105409197 Crude Oil Emulsions

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Chapter 19Crude Oil EmulsionsH. Vernon Smith, Meridian Corp.Kenneth E. Arnold, Paragon Engineermg Scr~icm Inc.

IntroductionMuch of the oil produced worldwide is accompanied bywater in an emulsion that requires treating. Even in thosefields where there is essentially no initial water produc-tion. water cuts may increase in time to the point whereit is necessary to treat the emulsion. Water content of theuntreated 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 contractualagreements and typically range from 0.2 to 3.0%. BY&Wis 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. andprecipitates of dissolved solids. These troublesome solidsvary 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 andcannot be removed in conventional storage tanks.emulsion-treating methods must be used. The methods.procedures, equipment, and systems generally used intreating 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-topicsexist on which entire chapters can be written. This chap-tcr contains an abbreviated discussion of only a few ofthe most important and pertinent considerations of crudeoil emulsions. More detailed and diversified discussionson crude oil emulsions can be found in the General Refer-ences at the end of the chapter.

Theories of EmulsionsDefinition of an EmulsionAn emulsion is a heterogeneous liquid system consistingof two immiscible liquids with one of the liquids intimatelydispersed in the form of droplets in the second liquid. Anemulsion is distinguished from a simple dispersion of oneliquid in another by the fact that, in an emulsion, the prob-ability of coalescence of droplets on contact with oneanother is greatly reduced because of the presence of anemulsifier, which inhibits coalescence. Such inhibition isnot present in a dispersion.

The stability of the emulsion is controlled by the typeand amount of surface-active agents and/or finely divid-ed solids. which commonly act as emulsifying agents oremulsifiers. As shown in Fig. 19.1, these emulsifyingagents form interfacial films around the droplets of thedispersed phase and create a barrier that slows down orprevents 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 theform of small droplets is called the internal, dispersed,or discontinuous phase. The emulsions considered in thischapter consist of crude oil and water or brine producedwith it.In most emulsions of crude oil and water, the water isfinely dispersed in the oil. The spherical form of the waterglobules is a result of interfacial tension (IFT). which com-pels them to present the smallest possible surface area tothe oil. This is a water-in-oil emulsion and is referred toas a normal emulsion. The oil can be dispersed in thewater to form an oil-in-water emulsion, which is referredto as an inverse or reverse emulsion. A typicalreverse 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 oroil-in-water to begin with, but additional agitation may


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PETROLEUM ENGINEERING HANDBOOK

Fig. 19.1Photomicrograph 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 Form

The three conditions necessary for the formation of anemulsion are (1) the two liquids forming the emulsionmust be immiscible, (2) there must be sufficient agitation

to disperse one liquid as droplets in the other, and (3) theremustbe 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 will

be between the oil above and the water below.When considering crude oil emulsions, we are usually

concerned 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. 19.2Photomicrograph of reverse emulsion. Uniformlysized oil particles are about 10 m 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 m. Emul-sions that have smaller droplets of water are usually more

stable 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.


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CRUDE OIL EMULSIONS 19-3

Fig. 19.3Photomicrograph of oil-in-water-in-oil emulsion. Oil Fig. 19.4Photomicrograph of multiple-stage emulsion fromdroplets are shown dispersed in water droplets that Rocky Mountain field. The dispersed water phaseare dispersed in the continuous oil phase. contains small oil particles.

If an emulsion is not treated, a certain amount of waterwill separate from the oil by natural coalescence and

settling 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 range

of emulsified water in crude oil heavier than 20 API isfrom 10. to 35%.

Emulsifying Agents

Emulsifying 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. 19.5Photomicrograph of loose emulsion from western

Kansas containing about 30% emulsified water in theform of droplets ranging in diameter from about 60m downward.


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19-4 PETROLEUM ENGINEERING HANDBOOK

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

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

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

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 prevent

the 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 and

transitory. 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 breakingor 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


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CRUDE OIL EMULSIONS

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

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 Emulsions

If 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 operating

practices.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 centrifugal

pumps can actually cause coalescence if they are installed

Fig. 19.10Photomicrograph showing a collection of inorganic

solids 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 Emulsions

The 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 Emulsions

Generally, 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


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

Effect of Emulsion on Viscosity of FluidsEmulsions are always more viscous than the clean oil con-tained in the emulsion. The ratio of the viscosity of anemulsion to the viscosity of the clean crude oil in oilfieldemulsions depends on the shear rate to which it has beensubjected. The authors have found that for many emul-sions and the shear rates normally encountered in pipingsystems, this shear rate can be approximated by the fol-lowing equation if no other data are available.

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

cc = viscosity of emulsion.PO = viscosity of clean oil, andf = fraction of the dispersed phase.

Sampling and Analyzing CrudeOil EmulsionsPurchasers of crude oil have established certain specifi-cations that must be met before they will accept oil froma producer. These specifications limit the amount ofBS&W in the oil. The limitations are usually strict, andif the amount of ES&W in the oil exceeds the specifiedlimit. the oil may not be accepted by the purchaser. Theseller 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 systemscan be observed and studied by the practice of regularlyand periodically withdrawing and analyzing samples ofthe contents at multiple levels in the vessels or multiplepoints in the systems. This is particularly beneficial intreating emulsions involving viscous oils. Samples ofemulsions should be representative of the liquid fromwhich they are taken. Emulsification should not occurwhen the sample is extracted. Samples obtained at thewellhead. manifold, or oil and gas separator may showa high percentage of emulsion, but the oil and water inthe system may actually not be emulsified. This indicatesthat emulsification occurred because of the turbulencecreated as the sample was removed from the pressure zoneto the sample container.

It is possible to take a sample from a pressure zonewithout further emulsification of the liquids if the veloci-ty of the discharging liquid is controlled. One method isto use a piece of small-diameter tubing approximately 10

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

Another method of withdrawing a representative sam-ple of emulsion is to use a sample container initially filledwith water. The sample container is equipped with valvesat the top and bottom with the top valve connected to thepoint from which the sample is to be extracted. The topvalve of the container is opened first and the containerpressured from the line. The valve at the bottom of thecontainer is then opened and the water discharged intothe atmosphere as the sample enters the container. Therewill be no emulsification in the container because thereis 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 effecton the sample.

Small centrifuges are used to determine BS&W con-tent of crude oil. The centrifuges may be driven by handor electric motor. A small measured volume of sampleis diluted with solvent and placed in graduated glass con-tainers. These are then inserted into the centrifuge androtated at high speed for a few minutes. Separation of theoil, water, and solids is accomplished by centrifugal force.The percentages of each constituent can be read directlyfrom 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 oilfor custody transfer are included in the API Mur~uul ofPetroleum Measurement Standards. Also see Chap. 17.

Methods Used in TreatingCrude Oil EmulsionsThree basic steps usually are required to separate a crude-oil/water emulsion into bulk phases of oil and water.Step -Destabil izat ion. An emulsion is destabilized by

counteracting the stabilizing effect of the emulsifier. Thetough skin or film surrounding the dispersed waterdroplets must be weakened and broken. This is usuallyaccomplished by adding heat and/or a properly selected,interfacially active chemical compound to the emulsion.Step 2-Coal escence. After the films encasing the dis-

persed droplets are broken, the dispersed droplets mustcoalesce into drops large enough to settle out of the con-tinuous phase of oil. Fig. 19.11 shows a small dropletof water breaking through a destabilized emulsion filmto coalesce with the bigger drop. This usually is accom-plished by imposing a period of moderate agitation or bysubjecting the destabilized emulsion to an alternating elec-tric field. This will increase the dispersed droplets con-tacting rate. Thus coalescence will increase, resulting inlarger droplets.Step 3-Gravi t y Separat i on. A quiet period of settling

must be provided to allow the coalesced drops to settleout of the oil because of the difference in density betweenthe water and oil. This is accomplished by providing a

to 15 ft.long. One end of the tubing is connected to a sufficient residence time and a favorable flow pattern inbleeder valve on the line or vessel from which the sam- a tank or vessel that will allow the coalesced drops ofple is to be extracted, and the other end is connected to water to separate from the oil.the sample container. The bleeder valve should be opened Another way of stating the general emulsion-treatingfully and the sample allowed to flow through the small- procedure is that to resolve a crude-oil/water emulsiondiameter tubing into the container. The pressure drop from into bulk oil and water three things must be done:


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CRUDE OIL EMULSIONS

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 dispersedwater droplets on contact, (2) make the rate of contactof dispersed water droplets high without creating highshear forces, and then (3) allow the liquids to settle quietlyso that they can separate into bulk phases of oil and water.All the incidental variables, such as selection of properchemical, rate of chemical injection, treating temperatureand pressure, oil and emulsion viscosity, flow rate, ves-sel design, vessel size, and fluid levels, are controlled toexecute these three steps in the quickest and most eco-nomical manner.

An emulsion-treating unit or system will use one ormore of the methods in Table 19. I to aid in destabiliz-ing, coalescence, and/or settling. Each of these treatingmethods that can be used to resolve an emulsion is dis-cussed separately.HeatingThe use of heat in treating crude oil emulsions has fourbasic benefits.

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

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TABLE 19.1-METHODS TO AID DESTABILIZATION,COALESCENCE, AND/OR SETTLINGDestabilization

ChemicalHeatingCoalescence

AgitationCoalescing platesElectric fieldWater washingFilteringFibrous packingHeatingRetention timeCentrifugation

Gravity SeparationGravity settlingHeatingCentrifugation

other temperatures by drawing a straight line parallel tothe others. If the viscosity is unknown at any tempera-ture, the lines on the chart may be used. API Spec. l2Lrecommends that crude be heated so that its viscosity isbelow 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., dissolvingparaffin crystals) or it can enhance the action of treatingchemicals, causing the chemical to work faster and morethoroughly to break the film surrounding the droplets ofthe dispersed phase of the emulsion.

4. Heat may also increase the difference in density be-tween the oil and the water, thus accelerating settling. Ingeneral, at temperatures below 180F, the addition of heatwill increase the difference in density. Most light oils aretreated below 180F; thus the effect of heat on gravityis beneficial. For heavy crudes (below 20API). whichnormally are treated above 180F, 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 lessthan that of oil. This effect is shown in Fig. 19.13.

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

The gas liberated when crude oil is treated may alsocreate 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 thecoalescing section. The liberated gas can create enoughturbulence and disturbance to inhibit coalescence. Perhapsmore important, the small gas bubbles have an attractionfor surface-active material and hence for the waterdroplets; thus they have a tendency to keep the waterdroplets from settling and even may cause them to be dis-charged with the oil.


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19-8

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

10 *oo 200 300Temperature.DF

Water

Crude C

0 100 200 300Temperature. DFFig. 19.13--Relationship of specific gravity with temperature forthree crude oils.

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

If properly applied, heating an emulsion can have greatbeneficial effect on water separation. The most econom-ical emulsion treating may be obtained by use of less heatand 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 moredifficult to treat when it is cool-at night, during a rain,or in winter months when the atmospheric temperaturesare lowest. Treatment, especially heating, may not be re-quired in warmer summer months. Where the treatingproblem is seasonal, some emulsions can be resolved suc-cesstilly by addition of more chemical demulsifiers duringwinter months. Study is required to determine the propereconomic balance of heat and chemicals.

Crude oil emulsions with similar viscosity ranges donot always require the same type of treating equipmentor the same treating temperature. Emulsions produced


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

TYPICAL 33 APIGRAVITY LOSS

TEMPERATURE, F

from different wells on the same lease or from the sameformation in the same field may require different treat-ing temperatures. For this reason, it is recommended thatlow treating temperatures be tested so that the lowest prac-tical treating temperature for each emulsion and treatingunit or system can be determined by trial.The heat input and thus the fuel required for treatingdepends on the temperature rise, amount of water in theoil, and the flow rate. It requires about twice as muchenergy to heat a given volume of water as it does to heatthe same volume of oil. For this reason, it is beneficialto 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 thesame vessel.

The required heat input for an insulated vessel (heat lossis assumed to be 10% of heat input) can be approximatedfrom

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

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, andYn = specific gravity of water.

Chemical DemulsifiersCertain 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 150TEMPERATURE, l

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

chemicals are easily applied to the emulsion, usually arereasonable in cost, and usually minimize the amount ofheat and settling time required.

The chemical counteracts the emulsifying agent, allow-ing the dispersed droplets of the emulsion to coalesce intolarger 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 allof the protective films surrounding all of the disperseddroplets, and (3) displace or nullify the effect of the emul-sifying agent at the interface. A period of continuedmoderate agitation of the treated emulsion to produce con-tact between and coalescence of the dispersed droplets anda quiet settling period must exist to allow separation ofthe 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 oilphase to reach the droplet interface where it must coun-teract the emulsifying agent.Flocculation. The demulsifier must have an attractionfor water droplets with a similar charge and bring themtogether. In this way, large clusters of water dropletsgather, which look like bunches of fish eggs under amicroscope.

Coalescence. After flocculation, the emulsifier film isstill continuous. If the emulsifier is weak, the floccula-tion force may be enough to cause coalescence. This isnot true in most cases, and the demulsifier must there-fore neutralize the emulsifier and promote rupture of thedroplet 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 mudscan be made water-wet, causing them to leave the inter-face and be diffused into the water droplets. Paraffins and


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asphaltenes can be dissolved or altered by the demulsitierto 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 asettling tank, a relatively slow-acting demulsifier can beapplied 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 theelectric 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 settlingtank and that of an electrostatic treater.

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

While the first commercial emulsion-treating chemicalwas a solution of soap, present-day chemicals are basedon highly sophisticated materials. Chemical emulsionbreakers 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 ofhydrophobeihydrophile balance to the chemical as desired.The active components are highly viscous and sometimeseven solids. It is necessary to use a carrier that will makehandling easier: this carrier is almost without exceptionan organic solvent. Solvent systems are designed to makeemulsion breakers compatible with the crude oil systemin which they are used. It is also necessary to omit mate-rials that will interfere with refining processes, such asthose that will poison catalysts. Therefore, no organicchlorides, bromides, iodides, fluorides, or compounds ofarsenic or lead are used in the manufacture of mostemulsion-treating chemicals.

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

Pol~~lvcc~lesters are characterized by quick brighteningof emulsjons. but frequently tend toward slow water dropand sludging; they are subject to overtreating problems.Lo~r,-lnolrculrrr-~~~~i~~~tesin derivatives tend towardrapid water drop and fair to good overall demulsificationproperties; they show some tendency toward overtreat-ment in high-API-gravity emulsions.

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

Sulfonates exhibit fair to good wetting and water-dropperformance, some ability to brighten oil, and very littletendency to overtreat, particularly in high-gravityemulsions.

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

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

Oxyalkylatedphenols are predominantly wetting agentswith fair to poor demulsification properties; they are usedin 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 thesebroad categories. Most demulsifiers used in breakingcrude oil emulsions are blends of the above and other com-pounds. The components selected for a given demulsifierare chosen to provide the necessary actions to achievecomplete emulsion treatment. The number of differentsurface-active materials that can act as emulsifiers in crudeoil is large. The possible combinations of these emulsify-ing agents is almost infinite. Therefore, the number ofdemulsifiers and their combinations must likewise benumerous to treat the emulsions. The type and composi-tion of the crude oil in the emulsion being treated has moreinfluence on how a certain chemical demulsifier will per-form than does the specific category of components in-cluded in the treating chemical. For example, alow-molecular-weight resin used in treating an emulsionof 35API oil may exhibit rapid water drop, but that samechemical, when used in treating an emulsion of I5APIoil, may not cause rapid water drop. This illustrates thatdemulsifying 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 theoil emulsion. One chemical must not react with the otherto cause problems, such as stabilizing the oil in the water.Compatibility of the two chemicals must be tested by bottletests and then by field tests in the actual treating system.Also, compatibility tests should be performed for anyother chemicals added to the produced fluids.

Selection of the optimum chemical to use usually startswith bottle tests. A representative sample of fluid is takenand transferred into several test bottles. Several demul-sifying chemicals are added to the test bottles in variousamounts to determine which chemical will best break theemulsion. Additional tests are made to determine the op-timum ratio of chemical to fluid. Several series of testsmay be necessary at various ratios and temperatures beforea selection can be made. Many factors-such as the colorand appearance of the oil, clarity of the water, interfacequality, required operating temperature, settling time, andBS&W content-are observed during these bottle tests.

Bottle tests can be made with the samples of emulsiontaken at the wellhead. anywhere in the flowline, at themanifold, or at the entrance to the treating system or tank.Well-equipped mobile laboratories are available, so thistype of work can be done in the field. These mobile unitsshould be operated by trained technicians who canminimize testing and optimize selection of chemicaldemulsifiers.

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


11/34


CHEMICAL%-IN. COUPLING

DOUGHNUTMADEOF

DOUGHNUT. AREA OF6 HOLES TO BE LESSTHAN CSA OF %-IN. PIPEAREA %-IN. PIPE=O.19635 SQ IN

HOLE A TO BE DRILLED

8 HOLES FOR CHEMICAL D=0.177 IN.DRILLED ON UPSTREAM USE %-IN. HOLE (0.156)FACE OF DOUGHNUT HOLES ON FAR SIDE

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 finalselection is made on the basis of performance and cost.The optimum chemical is one that will provide theclearest, cleanest separation of water from oil at the lowesttemperature 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 chemicalmay be as high as 8 gal/l,000 bbl (about 200 ppm) oras low as 1 ga1/5,000 bbl (about 5 .O ppm). This is a rangeof 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 demulsifierhas 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 placeat a more rapid rate at higher temperatures.

The point of injection of demulsifier chemical into theemulsion is important. The chemical should be injectedinto the emulsion and mixed with it so that it is evenlyand intimately distributed throughout the emulsion whenit 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 shouldnot 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 andre-emulsification may occur.

Turbulence accelerates the diffusion of the demulsifierthroughout the emulsion and increases the number andintensity of impacts between water droplets. Turbulencemust 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 ofthe turbulence must be controlled so that it will not causefurther emulsification. Turbulence is the dynamic factorthat 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 bynormal flow in surface lines, manifolds, and separatorsand 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 volumeof chemical with a diluenr and then to inject and mix thediluted chemical with the emulsion. The larger volumeof the mixture may make it possible for the chemical tobe more uniformly and intimately mixed with theemulsion.

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

When a tank of wet oil (oil containing more than thepermissible 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 thenallowing time for the water to settle in the tank. Trailer-mounted units that include a heater, circulating pump, andchemical injector are sometimes used for this method oftank treating. This batch-treatment method normally isused as an emergency measure.

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


12/34


Fig. 19.17Kinetic (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, excess ive 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.

Agitation

Agitation 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.

4WATER IN

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

I N S T A L L A T I O N

I:= 13WATER OUT

A T MO S . VENT

OIL OUT

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

Fig. 19.18The S. P. Pack grows a larger drop size on theinlet separator of a gravity settler.

The flow of emulsions at moderate Reynolds numbersthrough long pipelines has been shown to cause coales-cence and develop droplets that exceed 1,000 m in di-ameter. The length of the pipeline required to obtaincoalescence can be dramatically decreased by using a de-fined flow path as in the special flow coalescing deviceshown in Fig. 19.18.

The demulsification process may be assisted by the useof baffle plates placed inside the treating vessel. Properly

designed and located baffle plates can evenly distributeemulsion in a vessel and cause gentle agitation that maybring about collisions of dispersed water particles to aidin coalescing the droplets. Excessive baffling should beavoided because it can cause excessive turbulence, whichmay result in increased emulsification and impede water-droplet settling. Special baffling in the form of perforat-ed plates properly placed inside treating vessels affordssurfaces upon which water droplets in the emulsion maycoalesce. As the emulsion flows through the perforations,slight agitation in the form of eddy currents is created,causing coalescence. If the perforations are too small,however, shearing of the water droplets can occur, re-sulting in a tighter emulsion.


13/34

CRUDE OIL EMULSIONS

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 Coalescing

The 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 are

brought 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 settle

by gravity.3. The electric field tends to distort and thus to weaken

the 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 easily

broken 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 chainingand 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-Washing

In some emulsion-treating vessels, separation of liquids

Fig. 19.19PerformaxTM

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 internal

phase 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.


14/34

19-14

FilteringA filtering material with the proper size of pore spacesand the proper ratio of pore spaces to total area can beused to filter out the dispersed water droplets of a crudeoil emulsion by preferentially wetting the filtering mate-rial with oil and keeping it submerged in oil. When usedin this manner, the pack is correctly called a filter be-cause it filters out the liquid that it prevents from passingthrough.

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 ofthe high affinity the cellulose fibers have for water. If theexcelsior is initially wetted by oil, however. the dispersedwater droplets in the oil will not normally take posses-sion of the excelsior fibers because the fibers are saturatedwith oil. If the water droplets do take possession of theexcelsior fibers, possession will occur at a slow rate andpenetration of the pack by the water will be only partiallycomplete.Excelsior is wood that is cut into small shreds or fibers.Observed under a microscope, the surfaces of each strandof 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 waterdroplets, thereby encouraging adherence of the dropletsto the strands of excelsior. This results in coalescence ofthe water droplets into drops large enough to settle outof the oil. Excelsior should be made from pitch-freewoods. such as aspen, cottonwood, or poplar. Pine ex-celsior is not recommended for crude oil emulsion-treatingpurposes. Excelsior should be used at less than 180Ftreating temperature. Higher temperature will delignifyand deteriorate the excelsior. It will also make it difficultto remove from the vessel.

Glass wool and other porous materials have been usedas 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 fiberswill be more wettable by oil than untreated glass woolfibers. Glass wool is not widely used for filtering becauseof its initial expense and its fouling problems.

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

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

Fibrous PackingFibrous coalescing packs are not commonly used in oiltreating. They are mentioned for completeness and todifferentiate 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 thatis wetted by the water, causing the water to coalesce intolarger drops. Separation of two emulsified liquids by use


of a coalescing pack operates on the principle that twoimmiscible liquids with different surface tensions cannotsimultaneously take possession of a given surface. Thecoalescing pack is wetted with or submerged in water.When the dispersed droplets of water come in contact withthe water-wet coalescing material. the water dropletscoalesce and adhere to the coalescing surfaces. Oil willpass through the pore spaces of the coalescing material.Separation of the two liquids in a coalescing pack is notcaused 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 chemicalsand/or heat and by repeated contact between the waterparticles and the surface of the coalescing materials asthe emulsion flows through the pack. When this film hasbeen broken, the water particles adhere to the surface ofthe coalescing material until they combine into drops largeenough to settle out of the oil.

Glass wool can be used as coalescing material inemulsion-treating vessels. It will not deteriorate like woodexcelsior and will prolong the service life of the coales-cing pack. Glass wool fouls rather easily and may causechanneling. Woven wire mesh can also be used but tendsto be more expensive than glass wool.Gravity SettlingGravity settling is the oldest, simplest, and most widelyused method of treating crude oil emulsions. The differ-ence in density of the oil and water causes the water tosettle through and out of the oil. Because the waterdroplets 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 areequal, a constant velocity is reached that can be comput-ed from Stokes law as

I .78 x 10 -6(A~CIM.)d2)> ) . . . . . . . . .PL, (3)

wherev=d=

AY o,, =

downward velocity of the water dropletrelative to the oil, ft/sec,diameter of the water droplet, pm.

difference in specific gravity between theoil 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 bottomof the vessel, and thus the easier it is to treat the oil.

2. The greater the difference in density between thewater droplet and the oil, the greater the downwardvelocity-i.e., the lighter the oil, the easier it is to treatthe oil. If the oil gravity were lOAP1 and the water fresh,the settling velocity would be zero because there is nogravity difference.


15/34


3. The higher the temperature, the lower the viscosityof the oil, and thus the greater the downward velocity ofthe water droplets-i .e., it is easier to treat the oil at hightemperatures than at low temperatures (assuming a smalleffect 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 increaseswater droplet size, however, gravity settling providesseparation of water from oil.Retention TimeIn a gravity settler, such as an oil-treating tank or thecoalescing section of an oil-treating vessel, coalescencewill occur. Because of the small forces at work, however,the rate of contact between water droplets is small andcoalescence seldom occurs immediately when two dropletscollide. Thus the process of coalescence, although it willoccur with time, follows a steep exponential curve wheresuccessive doubling of retention time results in small in-cremental increases in droplet size.

The addition of retention time alone, after some smallamount necessary for initial coalescence. may not signif-icantly affect the size of the water droplet that must beseparated by gravity to meet the desired oil quality. Ataller tank will increase the retention time but will notdecrease the upward velocity of the oil or may not signif-icantly increase the size of the water drop that must beseparated from the oil. Thus the additional retention timegained by the taller tank may not materially affect thewater content of the outlet oil.

A larger-diameter tank will increase the retention time.More important, it will slow the upward velocity of theoil and thus allow smaller droplets of water to settle outby gravity. In this case, it may not have been the increasein retention time that improved the oil quality but ratherthe reduction in flow velocity, which decreased the sizeof the water droplets that can be separated from the oilby gravity.CentrifugationBecause of the difference in density between oil and water.centrifugal force can be used to break an emulsion andseparate it into oil and water. Small centrifuges are usedto determine the BS&W content of crude oil emulsionsamples. A few centrifuges have been installed in the oilfield to process emulsions. They have not been widelyused for treating emulsions, however, because of high in-itial cost, high operating cost. low capacity, and a ten-dency to foul.DistillationDistillation can be used to remove water from crude oilemulsions. The water, along with lighter oil fractions, canbe distilled by heating and then separated by appropriatemeans. The lighter oil fractions are usually returned tothe crude oil.

The only current use of distillation is in the flash sys-tem used in 15API and lower oil. These systems usethe excess heat in the oil received from the treater or treat-ing system and convert this sensible heat to latent heatat 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 thatwould ordinarily be wasted. Fig. 19.20 shows a typicalflash distillation system for dehydrating emulsions ofheavy viscous crude oils.

The disadvantage of distillation is that it is expensiveand that all the dissolved and suspended solids containedin the water are left in the oil when the water is removedby evaporation.Emulsion-Treating Equipment and SystemsThe design of equipment or a system for treating crudeoil emulsions and the sizing of each piece of equipmentfor a specific application requires experience and engi-neering judgment. It would be ideal if a procedure existedthat would permit the engineer to infer from measuredproperties of the emulsion the most economical treatingprocess, taking into account treating temperature, chem-ical usage, and physical size of treating equipment. Un-fortunately, such a procedure is not available and theengineer must rely on experience and empirical data fromother wells or fields in the area and on laboratory ex-periments.

For example, the economic balance between the amountof chemical and heat to use to destabilize the emulsionand aid in coalescence is difficult to predict. Almost allemulsion-treating systems use demulsifying chemicals. Inmost instances, the lower the treating temperature, thegreater 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 lightcrudes that are produced. Other operators under the sameconditions add heat when treating similar crudes tominimize chemical cost and the size of the emulsion-treating equipment.Another example is the economic balance that must beconsidered between those factors that promote coalescence(chemicals, water wash, heat, coalescing plates, etc.) andthe size of the treating vessels. The larger the size of thetreating vessel, the smaller the size of water droplets thatcan be separated from the emulsion. Thus the use ofcoalescing aids may reduce the size of the equipment byincreasing 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 increasedcapital 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 timefor design purposes. Unfortunately, these tests are staticin nature and do not model closely the dynamic effectsof water droplet dispersion and coalescence that occur inthe actual equipment because of flow through controlvalves, pipes, inlet diverters, baffles, and water-washsections. Bottle tests, however, can be useful in estimat-ing treating parameters such as temperature, demulsifiervolume, settling time, etc.

When evaluating empirical data from similar wells orfields, the designer should recognize that the temperatureat which an emulsion is treated may not be as critical asthe viscosity of the crude at that temperature. The designof an oil-treating system can be assisted by observing anexisting system, knowing the viscosity of the crude attreating temperature, and calculating from the flow gemometry and Stokes law the minimum size water droplet


16/34


;cFLASH150 to 18OOFProduction Inlet15 to 30% cut TEMPERATURE OF SHELL SIDEAPPROXIMATELY 20Fr TREATER AT 280F1 CONDENSATETOWERLl

220FSTORAGE

1 I -I1 j-+ WATER

+ TREATED CRUDEAT 2% CUT

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 canthen be designed that will heat the emulsion to the tem-perature required to obtain the same viscosity that existsin the sample field, and then any one of the pieces ofequipment or combinations thereof described in the nextsection can be selected and sized so that all water dropletslarger than the calculated minimum diameter can be sepa-rated from the oil.

Because of the uncertainties in attempting to scale upfrom laboratory data or to infer designs from empiricaldata from similar wells or fields, a new treating systemshould be designed with either larger equipment or moreheat input capacity than the engineer calculates to be nec-essary. The amount of overdesign to be built into thetreating system depends on an assessment of the cost ofthe extra capacity balanced against the risk of not beingable to treat the design throughput.Description of Equipment Used inTreating Crude Oil EmulsionsThe characteristics of the emulsion to be treated shouldbe understood before a treating system is selected. Severaldifferent types of equipment or systems may satisfactorilyresolve an emulsion, but one particular type of equipmentor system may be superior to others because of basic con-siderations in design, operation, initial cost, maintenance

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

The combination of the various emulsion-treatingmethods 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 mayguide the buyer to the optimum combination of treatingmethods, but field testing will be required to confirm theselection.

The following discussion describes various emulsion-treating equipment and systems. Each piece of treatingequipment 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 untilthe desired treating results are obtained. The design andselection of all the components of the treating systemshould 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 asdesired or if operating conditions change, additional fea-tures can usually be added or operating procedures alteredto obtain the desired results.


17/34


WE13 NIPPLE TO MAINTAINGAS CUSHION IR VESSEL

Fig. 19.21-Typical vertical FWKO

Free Water KnockoutsWhere large quantities of water are produced, it usuallyis desirable to separate the free water before attemptingto treat the emulsion. When oil and water are agitated withmoderate intensity and then allowed to settle for a periodof time, three distinct phases normally will form: a layerof essentially clean oil at the top with a small amount ofwater dispersed in the oil in very small droplets, relativelyclean water (free water) at the bottom with a small amountof dispersed oil in very small droplets, and an emulsionphase in between. With time, the amount of emulsion willapproach zero as coalescence occurs.

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

Free-water knockouts (FWKOs) are designed as eitherhorizontal or vertical pressure vessels. Fig. 19.21 is aschematic of a vertical FWKO. and Fig. 19.22 shows ahorizontal FWKO. The fluid enters the vessel and flowsagainst an inlet diverter. This sudden change in momen-tum causes an initial separation of liquid and gas, whichwill prevent the gas from disturbing the settling sectionof the vessel. In some designs, the separating section con-tains a downcomer that directs the liquid flow below theoil/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 oilat the top, while the free water settles to the bottom. Whenthere is appreciable gas in the inlet stream, a three-phaseseparator can be used as an FWKO. See Chap. 12 fora description of both vertical and horizontal three-phaseseparators.

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 normallyat an angle to the horizontal of between 45 and 60. Ifa cone is used. it can be the bottom head of the vessel,or for structural reasons, it can be installed internally inthe vessel. In such a case. a gas-equalizing line must beinstalled 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 sandfrom the vessel.Oil and water are usually separated more quickly andcompletely in an FWKO when the liquid travels throughthe 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 throughan upward-moving stream; therefore, the downwardmovement of water is retarded by upward movement ofthe oil and emulsion.


18/34

19-18

L.L.C. ;VITH EIGHTED FLOAT TOSIP II: ?IL ND EMJLSION ANDFLOAT ONLY I:; REE VJATZR.


'wEIf?IPPLE TO MAINTAINOIL AND GAS GAS "CUSHION" IN VESSF3.a

PERFORATED WAVE I~PINGENENT

BREAKER OUTLET

FLUID IMLST

Fig. 19.22-Typical horizontal FWKO.

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

Many configurations are possible for providing bafflesand maintaining levels in an FWKO. A good design willprovide the functions described previously, i.e., degass-ing, water-washing, and providing sufficient retentiontime and correct flow pattern so that free water will beremoved from the emulsion.

When the free water is removed, it may or may not benecessary to treat the oil further. In many fields producinglight oil, a well-designed FWKO with ample settling timeand with a reasonable chemical-treating program can pro-vide pipeline-quality oil. Most often, however, furtheremulsion treating is required downstream of the FWKO.Storage TanksOil generally should be water-free before it is flowed intolease storage tanks. If there is only a small percentageof water in the oil and/or if the water and oil are looselyemulsified, however, it may be practical to allow the waterto settle to the bottom of the oil storage tank and to drawoff the water before oil shipment. This practice is notgenerally recommended or followed. but for smallvolumes of free or loosely emulsified water on small leasesor for low-volume marginal wells, it may be a practicaland economical procedure.

When a storage tank is used for dehydration, the oilis flowed into the tank and allowed to settle. When thetank 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 waterhas been separated from the oil by settling, water isdrained 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 standardstorage tank. If there is a water-wash, its shallowness andthe absence of a proper spreader causes it to be of littleor no benefit.Settling TanksVarious names are given to settling tanks used to treatoil. Some of the most common are gunbarrels, wash tanks,and dehydration tanks. The design of these tanks differsin detail from field to field and company to company. Allcontain all or most of the basic elements shown in Fig.19.24.

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

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


19/34

CRUDE OIL EMULSIONS

BAFFLE

19-19

BAFFLE(SIDE PERFORATED~

LEVEL CONTROLLER

, BAFFLE (SOLID?

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 dropletsthat will settle out of the emulsion.

There are many types of spreader designs. Spreaderscan be made by cutting slots in plate, use of angle iron,or holes in pipe. By causing the emulsion stream toseparate into many small streams, the spreader causes amore intimate contact with the water to help promotecoalescence in the water-wash section. This is shown inFigs. 19.25 and 19.26. Most spreaders contain small holesor slots to divide the oil and emulsion into small streams.Large holes (3 to 4 in. in diameter) will not be nearly aseffective in dividing the stream as small holes (/8 o 1 in.in diameter). In designing a spreader, however, it is im-portant that the fluid is not agitated to the point whereshearing 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 solidsand are difficult to clean. Free-flow coalescing devices,such as S.P. Packs TM (Fig. 19.18), can be installed onthe downcomer/spreader to promote coalescence and tominimize 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 theflow of the oil by gravity. Because there may be very lit-tle coalescence above the oil/water interface, increasingthe height of the oil-settling section above some minimumto aid in spreading out the flow may not materially affectthe oil outlet quality.

ADJUSTABLEIN:fPRPFCE

GASOUTLET

GAS SEPARATING G&S ECUALIZING

WELL PRODuCTtON

OIL SETTLING

Fig. 19.24-Typical settling tank with internal downcomer andemulsion spreader.


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1Q-20 PETROLEUM ENGINEERING HANDBOOK

rOtL SETTLING SECTION

NOTE VELOCITY OF WELL FLUID THRU-THE HOLES IN THE DISTRIBUTOR

INTO THE WATER WASH SHOULD NOTEXCEED I 0 FT PER SECOND ( !I

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

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

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 fromthe 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 approachplug flow conditions more nearly. The water outlet col-lector must prevent vortexing of the water and mustminimize horizontal movement of the water. The wateroutlet collector should be located near the tank bottom.There must be enough vertical distance between it andthe inlet spreader to allow sufficient clarification of thewater, and it should be at least 6 to 12 in. above the tankbottom 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-collectorsystem. It may be difficult to make these drains operatesatisfactorily because the water flow to each drain mustbe on the order of 3 ft/sec to suspend the sand. Sand drainsmay lengthen the amount of time between tank cleanings,but the additional cost of sand drains in tanks may notbe warranted.

In Fig. 19.24, the oil/water interface is established byan 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

wherehM.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, andY II = specific gravity of water.

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

It is also common to control the oil/water interface withinternal weirs or with an interface liquid-level controllerand a water-dump valve. In heavy oils, electronic probesare most often used to sense the interface and operate awater-dump valve. In lighter oils, floats that sink in theoil 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 onthe overall process selected for the facility, emulsion prop-erties, flow rates, and desired effluent qualities. WhileFig. 19.24 is representative of the majority of settlingtanks currently in use, other tanks have a different flowpattern. A series of parallel vertical baffles from the bot-tom of the vertical tank to above the oil level, as shownin Fig. 19.27, cause the flow of the emulsion to be


21/34


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

A direct fired heater, sometimes referred to as a jug*heater, is one in which the fluid to be heated comes indirect contact with the immersion-type heating tube or ele-ment of the heater. Direct fired heaters are generally usedto heat low-pressure noncorrosive liquids. These unitsnormally are constructed so that the heating tube can beremoved for cleaning, repair, or replacement.

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

Indirect fired heaters are less likely to catch on fire thandirect 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 individuallyremovable for cleaning and replacement. They tend to bemore expensive than direct fired heaters.Heat exchangers normally are used where waste heatis recovered from an engine, turbine, or other processstream or where fired heaters are prohibited. In complexfacilities, especially offshore, a central heat-transfersystem recovering waste heat and supplying it through heatexchangers to all process heat demands is sometimes moreeconomical and may be the only way to meet establishedsafety 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 andinto the flume pipe or gas boot of the gunbarrel tank. Thismoderate 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 gasboot. 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 adjustedover a wide range, providing additional flexibility.

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

Heat can also be supplied to the system by circulatingthe water in the water-wash section to a heater and backto 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

WATER OUTLET[BELOW)

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

driving force for the circulation if the heat source is notfar from the tank. The water also may be pumped to theheater and circulated back through the flume, as shownin Fig. 19.28. In this system, the settling space in the gun-barrel may be disturbed by gas released from the oil whenit comes in contact with the hot water. It has two advan-tages. First, oil will not be overheated because it nevercomes in contact with the heating element in the heaterbut is heated by the water bath in the gunbarrel. Thisminimizes vapor losses from the oil and tends to maintainmaximum oil gravity. It also minimizes coking and scal-ing. Second, this system is as safe from fire hazards asa system involving a fired vessel can be because onlywater flows through the heater. There is no oil or gas inthe fired vessel.

Settling or gunbarrel tanks can also be heated directlywith a fire tube, as shown in Fig. 19.29, or with internalheat exchangers, using steam or other heat media. Heatexchangers can be either pipe coils or plate-type heatingelements.

Plate-type heating elements are usually 18 to 32 in. byabout 5 to 8 ft. These usually are preferred over pipe coilsbecause the heat-transfer coefficient is 10 to 20% higherfor the plate-type heating elements when immersed in oilthan for a corresponding area of pipe. Further, the gentleagitation brought about by the convection flow of the oilup the surface of the plate-type element assists in coales-cence. Plate-type heating elements are available with awide range of pressure ratings. They can be purchasedfor steam service or hot-water service, but the same unitshould not be used for both because the construction ofthe cells is different for the two types of heating media.

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

When settling tanks are heated directly, they operatein much the same manner as vertical or horizontal emul-sion treaters.


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tGAS

WELL FLUID INLET- a-

WA+ER LEVEL-AAA-- I II II I

1 GUN BARRELAUXILIARY WELL INLET

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

P

IGAS VAPOR

AS OUTLET,-- DEGASSER BOOTe-INLET

:

OIL OUTLET

WATER OUTLET

Fig. 19.29-Heated gunbarrel emulsion treater.

WATEROUTLET

Vertical Emulsion TreatersThe 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 gasseparation 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 canbe very small. The gas separation section should have aninlet diverter and a mist extractor.

The liquid flows through a downcomer to the bottomportion of the treater, which serves as an FWKO andwater-wash section. If the treater is located downstreamof an FWKO, the bottom section can be very small. Ifthe total wellstream is to be treated, this section shouldbe sized for suffkient retention time to allow the free waterto settle out. This will minimize the amount of fuel gasneeded to heat the liquid rising through the heating section.

The oil and emulsion flows upward around the tire tubesto a coalescing section, where sufficient retention timeis provided to allow the small water droplets to coalesceand to settle to the water section. Treated oil flows outthe oil outlet. Any gas flashed from the oil because ofheating flows through the equalizing line to the gas spaceabove. 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 onthe fire tubes. This can be done by employing the 40rule-i.e., the operating pressure is kept equal to the


23/34

CRUDE OIL EMULSIONS

pressure of saturated steam at a temperature equal to theoperating temperature plus 40F. This is desirable becausethe normal full-load temperature difference between thefire tube wall and the surrounding oil is approximately30F in most treaters. Allowing 10F for safety, the 40rule 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 haypacks. In most applications these may not be needed, buta manway may be provided in case one may need to beadded 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 itenters the treater. For safety reasons, some offshore oper-ators prefer a heat-transfer fluid and a pipe or plate heatexchanger inside the treater rather than a fire tube.Horizontal Emulsion TreatersFor most multiwell leases, horizontal treaters normallyare preferred. Fig. 19.31 shows a typical design of ahorizontal treater. Flow enters the front section of thetreater where gas is flashed. The liquid flows downwardto near the oil/water interface where the liquid is water-washed and the free water is separated. Oil and emulsionrises 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, whichoperates a dump valve for the free water.

The oil and emulsion flows through a spreader into theback 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 atthe top through a collection device used to maintain uni-form vertical flow of the oil. Coalescing water dropletsfall countercurrent to the rising oil. The oil/water inter-face level is maintained by a level controller and dumpvalve for this section of the vessel.

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

The inlet section must be sized to handle separation ofthe free water and heating of the oil. The coalescing sec-tion must be sized to provide adequate retention time forcoalescence to take place and to allow the coalescing waterdroplets to settle downward countercurrent to the upwardflow of the oil.

Fig. 19.32 shows another design of a horizontal emul-sion treater with a different flow pattern that minimizesvertical flow of the emulsion. Oil, water, and gas enterthe top of the treater at the left side (facing the burners)and trave

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105409197 Crude Oil Emulsions