 15 ft.long. One end of the tubing is connected to a bleeder valve on the line or vessel from which the sam- ple is to be extracted, and the other end is connected to the sample container. The bleeder valve should be opened fully and the sample allowed to flow through the small- diameter tubing into the container. The pressure drop from

the line to the container is absorbed by flow through the tubing. Flow through the tubing, however, can cause either coalescence or additional emulsification.

Another method of withdrawing a representative sam- ple of emulsion is to use a sample container initially filled with water. The sample container is equipped with valves at the top and bottom with the top valve connected to the point from which the sample is to be extracted. The top valve of the container is opened first and the container pressured from the line. The valve at the bottom of the container is then opened and the water discharged into the atmosphere as the sample enters the container. There will be no emulsification in the container because there is no pressure drop between the source and sample con- tainer to cause turbulence. Once the sample is taken, pres- sure can be bled off through a third valve with little effect on the sample.

Small centrifuges are used to determine BS&W con- tent of crude oil. The centrifuges may be driven by hand or electric motor. A small measured volume of sample is diluted with solvent and placed in graduated glass con- tainers. These are then inserted into the centrifuge and rotated at high speed for a few minutes. Separation of the oil, water, and solids is accomplished by centrifugal force. The percentages of each constituent can be read directly from the graduated containers in which the sample is cen- trifuged. The speed used in these small centrifuges var- ies from 2,000 to 4,000 revimin.

Methods of taking and analyzing samples of crude oil for custody transfer are included in the API Mur~uul of Petroleum Measurement Standards. Also see Chap. 17.

Methods Used in Treating Crude Oil Emulsions Three basic steps usually are required to separate a crude- oil/water emulsion into bulk phases of oil and water.

Step l-Destabilization. An emulsion is destabilized by counteracting the stabilizing effect of the emulsifier. The tough skin or film surrounding the dispersed water droplets must be weakened and broken. This is usually accomplished by adding heat and/or a properly selected, interfacially active chemical compound to the emulsion.

Step 2-Coalescence. After the films encasing the dis- persed droplets are broken, the dispersed droplets must coalesce into drops large enough to settle out of the con- tinuous phase of oil. Fig. 19.11 shows a small droplet of water breaking through a destabilized emulsion film to coalesce with the bigger drop. This usually is accom- plished by imposing a period of moderate agitation or by subjecting the destabilized emulsion to an alternating elec- tric field. This will increase the dispersed droplets con- tacting rate. Thus coalescence will increase, resulting in larger droplets.

Step 3-Gravity Separation. A quiet period of settling must be provided to allow the coalesced drops to settle out of the oil because of the difference in density between the water and oil. This is accomplished by providing a sufficient residence time and a favorable flow pattern in a tank or vessel that will allow the coalesced drops of water to separate from the oil.

Another way of stating the general emulsion-treating procedure is that to resolve a crude-oil/water emulsion


Fig. 19.11 -A waler-in-oil emulsion with the film or skin surround- ing the water droplet in the process 01 rupturing.

(I) increase the probability of coalescence of dispersed water droplets on contact, (2) make the rate of contact of dispersed water droplets high without creating high shear forces, and then (3) allow the liquids to settle quietly so that they can separate into bulk phases of oil and water. All the incidental variables, such as selection of proper chemical, rate of chemical injection, treating temperature and pressure, oil and emulsion viscosity, flow rate, ves- sel design, vessel size, and fluid levels, are controlled to execute these three steps in the quickest and most eco- nomical manner.

An emulsion-treating unit or system will use one or more of the methods in Table 19. I to aid in destabiliz- ing, coalescence, and/or settling. Each of these treating methods that can be used to resolve an emulsion is dis- cussed separately.


The use of heat in treating crude oil emulsions has four basic benefits.

I. Heat reduces the viscosity of the oil, resulting in a greater force during collision of the water droplets. Also, the reduced oil viscosity allows the water droplets to settle more rapidly through the less viscous oil, Fig. 19.12 can be used to estimate crude oil viscosity/temperature rela- tionships. Viscosities vary widely from one crude to another. The curves should be used only in the absence of specific data. If the viscosity of the crude is known at two temperatures, the viscosity at other temperatures can be approximated by a straight line. If the viscosity is known at one temperature, it can be approximated at


Destabilization Chemical Heating

Coalescence Agitation Coalescing plates Electric field Water washing Filtering Fibrous packing Heating Retention time Centrifugation

Gravity Separation Gravity settling Heating Centrifugation

other temperatures by drawing a straight line parallel to the others. If the viscosity is unknown at any tempera- ture, the lines on the chart may be used. API Spec. l2L recommends that crude be heated so that its viscosity is below 150 SSV (about 50 cSt) for treating.

2. Heat increases the droplets’ molecular movement. This aids in coalescence through increased collision fre- quency of the dispersed-phase droplets.

3. Heat may deactivate the emulsifier (e.g., dissolving paraffin crystals) or it can enhance the action of treating chemicals, causing the chemical to work faster and more thoroughly to break the film surrounding the droplets of the dispersed phase of the emulsion.

4. Heat may also increase the difference in density be- tween the oil and the water, thus accelerating settling. In general, at temperatures below 180”F, the addition of heat will increase the difference in density. Most light oils are treated below 180°F; thus the effect of heat on gravity is beneficial. For heavy crudes (below 20”API). which normally are treated above 180”F, heat may have a nega- tive effect on difference in density. In special cases, in- creased heat may cause the density of water to be less than that of oil. This effect is shown in Fig. 19.13.

Heating well fluids is expensive. Adding heat can cause a significant loss of the lower-boiling-point hydrocarbons (light ends). This results in “shrinkage” of the oil, or loss of volume. Because the light ends are boiled off, the remaining liquid has a lower API gravity and thus may have a lower value. Figs. 19. I4 and 19.15 illustrate typi- cal gravity and volume losses for 33”API crude vs. tem- perature. The molecules leaving the oil phase may be vented or compressed and sold with the gas. Even if they are sold with the gas, there probably will be a net loss in income.

The gas liberated when crude oil is treated may also create a problem in the treating equipment if the equip- ment is not properly designed. In vertical emulsion treat- ers and gun barrels, some gas may rise through the coalescing section. The liberated gas can create enough turbulence and disturbance to inhibit coalescence. Perhaps more important, the small gas bubbles have an attraction for surface-active material and hence for the water droplets; thus they have a tendency to keep the water droplets from settling and even may cause them to be dis- charged with the oil.


Fig. 19.12-Approximate viscosity/temperature relationships for crude oil

1 0 *oo 200 300

Temperature. D F


Crude C

0 100 200 300 Temperature. D F

Fig. 19.13--Relationship of specific gravity with temperature for three crude oils.

Fuel is required to provide heat, and the cost of fuel must be considered. If the oil is much above ambient tem- perature when discharged from the treating unit, it can be flowed through a heat exchanger with the incoming well fluid to transfer the heat to the cooler incoming well fluid. This will minimize evaporation losses and reduce fuel cost. It will also increase the vapor pressure of the crude, however, which may be limited by contract.

If properly applied, heating an emulsion can have great beneficial effect on water separation. The most econom- ical emulsion treating may be obtained by use of less heat and a little more chemical, agitation, and/or settling space.

In some geographic areas, emulsion heating require- ments vary in accordance with daily and/or seasonal at- mospheric temperatures. Emulsions are usually more difficult to treat when it is cool-at night, during a rain, or in winter months when the atmospheric temperatures are lowest. Treatment, especially heating, may not be re- quired in warmer summer months. Where the treating problem is seasonal, some emulsions can be resolved suc- cesstilly by addition of more chemical demulsifiers during winter months. Study is required to determine the proper economic balance of heat and chemicals.

Crude oil emulsions with similar viscosity ranges do not always require the same type of treating equipment or the same treating temperature. Emulsions produced


Fig. 19.14-API gravity loss vs. temperature for crude oil.




from different wells on the same lease or from the same formation in the same field may require different treat- ing temperatures. For this reason, it is recommended that low treating temperatures be tested so that the lowest prac- tical treating temperature for each emulsion and treating unit or system can be determined by trial.

The heat input and thus the fuel required for treating depends on the temperature rise, amount of water in the oil, and the flow rate. It requires about twice as much

energy to heat a given volume of water as it does to heat the same volume of oil. For this reason, it is beneficial to separate free water from the emulsion to be treated. Often this is accomplished in a separate free-water knock- out vessel upstream of the point where heat is added. Sometimes it is accomplished in a separate section of the same vessel.

The required heat input for an insulated vessel (heat loss is assumed to be 10% of heat input) can be approximated from

Q= 16AT(OSy,y, +q,,,yb,,), (2)


Q = heat input, Btu/hr.

AT = increase in temperature, “F,

90 = oil flow rate, B/D,

9 1, = water flow rate, B/D,

Yo = specific gravity of oil, and

Yn = specific gravity of water.

Chemical Demulsifiers

Certain chemical compounds are widely used to destabi- lize and to assist in coalescence of crude oil emulsions. These are referred to as dehydration chemicals or demul- sifiers. This treatment method is popular because the

50 70 80 110 130 150


Fig. 19.15-Percent loss by volume vs. temperature for crude oil.

chemicals are easily applied to the emulsion, usually are reasonable in cost, and usually minimize the amount of heat and settling time required.

The chemical counteracts the emulsifying agent, allow- ing the dispersed droplets of the emulsion to coalesce into larger drops and settle out of the matrix. For demulsifi- ers to work, they must (1) be injected into the emulsion, (2) intimately mix with the emulsion and migrate to all of the protective films surrounding all of the dispersed droplets, and (3) displace or nullify the effect of the emul- sifying agent at the interface. A period of continued moderate agitation of the treated emulsion to produce con- tact between and coalescence of the dispersed droplets and a quiet settling period must exist to allow separation of the oil and water.

Four actions are required of a chemical demulsifier. Strong attraction to the oil/warer interjace. The demul-

sifier must have ability to migrate rapidly through the oil phase to reach the droplet interface where it must coun- teract 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 look like bunches of fish eggs under a microscope.

Coalescence. After flocculation, the emulsifier film is still continuous. If the emulsifier is weak, the floccula- tion force may be enough to cause coalescence. This is not true in most cases, and the demulsifier must there- fore neutralize the emulsifier and promote rupture of the droplet interface film. This allows coalescence to occur. With the emulsion in a flocculated condition, the film rup- ture results in growth of water drop size.

Solids Wetting. Iron sulfides, clays, and drilling muds can be made water-wet, causing them to leave the inter- face and be diffused into the water droplets. Paraffins and


asphaltenes can be dissolved or altered by the demulsitier to make their films less viscous, or they can be made oil- wet so that they will be dispersed in the oil.

The demulsifier selection should be made with all func- tions 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 sys- tem is an electrostatic process, where some of the floc- culation and coalescing action is accomplished by the electric field, there is need for a quick-acting demulsifi- er. Time for demulsifier action in a vertical emulsion treat- er normally will be somewhere between that of a settling tank and that of an electrostatic treater.

As field conditions change and/or the treating process is modified, the chemical requirements may change. Seasonal changes may cause paraffin-induced emulsion problems. Well workovers may change solids content, which may alter emulsion stability. So no matter how satisfactory a demulsifier is, it cannot be assumed that it will always be satisfactory over the life of the field.

While the first commercial emulsion-treating chemical was a solution of soap, present-day chemicals are based on highly sophisticated materials. Chemical emulsion breakers are complex organic compounds with surface- active characteristics. The active properties may be de- rived from any one or a combination of nonionic, cation- ic, and anionic materials. Within each of these types, compositions are used that will confer various degrees of hydrophobeihydrophile balance to the chemical as desired. The active components are highly viscous and sometimes even solids. It is necessary to use a carrier that will make handling easier: this carrier is almost without exception an organic solvent. Solvent systems are designed to make emulsion breakers compatible with the crude oil system in which they are used. It is also necessary to omit mate- rials that will interfere with refining processes, such as those that will poison catalysts. Therefore, no organic chlorides, bromides, iodides, fluorides, or compounds of arsenic or lead are used in the manufacture of most emulsion-treating chemicals.

There is no simple designation of specific chemicals to treat specific emulsions. There are, however, certain com- mon demulsifier types that tend to produce a consistent reaction in many water-in-oil emulsions. Some of the demulsifier types are as follows.

Pol~~lvcc~l esters are characterized by quick brightening of emulsjons. but frequently tend toward slow water drop and sludging; they are subject to overtreating problems.

Lo~r,-lnolrculrrr-~~‘~~i~~~t resin derivatives tend toward rapid water drop and fair to good overall demulsification properties; they show some tendency toward overtreat- ment in high-API-gravity emulsions.

High-molecular-weight resin derivatives generally have a strong wetting tendency and fair brightening and water- drop characteristics; they are always used in combination with other materials.

Sulfonates exhibit fair to good wetting and water-drop performance, some ability to brighten oil, and very little tendency to overtreat, particularly in high-gravity emulsions.

Polymerized oils and esters produce specific character- istics on particular emulsions; they are generally poor for widespread application and are always used in combina- tion with other materials.

Alkanolamine condensates promote water drop in some emulsions and may produce some brightening; they are blended with other materials for overall good per- formance.

Oxyalkylatedphenols are predominantly wetting agents with fair to poor demulsification properties; they are used in blending to improve demulsifier performance.

Polyamine derivatives produce good brightening char- acteristics and are good blending agents; they are rela- tively poor in other respects.

There are many specific variations within each of these broad categories. Most demulsifiers used in breaking crude oil emulsions are blends of the above and other com- pounds. The components selected for a given demulsifier are chosen to provide the necessary actions to achieve complete emulsion treatment. The number of different surface-active materials that can act as emulsifiers in crude oil is large. The possible combinations of these emulsify- ing agents is almost infinite. Therefore, the number of demulsifiers and their combinations must likewise be numerous to treat the emulsions. The type and composi- tion of the crude oil in the emulsion being treated has more influence on how a certain chemical demulsifier will per- form than does the specific category of components in- cluded in the treating chemical. For example, a low-molecular-weight resin used in treating an emulsion of 35”API oil may exhibit rapid water drop, but that same chemical, when used in treating an emulsion of I5”API oil, may not cause rapid water drop. This illustrates that demulsifying chemicals must be compounded for each par- ticular emulsion.

Each treating system must be tested and checked to en- sure that the chemicals used for treating the water for dis- posal do not conflict with chemicals used for treating the oil emulsion. One chemical must not react with the other to cause problems, such as stabilizing the oil in the water. Compatibility of the two chemicals must be tested by bottle tests and then by field tests in the actual treating system. Also, compatibility tests should be performed for any other chemicals added to the produced fluids.

Selection of the optimum chemical to use usually starts with bottle tests. A representative sample of fluid is taken and transferred into several test bottles. Several demul- sifying chemicals are added to the test bottles in various amounts to determine which chemical will best break the emulsion. Additional tests are made to determine the op- timum ratio of chemical to fluid. Several series of tests may be necessary at various ratios and temperatures before a selection can be made. Many factors-such as the color and appearance of the oil, clarity of the water, interface quality, required operating temperature, settling time, and BS&W content-are observed during these bottle tests.

Bottle tests can be made with the samples of emulsion taken at the wellhead. anywhere in the flowline, at the manifold, or at the entrance to the treating system or tank. Well-equipped mobile laboratories are available, so this type of work can be done in the field. These mobile units should be operated by trained technicians who can minimize testing and optimize selection of chemical demulsifiers.

After the bottle tests are made and the best two or three chemicals have been selected, they should be field tested in the treating system to verify that the best chemicals have been selected. Tests should be made in the treating sys-









Fig. 19.16-Chemical distributor for flowlines 10 in. and larger

tern at various concentrations, operating temperatures, settling times, degrees of mixing, etc., before the final selection is made on the basis of performance and cost. The optimum chemical is one that will provide the clearest, cleanest separation of water from oil at the lowest temperature in the shortest time at the lowest cost per bar- rel treated and that will not interfere with subsequent deoil- ing of the water.

The required concentration of demulsifying chemical may be as high as 8 gal/l,000 bbl (about 200 ppm) or as low as 1 ga1/5,000 bbl (about 5 .O ppm). This is a range of 40 to 1. The most common range of chemical injec- tion is between 10 and 60 ppm.

Application of heat to an emulsion after a demulsifier has been mixed with it increases effectiveness of the chem- ical by reducing the viscosity of the emulsion and facilitat- ing more intimate mixing of chemical with emulsion. Chemical reaction at the oil/water interface takes place at a more rapid rate at higher temperatures.

The point of injection of demulsifier chemical into the emulsion is important. The chemical should be injected into the emulsion and mixed with it so that it is evenly and intimately distributed throughout the emulsion when it is heated, coalesced, and settled in the treating system. The demulsifying chemical should be injected in a con- tinuous stream, with the chemical volume directly propor- tional to the emulsion volume. Certain demulsifiers should

not be present in the emulsion during excessively pro- longed agitation because the beneficial effect of the demul- sifier may be spent or counteracted by the agitation and re-emulsification may occur.

Turbulence accelerates the diffusion of the demulsifier throughout the emulsion and increases the number and intensity of impacts between water droplets. Turbulence must be prolonged for a sufficient time to permit the chem- ical to reach the interface between the oil and all the dis- persed 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 that disperses the water in the oil and is a prerequisite

to emulsion formation. A moderate level of controlled tur- bulence, however, causes the dispersed droplets to col- lide 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.

One way of assisting in dispersing the chemical through- out the entire volume of emulsion is to mix a small volume of chemical with a diluenr and then to inject and mix the diluted chemical with the emulsion. The larger volume of the mixture may make it possible for the chemical to be more uniformly and intimately mixed with the emulsion.

When flow rates are low (less than 3 ft/sec) or when laminar flow is encountered, the injection of chemical into a coupling welded in the side of the pipe is not recom- mended. In such cases, an injection quill (which injects the chemical in the stream at a location removed from the wall), a chemical distributor (Fig. 19.16), and/or a kinetic mixer (Fig. 19.17) is recommended. The kinetic mixer consists of a series of staggered, helically convolut- ed vanes that use the velocity of the fluid to accomplish mixing.

When a tank of wet oil (oil containing more than the permissible amount of water) accumulates, the tank con- tents can be treated by adding a small proportion of demul- sifier, agitating or circulating the tank contents, and then allowing time for the water to settle in the tank. Trailer- mounted units that include a heater, circulating pump, and chemical injector are sometimes used for this method of tank treating. This batch-treatment method normally is used as an emergency measure.

Excessive amounts of treating chemical can result in increased stability of the water-in-oil emulsion or of the oil-in-water emulsion in the produced water, increase the stability or the volume of the interfacial emulsion and/or sludge, or waste money equal to the cost of the excessive volume of chemical over the optimum volume. Also, the cost of handling and injecting the excessive amount of chemical must be considered along with the purchase cost of the chemical. Insufficient treating chemical can fail to








Fig. 19.17—Kinetic (static) mixer for mixing chemical demulsifi-er with emulsion.

break the emulsion; allow a quick buildup of excessiveamounts of emulsion and/or sludge; and result in a needfor excessive heat to break the emulsion, a need for ex-cessive settling time to resolve the emulsion, reduced ca-pacity of the treating equipment, excessive waterremaining in the crude oil causing accumulation of un-salable oil and the resultant cost of retreating the crude,or more difficulty in removing oil from the producedwater.

AgitationAgitation or turbulence is necessary to form a crude oilemulsion. When turbulence is controlled, however, it canassist in resolving the emulsion. Agitation causes in-creased collisions of dispersed particles of water and in-creases the probability that they will coalesce and settlefrom the emulsion. Caution should be exercised to pre-vent excessive agitation that will result in further emul-sification instead of resolving the emulsion. If theturbulence is kept to moderate Reynolds numbers of50,000 to 100,000, good coalescing conditions usuallyshould be achieved.


S . P . P A C K T A N K






F R E E - F L O W C O A L E S C E N C E

Fig. 19.18—The S. P. Pack’” grows a larger drop size on thinlet separator of a gravity settler.

The flow of emulsions at moderate Reynolds numberthrough long pipelines has been shown to cause coalescence and develop droplets that exceed 1,000 µm in diameter. The length of the pipeline required to obtaicoalescence can be dramatically decreased by using a defined flow path as in the special flow coalescing devicshown in Fig. 19.18.

The demulsification process may be assisted by the useof baffle plates placed inside the treating vessel. Properlydesigned and located baffle plates can evenly distributemulsion in a vessel and cause gentle agitation that maybring about collisions of dispersed water particles to aidin coalescing the droplets. Excessive baffling should bavoided because it can cause excessive turbulence, whichmay result in increased emulsification and impede waterdroplet settling. Special baffling in the form of perforated plates properly placed inside treating vessels affordsurfaces upon which water droplets in the emulsion maycoalesce. As the emulsion flows through the perforationsslight agitation in the form of eddy currents is createdcausing coalescence. If the perforations are too smallhowever, shearing of the water droplets can occur, resulting in a tighter emulsion.


Other designs of baffle plates provide coalescing sur-faces for the water droplets, as shown in Fig. 19.19. Flowthrough the plates is laminar, but directional changes en-able the water droplets to contact the plates and coalesce.Such a device may plug easily and become inoperablequickly.

Electrostatic CoalescingThe small water drops dispersed in the crude oil can becoalesced by subjecting the water-in-oil emulsion to ahigh-voltage electrical field. When a nonconductive liq-uid (oil) containing a dispersed conductive liquid (water)is subjected to an electrostatic field, the conductive parti-cles or droplets are caused to combine by one of threephysical phenomena.

1. The water droplets become polarized and tend toalign themselves with the lines of electric force. In sodoing, the positive and negative poles of the droplets arebrought adjacent to each other. Electrical attraction bringsthe droplets together and causes them to coalesce.

2. The water droplets are attracted to an electrode be-cause of an induced electric charge. In an AC field, be-‘cause of inertia, small droplets vibrate a greater distancethan larger droplets, promoting coalescence. In a DCfield, the droplets tend to collect on the electrodes, form-ing larger and larger droplets until eventually they settleby gravity.

3. The electric field tends to distort and thus to weakenthe film of emulsifier surrounding the water droplets.Water droplets dispersed in oil subjected to a sinusoidalalternating-current field will be elongated along the linesof force as voltage rises during the first half-cycle. Asthey are relaxed during the low-voltage portion, the sur-face tension pulls the droplets back toward sphericalshape. The same effect is obtained in the next half of thealternating cycle. The weakened film is thus more easilybroken when droplets collide.

Whatever the actual mechanism, the electrical fieldcauses the droplets to move about rapidly in random direc-tions, which increases the chances of collision with otherdroplets. When droplets collide with the proper velocity,coalescence occurs. The greater the voltage gradient, thegreater the forces causing coalescence. Experimental datashow, however, that at some voltage gradient, the waterdroplet can be pulled apart and a tighter emulsion can re-sult. For this reason, electrostatic treaters normally areequipped with a mechanism for adjusting the voltage gra-dient in the field.

If the quantity of water in the oil is large there is a ten-dency for the formation of a chain of charged water par-ticles, which may form links between the two electrodes,causing short-circuiting. This is referred to as “chaining”and has been observed in emulsions containing 4% or lesswater. The short-circuit releases a burst of electrical ener-gy that immediately causes this chain of water particlesto become steam. The resulting explosions sound like pop-ping popcorn. If chaining occurs, the voltage gradient istoo large (i.e., the electrical grids of the electrostatic treat-er are too close together or the voltage is too high) forthe amount of water being handled. Small amounts of gasbreaking out of solution may also create sufficient turbu-lence and impede the coalescing process.

Water-WashingIn some emulsion-treating vessels, separation of liquids

Fig. 19.19—Performax TM plate pack, a special coalescingmedium for crude oil emulsions.

and vapors takes place in the inlet diverter, flume, or gasboot located at the top of the vessel. The liquid flows bygravity to the bottom of the vessel through a large con-ductor pipe or conduit. A spreader plate on the lower endof the conduit spreads the emulsion into many smallstreams or rivulets that move upward through the water,accomplishing a water-wash. After the emulsion haspassed through the water-wash, it flows to the upper por-tion of the vessel, where the coalesced water droplets settleout of the oil by gravity separation.

If an emulsion is flowed through an excess of the inter-nal phase of the emulsion, the droplets of the internalphase will tend to coalesce with the excess of the internalphase and thus be removed from the continuous phase.This is the principle on which a water-wash operates. Thewater-wash is more beneficial if the emulsion has beendestabilized by addition of a demulsifier and if the wateris heated. The effectiveness of a water-wash greatly de-pends on the ability of the spreader plate or distributorto divide the emulsion into small streams or rivulets andto cause the emulsion to be in maximum intimate contactwith the water bath so that the small drops of water cancoalesce with the water.

If an-emulsion-treating system or unit uses a water-wash, it can be charged with water to facilitate initial op-eration. Water from the emulsion to be treated should beused if available. If it is not available, extraneous watermay be used.



A filtering material with the proper size of pore spaces and the proper ratio of pore spaces to total area can be used to filter out the dispersed water droplets of a crude oil emulsion by preferentially wetting the filtering mate- rial with oil and keeping it submerged in oil. When used in this manner, the pack is correctly called a “filter” be- cause it filters out the liquid that it prevents from passing through.

When excelsior is used as a filter in an emulsion treat- er, it is immersed in oil above the oil/water interface lev- el, Excelsior is preferentially wetted by water because of the high affinity the cellulose fibers have for water. If the excelsior is initially wetted by oil, however. the dispersed water droplets in the oil will not normally take posses- sion of the excelsior fibers because the fibers are saturated with oil. If the water droplets do take possession of the excelsior fibers, possession will occur at a slow rate and penetration of the pack by the water will be only partially complete.

Excelsior is wood that is cut into small shreds or fibers. Observed under a microscope, the surfaces of each strand of excelsior bristle with tiny sharp barbs. When emul- sion flows through an excelsior pack, these rough sur- faces cause distortion of the film surrounding the water droplets, thereby encouraging adherence of the droplets to the strands of excelsior. This results in coalescence of the water droplets into drops large enough to settle out of the oil. Excelsior should be made from pitch-free woods. such as aspen, cottonwood, or poplar. Pine ex- celsior is not recommended for crude oil emulsion-treating purposes. Excelsior should be used at less than 180°F treating temperature. Higher temperature will delignify and deteriorate the excelsior. It will also make it difficult to remove from the vessel.

Glass wool and other porous materials have been used as filtering material. Glass wool. when the fibers are prop- erly sized and compacted, can serve as a filtering materi- al for filtering water droplets out of a crude oil emulsion. If the glass wool is coated with silicone, its filtering ef- fect will be enhanced because the silicone-coated fibers will be more wettable by oil than untreated glass wool fibers. Glass wool is not widely used for filtering because of its initial expense and its fouling problems.

Porous materials, both plastics and metals, are availa- ble that will filter dispersed water droplets from a crude oil emulsion. These porous materials are not widely used because of the difficulty of obtaining and maintaining the proper size pores and because they easily foul and be- come inoperable.

Treating crude oil emulsions by filtering is not widely used because of the difficulty in obtaining and maintain- ing the desired filtering effect and because the filtering material is easily plugged by foreign material.

Fibrous Packing

Fibrous coalescing packs are not commonly used in oil treating. They are mentioned for completeness and to differentiate between filtering and coalescence. A coales- cing pack is a section or compartment in an emulsion- treating tank or vessel that is packed with a material that is wetted by the water, causing the water to coalesce into larger drops. Separation of two emulsified liquids by use

of a coalescing pack operates on the principle that two immiscible liquids with different surface tensions cannot simultaneously take possession of a given surface. The coalescing pack is wetted with or submerged in water. When the dispersed droplets of water come in contact with the water-wet coalescing material. the water droplets coalesce and adhere to the coalescing surfaces. Oil will pass through the pore spaces of the coalescing material. Separation of the two liquids in a coalescing pack is not caused by filtering but by the greater affinity of the water- wet coalescing material for the water droplets.

The film of oil containing the emulsifying agent sur- rounding the dispersed water particles must be broken be- fore these droplets will adhere to a coalescing medium. The film is broken with the aid of demulsifying chemicals and/or heat and by repeated contact between the water particles and the surface of the coalescing materials as the emulsion flows through the pack. When this film has been broken, the water particles adhere to the surface of the coalescing material until they combine into drops large enough to settle out of the oil.

Glass wool can be used as coalescing material in emulsion-treating vessels. It will not deteriorate like wood excelsior and will prolong the service life of the coales- cing pack. Glass wool fouls rather easily and may cause channeling. Woven wire mesh can also be used but tends to be more expensive than glass wool.

Gravity Settling

Gravity settling is the oldest, simplest, and most widely used method of treating crude oil emulsions. The differ- ence in density of the oil and water causes the water to settle through and out of the oil. Because the water droplets are heavier than the volume of oil they displace, they have a downward gravitational force exerted on them. This force is resisted by a drag force caused by their down- ward movement through the oil. When the two forces are equal, a constant velocity is reached that can be comput- ed from Stokes’ law as

I .78 x 10 -6(A~CIM.)d2 )> = ) . . . . . . . . .

PL, (3)

where v=


AY o,,‘ =

downward velocity of the water droplet

relative to the oil, ft/sec,

diameter of the water droplet, pm. difference in specific gravity between the

oil and water, and

CL, - dynamic viscosity of the oil, cp.

Several conclusions can be drawn from this equation. 1. The larger the size of a water droplet, the greater

its downward velocity-i.e., the bigger the droplet size, the less time it takes for the droplet to settle to the bottom of the vessel, and thus the easier it is to treat the oil.

2. The greater the difference in density between the water droplet and the oil, the greater the downward velocity-i.e., the lighter the oil, the easier it is to treat the oil. If the oil gravity were lO”AP1 and the water fresh, the settling velocity would be zero because there is no gravity difference.


3. The higher the temperature, the lower the viscosity of the oil, and thus the greater the downward velocity of the water droplets-i .e., it is easier to treat the oil at high temperatures than at low temperatures (assuming a small effect on gravity difference because of increased tem- perature).

Gravity settling alone can be used to treat only loose, unstable emulsions. When other treating methods destabi- lize the emulsion and create coalescence, which increases water droplet size, however, gravity settling provides separation of water from oil.

Retention Time

In a gravity settler, such as an oil-treating tank or the coalescing section of an oil-treating vessel, coalescence will occur. Because of the small forces at work, however, the rate of contact between water droplets is small and coalescence seldom occurs immediately when two droplets collide. Thus the process of coalescence, although it will occur with time, follows a steep exponential curve where successive doubling of retention time results in small in- cremental increases in droplet size.

The addition of retention time alone, after some small amount necessary for initial coalescence. may not signif- icantly affect the size of the water droplet that must be separated by gravity to meet the desired oil quality. A taller tank will increase the retention time but will not decrease the upward velocity of the oil or may not signif- icantly increase the size of the water drop that must be separated from the oil. Thus the additional retention time gained by the taller tank may not materially affect the water content of the outlet oil.

A larger-diameter tank will increase the retention time. More important, it will slow the upward velocity of the oil and thus allow smaller droplets of water to settle out by gravity. In this case, it may not have been the increase in retention time that improved the oil quality but rather the reduction in flow velocity, which decreased the size of the water droplets that can be separated from the oil by gravity.


Because of the difference in density between oil and water. centrifugal force can be used to break an emulsion and separate it into oil and water. Small centrifuges are used to determine the BS&W content of crude oil emulsion samples. A few centrifuges have been installed in the oil field to process emulsions. They have not been widely used for treating emulsions, however, because of high in- itial cost, high operating cost. low capacity, and a ten- dency to foul.


Distillation can be used to remove water from crude oil emulsions. The water, along with lighter oil fractions, can be distilled by heating and then separated by appropriate means. The lighter oil fractions are usually returned to the crude oil.

The only current use of distillation is in the “flash sys- tem” used in 15”API and lower oil. These systems use the excess heat in the oil received from the treater or treat- ing system and convert this sensible heat to latent heat at or near atmospheric pressure. The flashed steam is con- densed in a surface condenser in the incoming cooler

stream of raw crude. thus scavenging the excess heat that would ordinarily be wasted. Fig. 19.20 shows a typical flash distillation system for dehydrating emulsions of heavy viscous crude oils.

The disadvantage of distillation is that it is expensive and that all the dissolved and suspended solids contained in the water are left in the oil when the water is removed by evaporation.

Emulsion-Treating Equipment and Systems The design of equipment or a system for treating crude oil emulsions and the sizing of each piece of equipment for a specific application requires experience and engi- neering judgment. It would be ideal if a procedure existed that would permit the engineer to infer from measured properties of the emulsion the most economical treating process, taking into account treating temperature, chem- ical usage, and physical size of treating equipment. Un- fortunately, such a procedure is not available and the engineer must rely on experience and empirical data from other wells or fields in the area and on laboratory ex- periments.

For example, the economic balance between the amount of chemical and heat to use to destabilize the emulsion and aid in coalescence is difficult to predict. Almost all emulsion-treating systems use demulsifying chemicals. In most instances, the lower the treating temperature, the greater the amount of chemical required to treat the emul- sion. In many areas of west Texas and the Gulf of Mexico, some operators do not add heat to treat the relatively light crudes that are produced. Other operators under the same conditions add heat when treating similar crudes to minimize chemical cost and the size of the emulsion- treating equipment.

Another example is the economic balance that must be considered between those factors that promote coalescence (chemicals, water wash, heat, coalescing plates, etc.) and the size of the treating vessels. The larger the size of the treating vessel, the smaller the size of water droplets that can be separated from the emulsion. Thus the use of coalescing aids may reduce the size of the equipment by increasing the size of the water droplet that must be sepa- rated from the oil to meet the required quality. The sav- ings in vessel costs must be balanced against the increased capital and operating cost (e.g., fuel and increased main- tenance because of plugging) of the coalescing aids.

Bottle tests in the laboratory provide a means for es- timating ranges of treating temperature and retention time for design purposes. Unfortunately, these tests are static in nature and do not model closely the dynamic effects of water droplet dispersion and coalescence that occur in the actual equipment because of flow through control valves, pipes, inlet diverters, baffles, and water-wash sections. Bottle tests, however, can be useful in estimat- ing treating parameters such as temperature, demulsifier volume, settling time, etc.

When evaluating empirical data from similar wells or fields, the designer should recognize that the temperature at which an emulsion is treated may not be as critical as the viscosity of the crude at that temperature. The design of an oil-treating system can be assisted by observing an existing system, knowing the viscosity of the crude at treating temperature, and calculating from the flow gem ometry and Stokes’ law the minimum size water droplet



150 to 18OOF Production Inlet 15 to 30% cut TEMPERATURE OF SHELL SIDE







1 I

-I 1 j-+ WATER


Fig. 19.20-Typical flash distillation system for dehydrating emulsions of heavy viscous crude oils

that can be settled from the crude. A treating system can then be designed that will heat the emulsion to the tem- perature required to obtain the same viscosity that exists in the sample field, and then any one of the pieces of equipment or combinations thereof described in the next section can be selected and sized so that all water droplets larger than the calculated minimum diameter can be sepa- rated from the oil.

Because of the uncertainties in attempting to scale up from laboratory data or to infer designs from empirical data from similar wells or fields, a new treating system should be designed with either larger equipment or more heat input capacity than the engineer calculates to be nec- essary. The amount of “overdesign” to be built into the treating system depends on an assessment of the cost of the extra capacity balanced against the risk of not being able to treat the design throughput.

Description of Equipment Used in Treating Crude Oil Emulsions The characteristics of the emulsion to be treated should be understood before a treating system is selected. Several different types of equipment or systems may satisfactorily resolve an emulsion, but one particular type of equipment or system may be superior to others because of basic con- siderations in design, operation, initial cost, maintenance

cost, operating cost, and performance. Effort should be made to select the minimum number of pieces of equip- ment or the simplest design for each treating system to optimize initial and operating costs.

The combination of the various emulsion-treating methods that will provide the lowest use of chemical, lowest treating temperature, lowest loss of light hydrocar- bons, lowest overall treating cost, and the best perform- ance should be used. Experience and empirical data may guide the buyer to the optimum combination of treating methods, but field testing will be required to confirm the selection.

The following discussion describes various emulsion- treating equipment and systems. Each piece of treating equipment and each treating system affords a wide selec- tion of the type, configuration, size, component selection, component design, and usage. Additional treating equip- ment can usually be added to each unit or system until the desired treating results are obtained. The design and selection of all the components of the treating system should be made at the time of initial purchase and instal- lation. Because of the modular design of most systems, however, if the selected equipment does not perform as desired or if operating conditions change, additional fea- tures can usually be added or operating procedures altered to obtain the desired results.



Fig. 19.21-Typical vertical FWKO

Free Water Knockouts

Where large quantities of water are produced, it usually is desirable to separate the free water before attempting to treat the emulsion. When oil and water are agitated with moderate intensity and then allowed to settle for a period of time, three distinct phases normally will form: a layer of essentially clean oil at the top with a small amount of water dispersed in the oil in very small droplets, relatively clean water (free water) at the bottom with a small amount of dispersed oil in very small droplets, and an emulsion phase in between. With time, the amount of emulsion will approach zero as coalescence occurs.

The free water is the water that separates in 3 to 10 minutes. It may contain small droplets of dispersed oil that may require treament before disposal. Equipment to do this is discussed in Chap. 15.

Free-water knockouts (FWKO’s) are designed as either horizontal or vertical pressure vessels. Fig. 19.21 is a schematic of a vertical FWKO. and Fig. 19.22 shows a horizontal FWKO. The fluid enters the vessel and flows against an inlet diverter. This sudden change in momen- tum causes an initial separation of liquid and gas, which will prevent the gas from disturbing the settling section of the vessel. In some designs, the separating section con- tains a downcomer that directs the liquid flow below the oil/water interface to aid in water-washing the emulsion.

The liquid-collecting section of the vessel provides suffi- cient time for the oil and emulsion to form a layer of oil at the top, while the free water settles to the bottom. When there is appreciable gas in the inlet stream, a three-phase

separator can be used as an FWKO. See Chap. 12 for a description of both vertical and horizontal three-phase separators.

Sometimes a cone-bottom vertical three-phase separa- tor is used. This design is used if sand production is an- ticipated to be a major problem. The cone is normally at an angle to the horizontal of between 45 and 60”. If a cone is used. it can be the bottom head of the vessel, or for structural reasons, it can be installed internally in the vessel. In such a case. a gas-equalizing line must be installed to ensure that the vapor behind the cone is al- ways in pressure equilibrium with the interior of the ves- sel. Water jets can be used to dislodge and flush the sand from the vessel.

Oil and water are usually separated more quickly and completely in an FWKO when the liquid travels through the vessel in a horizontal rather than a vertical direction. Horizontal flow permits a less restricted downward move- ment of the water droplets. If the emulsion flows verti- cally upward, the water must move downward through an upward-moving stream; therefore, the downward movement of water is retarded by upward movement of the oil and emulsion.







Fig. 19.22-Typical horizontal FWKO.

It is possible to add a heating tube to an FWKO, as shown in Fig. 19.23, or to add heat upstream of the FWKO. In such cases, even though the vessel may be called an FWKO, it is performing the function of an emul- sion treater.

Many configurations are possible for providing baffles and maintaining levels in an FWKO. A good design will provide the functions described previously, i.e., degass- ing, water-washing, and providing sufficient retention time and correct flow pattern so that free water will be removed from the emulsion.

When the free water is removed, it may or may not be necessary to treat the oil further. In many fields producing light oil, a well-designed FWKO with ample settling time and with a reasonable chemical-treating program can pro- vide pipeline-quality oil. Most often, however, further emulsion treating is required downstream of the FWKO.

Storage Tanks

Oil generally should be water-free before it is flowed into lease storage tanks. If there is only a small percentage of water in the oil and/or if the water and oil are loosely emulsified, however, it may be practical to allow the water to settle to the bottom of the oil storage tank and to draw off the water before oil shipment. This practice is not generally recommended or followed. but for small volumes of free or loosely emulsified water on small leases or for low-volume marginal wells, it may be a practical and economical procedure.

When a storage tank is used for dehydration, the oil is flowed into the tank and allowed to settle. When the tank is full of liquid, flow into the tank is stopped or

switched to another tank and the tank is allowed to re- main idle while water settles out of the oil. After the water has been separated from the oil by settling, water is drained from the bottom of the tank and the oil is gauged, sampled, and pumped or drained to a truck or pipeline. No water-wash is used in conjunction with the standard storage tank. If there is a water-wash, its shallowness and the absence of a proper spreader causes it to be of little or no benefit.

Settling Tanks

Various names are given to settling tanks used to treat oil. Some of the most common are gunbarrels, wash tanks, and dehydration tanks. The design of these tanks differs in detail from field to field and company to company. All contain all or most of the basic elements shown in Fig. 19.24.

The emulsion enters a gas separation chamber or gas boot where a momentum change causes separation of gas. Gas boots can be as simple as the piece of pipe shown in Fig. 19.24, or they can contain more elaborate nozzles, packing, or baffles to help separate the gas. If there is much gas in the well stream, it is usually preferable to use a two- or three-phase separator upstream of the settling tank. In this case, the gas boot must separate only the gas that is liberated as the pressure decreases during flow from the separator to the settling tank.

A downcomer directs the emulsion below the oil/water interface to the water-wash section. On most large tanks, a spreader is used to distribute the flow over the entire cross section of the tank. This minimizes short-circuiting. The more the upward-flowing emulsion spreads out and






Fig. 19.23--Schematic view of FWKO with heating element in each end

approaches plug (or uniform) flow, the slower its aver- age upward velocity and the smaller the water droplets that will settle out of the emulsion.

There are many types of spreader designs. Spreaders can be made by cutting slots in plate, use of angle iron, or holes in pipe. By causing the emulsion stream to separate into many small streams, the spreader causes a more intimate contact with the water to help promote coalescence in the water-wash section. This is shown in Figs. 19.25 and 19.26. Most spreaders contain small holes or slots to divide the oil and emulsion into small streams. Large holes (3 to 4 in. in diameter) will not be nearly as effective in dividing the stream as small holes (‘/8 to 1 in. in diameter). In designing a spreader, however, it is im- portant that the fluid is not agitated to the point where shearing of the water droplets in the emulsion takes place, causing the emulsion to become harder to separate. In ad- dition, small holes can be more easily plugged with solids and are difficult to clean. Free-flow coalescing devices, such as S.P. Packs TM (Fig. 19.18), can be installed on the downcomer/spreader to promote coalescence and to minimize shearing of the water droplets by the spreader.

As the emulsion rises above the oil/water interface, water droplets settle from the oil countercurrent to the flow of the oil by gravity. Because there may be very lit- tle coalescence above the oil/water interface, increasing the height of the oil-settling section above some minimum to aid in spreading out the flow may not materially affect the oil outlet quality.






Fig. 19.24-Typical settling tank with internal downcomer and emulsion spreader.




Fig. 19.25-Proper design of well fluid inlet distributor for wash or gunbarrel tank showing use of small holes in dls- tributor.

Sometimes oil collectors similar in design to oil spread- ers are used to aid in establishing plug flow. The oil col- lector must not allow vortexing and should collect oil from the top of the tank in such a way that horizontal move- ment of the oil will be minimized.

Some tanks discharge the water through a water col- lector designed to cause the flow of water to approach plug flow conditions more nearly. The water outlet col- lector must prevent vortexing of the water and must minimize horizontal movement of the water. The water outlet collector should be located near the tank bottom. There must be enough vertical distance between it and the inlet spreader to allow sufficient clarification of the water, and it should be at least 6 to 12 in. above the tank bottom to allow for accumulation of sand.

Some tanks have elaborate sand-jetting and drain sys- tems that may or may not be part of the water-collector system. It may be difficult to make these drains operate satisfactorily because the water flow to each drain must be on the order of 3 ft/sec to suspend the sand. Sand drains may lengthen the amount of time between tank cleanings, but the additional cost of sand drains in tanks may not be warranted.

In Fig. 19.24, the oil/water interface is established by an external adjustable weir sometimes called a water leg. The height of the interface is determined by the differ- ence in height of the oil outlet and weir and the fluid prop- erties. It may be calculated from


Fig. 19.26~Improper design of well fluid inlet for wash or gun- barrel tank.

where hM.d = height of water-draw-off overflow nipple in

weir box above tank bottom, ft,

h 01, = height of clean oil outlet above tank

bottom, ft, h M'W = desired height of water-wash in tank above

tank bottom, ft,

Yo = specific gravity of oil, and

Y II = specific gravity of water.

Water legs are used successfully for emulsions where the gravity is above 20”API and there is sufficient differ- ence in gravity between the oil and water. Marginal per- formance is obtained on oil between 15 and 20”API. Below lS”API, water legs normally are not used.

It is also common to control the oil/water interface with internal weirs or with an interface liquid-level controller and a water-dump valve. In heavy oils, electronic probes are most often used to sense the interface and operate a water-dump valve. In lighter oils, floats that sink in the oil and float in the water are more common.

Not all settling tanks contain all the sections and de- sign details described previously. The choice depends on

the overall process selected for the facility, emulsion prop- erties, flow rates, and desired effluent qualities. While Fig. 19.24 is representative of the majority of settling tanks currently in use, other tanks have a different flow pattern. A series of parallel vertical baffles from the bot- tom of the vertical tank to above the oil level, as shown in Fig. 19.27, cause the flow of the emulsion to be


stallations. When settling tanks are heated directly, they operate

in much the same manner as vertical or horizontal emul- sion treaters.

horizontal rather than vertical. With this type of flow path, the water droplets fall at right angles to the oil flow, rather than countercurrent to the oil flow. Some settling tank designs employ a vortex or swirling motion at the inlet of the tank to aid in coalescence and settling and to minimize short-circuiting. Many settling tanks employ heat to aid in the treatment process. Heat can be added to the liquid by an indirect heater, a direct heater, or any type of heat exchanger.

A direct fired heater, sometimes referred to as a “jug*’ heater, is one in which the fluid to be heated comes in direct contact with the immersion-type heating tube or ele- ment of the heater. Direct fired heaters are generally used

to heat low-pressure noncorrosive liquids. These units normally are constructed so that the heating tube can be removed for cleaning, repair, or replacement.

An indirect fired heater is one in which the fluid passes through pipe coils or tubes immersed in a bath of water, oil, salt, or other heat-transfer medium that, in turn, is heated by an immersion-type heating tube similar to the one used in the direct fired heater. The contents of the bath of an indirect fired heater are caused to circulate by thermosiphonic currents. The immersion-type heating tube heats the bath, which heats the fluid flowing through coils immersed in the bath. When water is used as the bath, water free of impurities will prolong the life of the heater and prevent fouling of the surface of the heating tube and coils.

Indirect fired heaters are less likely to catch on fire than direct fired heaters and generally are used to heat corro- sive or high-pressure fluids. They usually are construct- ed so that the heating tube and pipe coil are individually removable for cleaning and replacement. They tend to be more expensive than direct fired heaters.

Heat exchangers normally are used where waste heat is recovered from an engine, turbine, or other process stream or where fired heaters are prohibited. In complex facilities, especially offshore, a central heat-transfer system recovering waste heat and supplying it through heat exchangers to all process heat demands is sometimes more economical and may be the only way to meet established safety regulations.

Advantages of heating the entire stream of emulsion be- fore it enters the settling tank are as follows.

1. After the fluid is heated, it flows through piping and into the flume pipe or gas boot of the gunbarrel tank. This moderate agitation of the heated fluid can assist in coales- cence of water droplets.

2. The emulsion is heated before it reaches the gunbar- rel. which aids in removing gas from the oil in the gas boot. This helps maintain quiescence in the settling por- tion of the gunbarrel.

3. The heater and gunbarrel can be sized independently, which allows flexibility in sizing the system.

4. Water-wash volume in the gunbarrel can be adjusted over a wide range, providing additional flexibility.

5. Continuous flow of fresh fluids through the heater tends to prevent coking and scaling and helps keep the heating surface clean, which will prolong the heater life.

Heat can also be supplied to the system by circulating the water in the water-wash section to a heater and back to the tank. The hot-water-wash section warms the incom- ing emulsion. A thermosiphon caused by density differ- ences of the hot and the cold water can be used as the


Fig. 19.27-Plan view of vertical tank with horizontal flow settling pattern.

driving force for the circulation if the heat source is not far from the tank. The water also may be pumped to the heater and circulated back through the flume, as shown in Fig. 19.28. In this system, the settling space in the gun-

barrel may be disturbed by gas released from the oil when it comes in contact with the hot water. It has two advan- tages. First, oil will not be overheated because it never comes in contact with the heating element in the heater but is heated by the water bath in the gunbarrel. This minimizes vapor losses from the oil and tends to maintain maximum oil gravity. It also minimizes coking and scal- ing. Second, this system is as safe from fire hazards as a system involving a fired vessel can be because only water flows through the heater. There is no oil or gas in the fired vessel.

Settling or gunbarrel tanks can also be heated directly with a fire tube, as shown in Fig. 19.29, or with internal heat exchangers, using steam or other heat media. Heat exchangers can be either pipe coils or plate-type heating elements.

Plate-type heating elements are usually 18 to 32 in. by about 5 to 8 ft. These usually are preferred over pipe coils because the heat-transfer coefficient is 10 to 20% higher for the plate-type heating elements when immersed in oil than for a corresponding area of pipe. Further, the gentle agitation brought about by the convection flow of the oil up the surface of the plate-type element assists in coales- cence. Plate-type heating elements are available with a wide range of pressure ratings. They can be purchased for steam service or hot-water service, but the same unit should not be used for both because the construction of the cells is different for the two types of heating media.

Pipe coils are popular because of the local availability of materials. The cost is normally slighter higher than for plate-type exchangers, however, especially in larger in-





- a-





Fig. 19.29-Heater and gunbarrel in forced circulation method of heating.










Fig. 19.29-Heated gunbarrel emulsion treater.

Vertical Emulsion Treaters

The most commonly used one-well lease emulsion treat- er is the vertical unit. A typical design is shown in Fig. 19.30. Flow enters near the top of the treater into a gas separation section. This section must have adequate di- mensions to separate the gas from the liquid. If the treat- er is located downstream of a separator, this section can be very small. The gas separation section should have an inlet diverter and a mist extractor.

The liquid flows through a downcomer to the bottom portion of the treater, which serves as an FWKO and water-wash section. If the treater is located downstream of an FWKO, the bottom section can be very small. If the total wellstream is to be treated, this section should be sized for suffkient retention time to allow the free water to settle out. This will minimize the amount of fuel gas needed to heat the liquid rising through the heating section.

The oil and emulsion flows upward around the tire tubes to a coalescing section, where sufficient retention time is provided to allow the small water droplets to coalesce and to settle to the water section. Treated oil flows out the oil outlet. Any gas flashed from the oil because of heating flows through the equalizing line to the gas space above. The oil level is maintained by pneumatic or lever- operated dump valves. The oil/water interface level is con- trolled by an interface controller or an adjustable exter- nal water leg.

It is necessary to prevent steam from being formed on the fire tubes. This can be done by employing the “40” rule”-i.e., the operating pressure is kept equal to the


pressure of saturated steam at a temperature equal to the operating temperature plus 40°F. This is desirable because the normal full-load temperature difference between the fire tube wall and the surrounding oil is approximately 30°F in most treaters. Allowing 10°F for safety, the 40” rule will prevent flashing of steam on the wall of the heat- ing tube.

Baffles and spreader plates may be placed in the coales- cing section of the treater above the fire tubes. Many treat- ers were originally equipped with excelsior or “hay” packs. In most applications these may not be needed, but a manway may be provided in case one may need to be added in the field.

Although Fig. 19.30 shows a treater with a fire tube, it is also possible to use an internal heat exchanger to pro- vide the required heat or to heat the emulsion before it enters the treater. For safety reasons, some offshore oper- ators prefer a heat-transfer fluid and a pipe or plate heat exchanger inside the treater rather than a fire tube.

Horizontal Emulsion Treaters

For most multiwell leases, horizontal treaters normally are preferred. Fig. 19.31 shows a typical design of a horizontal treater. Flow enters the front section of the treater where gas is flashed. The liquid flows downward to near the oil/water interface where the liquid is water- washed and the free water is separated. Oil and emulsion rises past the fire tubes and flows into an oil surge cham- ber The oil/water interface in the inlet section of the ves- sel is controlled by an interface-level controller, which operates a dump valve for the free water.

The oil and emulsion flows through a spreader into the back or coalescing section of the vessel, which is fluid- packed. The spreader distributes the flow evenly through- out the length of this section. Treated oil is collected at the top through a collection device used to maintain uni- form vertical flow of the oil. Coalescing water droplets fall countercurrent to the rising oil. The oil/water inter- face level is maintained by a level controller and dump valve for this section of the vessel.

A level control in the oil surge chamber operates a dump valve on the oil outlet line regulating the flow of oil out the top of the vessel and maintaining a liquid-packed con- dition in the coalescing section. Gas pressure on the oil in the surge section allows the coalescing section to be liquid-packed.

The inlet section must be sized to handle separation of the free water and heating of the oil. The coalescing sec- tion must be sized to provide adequate retention time for coalescence to take place and to allow the coalescing water droplets to settle downward countercurrent to the upward flow of the oil.

Fig. 19.32 shows another design of a horizontal emul- sion treater with a different flow pattern that minimizes vertical flow of the emulsion. Oil, water, and gas enter the top of the treater at the left side (facing the burners) and travel toward the front and downward. Gas remains at the top, and oil and water are heated as required. Some heat is applied to the water in this section, but because this section has its own temperature controller, it can be regulated up or down for optimum performance.

The cross section in Fig. 19.32 shows that the emul- sion flows under a longitudinal baffle and through a large slot in the partition plate near the front of the treater at

Fig. 19.30-Schematic view of typical vertical emulsion treater.

the bottom of the fire tube where it is water-washed. In the right compartment of Section AA, the oil and emulsion flow longitudinally up across the fire tube at about a 10 to 1.5” incline from horizontal.

The heating and settling section separation baffle blocks the passage of foam at the top and blocks emulsion at the bottom. Heated oil travels through a slot in a partition that is about at the centerline of the top fire tube. Free water is allowed to travel under the baffle. As emulsion accumulates at the interface, it rises to touch the tire tube, which is only 6 in. above the interface. The fire tube then tends to heat and eliminate the emulsion pad to maintain a uniform emulsion-pad thickness.

Channeling, skimming, and stratifying are all reduced by the application of louvered baffles, which are made of a stainless steel sheet punched with a louvered pattern that ranges from 15 to 60% open area. The baffles are solid at the top to prevent foaming or skimming and ex- tend down near but do not touch the water. All the emul- sion goes through the louvered openings, which provide a slight impedance to flow to develop even flow distribu- tion and aid in coalescence.

Oil level in the treater is maintained by a weir and an oil box. Water level in the treater is critical; thus a weir is placed approximately 5 ft from the rear head seam, and the oil/water interface level upstream of this weir is main- tained by the weir. Adjustment of the water-level con- troller, which is located downstream of this weir, has no effect on the water level in the main treater body upstream of the weir.

Because the emulsion flow path in this design is essen- tially horizontal, the water particles are not opposed by the velocity of upflowing oil as in a treater with a verti- cal flow pattern. This is especially important in heavy crudes where the differential specific gravity between oil and water is small and the settling velocity is low.





\” f, _- ,-a-OIL OUT

------- ----



+ WATER _r’ ~------

---- WATER - --I









Fig. 19.31-Typical horizontal emulsion treater with vertical flow












Fig. 19.32-Horizontal emulsion treater with horizontal flow.











-- -,- - WATER - - --I









Fig. 19.33-Typical horizontal electrostatic emulsion treater with vertical flow

Other flow patterns are available if different baffle de- signs are used in horizontal treaters. The two described previously are examples to show the concepts that are most generally applied. Other methods of heating the emulsion can be used if it is desirable to eliminate the fire tubes.

Electrostatic Coalescing Treaters

Electrostatic treating can be used in either vertical or horizontal emulsion treaters by including electrical grids in the settling or coalescing sections. Figs. 19.33 and 19.34 show how grids can be installed in the horizontal treaters shown in Figs. 19.31 and 19.32.

Two grids of electrodes typically are installed in elec- trostatic emulsion treaters. One is wired to a source of electric current and the other is grounded. The emulsion flows between these electrodes, which are charged with a very high voltage. The electrodes are installed in the vessel to provide a final stage of coalescence to the emul- sion after it has already been treated to near pipeline qual- ity. In the design of Fig. 19.33, the upflowing oil passes the “hot” electric grid, which is usually steel or stain- less steel rods or bars spaced 4 to 6 in. apart. This grid is stationary and hangs from multiple electric insulators. AC current is wired to this grid from an external single- phase transformer. The “cold” electric grid is mounted directly above the hot grid and is adjustable from 2.5 to 12 in. from the hot grid. The normal operating spacing between the two grids is usually 4 to 6 in.

Coalescing takes place between the oil/water interface and the hot grid, as well as between and above the grids. The oil continues vertically to the outlet collector pipe with

small calibrated holes in the top of the pipe to ensure uni- form distribution. The electric section has no oil/gas in- terface. All gas must be removed in the heating section.

The electric coalescing function in the treater shown in Fig. 19.34 is similar to the horizontal grid unit of Fig. 19.33 except that the vertical grids provide the advantage of the horizontal flow pattern for the emulsion and im- prove the performance of this unit.

In addition to the safety controls normally found on emulsion treaters with fireboxes, there are also low-liquid- level safety switches on the electric treater to avoid the possibility of the electric power being applied when the high-voltage grid is surrounded with gas instead of liquid.

The greater the voltage gradient, the greater the forces causing coalescence. Experimental data show, however, that at some voltage gradient the water droplets can be pulled apart and a tighter emulsion can result. For this reason, electrostatic treaters are normally equipped with a mechanism for adjusting the voltage gradient in the field so that the optimum can be obtained.

The voltage gradient can be changed (1) by selecting optional transformer voltage taps. (2) by adjusting the vol- tage gradient by raising or lowering the oil/water inter face in units using horizontal grids-the water level is. in effect, a grounded electrode against which most of the coalescing takes place; or (3) by adjusting the hot or cold grid location to change the voltage gradient.

The transformer is normally an 18.000- to 20,000-V secondary, single-phase, oil-tilled. 100%reactance-type transformer. It is mounted on the top, side, or end of the treater with a short, high-voltage conduit connected to an


Fig. 19.34-Typical horizontal electrostatic emulsion treater with vertical electric grids for horizontal flow of fluids

appropriate entrance probe assembly. The high-voltage line is entirely submerged in transformer oil, which is nor- mally a highly refined hydrocarbon that has been vacuum dried and contains no moisture.

The application of electrostatic treaters should be limited to “polishing” of oil to avoid chaining and short-circuiting of the grids. They are particularly effective in reducing the water content of oil to very low levels (less than 0.5 to 1 .O%). Electrostatic coalescence may also aid in reduc- ing heat and/or chemicals required to treat crude oil to a specific quality.

Desalting Crude Oil

Most produced water contains salts, which may cause problems in production and refining processes when the solids precipitate to form scale on heaters, plug ex- changers, etc. This can cause accelerated corrosion in pip- ing and equipment.

In almost all cases, the salt content of crude oil con- sists of salt dissolved in small droplets of water that are dispersed in the crude. In some instances, the produced oil can contain crystalline salt, which forms because of changes in pressure and temperature as the fluid flows up the wellbore and through the production equipment. Crystalline salt will flow out with the water and is not of importance in desalting operations.

The salinity of produced brine varies widely, but most produced water falls in the range of 15,000 to 130,000 ppm of equivalent NaCl. Crude oil containing only 1 .O% water with a 15,000 ppm salt content will have 55 lbm salt/l ,000 bbl of water-free crude. The chemical compo- sition of these salts varies, but the major portion is near- ly always NaCl with lesser amounts of calcium and

magnesium chloride. Because of the operational problems associated with salts, most refineries buy crude at a salt content of 10 to 20 lbm/l,OOO bbl, then desalt the oil to 1 to 5 lbm/l,OOO bbl before charging to crude stills.

The purpose of a desalting system is to reduce the salt content of the treated oil to acceptable levels. In cases where the salinity of the produced brine is not too great, salt content can be reduced by merely ensuring a low frac- tion of water in the oil. In this case, the terms desalting and emulsion treating are identical, and the concepts and equipment described previously can be used.

The required maximum concentration of water in oil to meet a known salt specification can be derived from

c,, =0.35c,,y,“f&., . . . . . . . . . . . . (5)

where C,, = salt content of the oil, lbm/l,OOO bbl, c SM’ = concentration of salt in produced water,


Y w = specific gravity of produced water, and

fW = volume fraction of water in crude oil.

If the produced brine has a high salt concentration, it

may not be possible to treat the oil to a low enough water content (less than 0.2 to 0.25% is difficult to guarantee). In such a case, desalting implies the mixing of low-salt- content water with the emulsion before treating, as shown in Fig. 19.35. This lowers the effective value of C,, in Eq. 5. If a single-stage desalting system will require too much dilution water, then a two-stage system, such as that shown in Fig. 19.36, is used.



OIL -a



Fig. 19.35-Single-stagedesalting with dilution water injection.

Although it is possible to desalt with most of the emulsion-treating equipment discussed previously, most desalting systems use electrostatic treaters to obtain the lowest possible water content in the oil and thus minimize the amount of dilution water needed.

One of the most important parts of desalting systems is the method and efficiency of the method of mixing the wash water with the crude. The smaller the diameter of the wash-water drops dispersed in the oil, the greater the possibility of their coming in contact and coalescing with entrained saltwater droplets.

Excessive agitation when mixing the wash water with the crude oil can result in emulsions that are too tight (sta- ble) to resolve easily. Therefore, the amount of mixing provided should be adjustable to zero. This requirement tends to make pumps and level-control valves poor choices for mixing. The most commonly used mixing system con- sists of some type of special mixing tee or static mixer followed by a globe-type mixing valve.

Mixing efficiency in a desalting system refers to the fraction of wash water that actually mixes with the pro- duced water. The remainder of the water, in effect, bypasses the desalting stage and is disposed of as free water. A mixing efficiency of 70 to 85% can be consid- ered a reasonable range of attainment. Part of the energy for mixing is obtained from the pressure of the wash water, which should enter the mixer at approximately 25 psi above the pressure in the vessel.

Reverse Emulsions Most emulsions are the water-in-oil type; they occur much more frequently than the oil-in-water type. Oil-in-water (reverse) emulsions are most likely to be produced where the WOR is high, the dissolved solids content of the water is low, the water is slightly alkaline, and the oil has a naphthenic base. The oil content of these emulsions may vary from as low as a few ppm to 40%. They may vary in consistency from watery thin to a moderately heavy cream.

The produced water from some leases and ballast water from some oil tankers contain sufficient oil to be or have the characteristics of an oil-in-water emulsion Such water is usually treated with chemicals formulated for water treating and with equipment described in Chap. 15.

Reverse emulsions may not require much, if any, heat. Because the external phase is water, the viscosity is quite low at ambient temperature. The chemicals used to treat reverse emulsions are usually some type of surface-active compounds that will neutralize the charges on the oil par- ticles and allow them to coalesce during the gentle agita- tion that should follow introduction and mixing of the chemical with the emulsion. Overtreatment of this type of emulsion with chemical can result in stabilization rather than breaking of the emulsion.

Empirical data and experience are required to design equipment and/or systems for resolving reverse emulsions.







Fig. 19.36-Two-stage desalting using second-stage recycle.


Treating Emulsions Produced From EOR Projects

Standard emulsion-treating procedures, equipment, and systems used during primary and secondary oil produc- tion may not be adequate to treat the emulsions encoun- tered in EOR projects. EOR methods of oil production- such as in-situ combustion and steam, COz, caustic. polymer, and micellar (surfactantipolymer) floods-may result in the production of emulsions that may not respond to treatment normally used in primary and secondary oil production operations.

The treatment of the emulsions from EOR projects is usually handled independent of the primary and secon- dary emulsions from the same fields. Emulsion-treating procedures, equipment, and systems have been and are continuing to be developed for use in these EOR projects.

Clarification of Water Produced with Emulsions

Even though a normal (water-in-oil) emulsion exists in the oil production system, when produced water is sepa- rated from crude oil, the water usually contains small quantities of oil. The oil has been divided into small par- ticles and dispersed in the water by agitation and turbu- lence caused by flow in the formation; into the wellbore; through the bottomhole pump, standing valve, traveling valve, and tubing; reciprocation of sucker rods; flow through the wellhead choke, flowline, manifold, oil and gas separator, and treating system; and by surface trans- fer pumps.

These small particles of oil will be suspended in the water and held there by mechanical. chemical. and elec- trical forces. The amount of oil contained in the untreated produced water in most systems will vary from an aver- age low of about 5.0 ppm to an average high of about 2,000 ppm. In some water systems, oil contents as high as 20.000 ppm (2.0%) have been observed.

The oil particles in the untreated produced water will usually vary in size from 1 to about 1,000 pm, with most of the oil particles ranging between 5 and 50 pm in di- ameter.

Nine methods can be used to remove oil from the pro- duced water: chemical, heat, gravity settling (skim tanks, API separators, etc.), coalescence (plate, pipe/free flow), tilted plate (corrugated) interceptors, flotation. floccula- tion. filtering, and combinations of the above. Refer to Chap. 15 for a discussion of the details of deoiling the produced water.

Operational Considerations for Emulsion-Treating Equipment Burners and Fire Tubes

The design of burners and fire tubes is of importance be- cause of the high cost of fuel and the operating problems that can occur when they malfunction. The burner should be designed to provide a flame that does not impinge on the walls of the fire tube, but that is almost as long as and concentric with the fire tube. If the flame touches the fire-tube wall. hot spots can develop, which can lead to premature failure.

Burners should not be allowed to cycle off and on frc- quently because thermal stresses caused by temperature reversals can damage the firebox. The combustion con-

trols should be accessible and designed so that the opera- tor can easily adjust the air and gas to achieve optimum tlame pattern and peak combustion efficiency.

A reliable pilot burner is required. Many operators and some regulatory agencies require burner safety shutdown valves that will shut off fuel to the burner in case of pilot failure. Unless specifically requested by the purchaser, most small emulsion treaters normally will not include this feature.

API RP 14C, “Analysis, Design, Installation and Test- ing of Basic Surface Safety Systems for Offshore Produc- tion Platforms,” contains a basic description of recommended safety devices needed for fired- and exhaust-heated units. Consideration should be given to in- stalling these devices on onshore, as well as offshore, fired treaters. They include process high-temperature shut- down. burner exhaust high-temperature shutdown, low- flow devices and check valves for heat exchangers, high- and low-pressure shutdown sensors, pressure-relief valves, flame arresters, fan motor starter interlocks on forced draft burners, etc.

Every gas-fired crude oil heating unit should be provid- ed with fuel gas from which liquids have been “scrubbed.” In large facilities, this can be accomplished with a central fuel-gas scrubber or filter providing fuel gas to all fired units. Many small facilities are equipped with individual fuel-gas scrubber vessels for each fired unit. These fuel-gas scrubbers are typically 8 to 12 in. in diameter and 2 to 4 ft tall, and contain a float-operated shutoff valve. If liquid enters the fuel-gas scrubber. the float will close a valve and stop gas flow to the burners of the heating unit. This will prevent oil from entering the combustion chamber and possibly prevent a fire.

Most fire tubes that transfer heat to crude oil or emul- sion are sized to transfer 7,500 Btuihr-sq ft. although some manufacturers use heat-transfer rates as high as 10,000 Btuihr-sq ft. Fire tubes that transfer heat to the water- wash section of a treater, as in a vertical treater. are sized for 10,000 Btuihr-sq ft, although some manufacturers use heat-transfer rates as high as 15,000 Btu/hr-sq ft. These higher rates are not recommended because they can be overly optimistic and thus may undersize the required fire tube area.

The temperature controller. fuel control valve, pilot burner, main burner, combustion safety controls. and fuel- gas scrubber for controlling and cleaning the fuel gas for fired treating vessels should be inspected and cleaned peri- odically as required. A schedule of preventive main- tenance is recommended for this equipment.

Deposits of soot, carbon, sulfur, and other solids, if any, should be removed from the combustion space peri- odically to prevent reduction in heating capacity and loss of combustion efficiency. On oil-fired units, the follow- ing items should be inspected and maintained periodically: combustion controls, burner nozzles, combustion refrac- tory, air/fuel control linkages. oil pump, oil preheater, pressure and temperature gauges, and 02 and/or CO2 analyzers.

Cleaning Vessels

Crude oil emulsions may contain mud, silt, sand, salts, asphalt. paraffin, and other impurities produced in con- junction with crude oil and accompanying water. In most


instances, these impurities are present in small quantities and add little to the treating problem. However, the treat- ing problem may be made difficult and expensive because of the presence of one or more of these impurities in ap- preciable quantity. Special equipment and techniques may be required to handle these materials.

It is good practice to equip all treating vessels with cleanout openings and/or washout connections so that the vessels can be drained and cleaned periodically. Larger vessels should be equipped with manways to facilitate cleaning them. Steam cleaning may be required periodi- cally. Acidizing may be required to remove calcium car- bonate or similar deposits that cannot be removed by hot water or by steam cleaning.

One of the most likely causes of difficulty in operating fired emulsion-treating vessels is the deposition of solids on heating tubes and nearby surfaces. It is desirable to prevent such deposits, but if they cannot be prevented, these surfaces should be cleaned periodically. The deposits insulate the heating tube, reducing heating capacity and efficiency. Also, these materials may cause accelerated corrosion.

Of the salts commonly found in oilfield waters, the chlo- rides, sulfates, and bicarbonates of sodium, calcium, and magnesium are predominant. The most prevalent of the chlorides is NaCl. Calcium and magnesium chloride are next in quantity. These salts can be found in practically all water associated with crude oil. Salts are seldom found in the crude oil, but if they are present, they are mechan- ically suspended and not dissolved in it.

Emulsion-heating equipment is particularly susceptible to scaling and coking. These processes of deposition are not distinctly separate but may occur simultaneously. Also, one may hasten the other.

Calcium and magnesium carbonates and calcium and strontium sulfates are readily precipitated on heating sur- faces in emulsion-treating equipment by decomposition of their bicarbonates and the resultant reduced solubility in the water carrying them. These materials will be deposited in pipes, tubes, fittings, and the inside surface of treating vessels. Maximum deposition will occur at the hottest surfaces, such as on heating coils and fire tubes.

Scale deposition also may occur when pressure on the fluid is reduced. This is the result of release of CO* from the bicarbonates in salt water to form insoluble salts that tend to adhere to surfaces of equipment containing the fluid.

Coke is not generally a primary fouling material. When deposits of salt, scale or any other fouling material build up, however, coking begins as soon as the insulating effect of the fouling material causes the skin temperature of the heating surface (heating tube or element) to reach 600 to 650°F. At this temperature, coke begins to form, which further aggravates fouling and reduces heat transfer. Once coking starts, a burnout of the lirebox may follow quickly.

In areas where fluids cause considerable scaling or cok- ing, the amount of such deposits can be reduced to a mini- mum by decreasing the treating temperature or by use of chemical inhibitors, properly designed spreader plates, and favorable fluid velocities through the equipment. Ar- ranging the internals of the equipment so that all surfaces are as smooth and continuous as possible will also reduce such deposits. The operator should periodically inspect the equipment internally and clean the surfaces as required

if trouble-free operation is to be obtained over a long peri- od of time. It is impossible to eliminate the deposition of solids entirely in emulsion-treating equipment, but it can be minimized.

Removing Sand and Other Settled Solids

Sand and silt may be produced with many crude oils. They may settle out in the vessel and be difficult to remove. It is common to shut down and drain the vessel periodi- cally for cleaning. Sand can be removed from the unit with rakes and shovels or with a vacuum truck. The use of “sand pans,” automated water jets, and drain systems can eliminate or minimize the problem of sand and silt in emulsion-treating vessels, but it is very difficult to elim- inate sand buildup in large-diameter tanks.

Sand pan is the name given to a special perforated or slotted box or enclosure located in the bottom portion of a vessel or tank. Sand pans are designed to cover the area of the vessel that the flow of discharging water will clean. Often they are designed to work in conjunction with a set of water jets. The sand pans for horizontal vessels usually consist of elongated, inverted V-shaped troughs that are located parallel with and on the bottom of the vessels and that straddle the vertical centerline of the vessel. In the design in Fig. 19.37, the sand pans have sides that make an angle of 60” with the horizontal. The bottom edges of the sloping sides are serrated with 2-in. V-shaped slots and are welded to the interior of the shell of the treater. Most sand pans used in horizontal vessels are 5 ft long; a 60-ft-long horizontal vessel will typically have 11 sand pans and 11 sand-dump valves.

Sand pans, without a water jet system, have satisfac- torily removed sand from most horizontal vessels up to 6 or 8 ft in diameter. Horizontal vessels larger than 4 ft in diameter should be equipped with a water jet system in addition to sand pans to keep sand cleaned from the vessel. Typical sand pans with a water jet system are il- lustrated in Fig. 19.37.

In vertical vessels, the sand pan may be a flanged and dished head approximately one-third the diameter of the vessel in which it is concentrically located. The sand pan is usually serrated around the periphery where it is welded to the bottom head of the vertical vessel concentric with the water outlet.

Water jets usually are designed to flow approximately 3.0 galimin of water through each jet with a differential pressure of 30 psi. Standard jets are available for this serv- ice that have a 60” flat fan jet pattern. The jets are usually spaced on 12- or 16-in. centers. The water jet header is U-shaped so that the vessel is cleaned on both sides of the sand pan simultaneously. The water jets can be pro- grammed for all the jets to flow at the same time, or they can be controlled by operation of the water jets and the sand dump valves in sequential cycles.

One problem in removing sand from vessels is that very few, if any, water-discharge control valves can withstand the abuse of sand-cutting during the water-discharge peri- od for the long term. The partial answer to this problem is to arrange the instrumentation to open and close the water-discharge control valve on clean sand-free water and to use special slurry-type valves.

The most sophisticated sand-removal systems use programmable logic controllers. This solves the problem of selection of the proper time intervals between dumps


Fig. 19.37-Sand pans and water jet system in a horizontal vessel.

and automatically controls the length of the water/sand discharge. The timing must be coordinated with the water jet system and the normal water-dump controller. A prop- erly designed sand-removal system with proper water jet- ting and water/sand dumping can operate for many years without the need for a shutdown to clean out the sand or to repair or replace the dump valve.

Most emulsion-treating systems that handle large volumes of sand should not rely on hand or non- programmed operation for removal of the sand. If the operator fails to activate the dump valve often enough, the sand will cover the sand pans and plug or partially plug the water outlet, and the drains will become inoper- ative. With sand pans in the treater but without a program- mer, large volumes of sand will usually cause trouble by plugging or partially plugging the water outlets and/or by cutting or wearing the drain valve.

Because both the amount and type of sand vary greatly, the length and frequency of the water-jetting and dump- ing cycles must vary to suit local conditions. Most of the coarser sand will settle out in the inlet end of the treater; the fine sand will settle out near the outlet end of the treat- er. It may be necessary to cycle the water jets and drain valves near the inlet end of the treater three to four times more frequently than those near the outlet end of the unit. Many timers are set for 30 minutes between jetting and dumping cycles and for 20- to 60-second jetting and dump- ing periods.

Interfacial Buildup

Interfacial buildup, sometimes referred to as sludge, is material that may collect at or near the oil/water inter- face of emulsion-treating tanks and vessels. Interfacial

buildup may contain paraffin, asphaltenes, bitumen, water, sand, silt, salt, carbonates, oxides, sulfides, and other impurities mixed with the emulsion. It can be rem moved from the vessel through a drain installed at the in- terface. The most common procedure, however, is to close the water dump valve and float it out to a bad-oil tank for further processing or disposal. Interfacial build- up can also be discharged with the water by opening the water-drain valve.


Emulsion-treating equipment that handles corrosive fluids should periodically be inspected internally to determine whether remedial work is required. Extreme cases of cor- rosion may require a reduction in the working pressure of the vessel or repair or replacement of vessel and pip- ing. Periodic ultrasonic tests can measure the wall thick- ness of vessels and piping to detect the existence and extent of corrosion.

Corrosion of emulsion-treating equipment is usually mitigated or controlled by a combination of the following.

Exclusion of Oxygen. Corrosion rates in most oilfield applications can be kept low if O2 is excluded from the system. Care must be taken in the process design to in- stall and maintain gas blankets on all tanks in the process and to exclude rainwater from the system. Recycled water from sump systems and storage tanks is a prime source for 02 entry into the process.

Corrosion Inhibitors. An inhibitor is a material that, when added in small amounts to an environment poten- tially corrosive to a metal or alloy, effectively reduces


the corrosion rate by diminishing the tendency of the metal or alloy to react with the solution. Inhibitors, in the form of liquid solutions or compounds, can be injected into the flow stream in the flowline, manifold. or production sys- tern to inhibit corrosion that would occur otherwise.

Cathodic Protection. Sacrificial galvanic anodes are com- monly used for cathodic protection. They are made of a metal that will provide sacrificial protection to the steel vessel because of its relative position in the galvanic ser- ies. Most galvanic anodes used in emulsion treaters are about 3 to 6 in. in diameter and about 3 to 4 ft long. Mul- tiple anodes usually are installed in each vessel. The anodes usually are sized to last from 10 to 20 years. They are considered expendable and are always installed in the vessel through a flange or quick coupling so that they can be easily replaced when expended.

The galvanic anodes must be installed so that they are immersed in the water, which serves as an electrolyte. They will not protect the treater if they are immersed in the oil. The anodes must “see” all metal surfaces that are to be protected-i.e., there must be no obstructions between the anodes and the surface they are to protect. Each anode should be located as near the center of the compartment or area they are to protect as practical.

An impressed electric-current cathodic protection sys- tern can also be used to inhibit corrosion. It is a direct electric current supplied by a device using a power source external to the electrode system. The DC current can be obtained by rectifying AC current. When resistivity ol the electrolyte ranges from 25 to 300 Q.crn and above. consideration should be given to the use of an impressed current system. Impressed current systems are difficult and costly to maintain. however. and usually require skilled technicians.

Electrical current density requirements for cathodic pro- tection of emulsion-treating vessels usually range from 5 to 40 mA/sq ft of bare water-immersed steel.

Internal Coating. Emulsion-treating vessels can be coated internally for protection from corrosion. It is important that the internal surfaces and the welds of the vessels be properly prepared to receive the coating. A coating system must be selected that will withstand the physical and chem- ical environment to which it will be exposed. Coating specifications. application techniques. and final inspcc- tion are very important considerations. Most coating sys- tems will contain some holidays (breaks in the coating) or may be damaged in shipping or installation. Therefore. coating alone should not be relied on to prevent corrosion.

Steel tanks can be galvanized or lined in the field with fiberglass or other coatings. Some operators use fiber- glass tanks in their emulsion-treating process, while others feel that this represents an unnecessary fire hazard.

Special Metallurgy. In particularly severe environments, such as where large quantities of CO: are cxpccted and where O1 cannot be practically eliminated from the sys- tem. it is possible to minimize corrosion by using stain- less steel vessels or an internal stainless cladding in carbon steel vessels. In most low-pressure applications, stainless vessels are less expensive than clad vessels. It may also bc cheaper to use a stainless vessel than one that is inter- nally coated because of the labor required to prepare and to coat the internal surfaces of the vessel.

Level Controllers and Gauges

A wide selection of liquid-level controllers is available for liquid/gas control and for oil/water interface control in light crude oil (above 20”APl) systems. For interfa- cial controllers in light crude oils. floats that sink in the oil but float in the Later normally are used.

For heavy crude oils, electronic interface controIIers have been very successful. These operate on the princi- plc of the differences between oil and water electrical con- ductivity, electrical capacitance, or radio frequency. The most common type is called “capacitance probes”; they USC the dielectric strength of the fluid in which they arc immersed.

Standard gauge glasses (reflex or transparent) are used on 20”API crude oil and higher. Reflex gauges normally are used on liquid/g% levels and transparent gauges for oil/water levels. Armored gauge glasses normally are used on pressure vcsscls and tubular gauge glasses on tanks. Some operators use the tubular gauge glasses on low pressure treating equipment. Tubular gauge glasses nor mally are furnished on standard low-pressure vessels un- less armored gauges are specified.

For API gravities below 20”APl, gauge glasses are not recommended. particularly for interfacial service. because they are difficult or impossible to read. In lieu of gauge glasses. a system of sample valves is used with the sam- ple lines all piped to a single point just above a sample box. Generally, the lines are insulated to keep them warm. A nameplate is clamped on each sample valve to dcsig- nate the elevation it represents in the treater. The sample box is fitted with a drain line piped to the sump.

Water-in-Oil Detectors (BS&W Monitors)

Several companies manufacture devices for detecting and measuring the water content of crude oil. They are com- monly called BS&W monitors. BS&W monitors are typi- cally analog instruments that measure dielectric strength and are specifically designed for determination of the water content of crude oil containing a low percent of water. They do not operate satisfactorily on streams con- taining free water. The unit provides a water reading car responding to the water content of the oil. It can be made to alarm, record. and control if the detected percentage exceeds the field-selectable preset limit of BS&W content.

Special Safety Features for Electrostatic Treaters

Because of the high voltage and the associated potential hazard to personnel that can result from entering a drained vessel with the grids activated, electrostatic treaters re- quire a positive shutdown switch for the high-voltage transformer. This disconnects the transformer if the fluid lcvcl falls below a predetermined level in the treating ves- sel. Some manufacturers install an internal grounding device inside the treater that grounds the hot grid if fluid is not present.

Changing Excelsior Packs

Excelsior used in treating emulsions may have a service- able lift ranging from just a few days to several years. The best grade excelsior should be used because cost of the excelsior is small compared to the expense of removing and replacing it. In some fields. the excelsior must be chopped into blocks with an ax and removed in chunks.


Serviceable life of the excelsior may be extended by periodically washing it with hot water. The water level can be allowed to build up above the top of the excelsior pack and the water heated to about 2 10°F. The tempera- ture should be kept this high for about I hour. The water should be drained quickly from the vessel while it is hot. The hot water may carry most of the foreign material with

it. If the application of heat only partially cleans the ex- celsior, a second heating may clean it further. Care should be taken to use water that will not deposit solids in the treater while it is being heated.

Economics of Treating Crude Oil Emulsions The object of operating oil-producing properties is to deliver consistently the maximum volume of highest-API- gravity oil to the pipeline at the lowest possible cost. Emulsions should be prevented wherever feasible and treated at the lowest cost where they cannot be prevented.

Implementation of the following directives can minimize the occurrence of emulsions and the costs of treating.

1. Eliminate production of water with oil where possi- ble and practical.

2. Minimize the investment in emulsion-treating equip- ment by studying the treating problem and the selection and use of appropriate treating methods, equipment, and procedures. The emulsion treating system should be as small as possible, yet capable of adequately handling treat- ing requirements on the lease. Treating systems may be initially oversized to allow for future development. lease expansion, or increased water production. Such antici- pation of future needs should be considered when treating equipment is purchased; however, needlessly oversized systems involve unnecessary expense and accomplish nothing that properly sized systems will not accomplish.

3. Minimize the loss of oil with water and salvage oil from interfacial sludge and tank bottoms where feasible. Oil may be discharged with the water as it flows from FWKO’s, emulsion treaters, gunbarrels, or other treat- ing vessels. The fraction of oil is low and the oil is usually dispersed in small droplets. Sometimes this oil is pumped

along with the water to disposal wells or delivered to oper- ators of water disposal companies without recovery or without credit being received by the lease. This oil loss can be minimized by maintaining proper operating vari- ables with adequately sized and maintained vessels and controls and by properly designed water treating systems.

4. Minimize chemical treating costs by use of the most appropriate chemical demulsifier compound(s), the opti- mum quantity of chemical, the proper location and method of injection of chemical, the proper means of intimately mixing chemical with emulsion, and the proper use of heat. Treating chemicals are not recoverable and consti- tute a continuing expense. Some crude oil can be adequate- ly treated by chemical injection used in conjunction with coalescing and/or settling without heat. However, some emulsions require an increased temperature during the coalescing and settling period. A proper balance of chem- ical and heat aids in providing the most economical and efficient treating system. The chemicals must be intimately mixed with emulsion so that a minimum amount of chem- ical will provide maximum benefit. Chemicals may be wasted by being injected into the oil in large slugs and not intimately mixed with the emulsions.

5. Ensure that chemicals added to the produced fluids are compatible. Some corrosion inhibitors can cause emul- sions or affect the action of oil-treating chemicals. Chem- icals used in produced-water-treating systems may be recycled to the oil-treating system with the skimmed oil and cause emulsion-treating problems.

6. Conserve gravity and volume of oil by using opti- mum treating temperature, cooling oil before discharging to storage, discharging vent gases from treating vessels through cooler oil in stock tanks. maintaining slight gas pressure on treating system and storage tanks, and using vapor recovery equipment on vessels and tanks. Crude oil emulsions should be resolved at the lowest effective temperature. Excessive heat drives condensible vapors from the oil, and they are discharged with the gas. Loss of these light ends lowers the API gravity of the oil and simultaneously reduces the oil volume. A further disad- vantage of overheating is the increased maintenance rc- quired on treating systems caused by hot spots. salt deposition, scaling, and increased rate of corrosion, es- pecially of the fireboxes.

7. Use all treating equipment to the best advantage. By careful observations, supervision, and record keeping, emulsion-treating equipment can be used to maximum ef- ficiency, Transfer of equipment and alterations or addi- tions to the treating system may be made to use existing equipment better. Constant testing and vigilance are re- quired to obtain maximum results.

8. Practice preventive maintenance to minimize ir- retrievable loss of oil production because of downtime for equipment repairs. The more complex the treating system, the greater will be the possibility of mechanical failure. Oversized and overly complex systems have a greater failure frequency than more appropriately designed, sim- pler, and more compact systems.

9. Exchange information on treating methods and re- sults among company personnel, with other operators, engineering firms, vendors, and chemical-treating com- panies. Experience can be gained and shared by person- nel responsible for handling treating problems, which will result in lower treating costs.

Cost records are important in oil emulsion-treating op- erations. To achieve optimum operation of emulsion- treating equipment at minimum cost, proper records must be kept of operating temperatures, pressures, fuel and/or power consumption, chemical usage, performance, etc.

Such records should be kept on a daily, weekly, or month- ly basis, reviewed regularly, and kept available for su- pervisory personnel.

Cost records make it possible to predict whether an ex- isting system should be modified or replaced. Justifica- tion for modifying or replacing an existing system will depend on the efficiency of the system, and this can be determined best from accurate and reliable cost and per- formance records. Cost records on existing methods or systems will assist in determining the type, kind, and size of treating systems for new leases. Treating cost records should make it possible to determine current operating costs, probable installation costs for new systems, and probable future operating costs of similar systems.

Each operator should determine what is to be charged to emulsion-treating costs. Listed in Table 19.2 is an out-

line of items that may be considered part of the data base for a cost-accounting system. Some of these items will


not be applicable to all treating systems, and some oper- ators may elect to group some of the categories. A com- prehensive general listing is presented for those who wish to consider all items of cost. Special systems and condi- tions may require additional cost items.

It is necessary to consider all factors listed in Table 19.2 if complete and accurate treating cost records are to be compiled. This information should be obtained and recorded on a continuous daily, weekly, or monthly basis, and it must be accurate and concise if cost records are to be of maximum value.

Investment costs must include the initial cost of all equipment used, including the cost of transporting it to the location, of erecting and installing the equipment, and of readying the system for operation. Such items as pipe and pipe fittings, valves, grade work, foundations, and fencing should be included.

The labor cost should include supervisory personnel, cost of company gang and contract gang, and other labor required to obtain, install, and put the treating system into operation. Operating cost should be kept separate from maintenance cost and should include such items as super- visory labor, operating labor, chemicals, fuel, and mis- cellaneous supplies. Maintenance cost should include cost of maintaining and repairing all treating equipment. This should include such items as cleaning. repairing, painting, and other similar items.

The Overall System Performance section should include an accurate record of the volume of oil treated and the volume of water separated, treated, and handled. This part of the record should also include reference to troubles ex- perienced with the system and a commentary on day-to- day performance of the unit or system.

Key Equations in Metric Units

Q=53.09aT(0.5y,,y,,+y,,.y,,.), . . (2)

where Q is in watts. ilT is in Kelvin. y,, is in m’ld. y,, is dimensionless, (I,,. is in m j/d. and yII. is dimensionless.

5.43x 10 -‘o(Ay(,\,)d2 ,‘Z . (3)

CL il

where 1’ is in m/s.

AY l,il is dimensionless. d is in pm. and p,, is in Pa.s.

Bmdxd.. P.L. and Bcshlcr. D.U.: “Cold Trealing of Oilfield Einul- \ionr,” presented ;~t the Southwehlern Petroleun~ Short Courw. Dcpr. ot Purroleu~n Englncerinf. Tcx;r\ Tech U.. Luhboch. April 1975


Equipment Investment Costs

Material Treating equipment and facilities Auxiliary equipment, controls, and accessories

Labor to install equipment Company labor Contract labor

Other expenses Surface rights Special services Other

Operatmg Costs

Material Chemicals Chemical injection equipment Diluents and solvents Testing apparatus Depreciation allowances Other

Labor Supervisory Operator or pumper Steaming or cleaning crew Gang Contract Other

Other expenses Equipment rental Fuel (gas or liquid) Electric current Transportation Laboratory expenses Other

Maintenance Costs

Material Maintenance Replacements and additions Repalrs

Labor Supervisory Pumper or operator Mechanic Painting Gang Contract Other

Other Expenses Equipment rental Transportation Other

Overall System Performance

Volume of oil treated Water content of treated oil Volume of water produced Volume of water treated Volume of oil salvaged from water treatment Remarks or observations


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