Emulsion and Oil Treating

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Oil and Gas Facilities EngineeringEmulsion and Oil Treating

Facilities Engineering OJT ModuleExxon Company, U.S.A.Production Department Training


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Copyright 1983, 1984, 1986Reprinted 1991by Exxon Company, U.S.A.a division of Exxon Corporation

All rights reserved. No part of this publication may be reproduced or used in any form withoutpermission from Exxon Company,U.S.A.By receipt of this publication, the recipient agrees to abide, for the term of the copyright specifiedabove, by the terms and conditions stated herein. No part of this publication may be reproducedor transmitted in any form or by any means without permission in writing from Exxon Company,U.S.A. This publication is leased to the recipient for the life of the document, and all propertyrights in the publication remain with Exxon Company, U.S.A. This lease is nontransferable, andthis publication may not be sold, leased, loaned, or otherwise transferred to any other party. Thislease constitutes a limited license, granted by Exxon Company, U.S.A. under copyright, whichspecifically restricts use of this publication to the recipient. Recipient will not reexport technicaldata contained in the publication, or export the direct product of such data, without priorauthorization by Exxon Company,U.S.A.By receipt of this publication, the recipient who is an employee of Exxon Corporation or anaffiliate of Exxon Corporation agrees upon termination of such employment, to deliver thepublication to Exxon Corporation or to the affiliate of Exxon Corporation with whom recipientwas last employed.


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TABLE OF CONTENTSAcknowledgements vIntroduction . . . VIModule Objectives. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Module Instructions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Lesson 1: Emulsion Theory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Emulsions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Minimization of Free Energy . . . . . . . . . . . . . . . . . . . . . . 6Factors Affecting Emulsion Stability . . . . . . . . . . . . . . . . 8Stabilizer Characteristics. . . . . . . . . . . . . . . . . . . . . . . . 8Oil Viscosity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Differential Density. . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Age of Emulsion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Size of Water Droplets . . . . . . . . . . . . . . . . . . . . . . . . . 10Water Percentage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Agitation 10

Exercise 1 11Lesson 2: Emulsion Treating Methods . . . . . . . . . . . . . . . . . . . . . . . . . 13Primary Crude Oil Treating Methods 14

Chemical Addition 15Bottle Test Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . 17Bottle Test Considerations 19Water Drop-Out Rate 19Sludge. . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . 20Interface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Water Turbidity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Oil Color . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Centrifuge 20

Chemical Selection Considerations 21Settling Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Heat............... . 24Electrostatic Coalescing 24

Exercise 2 25


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Lesson 3: Emulsion Treating Equipment 28Freewater Knockouts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29Gunbarrels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Heaters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Indirect Heaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Direct Heaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36Waste Heat Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . 37Heater Sizing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Flow Treaters (Heater-Treaters) . . . . . . . . . . . . . . . . . . . . 37Treater Sizing 39Estimating Heat Capacity . . . . . . . . . . . . . . . . . . . . . 39Quantity of Fluid. . . . . . . . . . . . . . . . . . . . . . . . . . . . 40Heating Rate . . . . . . . . . . 41Settling Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42Electrostatic Coalescers. . . . . . . . . . . . . . . . . . . . . . . . . . . 43Practical Design of an Oil Treating System 45Exercise 3 54

Lesson 4: Other Oil Treating Considerations. . . . . . . . . . . . . . . . . . . . 57Crude Oil Stabilization and Vapor Recovery 58Stabilizer Tray Design ... :..................... 59Sour Crude Stabilization. . . . . . . . . . . . . . . . . . . . . . . . 60Crude Oil Desalting 62Oil Storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65Vapor Recovery for Oil Storage Tanks. . . . . . . . . . . . 67Oil Storage Operating Considerations ; . . 68Oil Storage Design References. . . . . . . . . . . . . . . . . . . 69Exercise 4 70

Exercise Answer Key 73


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ACKNOWLEDGEMENTSSpecial appreciation is expressed to J. T. Brumble, East Texas Division,

for providing the technical content for Emulsion and Oil Treating. Thanks arealso extended to Joe V. Morse, East Texas Division, and Mike Krywanio,Southeastern Division-technical validators, and Jim Seale, Western Divisionand Robbie Schilhab, East Texas Division-primary training project com-mittee members.We acknowledge, with thanks, permission of the authors, publishers, orcopyright holders to reproduce the following copyrighted material:Fundamentals of Petroleum, 2d ed., Petroleum ExtensionService, The University of Texas at Austin, Austin, 1981.Smith Industries, Inc., Equipment Manual, Oil and GasDivision, Houston.Sivalls, Richard C., Crude Oil Treating Systems DesignManual, Odessa.

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INTRODUCTIONThis module is organized around four lessons that should be worked insequence.Lesson One, Emulsion Theory, describes emulsions and discusses the ba-sic principle of why emulsions fonn-the minimization of free energy. Thelesson also discusses the factors affecting the stability of an emulsion.Lesson Two, Emulsion Treating Methods, introduces the primary meth-ods for treating crude oil and describes the procedure for performing a bottletest which aids in determining the most effective method to treat an emulsion.

Lesson Three, Emulsion Treating Equipment, discusses the operation ofvarious emulsion treating equipment. This lesson presents several exampleproblems and demonstrates the practical design of an oil treating system.Lesson Four, Other Oil Treating Considerations, discusses crude oil sta-bilization, vapor recovery, desalting, and oil storage.During the past 10-15 years, innovations in automated equipment havemade it possible to measure and allocate untreated oil emulsions. This hasallowed for the use of more efficient systems for centralized oil treating fa-cilities. For example, the production from many fields is now treated in one

facility, whereas, prior to net oil measurement, a treating facility was requiredfor each lease or royalty interest. Central oil treating system designs vary inequipment from the simplest settling tank method (without adding heat) tomulti-vessel complex systems which include electrostatic vessels, desaltingprocesses, vapor recovery systems, and large storage tanks.Language in the oil and gas industry consists of many words and phrases(some of which are slang), but their usage as applied to production of oil andgas differs from the more normal usage. The same terminology may havedifferent meanings, varying from area to area. A list of some of the wordsand phrases used in crude oil treating operations can be found in the glossary

of the American Petroleum Institute's Introduction to Oil and Gas Production.In order to be effective in communicating with operations personnel, manu-facturers, management, and other engineers within the industry, the engineermust be familiar with terminology related to crude oil emulsions, treating, andstorage equipment.



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MODULE OBJECTIVESUpon completion of this module, you will be able to: Describe the bottle test procedure. Given flow conditions and other pertinent data, select emulsion treatingprocesses and equipment configurations which will effectively treat crudeoil emulsions to pipeline quality specifications. Describe the process and equipment used to accomplish crude oil sta-bilization, vapor recovery, desalting, sour crude treating, and crude oilstorage.

MODULE INSTRUCTIONSThis module is designed as a self-paced course and reference guide onemulsion and oil treating. The module consists of four lessons. At the begin-ning of each lesson are objectives which identify exactly what you are ex-pected to learn. Exercises are provided at the end of each lesson to reinforceyour understanding of the subject matter and to pinpoint problem areas whichmay require further study. Because this module requires various calculations,a small calculator is required. You should allow approximately five hours tocomplete this module.Upon completion of this module, you will be asked to take a short testto measure your overall comprehension of the course material, and to deter-mine whether you are ready to move on to more advanced modules in theFacilities Engineering OJT series.



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LESSON 1: EMULSION THEORY

LESSON OBJECTIVESUpon completion of Lesson 1, you will be able to: Describe emulsions and explain why and where they are formed. Describe and list the factors affecting emulsion stability. Define the following terms:-normal emulsion-inverse emulsion-stable emulsion-unstable emulsion

Explain the Principle of Minimization of Free Energy in a system.

Emulsion and Oil 'I'reatinz


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EMULSION THEORYA large amount of crude oil is produced with some quantity of water (free

water, emulsified, or both) that requires chemical and/or mechanical sepa-ration (Figure 1). The primary purpose of oil treating and storage is to meetthe sales requirements at the point of custody transfer between the producerand the transporter, e.g., to deliver a crude oil product with less than 1 percentBS&W (basic sediment and water) at an acceptable product temperature andvapor pressure. This lesson discusses emulsion theory which affects the ef-ficiency and effectiveness of separating crude oil from the water phase.-

PRODUCED F LU ID SEPARATED FLU ID AFTER CHEM ICALA ND /O R M EC HA NIC AL S EP AR ATIO NFigure 1 - Separation of Crude Oil from the Water Phase



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EMULSIONSAn emulsion is a mixture of two immiscible liquids in the presence of astabilizer. Most oil-water emulsions occur with water droplets dispersed in themixture as the internal phase. Figure 2 depicts a normal emulsion where theoil is the external phase. Also, note that the water droplets vary in size.

@ WATER 0FILM eEXTERNALPHASE (O IL )Figure 2 - Normal Water-in-Oil Emulsion

There are numerous theories about emulsions and their formation; butafter more than a century of investigation and field testing, breaking and han-dling of oil field emulsions remains mostly an art rather than a science. Oil-water emulsions are sometimes formed in the producing formation by tertiaryprojects, downhole pumps, downhole tubular equipment, flowlines, separa-tors, chokes, valves, pipe fittings, and surface pumping equipment. Two thingsare necessary to produce an emulsion of oil and water-agitation and a sta-bilizing (emulsifying) agent.Stabilizers are particles which prevent the union (coalescence) of the in-ternal phase droplets. They can come from the reservoir (asphaltines, silts,etc.), corrosion by-products (iron sulfides), oxygenated sulfur compounds, oreven stabilizer compounds from within salt water. Stabilizers are preferentiallyadsorbed at the interface between the oil and water phases. The interface pro-vides an environment of unbalanced molecular forces that are attracted to thedissolved stabilizers. Once these contaminants are adsorbed at the interface,they form a tough film that impedes or prevents the union of water dropletsin oil when they collide with one another. Thus, the contaminants are said to



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stabilize an emulsion. Figure 3 is a photomicrograph of a water-in-oil emul-sion. This figure shows two water droplets touching but unable to merge be-cause of the film around the droplets.

Figure 3 - Photomicrograph of a Water-in-Oil Emulsion (Cour-tesy PETEX)

Emulsions exist predominantly in the form of water-in-oil (normal emul-sion). The water droplets vary in size from large drops to small drops of aboutIll- (0.000039 inch) in diameter. The physical character of the water and oil(specific gravity, surface tension, viscosity, chemical constituents, etc.) andproduction methods determine the size, distribution, and stability of emulsionparticles.As the ratio of water to oil increases to predominantly water, there is atendency for inverse, or oil-in-water emulsions to form. Two different typesof oil-in-water emulsions are commonly found in oil production operations,and these are distinguished from one another by the relative amounts of waterand oil present in the system. Inverse emulsions contain a fairly large amountof oil (1-50 percent on a volumetric basis) and are typically encounteredwhenever a large amount of water is produced from an oil well. Waste oil-in-water emulsions contain a very small amount of oil on a volumetric basisand are typically encountered in the waste water streams leaving a productionsystem. These waste streams have normally undergone a settling period in the



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production system. They contain predominantly small oil droplets which aredifficult to coalesce. Because of the increased emphasis on environmental con-servation and governmental regulations in the treatment of waste water, thesetypes of emulsions are of high interest to the facility engineer.

MINIMIZATION OF FREE ENERGYThe formation of emulsions is based upon the thermodynamic principle-minimization of free energy (Figure 4). Free energy is the internal energy ofa system minus the product of its temperature and its entropy. This principlestates that, "the condition for equilibrium in any type of system is that statein which the free energy of the system is minimized." In systems having sev-eral chemically pure phases (i.e., immiscible liquids, vapors, solids, etc.), thefree energy of the system is simply the sum of the free energy associated withmaterial in the bulk phases (water and oil) plus the free energy associated withthe interfaces between the phases.

COALESCENCEOF WATERDROPLETS

Figure 4 - Principle of Minimization of Free Energy

G = Gbulk + Ginterfacewhere:

G = free energy.Gbulk = free energy for all material in the bulk phases.

Ginterface = free energy for all material at the interface betweenphases.



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For a given phase distribution, the magnitude of Gbulk in the above equa-tion is fixed so that the only way to minimize G is to minimize the interfacialcontribution, Ginterface' This contribution is proportional to the interfacial ten-sion, (J'ab between two phases a and b and the interfacial area, Aab, betweenthe two phases.

Ginterface = L ((J'ab Aab)The summation includes all interfaces in the system. Thus, to minimize thetotal free energy of a chemically pure system, it is necessary to minimize thesurface area between the distinct phases in the system.

One common example of this principle is a small raindrop falling throughthe air. If the viscous effects of drag are neglected, the drop will assume aspherical shape since this geometry provides the smallest surface area for agiven volume of water and thus, free energy is minimized.A second example would be a beaker containing two pure components-liquid water and liquid hydrocarbon (e.g., hexane). The equilibrium config-uration for such a system is one in which all of the water exists in a singlephase at the bottom of the beaker and the hexane is in a single phase floatingon top of the water. This configuration is attained even if the mixture is shakenvigorously to form an emulsion initially. After standing for some time, the

above final equilibrium state will be realized because it minimizes the freeenergy for the composite mixture.From this discussion, it is obvious that some additional mechanism mustoperate in order to form and stabilize emulsions that do not coalesce over aperiod of time. This mechanism is provided by impurities in the different liq-uid phases. These materials, called stabilizers, are usually complex, long chainorganic compounds which are both polar and non-polar. The adsorption ofstabilizers at the interface provides enough negative free energy to overcomethe positive contributions to free energy due to the increased surface area pro-vided by the emulsion.



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Absorption of the stabilizers at an interface takes some time to occur. Thetime element can have a very important bearing upon the difficulty encoun-tered in breaking emulsions in production systems. Indeed, emulsions whichare allowed to age are significantly harder to break than those which have Ilotaged. Consequently, in many production facilities the emulsion breaking ortreating operations are located as close to the wellhead as possible, so that theemulsions formed during flow in the production tubing and wellhead equip-ment are not allowed to age before treatment.

FACTORS AFFECTING EMULSION STABILITYA stable or tight emulsion is one which will not breakdown without someform of treating. The size of the water droplets is a good measure of stability.If the water droplets will not settle out of the oil because of their small sizeand surface tension, then treating is required, and the emulsion is describedas stable or tight. If the water droplets vary considerably in size and if mostof the water droplets are relatively large, then the emulsion is described asunstable or loose.The stability of an emulsion is dependent upon several factors. Thesefactors are: stabilizer characteristics oil viscosity differential density (oil-water) age of the emulsion size of the water droplets water percentage agitation

Stabilizer CharacteristicsThe type of stabilizer present is probably the most important factor indetermining the stability of emulsions. Without a stabilizer, the formation ofa stable emulsion would be impossible. There is no doubt that there is a con-siderable difference in the stabilizing effects of the various agents for differentconditions, but there are too many variables to permit even simple generaliza-tions to be made about their specific or relative activity.



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Oil ViscosityAn oil with a high viscosity, that is, an oil which flows slowly, tends tomaintain much larger drops of water in suspension than one with a low vis-cosity. Furthermore, a high viscosity oil requires much more agitation to createwater droplets as numerous or fine as a lower viscosity oil. Thicker crudesalso retard the migration of stabilizer particles to the interface. In general,higher viscosity crudes form less stable emulsions in terms of numbers ofsmall water droplets, but this is more than offset by the difficulty of waterseparation.

Differential DensityDifferences in densities (specific gravities) between oil and water phasesare used to some extent in all treating systems. If an oil is heavy (a highspecific gravity), it tends to keep water droplets in suspension longer. For alight oil (low specific gravity), water will not be suspended in the oil phaseso readily and will settle to the bottom of the tank. Therefore, other factorsbeing equal, the greater the difference in density between the oil and waterphases, the easier the separation .

.Age of EmulsionLittle or no emulsion exists in the oil bearing formation. The emulsionis formed during the production of the fluid and the degree of emulsificationis dependent on the agitation of the two phases by pumps, chokes, valves,etc. Before an emulsion is produced, the emulsifying agents (stabilizers) areevenly dispersed in the oil. As soon as the water phase is mixed with the oil,the stabilizing agents begin to cluster around the water droplet to form a stableemulsion. The hydrophilic (water loving) groups of stabilizers are attracted bywater and are extracted from the oil to produce an interfacial film around thewater droplet. While the initial stabilization may occur in a matter of a fewseconds, the process of film development may continue for several hours. Infact, it will continue until the film around the droplet of water is so dense that

no additional stabilizer can be attracted or until there is no more stabilizer leftto be extracted from the oil. At such time the emulsion has reached a state ofequilibrium and is said to be an aged emulsion. The time required for thisaging to occur varies from a few minutes to several hours. The older the emul-sion, the more difficult it is to treat.



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Size of Water DropletsAs discussed earlier, water droplet size varies from minute to large. Sincespecific gravity is an important factor in the separation of oil and water, gen-erally emulsions containing large water droplets tend to be less stable and areeasier to separate.

Water PercentageAs the water percentage increases, more agitation is required to com-pletely emulsify the 'water. Upon complete emulsification, a high water per-centage emulsion has a greater number of water droplets per unit volume which

increases the possibility and rate of contact between droplets. In general, largewater percentages tend to form less stable emulsions.

AgitationThe type and severity of agitation applied to an oil-water mixture gen-erally determines the water drop size. The more turbulence and shearing actionpresent in a production system, the more the water is divided into smaller andsmaller drops, and the emulsion becomes more stable.



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EXERCISE 11. A normal emulsion is _

a. water-in-oilb. sand-in-oilc. oil-in-waterd. water-in-stabilizerse. emulsifiers-in-stabilizers2. The factors that affect the stability of an emulsion are

a.b.c.d.e.f.g.

3. The free energy of a system is the sum of the bulk phase free energy andthe free energy of the between the phases.4. Particles which prevent the union of two phases are _a. immiscible agentsb. emulsifying agentsc. reverse agentsd. stabilizing agentse. band d5. In order for emulsions to form, and _

_____ are necessary.



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6. Match the following terms:__ inverse emulsion__ stable emulsion__ normal emulsion__ unstable emulsion

a. water-in-oilb. easy to separatec. oil-in-waterd. difficult to separate andrequires treating7. (TRUE or FALSE) The greater the differential density between the oil andwater phases, the easier the separation.8. (TRUE or FALSE) The older the emulsion, the more difficult to treat.9. (TRUE or FALSE) The more agitation induced, the more unstable theemulsion becomes.

CHECK YOUR ANSWERS AGAINST THOSE ATTHE END OF THE TEXT.



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LESSON 2: EMULSION TREATING METHODS

LESSON OBJECTIVESUpon completion of Lesson 2, you will be able to: List and describe the four methods for treating emulsions. Describe the bottle test procedure. Describe the difference between the tank battery concept and the cen-tral oil treating concept.



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EMULSION TREATING METHODSConditioning of crude oil to pipeline quality has historically been referredto as separation, treating, and storage. In recent years, various projects, suchas tank battery consolidation and automation, have resulted in new terminol-ogy being used for separation, treating, and storage facilities which descnbethe changes in oil field configuration. For years, and still existing in somefields, the tank battery is the name applied to the central location where thetotal production from a number of individual wells is separated, individualwell tests are conducted, the oil treated, and oil custody transfer takes place.

Inthe past, at least one tank battery was used for each royalty interest or lease.If a large number of wells were drilled and/or the lease covered a large area,more than one tank battery was constructed.

By moving the treating and storage or custody transfer facilities to a lo-cation remote from the primary separation facilities, new names evolved. Thelocation which contains the treating and custody transfer facilities is generallycalled a central tank battery or central treating station. In CPC (ComputerProduction Control) terminology, this may be referred to as the battery. Thelocation which contains the primary separation facilities may be referred to asanyone or all of the following: a test and separation station, a separationstation, a test site, a metering site, a satellite tank battery, a battery, or inCPC terminology, it may be a metering point or a sub-battery, or a combi-nation of sub-batteries and metering points. In some fields, even though theyare automated, operations personnel still continue to call these sites tank batteries.PRIMARY CRUDE OIL TREATING METHODS

Separating water from produced oil has been performed by various in-genious schemes with varying degrees of success. The problem of removingemulsified water has grown more widespread, and oftentimes more difficult,as producers lift more water with oil from water-drive formations, waterfloodzones, and wells stimulated by thermal and chemical recovery techniques.The pipeline industry views treating as a necessity to prevent overloadingtheir systems and as a method of reducing internal corrosion in their pipingsystems. Due to the large volume to be handled, the pipeline companies mustset certain specifications for oil entering their systems. These specificationsvary slightly among companies and among localities, but usually not more



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than one to two percent of foreign material may be present in the oil. Asidefrom the extra load, foreign materials (especially sand and water) are probablythe greatest contributors to wear and corrosion. Foreign materials present veryserious problems in the maintenance of old pipeline systems. Pipeline com-panies specify and perform sampling and measurement procedures to ensureoil quality,

Normally, the responsibility of treating oil to pipeline quality belongs tothe field operator (pumper) and Field Superintendent; however, the engineeris sometimes asked to help solve difficult treating problems, and certainlywhen new systems are designed or old systems modified, some knowledge ofoil treating technology and operation of oil treating equipment is required.The term treating refers to any procedure which is designed to separateforeign matter from crude petroleum. This foreign matter may include water,sand, sediment, or any other impurity in the oil. (Paraffin and asphalt are notgenerally considered impurities.) The actual treating process requires somecombination of the following: chemical addition settling time heat electrostatic coalescing

Chemical AdditionAn emulsion can be modified by the addition of chemical destabilizers(demulsifiers) by chemical injection pumps (Figure 5). These surface activeagents are absorbed at the water-oil interface, rupture the skin and/or displacethe stabilizer, and force the stabilizer back into the oil. As a result of addingthese chemicals, there is a lowering of the interfacial tension of the droplet.Apparently, the destabilizer functions (at least in the early stages of the pro-cess) by adsorbing at the oil-water interface where it spreads with sufficient

pressure to displace the natural stabilizing agent from the surface. This leavesan interface covered or partially covered with a very thin film which offerslittle resistance to coalescence.



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Figure 5 - Chemical Injection Pump

Time and turbulence aid diffusion of the treating chemical through theoil to the interface; therefore, it is more effective to add the destabilizer to theoil at the wellhead. Since the chemical must contact each stabilized waterdroplet in order to destabilize it, the chemical should be thoroughly mixedwith all of the emulsion. Generally, this is accomplished by adding the chem-ical as far upstream in the producing system as possible. This gives minimumtime for the stabilizer to concentrate at the interface and provides maximumagitation and time for the chemical destabilizer to work. The ultimate treatingmethod is to inject the chemical downhole; however, mechanical difficultiesmake the downhole injection method useful in only a few instances.

Chemical injection into the flowline near the wellhead would be an idealapproach; however, with many well systems, chemical injection at each wellpresents problems. The initial cost of many injectors is high and maintenanceand service is very time consuming.A compromise is sometimes used in that injectors are installed on a few

wells instead of all of them. Care must be exercised in selecting such wells.A good choice is a well producing a tight emulsion and high volumes of fluidcontinuously, or one whose flowline joins others before reaching the mainheader or treating plant.

Emulsion and Oil Treatin2


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A common point of chemical injection is at the main header. Injectionhere ensures that the chemical will be introduced continuously into all of theproduction fluid. The single injector gives a low-cost initial installation andprovides for minimum maintenance and servicing. Such savings may offsetthe cost of extra chemical which is usually required because of less agitationand time.In-line turbulators (mixers) can be installed in the flowline downstreamof the chemical injection point. These devices ensure a turbulent flow regimeand a thorough mixing of the chemical and the emulsion. Equipment and in-stallation costs are minimal, and chemical costs are also minimized by usingturbulators.The quantity of demulsifier necessary to produce the desired degree oftreatment is influenced by many factors. Among these are tightness (stability),agitation, temperature, and time. The variety of such influences and their com-binations makes it impossible to set a specific amount or ratio. An indicationof the amount necessary for a given system may be determined from a pre-liminary bottle test, but the optimum amount can only be found through trialand error in the plant. As a general technique, start with one quart per 100barrels of oil.Experience is a very useful teacher in selecting demulsifiers. Familiaritywith the history of treating in an area, the demands of the treating plants, andthe performance of chemicals are all valuable aids for selection; however, thisapproach should not be used when changes occur in emulsion characteristics,new emulsions are encountered, or new chemicals become available.

Bottle Test ProcedureBy far, the bottle test is the most successful means of selecting chemicalsto break emulsions. It involves adding various chemicals to samples of theemulsion and observing the results. The bottle test (Figure 6) is not a foolproofapproach, but when accomplished by a competent person, it will provide goodresults. There has been much criticism of the bottle test, but this stems mostlyfrom a lack of understanding of the test. This simple test has proven to bevery effective in (1) selecting the most efficient chemical, (2) providing anaccurate estimate of the amount of chemical required to break the emulsions,and (3) providing an estimate of settling time for vessel sizing.



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Figure 6 - Bottle Test (Courtesy PETEX)

Chemical sales companies provide samples of various families of chem-icals which can be tested on the particular emulsion. Once the most effectivefamily of chemicals is selected, then it becomes a matter of testing 20-50different formulations for the most efficient surfactant (surface active) chem-ical. Chemical sales representatives will normally conduct the bottle tests.

Three basic criteria must be followed in conducting bottle tests. Bottle testing should always be performed on a representative sample. Bottle testing should be performed as soon as the sample is obtainedbecause of possible detrimental aging effects. Testing should be performed as close to field treating conditions aspossible, i.e., agitation, heat, and settling time.Results of the bottle tests can be tabulated to determine which chemicalworks successfully in a given equipment configuration.



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Data Collected Use Freewater dropout readings ver-sus time for various chemicals andchemical concentrations.

Freewater knockout or three-phaseseparator vessels can be sized.Chemical costs can be calcu-lated. Vessel costs can beestimated . Remaining emulsion, as percentsaltwater can be determined. Treating system design can becompleted. Selection of the treat-ing vessel (electrostatic coales-cers, heater-treater, etc.) can be

made.The bottle test is used to select the most efficient chemical for a new oilfield; however, it should be used from time to time in existing fields to ensurethat the most efficient chemical for the currently existing emulsion is beingused. Many times, larger settling vessels are installed at great expense to pro-vide adequate settling time for the chemical being used when a more efficientchemical could have reduced the settling time required. Emulsions changeover the years in the same oil field as stabilizers change and as salt waterpercentages change.

Bottle Test ConsiderationsThe best demulsifier is the compound which results in the most rapid andcomplete separation of the phases at a minimum concentration. The importantcharacteristics in the bottle test will be dictated by the production needs andthe behavior of the system.

Water Drop-Out RateIn a high water volume system, a chemical that creates a fast water drop-

out is necessary to make the system function as designed. When free waterknockouts are used, the speed of water drop-out may become the most im-portant factor. Chemicals with fast water drop-out characteristics are some-times incomplete in treatment. In low volume systems or those fields withfacilities having longer than normal residence times, rate of water drop-outmay be of minor significance in selecting the best demulsifier. In all cases,the rate of water dropout should be noted and recorded.



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SludgeWhen basic sediment and water collect without breaking to water and oil,the result is commonly called sludge. In some systems, non-coalesced waterdroplets result in a loose agglomeration which breaks to water and oil causingno problems. Depending upon the system and sludge stability, interface sludgemayor may not cause a problem. Sludge is stabilized by finely divided solidsand other contaminates to form pads which cause a secondary emulsion locatedbetween the oil and water. Loose interface sludge can be detected by swirlingthe test bottle about its vertical axis, and if the material is loose, it will break.

InterfaceThe desired interface is one which has a shiny oil in contact with water.This is commonly referred to as a mirror interface. In all instances, the in-terface using a new chemical should be as good as that formed by the chemicalbeing replaced, if not better.

Water TurbidityThe turbidity (clarity) of the water is very difficult to interpret in the bottletest and correlate to plant behavior. When the chemical effects in the bottles

are pronounced and reproducible, some correlation can be expected. Clearwater is definitely the desired result.Oil Color

A characteristic of emulsions is their hazy appearance in contrast to thebright color of treated oil. Consequently, as a crude oil emulsion separates,the color tends to brighten. Although brightening of the oil can be encour-aging, it can also be deceptive if taken as the sole qualification for chemicalselection. While bright color is no guarantee of a successful chemical, lackof it assures that the compound is not worthy of further consideration.Centrifuge

An important quality in bottle testing is the final evaluation of the cen-trifuge results. It is always a good practice to make a centrifuge grind-out toaccurately determine the final amount of BS&W entrained in the oil.


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Chemical Selection ConsiderationsA thorough understanding of the treating plant and its contribution to the

treatment are necessary before chemical selection can be made. If little agi-tation is available, a fast-acting chemical is necessary. If a free water knockoutvessel is used, water dropout rate will be very important. Ifheat is unavailable,the chemical must work at ambient temperatures. Different type treating ves-sels require different chemical actions.

For a settling tank or gun barrel (Figure 7), speed is generally not tooimportant since such tanks usually have a high volume-to-throughput ratio.The chemical may continue acting over a relatively long period. An interfacelayer often develops, but usually stabilizes at some acceptable thickness. Aninterface layer in a gunbarrel sometimes aids the treating process in that it actsas a filter for solids and unresolved emulsions. Fresh oil containing demulsifierpassing up through the interface layer helps treat the interface and preventsan excessive buildup.

Figure 7 - Gunbarrel



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The vertical treater (Figure 8) volume-to-throughput ratio is usually lowerthan a gunbarrel so the speed of chemical action becomes more important.With this higher throughput, it is harder to stabilize an interface layer, so morecomplete treatment is necessary in a shorter time period. Solids control rimybe important in controlling the interface.

Figure 8 - Vertical Treater (Courtesy Smith Ind., Inc.)



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A horizontal treater (Figure 9) usually has high throughput so chemicalaction must be fast. The large interface area and shallow fluid depth requirethat the interface be fairly clean. Since this treater can tolerate only very littleinterface accumulation, the chemical treatment must be complete. Since solidstend to collect at the interface, the chemical must also effectively de-oil anysolids so that they may settle out by gravity.

Figure 9 - Horizontal Treater (Courtesy Smith Ind., Inc.)Settling Time

Following the addition of treating chemicals, settling time is required topromote gravity segregation of the coalescing water droplets. Anyone of anumber of settling-treating vessels may be designed to provide sufficient timefor free water to settle. Three-phase separators, freewater knockouts, heater-treaters, and gunbarrels are examples of settling/treating vessels. The timenecessary for free water to settle is affected by the differential density of theoil and water, viscosity of the oil, size of the water droplets, and more spe-cifically by the relative stability of the emulsion. Due to the variety of factorsinfluencing settling time, it will vary considerably from one system to another.Experience and preliminary bottle tests will give some indication of settlingtime required.



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HeatMost treating plants use heat in the treating process, since it aids in mix-ing' coalescing, and settling. Heat promotes the treatment by reducing viscosity of oil. weakening or rupturing the film between the oil and water drops byexpanding the water. altering the differential density of the fluids.In effect, heat accelerates the treating process and is used primarily to

reduce the size of the treating vessel. It must be emphasized, however, thatheat vaporizes the light hydrocarbons of the oil causing shrinkage, and unlesssome means is provided to conserve these hydrocarbons (i.e., installation ofa vapor recovery system), a reduction in API gravity and volumes will result.A gravity loss of 10 API causes a volume loss of 2.75 percent of 30.00 APIcrude. Excessive use of heat may result in reductions of crude prices in fieldswhere the API gravity is the basis for crude oil price. Heating of crude emul-sions is very expensive, and as heat is increased in a treating vessel, main-tenance problems increase. It is generally better to use slightly more chemicaland less heat so that volume and gravity losses are minimized.

Electrostatic CoalescingElectricity is frequently used instead of heat as an aid to the treating pro-cess. It is particularly valuable where space is important since the use of elec-tricity accelerates the settling process even more than heat and allows for useof a smaller vessel.As an emulsion passes through an electrical field, the small water dropletsare polarized and then stretched due to the polar attractions. This polarizationgreatly increases the speed and force of impact of the particles as they areattracted to the electrode. Because of the weakened film due to surface stretch-ing and because of the greater collision force due to increased speed, the drop-lets unite more readily. The electric field works best on loose emulsions andcannot tolerate solids. Therefore, the use of chemicals is generally necessary.



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EXERCISE 21. The term used to describe a procedure which is designed to separate for-

eign matter from crude oil is _a. meteringb. dehydratingc. treatingd. chokinge. absorption2. The location which contains the treating and custody transfer facilities iscalled a _

a. net oil detector facilityb. central treating stationc. primary separation facilityd. central tank batterye. b or d

3. (TRUE or FALSE) The tank battery terminology is applied to a centrallocation where the total production from individual wells is separated,tested, treated, and transferred.4. List the four primary methods of separating water from crude oil.

a . ~ -b . _ _ _c . _d . _ _ _

5. Agents absorbed at the water-oil interface to lower the interfacial tensionare called _a. emulsionsb. surfactantsc. coalescersd. destabilizerse. b or d



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6. The most efficient method to determine the chemicals to treat an emulsionis accomplished by _a. the bottle testb. electrostatic coalescencec. heatingd. agitatione. injection

7. The quantity of demulsifier necessary to produce the desired degree oftreatment is influenced bya.b .c.d.

8. (TRUE or FALSE) Bottle testing should always simulate field conditionsas close as possible.9. When selecting a chemical to treat an emulsion _

a. speed is generally not a consideration for a settling tank or gun barrelb. speed becomes a more important consideration for a vertical treaterc. speed is not an important consideration for a horizontal treaterd. all of the abovee. a and b only10. Settling time _

a. is usually required after chemical additionb. is dependent upon the differential density of the oil and waterc. is the time required for free water to separate from the emulsiond. all of the abovee. a and conly

Emulsion and Oil Treattna


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11. Heat is generally used in most treating systems because it aidsa.b.c. __

12. The application of heat in the treating process __a. reduces the size of the treating vesselb. may vaporize the light hydrocarbons in the oilc. is very expensived. all of the abovee. a and b only

13. Treating emulsions by electrostatic coalescing _a. accelerates the settling process more than heatb. increases the speed and force of impact between particlesc. requires a vessel larger than one that uses heatd. all of the abovee. a and b only




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LESSON 3: EMULSION TREATINGEQUIPMENT

LESSON OBJECTIVESUpon completion of Lesson 3, you will be able to: Describe the operation of emulsion treating equipment. Select the proper freewater knockout vessel dimensions, given the totalfluid production. Calculate the external water leg height for a gunbarrel, given the liquidgravity, height of the oil outlet, height of interface level, and heightof the water outlet. Determine the heating capacity required to size a treater, given theliquid production rate. Design an oil treating system, given the lease data, equipment costs,and operating costs.



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EMULSION TREATING EQUIPMENTTreating systems are some of the most expensive and troublesome of all

lease surface equipment. By selecting the most efficient treating system foreach location and accurately determining the exact size of equipment required,considerable expense can be saved.

FREEWATER KNOCKOUTSMost well streams contain water droplets of varying sizes. If they collectand settle to the bottom of a sample within five to seven minutes, they arecalled free water. This is an arbitrary definition that is generally used in de-signing equipment to remove water that settles out rapidly.One of the most effective pieces of equipment used to remove free waterfrom crude oil streams is called a freewater knockout (Figure 10). Freewaterknockouts should be located in the production stream where turbulence hasbeen minimized. Restrictions such as chokes or line fittings create turbulencewhich aggravate emulsions. Free water frequently settles readily to the bottomof a freewater knockout. The separated water enters the water disposal system,and the other stream components continue on for further processing.

GASINLET-

- WATEROUTLET

Figure 10 - Cutaway View of a Freewater Knockout (CourtesySmith Ind., Inc.)



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Capacities and pressure ratings for these vessels are readily available fromsuppliers. Since retention time is the only governing factor, the throughputrate and the volume of the vessel are the significant design criteria. Free waterfallout is greatly affected by temperature and gravity of the oil. A simple fieldcheck is often used to observe a fresh sample of wellhead emulsion to deter-mine the time required for free water to segregate. Abnormal volumes of gasin the wellhead stream may require proportionately larger vessels as these vol-umes affect the throughput rate. In many field installations where abnormalvolumes of gas are present, a two-phase vertical gas-oil separator is installedupstream of the freewater knockout to remove most of the gas and reduceturbulence in the settling vessel.Because of their location in the treating process flow stream, freewaterknockouts are generally 50 psig working pressure or less. They should beconstructed in accordance with the ASME code when purchased. All nozzlesshould be flanged, and the internal shell of the vessel should be coated orotherwise protected from corrosion since salt water will contact most of theinternal shell surfaces. To size the vessel for settling time, it is recommendedthat only the volume of the vessel occupied by the salt water be used. Thisprovides a safety factor for high percentage salt water fluid streams.

Example 1- Freewater Knockout Vessel SizingProblem: After performing a bottle test, a freewater vessel is to be installedto provide a minimum of 12 minutes retention time. A maximumof 4,000 BID total fluid is required to be processed. Salt water willoccupy 80 percent of the internal volume of the vessel.

Given:HorizontalVessel4' x 10'6' x 15'8' x 20'10' x 30'

Solution: 1. Calculate the volume (-rrr2L), in barrels (5.615 cu.ft. per barrel),for each vessel and reduce that volume by 20 percent.



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Horizontal MaximumVessel Volume, Bbls. 80% of Volume, Bbls.4' x 10' 22.4 17.96' x 15' 75.5 60.48' x 20' 178.9 143.210' x 3D' 419.4 335.5

2. Convert 4000 B/D to barrels per minute (2.8 B/min.) to de-termine the required retention time for each vessel at 80 percentof volume.Vessel Retention Time, Min.4' X 10'6' X 15'8' x 20'10' X 30'

17.9/2.8 = 6.460.4/2.8 = 21.6143.2/2.8 = 51.1335.5/2.8 = 119.8

Since the 6' x 15'FWKO provides more than enough retentiontime, it should be selected.

GUNBARRELSGunbarrels (Figure 11) are the oldest means used for oil treating in aconventional tank battery treating configuration. They are large tanks usually

having center flumes extending 2-5 feet from the bottom of the tank to 6-12feet above the top of the tank. The vessel is nothing more than a large at-mospheric vented settling tank which is normally higher than the oil storageor stock tank. This enables gravity flow of oil into the storage tanks. Theemulsion normally flowing from a separator, enters the flume where gas isliberated off the top and the oil-water mixture settles to the bottom of the tank.Exiting at the bottom of the flume, the mixture rises to the top of the sur-rounding layer of water. The water level is controlled by a water leg or au-tomatic water bleeder. The emulsion passage through the water helps collectthe entrained water and converts the emulsion into distinct oil and water identi-ties which continue gravity separation. Oil accumulates at the top and flowsout through the spillover line into the stock tanks. The water flows from thebottom of the tank, up through the water leg and into a surge tank or salt watergathering system. The height of the water leg regulates the amount of waterretained in the gunbarrel. Settling time in the vessel for the total fluid streamis usually 12-24 hours.



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OIL OUTLET -OIL

WATER

LEG

- WATER OUTLET

Figure 11 - Gunbarrel CutawayAPI 12 series specifications are the accepted industry standards for tanksused as gunbarrels. Gunbarrels normally vary in capacity from 250-2000 bar-rels and are either galvanized bolted steel or welded steel plate construction.Since final treatment to pipeline specification is the design criteria, heat mayalso be necessary to meet pipeline specifications. This may be accomplishedby applying heat upstream of the gunbarrel or, in rare instances, installing aheating coil in the gunbarrel. It should be emphasized that excessive heat,although reducing chemical costs, results in evaporation and API gravity losses.One of the design considerations for a gunbarrel is determining the heightof the external water leg (automatic water bleeder). The external water legcontrols the oil-water interface inside the gunbarrel and automatically allowsclean oil and salt water to exit the vessel. The following is an example problemillustrating this design consideration.



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Given:Oil gravity (at 600P)Water specific gravityHeight of oil outletHeight of interface levelHeight of water outlet

36API1.0523 ft.10ft. (for this example)1 ft.

141.5 141.5Oil specific gravity = 131.5 + 0API = 131.5 + 36 = 0.845Oil gradient* = 0.433 x 0.845 = 0.366 psi/ftWater gradient* = 0.433 x 1.05 = 0.455 psi/ft*Since the change in pressure with depth for fresh water is 0.433 psi/ft. of depth, the change inpressure with depth of fluid whose specific gravity is "t- would be 0.433-y.

Hydrostatic pressure inside tank = Hydrostatic pressure in the waterleg.Solution: 1. Calculate the height of the oil and the height of the water in thegunbarrel.

H; = 23' - 10' = 13'H; = 10' - I' = 9'

2. Perform a pressure balance.13ft. x 0.366 psi/ft + 9 ft. x 0.455 psi/ft =H x 0.455 psi/ft.13 x 0.366 + 9 x 0.455H =--------- 0.455= 19.5 ft.



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HEATERSHeaters are vessels used to raise the temperature of the liquid before it

enters a settling tank. Heaters have long been one of the major pieces of equip-ment used to treat crude oil emulsions. There are two types of heaters thathave been widely used in the oil industry, direct heaters and indirect heaters.Most heaters have two basic elements-a shell and firebox. Indirect heatershave a third element which is the process flow coil. Heaters have standardaccessories such as burners, regulators, relief valves, thermometers, temper-ature controllers, etc.

Indirect HeatersIn the indirect heater (Figure 13), oil flows through tubes which are im-mersed in water which in turn is heated by a fire-tube. An indirect heater hasthe advantage of maintaining a constant temperature over a long period of timeand is considerably safer than the direct heater. Hot spots are not as likely tooccur, if the calcium content of the heating water is controlled. The indirectheater has the disadvantage of requiring several hours to reach the desiredtemperature after it has been out of service.

Imil HEA T OR F IR EE'3WATER~EMULSIONFigure 13 - Indirect Heater Cutaway (Courtesy Smith Ind., Inc.)



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Direct HeatersThe crude oil in direct heaters (Figure 14) passes through an inlet dis-tributor and is heated directly by a firebox. Direct heaters are quick and ef-ficient, and the initial cost is relatively low. Direct fired heaters have a heatingefficiency of 75-90 percent. If fuel gas is available, the utilization of directfired heaters for oil treating (especially high volume oil treating) should beconsidered.

OI LOUTLET

CRUDE O IL-INLET

mi!l HEA TOR F IR E~ CRUDE OIL EMULSIONFigure 14 - Direct Heater Cutaway (Courtesy Smith Ind., Inc.)

Direct heaters are hazardous and require special safety equipment. Scalemay form on the oil side of the pipe coil preventing a transfer of heat fromthe firebox to the oil emulsion. Heat collects in steel walls under this scale,softens and buckles the metal, and eventually ruptures allowing oil to flowinto the firebox. The resultant blaze, if not extinguished, will be fed by theincoming oil stream.



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Waste Heat RecoveryDue to the rapid escalation of natural gas prices in recent years, many

other methods of adding heat to crude oil emulsions have been employed. Oneof the most innovative is the capture of waste heat from the exhaust stacks ofcompressors and other large engines. Heat exchangers are used to transfer thisrelatively inexpensive heat source to the crude oil emulsion stream.

Heater SizingThe material presented for Sizing Heater-Treaters in the following sectionis used as a guide in sizing heaters.

FLOW TREATERS (HEATER-TREATERS)Sometimes called heater-treaters or just treaters, flow treaters entered gen-eral field use in the 1940's. The upright cylindrical design is an improvementover the gunbarrel and heater system. Many designs are offered to handlevarious conditions such as viscosity, oil gravity, high or low flow rates, cor-rositivity, cold weather, etc. Some treaters use a bundle of excelsior (filterbed) to aid coalescence of the water droplets.Emulsion enters the vessel (Figure 15) where entrained gas carried over

from the separator is released. In some producing fields the gas-oil ratio isvery low, and gas-oil separators are not required. The wellstream enters thetreater directly, and the inlet diverter deflects the fluid to facilitate gas andliquid separation. Off-gas may be vented, delivered into a low pressure gassystem, or compressed for delivery into a higher pressure gas system. Theemulsion moves through a tube (downcomer) to the lower section of the vesseland emerges in proximity to a warming coil usually called afirebox orJiretubeheater. This drastic heating, usually to a temperature ranging from 90F to120F, breaks a larger part of the emulsion and water settles in the bottom ofthe vessel. The remaining emulsion moves upward through the relatively higherweight water bath and continues to coalesce until it attains a separated con-dition at the oil-water interface. Water at the bottom of the vessel is drainedintermittently in response to awater level control device. Treated oil exits thetreater through the oil outlet at the top of the settling section and passes throughthe oil valve to the storage tank.



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GAS OUT LE T

EM U L : : i I lJN--- - f l+H+-H::CONDUCTOR P IP E

(DOWNCOMER)

GAS SEPARAT INGSECTION

O IL OUTLET O IL LEVEL

INLET9 ATERm m 1 , OI L[J EMULSION

Figure 15 - Vertical Flow Treater Cutaway (Courtesy Sivalls, Inc.)

Heater-treaters have the following advantages and disadvantages as com-pared to gunbarrels that use heaters:Advantages

lower initial cost lower installation cost greater heat efficiency greater flexibility greater overall efficiency



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Disadvantages more complicated less storage space for basic sediment more sensitive to chemicalsHeater treaters are sensitive to chemical usage. Since heater treaters aretypically smaller than other treating vessels, such as gunbarrels, retention timeis minimal. Surfactant chemicals must be used properly to help break theemulsion and minimize the retention time required.Mechanical difficulties do occur with treaters. Problems may occur dueto internal corrosion of the downcomer pipe which will allow the inlet emul-sion to mix with the treated oil. Build up of sediment on the walls or bottomof the treater can cause interface levels to rise which will inevitably causeliquid carryover and/or oil exiting the treater with saltwater.Biannual inspections should be performed on heater-treaters to includeinternal inspection for corrosion, sediment buildup, and scale buildup.

Treater SizingThe two major factors controlling the selection of an emulsion treater arethe heat capacity required and the maximum quiet settling time allowed agiven volume of oil. Any treater can be selected for heating capacity alone,and in a majority of these installations, the unit will perform properly. In somecases, however, the emulsion may require a longer settling time than is al-lowed for the operating conditions of the vessel. It is advisable to check theoil-settling time in selecting a treater before the equipment is ordered.

Estimating Heat CapacityThe following information must be obtained in order to determine the

heat capacity required of an emulsion treater for any specific set of conditions: total volume of well fluid to be treated per hour. composition of the well fluid in volume percentages of oil and water(consider water cut at end of field life).



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initial temperature of the fluid as it enters the treater, in of (use coldesttemperature anticipated and consider ambient temperature conditions). treating temperature determined from bottle testing required to breakthe emulsion in of. maximum volume of clean oil to be treated, in barrels per hour. average settling time required to break the emulsion.

Quantity of FluidVariations in the composition of the well fluids from different fields andwells make it impossible to determine a simple formula for calculating therequired heating capacity directly for all cases. If the volume of well fluid tobe considered could be converted to an equivalent volume of a standard liquid,the procedure would be greatly simplified. The standard liquid chosen in thiscase is water.To simplify the conversion, use Figure 16. The following procedure shouldbe used:

7060

e o :::l0 50:I:e o :wc. . 40:5-'u..-'-'w~u,0. . . . icoco

EQ UIV. B BL. O F W ATER P ER H OU RFigure 16 - Equivalent Quantity of Water to Be Heated



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2. The values along the lefthand margin of Figure 17 represent the re-quired temperature rise in of. After determining the required temper-ature rise for the emulsion to be treated, draw in the correspondinghorizontal line. The temperature rise is the difference between the ini-tial fluid temperature and the required treating temperature.3. Determine the point of intersection of these two lines.4. This point of intersection will probably fall between two of the curvedlines on Figure 17, representing the heating capacity required. By in-terpolating between the curved lines, the actual heating capacity can

be determined.The heating rate required should be compared with the manufacturer'sspecifications. Select a treater that meets or exceeds the heating requirements.

Settling TimeTo check the available settling time, the following information is required:1. Maximum volume of clean oil to be treated in barrels per hour.2. Average settling time required to break the emulsion (from the bottletest).3. Maximum oil-settling volume listed in the manufacturer's specifica-tions for the treater selected.The available settling time is calculated by dividing the maximum oil-settling volume by the maximum volume of emulsion produced per hour fromthe well. The result is the actual time available for the emulsion to settle out.

If this time period is equal to or exceeds the average settling time required tobreak the emulsion, the treater selected is adequate.



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If the available settling time is too short, one of the following three con-siderations is recommended:

1. Select a larger size treater of the same type.2. Consider use of the same size treater in a more advanced type.3. Consider installing excelsior (filter bed) if not already specified.

ELECTROSTATIC COALESCERSIonization of oil and water emulsions was known and practiced as earlyas 1910 and came into ordinary refinery use in the 1930's. This process in-

creases in economic attractiveness directly with liquid volume to be handled,but it requires electricity. The advent of many tank battery consolidation proj-ects has resulted in the need to treat larger liquid volumes. Expanding powersystems also made electricity available at installations previously consideredremote. In the late 1950's, the electrostatic coalescer appeared in field pro-duction operations. It still is an attractive investment when large volumes ofliquids are treated.An electrostatic coalescer (Figure 18, commonly called a chern-electrictreater) is essentially a horizontal flow treater which contains an electric co-alescing section. As shown in Figure 19, the emulsion enters the heating sec-

tion, passes down over a baffle, up through a distributor, and in and aroundthe firetubes. Free water accumulates in the lower section and is drained byan interface control. The oil emulsion spills over a weir into a distributorlocated near the bottom of the coalescing section. From here, the oil and smallwater particles travel up into the grid section where the water droplets becomeelectrified or ionized, which starts them moving around in the oil until enoughdroplets join by coalescing to form a large enough droplet to settle to thebottom. The emulsion water is accumulated in the bottom of the coalescingsection and dumped by an interface control through a separate outlet. Theclean oil continues to move to the top of the coalescing section where it ac-cumulates in a pipe and exits the oil outlet by a differential controller.



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Figure 18 - Electrostatic Coalescer

GAS OUTLE Tt

O IL OUTLET

Figure 19 - Electrostatic Coalescer Cutaway



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Because of these forced collisions, electrostatic coalescing usually allowsthe treating process to operate at lower temperatures than those of conventionaltreaters. The use of lower temperatures is directly reflected in reduced fuelcosts. For cold weather operations, it may be necessary to use the heater ele-ment provided in this unit; however, the relative heat requirements shouldremain lower than those for conventional treaters.

Several variations of vessel design have evolved in recent years utilizingthe electric grid principle. With increasing emphasis on higher volume treating(for increased efficiency), vessels are now designed which contain only theelectric grid section. Application of this type system utilizes a separate vesselor vessels for free water removal and heating. When the volume to be treatedexceeds 15,000-20,000 BID, a separate electrostatic vessel system should beconsidered.

Design criteria for the electric grid section of the electrostatic coalescershould be closely coordinated with the manufacturer. Many manufacturers ofelectrostatic coalescers consider the design techniques for their vessels as pro-prietary information; therefore, the actual grid spacing and voltage data mustbe designed by the manufacturer. Normally, a sample of the crude oil and saltwater is required by the supplier for design purposes.Most electrostatic coalescers operate at 30 psig or less. These vessels

should be ASME code inspected and adequately protected from over-pressuring and internal electrical short circuits. All nozzles should be flangedand clean-out provisions should be included. Sizing considerations, other thanthose associated with the grid section, should be completed as previously dis-cussed under heating requirements for heater-treaters and retention time forfreewater knockouts.

PRACTICAL DESIGN OF AN OIL TREATING SYSTEMAs previously discussed, some emulsions can be treated successfully by

relatively low temperatures with or without adding chemicals; others respondto chemicals without heat. Inmany cases, it is expedient to use both. In somefields, particularly those having high water percentages, quiet settling withouteither heat or chemicals provides satisfactory oil and water segregation. Thesecases are rare, however, and may require extremely long retention times.



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Ordinarily, it is better (from the standpoint of installation, maintenance,and operating costs) to use chemicals instead of heat. Gunbarrels should beused if an isolated, single lease, high salt water percentage production is in-dicated (provided retention time requirements do not make gunbarrel sizingimpractical). When gunbarrels are used without heating, the vessels shouldprovide a retention time of 12-24 hours for total fluid volume and at leasteight hours for the oil. This is ample settling time for ordinary temperaturesand allows some storage of basic sediment during cold weather when thechemical efficiency declines. The basic sediment is cleaned from the tank dur-ing warm weather or by periodically rolling (circulating) the gunbarrel.Incases where heat is required, the best choice is usually a heater-treater.It is generally sound practice to install a slightly larger heater-treater than isnecessary. This allows extra capacity for unforeseeable production increasesand may also allow a reduction in the amount of treating chemical used. Areduction in chemical cost can easily payout the additional cost of a largertreater in a few years. A retention time of two hours for oil in the treater isa general average; however, the optimum time varies from one to four hours,depending on the characteristics of the oil and the efficiency of the chemical.The problems of gas conservation, utilization of produced gas as fuel,and the effect of treating on oil gravities and volumes should be considered.

Heater-treaters are somewhat flexible in their operation, and some control overgas-oil separation can be exercised. The gas from heater-treaters can be usedfor fuel, and this is important in fields where the gas supply is low. Oil treatedin heater-treaters tends to retain its gravity and volume because usually, gasis separated in several stages and the oil is cooled before entering stock tanks.In the gunbarrel-heater system, the one-stage, gas-oil separation in the flumecauses evaporation and gravity losses unless temperatures are carefully controlled.The use of a freewater knockout instead of a gunbarrel, the use of a three-phase separator instead of a freewater knockout or gunbarrel, or the use of anelectrostatic coalescer instead of a heater-treater, are all configuration consid-

erations which a facilities engineer may be required to determine. Inthe ex-ample problem which follows, the recommended approach to equipment con-figuration selection is developed.



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Example 3- Treating System DesignProblem: Design a conventional tank battery treating system for the followingsingle lease Exxon will operate in a competitive oil field.Given:

1. Exxon's lease is 320 acres; all productive.2. Field spacing for each well is 40 acres.3. Top well allowable is 100 barrels of oil per day; all wells will

be top allowable for 12 years.4. Strong water drive reservoir, initially wells will flow, water-free,but within 1-3 years will begin to produce water, increasing to+99% at abandonment after 20-year producing life. Gas-oil ratiowill not exceed 200 fr'lB.5. Bottle tests indicate one quart of Exxon Breaxit 8150 per 100barrels of oil will remove saltwater down to 6% emulsion after9 minutes; one quart per 50 barrels, down to 3% in 9 minutes;one quart per 150 barrels, down to 8% in 9 minutes. Cost of

chemical is $8Igallon. Pipeline requirement is less than 1%BS&W.6. Maximum liquid production for each well will not exceed1000 BID.7. Pumper coverage will be 7 days per week, twice each day, earlymorning and late afternoon.8. Assume the same pipeline oil storage tanks and emergency stor-age tank will be required with any treating system selected.9. If gunbarrel system is selected, a freewater knockout must beused to remove free water and a 350,000 Btu/hr heater must beused to raise temperature of fluid from 55F to 120F.



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Equipment available, including installed costs:Vertical Two-Phase Separator (will handle 10,000 barrels of liquidper day and 160 kcf/D, assume no retention time)-$20,000. -Freewater Knockouts: (Use 90% of volume for settling time).

10' x 30'-$45,0008' x 20'-$35,0008' x 15'-$30,0006' x 20'-$22,5006' x 15'-$20,000

Three-Phase Separators: (Use 67% of volume for settling, each vesselwill handle gas adequately).10' x 30'-$55,0008' x 20'-$45,0008' x 15'-$40,0006' x 20'-$35,0005' x 15'-$30,000

Vertical Flow Treaters: (will handle up to 875 B/D, treating below0.5% BS&W, the following emulsions).A. 3% Emulsion-$45,OOO plus $30,000/yr fuel costB. 6% Emulsion-$50,000 plus $30,000/yr fuel costC. 8% Emulsion-$60,000 plus $30,000/yr fuel costElectrostatic Coalescer: (will handle up to 875 BF/D, treating be-low 0.5% BS&W, the following emulsions).A. 3% Emulsion-$70,000 plus $20,000/yr fuel costB. 6% Emulsion-$80,000 plus $20,000/yr fuel costC. 8% Emulsion-$100,000 plus $20,000/yr fuel cost



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Gunbarrels: (12 hour retention time)750 Barrel-$60,000500 Barrel-$50,000

Heaters: 350,000 Btu/hr.-$20,000 plus $25,000/yr fuel costSolution: 1. Select all possible configurations of equipment which will pro-duce pipeline quality oil.

The treating system design should include the followingconsiderations: chemical injection is the most effective and inexpensivemethod to treat an emulsion. some method of primary separation to remove the gas shouldbe provided. a vessel is required for retention time and removal of freewater. a vessel capable of providing pipeline quality oil is required.Possible equipment configurations:

CHEMICAL THREE -PHASE ELECTROSTAT ICPUMP SEPARATOR COALESCER-, ~ na. ~ )a

CHEMICAL G A S-L IQ U ID S E PA R AT IO N PIPELINEINJECTION R E TE N TIO N T IM E Q UA LIT Y O IL

FR EE WATER REMOVAL

CHEMICAL TWO-PHASE FREEWATER HEATER GUNBARRELPUMP SEPARATOR KNOCKOUT

b. ~ 0 Q ~ 0CHEMICAL GAS-L IQUID RETENT ION T IME REQU IRED W ITH PIPELINEINJECTION SEPARAT ION FREE WATER GUNBARREL QUALITY

REMOVAL O IL



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CHEMICAL THREE-PHASE HEATER-TREATERPUMP SEPARATOR

c. -, a : ; ; = ; ; r > UCHEMICAL GAS -L IQU ID SEPARAT ION P IPEL INEINJECT ION R E TE N TIO N T IM E Q UA LIT Y O IL

F RE E W A T ER R EMOV A L

CHEMICAL TWO-PHASE FREEWATER HEATER-TREATERPUMP SEPARATOR KNOCKOUT

d . ~ 0 Q UCHEMICAL GAS-L IQUID R E TE N TIO N T IM E PIPELINEINJECT ION SEPARAT ION FREE WATER QUAL ITYREMOVAL O IL2. Size and select the vessels for the equipment configuration.

a. - ~ ~ - - ~ a : ; ; = ; ; r > ~--~n)3% ,6% ,8% EM ULSION 6' X 20' A ,B ,C COALESCER

The three-phase separator must be able to handle 8,000 barrelsof fluid per day.Separator volume per day (9 minutes retention time = 160 dumpsper day):V = 'TTr2L(0.67)(160)5' x 15'V = 'TTr2L(0.67)(160)

71'(2.5 ft .i (15 ft.)(0.67)(160)- 5.615 ft.3lB= 5,623 BID

6' x 20'V = 71'r2L(0.67)(160)

71'(3ft.)2(20 ft.)(0.67)(160)= 5.615 ft.3lB= 10,796 BID



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b.8% EMULSION 6' x 15' 5006

The freewater knockout must be able to handle 8,000 barrels offluid per day.V = 1ir2L(0.90)(160)6' x 15'

1i(3 ft.?(15 ft.)(0.90)(160)V= ----------~-------5.615 ft.3lB= 10,877 BIDThe gunbarrel must be able to handle 800 barrels of oil per day(100 barrels per day top well allowable for each well).Retention time 12 hours for each gunbarrel24 hr/D x 500 B = 1,000 BID12 hr

c.3%,6%, 8% EMULSION 6' x20' A ,6 ,C T RE A TE R

All treaters will handle the top well allowables.

d. -~----IOI----(3%,6%, 8% EMULSION 6' x 15'

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3. Assign installation and operating cost values and total the as-sociated costs. For this example, use the undiscounted cash flow(before income taxes) to select the most economical treating con-figuration. For further information, refer toNet Cash Flow Prin-ciples and Net Cash Flow Yardsticks modules.

3% - $11,680/YR6% - $ 5,840/YR8% - $ 3,893/YR


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Based on the 20-year, undiscounted cash flow, configuration A (8%emulsion) results in the lowest total cost over the life of the project, althoughits initial investment costs exceed the other four configurations. This exampleproblem emphasizes the importance of heating values to total project cost.

The equipment configuration selected can be influenced by many consid-erations if several configurations are economically near-equal. The fewer num-ber of vessels for maintenance should be a strong consideration. Very often,long delivery lead times on one type of equipment may require selection ofanother configuration, if that lead time will significantly delay the start-up ofoil sales from a new field. All of these and other factors should be consideredprior to configuration selection and equipment requisitioning.



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5. The prime consideration for direct heaters is _a. efficiencyb. safetyc. capacityd. ease of installatione. heat recovery

6. The primary disadvantage(s) of a flow treater is (are)a. more sensitive to chemicalsb. less storage space for basic sedimentc. more complicatedd. all of the abovee. a and b only

7. Given the following data, determine the required heat duty for a flowheater.Flow conditions - 40 barrels of liquid (40 percent crude, 60 percent brine)Temperature rise - lOOFa. 250,000 Btu/hrb. 575,000 Btu/hrc. 650,000 Btu/hrd. 1,020,000 Btu/hre. 1,225,000 Btu/hr

8. (TRUE or FALSE) Because of forced collisions, electrostatic coalescingusually allows the treating process to operate at lower temperatures thanthose of conventional heaters.



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9. Given the dimensions of the freewater knockouts below, determine theproper vessel size to handle 6,500 barrels of liquid per day. Assume 75percent of the internal volume will be occupied by salt water and a 10minute retention time.a . 4' x 12'b . 5' x IS'c . 6' X 18'd . 8' x 20'e. 10' x 20'

10. Identify the missing oil treating equipment in the following systems.

b .---un n,----ec'lrU -..."..)a.

c .


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LESSON 4: OTHER OIL TREATINGCONSIDERATIONS

LESSON OBJECTIVESUpon completion of Lesson 4, you will be able to: Describe the purpose of crude oil stabilization and vapor recovery ina production facility. Briefly describe the crude oil desalting process. Explain why stabilizing is necessary for sour crude treating and de-scribe the process. State the major publication used for oil storage tank design.



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OTHER OIL TREATING CONSIDERATIONSIncertain areas, crude oil may contain hydrogen sulfide, carbon dioxide,and salt. These contaminants must be removed and the oil must be stabilized(atmospherically safe) before it is stored for eventual transfer to the pipelinefor refining.

CRUDE OIL STABILIZATION AND VAPORRECOVERYA process currently gaining in popularity involves stabilization of the treatedcrude oil in a stabilizer. If the central oil treating facility is located near a low

pressure gas gathering system and Exxon enjoys a favorable gas plant productsposition, the economics of stabilization should be evaluated. In fields wherepricing of crude oil is based on API gravity, the installation of a stabilizationsystem, and the resulting decrease in API gravity must be thoroughly evaluatedby comparing the economics of gravity and volume loss versus vapor gains.The stabilization process uses low pressure vapor recovery to remove thelight hydrocarbons contained in the crude oil following the treating process.Through the use of a vertical tower equipped with horizontal trays (Figure20), the heated, clean crude oil relinquishes gas vapors to the top of the vessel.Because the vessel operates under low pressure conditions, crude stabilization

is very efficient. In some systems, a dry gas stream is injected into the sta-bilizer to enhance stripping the light hydrocarbons from the crude. The strip-ping gas is used to transfer one or more components in a liquid solution tothe stripping gas stream. The gas must have a greater attraction for the com-ponent than the liquid in order for the transfer to take place. Since the stabilizervessel operates under low pressure conditions, pumps are usually required totransport the stabilized crude oil from the bottom of the stabilizer or reboilerto oil storage.



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STABILIZER.- - -- -~ GAS TO GAS PLANT

FOR PROCESSING

DE -M IST SECT ION

MEDIUM

1-----,)- TO S TORAGE TANK S

Figure 20 - Crude Oil Stabilization

Stabilizer Tray DesignAlthough detailed stabilizer tray design is beyond the scope of this train-ing module, the following reference material may be helpful if you are re-quired to design a low pressure stabilizer or trouble-shoot an existing opera-tional stabilizer . Sieve Tray Design Program 1133 (Computer and Communication Sci-ences Library Number) is a computer tool for the design and rating ofnew or existing sieve trays. The purpose of Program 1133 is to:-design single or double pass sieve trays for new or existing towers.-check tray hydraulic performance and limitations for new or existingtrays at design and turndown conditions.-predict tray efficiencies at design and turndown conditions.A summary of Program 1133, along with a sample problem calcula-tion, program limitations, and other descriptions are included in ExxonResearch and Engineering's June 15, 1983 Computer InformationMemorandum, EXXON ENGINEERING, Technology Department bul-letin. A hand calculated sieve tray design is included in the ER&EDesign Practices, Section ill-B.



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TRIDAB, a calculation block in Exxon Production Research Compa-ny's Gas Process Simulator computer program, performs a rigoroussimulation of the counter-current, equilibrium stage separation whichoccurs in the stabilizer column. Sufficient flexibility in the program isprovided so that most column configurations encountered in gas pro-cessing can be simulated. For further information, refer to Gas ProcessSimulator User's Manual, EPR. 5MA.78.

Sour Crude StabilizationSour crude oil and condensate stabilization serve two basic functions: strip the light hydrocarbons from the oil and produce an atmospheri-cally stable (non-volatile) crude oil. strip the H2S and CO2 from the oil.From previous discussions, the bulk of gas-oil separation is accomplishedby primary separation. If the crude oil is sour, it contains a considerable quan-tity of sour gas which must be removed upstream of the stock tanks. The useof a heater-treater instead of a crude oil stabilizer is not a justifiable alterna-tive. With the application of heat at a reduced pressure (approximately 50psig) , all the light ends would evolve in the heater-treater. The resulting oilwould be non-volatile (stable) at atmospheric pressure; however, there are twomajor disadvantages to this application: the oil would be sour because all the H2S would not be removed fromthe oil. oil recovery would not be optimized because some of the heavy hy-drocarbons would evolve with the light hydrocarbons.How does a stabilizer tower remove H2S and CO2 (sweeten) and optimize

oil recovery? A stabilizer is equipped with approximately 30 trays. The traysperform two basic functions: the light hydrocarbons which evolve in the reboiler move from tray totray up through the column. As they bubble through the liquid on eachtray, they strip the dissolved H2S and CO2 from the oil. Therefore,light hydrocarbons are removed from the oil by heat generated in thereboiler. These light ends in tum strip the H2S and CO2 from the oil.The conventional heater-treater is incapable of removing H2S dissolvedin the oil because it lacks the trays necessary for stripping.

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some heavy hydrocarbons (butanes and gasolines) evolve in the reboilerjust as in the heater-treater; however, as the vapors rise in the tower,the liquid on the trays absorbs the heavy hydrocarbons and carries themto the bottom of the tower with the crude oil to optimize oil recovery.The heater-treater allows the heavy hydrocarbons to flash with the gas.

Figure 21 illustrates a flow schematic of an actual stabilizer installation(Jay Field) for sour crude, including operating temperatures and pressures.r----------------------------r~SOURGAS

SOURCRUDE----'150 STABILIZER

REBOILERL.--------___,~~t__-- .......TABILIZEDRUDE

Figure 21 - Sour Crude Stabilizer Installation

There are three general criteria which affect stabilizer design: a large number of trays provides efficient stripping action for removingH2S and for obtaining effective separation between light and heavy hy-drocarbons. The optimum number of trays is approximately 30. lower temperature decreases the required reboiler heat input. Highertemperature improves the separation of the light and heavy hydrocar-bons thereby maximizing oil recovery. higher pressure, with correspondingly higher reboiler heat duty input,provides better stripping efficiency in the tower. Adequate strippingefficiency is essential to remove H2S from the oil. Optimum stabilizerpressure is usually between 100 psig and 150 psig.



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Most of the operating problems associated with stabilizers occur from oneor more of the following: the stabilizer is operating far in excess of design throughput. the stabilizer is operating underloaded. water carries over into the stabilizer. foaming occurs on the trays.If the stabilizer is operating in excess of design throughput, a commonproblem known as downcomer filling may occur. In this case, the downcomeris too small to handle the volume of liquid working its way down the tower.

The liquid backs up the tower and out the overhead line. This will usuallyresult in a high level shutdown in the inlet scrubber.Ifwater is carried over into the stabilizer, it will flash back up the towerresulting in a situation known as jet flooding. In this case the vapor rate upthe tower is so great that it physically blows the liquids from one tray to thenext out the top of the tower.If the tower is underloaded a situation known as weeping may occur. Thevapor rate is so slow that the liquid runs down through the slots to the traybelow. As mentioned before, the desired path of the liquids is across the tray

and down the downcomer. Only gas should bubble up through the tray slots.Foaming is sometimes caused by well treating chemicals entering the towerfrom the inlet separators. If this becomes a problem, these chemicals cansometimes be dumped from the trays by lowering the reboiler temperature 50to lOOFfor a

Emulsion and Oil Treating

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