CHEVRON Pressure Vessel - Production Separators

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900 Production Separators

AbstractThis section presents design principles, process considerations, and sizing for production separators, including common oilfield separators and separator intecomponents and their functions. It discusses flash calculations, separation theofluid properties, and liquid/liquid separation. Also included is a discussion of theinput data needed for the PC “Bookware” programs for sizing separators.

Contents Page

910 Introduction 900-4

911 Objectives

912 General Background

920 Design of Production Separators 900-4

921 Introduction

922 Gas Plant Process Vessels and Compressor Knockout Drums

923 Oilfield Production Separators

924 Crude Oil Dehydration

930 PC Based Programs 900-5

931 Comparison with Company Design Procedure

932 Input to the Bookware Programs

933 Program Output

934 Cautions on Using the Bookware Programs

940 Common Oilfield Separators 900-8

941 Scrubbers

942 Gas Traps and Sand Traps

943 Three-Phase Horizontal Separators

944 Test Separators

945 Filter Separators (Coalescers)

946 Slug Catchers

Chevron Corporation 900-1 March 1990

900 Production Separators Pressure Vessel Manual

1

947 Steam Separators

948 Flash Separators

949 Flare Knockout or Vent Scrubbers

950 Separator Internal Components and Functions 900-12

951 Primary Separation Section and Inlet Diverters

952 Secondary Separation and Vessel Intervals

953 Mist Extractors

954 Serpentine Vanes

955 Dixon Plates

956 Centrifugal Mist Extractors

957 Vortex Breakers

958 Weir Buckets and Interface Controls

960 Design Principles and Process Considerations 900-2

961 Approximate Flash Calculations

962 Process Information and Facility Design

970 Separation Theory 900-31

971 Mechanisms of Particle Collection

972 Gravity Separation

973 Centrifugal Force

974 Impingement and Coalescence

980 Fluid Properties 900-33

981 Formation and Characteristics of Oil-Water Mixture

982 Free Water

983 Fluid Equilibrium

984 Fluid Shear

985 Fluid Gravity vs Temperature

986 Multiphase Flow

990 Liquid/Liquid Separation 900-37

991 Liquid Retention Time

992 Factors That Affect Separation Efficiency

993 Pressure and Temperature

994 Viscosity

995 Foam

March 1990 900-2 Chevron Corporation

Pressure Vessel Manual 900 Production Separators

996 Emulsions

997 Flow Rate Surge or “Slugs”

998 Turbulence

999 Sour Service



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910 IntroductionThis section presents general guidelines for the selection of oil/gas/water separsystems. In upstream oilfield operations, separators are the primary process elements in production systems. They separate the components of reservoir fluinto segregated gas, crude oil, and water streams for further processing. A reviethe factors affecting production separation efficiency is presented along with sizprocedures for primary production separators. This does not include detailed process simulation procedures, economic evaluations, sizing methods for equipment other than separators, or mechanical design of separators. The informatiothis section is not intended to be used for final separator design, although it willallow reasonable verifications of vendor's quotations.

911 ObjectivesThe objectives of this section are:

1. To acquaint the engineer with the factors that go into planning a crude oil sration system.

2. To simplify recognition and selection of the correct vessel configuration for any particular duty.

3. To provide procedures for selecting overall dimensions for two- and three-phase separators.

912 General BackgroundHistorically, vendors and engineering contractors perform much of the sizing fopressure vessels. In many cases, vendors and contractors use proprietary vessdesign equations or programs to size vessels. To a large degree, most of theseprograms are based on theoretical equations with limited field data to verify thebasic mathematical model. All crudes are different, and good modeling of perfomance involves knowledge not only of vessels but of crude characteristics. Infotion about crude oils is often vague and subject to change. Tools to accurately determine what is going on in the separator are now being developed. The theopresented below is the best current information, although empirical.

920 Design of Production Separators

921 IntroductionThis section discusses several methods for sizing horizontal and vertical separa

922 Gas Plant Process Vessels and Compressor Knockout DrumsThe Company Design Procedure as outlined in Section 300 is well suited for compressor knockout and process vessel design where quality phase separatio



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considered essential. This method uses a conservative design approach that geally accommodates variations in either process fluctuations or nominal flowrateincreases. It is recommended that this design method be used first when compvessel sizes with other design approaches.

923 Oilfield Production SeparatorsFor oilfield production separators, less conservative design methods are commused to provide adequate sizing of vessels, such as production gas traps or “potraps. Methods similar to API 12J using K factors are generally employed for thless critical bulk separation processes. In these applications the engineer is genally designing for rapid separation of gas and liquids, typically in the 1 to 3 minuliquid hold-up range.

The separator sizing computer programs discussed in Section 930 can be usedinitial sizing. Final calculation is vessel-specific and must take local operating erience into account. The PC sizing programs presented in Section 930 require tyou know certain process information that is key to obtaining a good separator design. In the event that process data are not available, program supplied defavalues can be used as guidelines to arrive at a “first pass” separator size. Mostcertainly the best design technique is to use field data (retention time, BS&W, eto determine input to the PC programs. With field data, the program should prova good method to predict comparative separator performance.

All methods should be used in conjunction with foam prediction methods. Foamgeneration, in high viscosity crudes is common, and process considerations of vessel design as outlined in Section 995 should be included in the final vessel design.

924 Crude Oil DehydrationOil dehydration is a complex subject that does not always lend itself to a simplediscussion of retention time vs oil gravity. It will not be covered in this manual; however, additional design information can be obtained by contacting: ChevronResearch and Technology Company (CRTC), Production & Process Facilities Group.

930 PC Based ProgramsThe “Production Facility Bookware Series” is a series on PC Based Programs fsizing separators. Module 101 is for two-phase separators; Module 102 is for thphase separators. Each module contains a personal computer program for desor rating a vertical or horizontal separator. Module 101 and 102 can be obtainecontacting Chevron Research and Technology Company, Production & ProcessFacilities Group. (See Reference 9 in the Reference section of this manual for minformation.)



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931 Comparison with Company Design ProcedureThe main difference between the “Bookware” method discussed here and the method recommended in Section 300 is in the correlations used for allowable vvelocity. Bookware uses a theoretical, droplet terminal settling velocity correlatifor vapor-liquid separation. The development is similar to that shown in Section334 for liquid-liquid separation where the correlation used is based on data fromoperating units (Equation 300-1 or 300-2).

For a vertical separator designed for 100 psig, specifying a liquid droplet diameof 250 microns causes the Bookware method to use about the same vapor veloas Equation 300-1 or 300-2. At 500 psig, a droplet diameter of 200 microns is necessary to produce agreement; at 2000 psig, a droplet of 175 microns is nee

For a horizontal separator, the allowable vapor velocity criterion applies despitefact that the liquid droplets settle in a direction perpendicular to the bulk flow of vapor. In the Bookware procedure, the settling velocity of droplets is compared the height of the vapor space and the residence time of the vapor in the separaother words, vapor moves in “plug flow” from the inlet end of the horizontal vessto the outlet end. A certain liquid droplet, moving at the horizontal velocity of thevapor, settles from the top of the vapor space toward the vapor-liquid interface. reaches the interface before reaching the outlet end, then all droplets of that sizwill be removed by the separator. See the cautions below regarding using Bookfor horizontal separators.

Liquid-liquid separation methods are similar in the Company and Bookware procedures.

The Bookware procedures do not include demisters, coalescers, feed inlet shrobaffles, and water boots.

932 Input to the Bookware ProgramsInput data to the Bookware Programs include the following:

• Operating temperature and pressure

• Gas flow rate and either composition or specific gravity

• Oil flow rate and either specific gravity or API gravity

• Water flow rate, if present, and gravity

• Optionally, viscosities of the above phases, or they will be estimated by internal correlations

• Maximum liquid droplet diameter in gas (default is 140 microns)

• Maximum water droplet diameter in oil (default is 500 microns)

• Maximum oil droplet diameter in water (default is 200 microns)

• Minimum oil retention time



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• Minimum water retention time

• Upper and lower bounds on L/D ratio. (Default values are 4 and 2.)

• With a horizontal separator, the fraction of the volume occupied by liquid(s)The default value is 0.5.

• Several mechanical items (with default values) used to estimate vessel wei

933 Program OutputThe program develops a set of vessels of “standard” dimensions that satisfy theseparation and retention time requirements. Standard diameters are multiples oinches; standard length increments are 1 foot. L/D varies from maximum to minimum. For each vessel, the program gives a measure of the excess capacitprovides. That excess may be in terms of gas or liquid rate, retention time, or droplet size separated.

934 Cautions on Using the Bookware ProgramsThe following precautions should be observed when using the Bookware Progr

• The criterion for acceptable vapor velocity in a horizontal vessel is that the time necessary for a liquid droplet to settle from the top of the vessel to thevapor-liquid interface shall be equal to the residence time of the vapor withithe vessel. This does not rule out use of a small fraction of vessel cross sefor vapor flow and high velocity of vapor. The result would be turbulence, disturbance of the liquid surface, and reentrainment of liquid. Bookware suggests liquid level at the vessel midpoint and cautions that L/D ratio highthan 5.0 can result in reentrainment; this advice is not very specific. The usof the program should apply the criteria of Section 351 to determine the crosection for vapor flow, even if the Bookware program then indicates that thevessel is oversized for vapor.

• A common practice is to state liquid gravity at standard conditions (60°F) athen correct liquid density to operating temperature. The Bookware programdo not adjust liquid gravities for temperature; therefore, the user should supliquid specific gravity at operating temperature (relative to water at 60°F).

• The programs do not adjust the fraction of horizontal vessel volume occupiby liquid. If the user's (or the default) value is not optimal, a lot of vapor or liquid volume can be unnecessary. The user should check the excess capafor vapor and liquid and adjust the liquid level appropriately.

• If total liquid volume in a three-phase separator is greater than what is needto satisfy hydrocarbon and water residence time requirements, the excess be allocated to oil and water in proportion to the original retention require-ments. The user might prefer a different distribution.



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940 Common Oilfield SeparatorsSeparators are used for many different applications. A few of the most commonservices are described in this section. Figure 900-1 is a flow chart showing a tyfield separation plant.

A production separator (also called a bulk separator or primary separator) is usseparate one or more combined wellstreams at a well site, gathering center, plaoffshore platform. It can be two- or three-phase. “Primary” separation indicates the first process of separation the produced fluids have encountered. If located plant, the production separator might be very large and handle the production fa whole field. In large plants, several production separators are often used in parallel.

941 ScrubbersA scrubber is a separator used on very high gas/oil ratio (GOR) flow streams to“scrub” small amounts of liquid from a gas stream. (See Figure 900-2.) Scrubbeare usually two-phase, vertical vessels, although in larger applications horizontscrubbers are not uncommon.

Fig. 900-1 Typical Field Separation Plant



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Suction and discharge scrubbers are placed upstream and downstream of gas compressors. Fuel gas scrubbers remove residual liquid from gas just prior to ituse as a fuel. Pipeline scrubbers remove condensate from gas streams flowingthrough long pipelines.

942 Gas Traps and Sand Traps

Gas TrapsA gas trap is a vertical separator that performs primary separation of gas from liquid flow from the wellhead. The vessels are two-phase, with both process streams proceeding to further processing. See Figure 900-3.

Fig. 900-2 Impingement and Droplet Growth in a Typical Filter Coalescer



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Sand TrapsA sand trap is a device for removing sand from a produced well-stream. Sand tare typically used on high pressure gas wells, where sand production is commo

943 Three-Phase Horizontal SeparatorsA three-phase horizontal separator is the primary component used for oil/waterseparation. See Figure 900-4.

Fig. 900-3 Typical Two-Phase Vertical Separator (Gas Trap)



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944 Test SeparatorsA test separator is also called an Automated Well Test Unit (AWT), clean-up serator, or a gage trap. A test separator determines the oil, water, and gas volumeeach producing reservoir or well, and monitors well performance if the facility isowned and operated by a single company. If the producing field has several co-owners, the field may be “unitized” and the test separator may also be used to mine relative revenue payment to each co-owner. A minimum test separator woseparate the liquid and gas and measure both phases. The density of the liquidbe measured by an accurate densimeter after the oil and water are completely rated in a test container.

A conventional test separator may be horizontal or vertical. The test separator isized for the maximum “best” full well potential and anticipated gas and water rates. The operating pressure of the test separator would be the same operatinsure as the first stage separator. The size of the test separator is normally fixedthe residence time required for oil/water separation.

945 Filter Separators (Coalescers)Filter separator is a generic term which includes true filter-separators, filter coalescers, and dry gas filters. They are used to separate liquid and solid contanants from a gas or liquid stream when particle size is too small to be removedconventional separator. See Figure 900-5.

946 Slug CatchersA slug catcher, or surge drum is a separator designed to separate bulk liquid-gaflow streams which are surging or slugging (see Section 970). The slug catcheralso serve as a production separator, in which case further processing is generrequired. Properly designed, slug catchers should smooth out the intermittent fl

Fig. 900-4 Typical Three-Phase Horizontal Separator



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947 Steam SeparatorsSteam separators are used in geothermal projects or with steam generators; thsimple separators which remove free water from steam, thus producing 100% quality steam.

948 Flash SeparatorsA flash separator is a two-phase vessel with the primary purpose of degassing liquid before it enters another process. An example would be a flash separator conjunction with an electrostatic coalescer or desalter where no free gas can betolerated. The fluid is first degassed in a flash separator which is elevated abovcoalescer so that once degassed the fluid will remain gas-free.

949 Flare Knockout or Vent ScrubbersFlare scrubbers or vent scrubbers are placed in gas outlet streams from producseparators to remove any residual liquids left or any condensates that may havformed in the line, prior to flaring or venting.

950 Separator Internal Components and FunctionsThe simple separation of gaseous and liquid hydrocarbon streams is normally achieved by four distinct processes:

1. Primary phase separation of predominantly liquid hydrocarbons from thosethat are predominantly gaseous.

2. Refine primary separation by removing the entrained hydrocarbon mist fromthe gas.

Fig. 900-5 Typical Filter Separator (Coalescer)



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3. Further refine the separation by removal of entrained bubbles from the liquphase so that, ideally, the liquid contains no more gas than would exist at elibrium at the pressure and temperature within the vessel.

4. Assure proper control by devices which will provide for the removal of the separated gas and separated liquid phases from the vessel without allowinopportunity for reentrainment of one into the other.

The physical properties used to achieve these processes are gravity, centrifugaforce, and impingement. The effective combination of these properties, and thegoverning principles, leads to efficient separator design. A description and expltion of a horizontal two-phase separator illustrates how these physical propertieand principles are employed. (See Figure 900-6.)

The separator consists of three basic sections plus the controls, which correspowith the four processes noted above. These are:

1. A primary separation section which controls or dissipates the energy of thefluids as they leave the flow line and enter the vessel.

2. A secondary separation section (mist extraction or coalescing section) whicminimizes turbulence in the gas section.

3. A liquid collecting and removal section which prevents reentrainment of theseparated phases.

951 Primary Separation Section and Inlet DivertersThe entrance stream into the gas/oil separator is a high velocity, turbulent flow stream with highly interspersed phases. The inlet mass of fluids has high momentum due to the velocity at which it leaves the flow line. In the separatingvessel, which has a much larger diameter than the flow line, the natural velocityfor the same continuous flow rate is much less. Therefore, the inertia effects entering the vessel must be quickly and effectively overcome so that natural gra

Fig. 900-6 Basic Two-Phase Separator



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separation under lower velocity conditions can occur. To accomplish this, a carefully designed and compact device is required for producing controlled deceleraof the incoming fluids. This device is usually referred to as a “momentum absor

Downstream of the momentum absorber, liquid material with much entrained gaseparates generally downward. Above the liquid layer is a predominantly gaseomaterial with much entrained liquid, moving either upward in a vertical separatinvessel or longitudinally in a horizontal vessel.

The configuration of the inlet device can take many shapes and should be givencareful consideration. Structural channel iron usually provides optimum results,angle iron, flat plates or dished heads have been considered optimum for certaapplications. Vertical vessels often employ a centrifugal inlet device. See Figure900-7 for typical configurations of inlet devices.

952 Secondary Separation and Vessel IntervalsThe secondary separation section of a separator is important for efficient separdesign. Here the properties of gravity separation and impingement are combinewith the control of turbulence to achieve the required quality of liquid droplet seration from the gas phase, and oil from water.

In two-phase separators, the primary function of the liquid retention section is toallow free gas bubbles to separate from the liquid. This is accomplished by providing sufficient residence time, free of excessive turbulence, to permit graviseparation to occur. Typically no special internals are required for “degassing” tliquid.

Fig. 900-7 Typical Configurations of Inlet Devices



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A second function of the liquid retention section in three-phase separators is torate oil and water. Depending on the degree of separation required, a liquid coalescing element can be used, or no element can be used, allowing only seption by gravity.

953 Mist ExtractorsThe stainless steel wire mesh mist extractor, an impingement type extractor, is perhaps the most common mist extractor. Most wire mesh mist extractor manufturers furnish charts depicting proper velocity design. A common pad of wire mused in production separators is 4 inches to 8 inches thick, having a density of lb/ft3 (0.011 inch diameter stainless steel wire). (See Figure 900-8.)

Gas velocities entering a mist extractor usually are in the turbulent flow range, sNewton's Law is applicable. Figure 900-9 shows various particle sizes found in nature and the ease with which they are separated. A well-designed mist extrachas no difficulty catching 10 micron particles. Mist extractors of poor design arethe market that allow even 1000 micron particles to pass. Most arrangements oangle iron pieces make poor mist extractors.

Fig. 900-8 Wire Mesh Mist Extractor Configurations

Fig. 900-9 Liquid Particle Characteristics



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C = Drag Coefficient

g = Gravitational constant, ft/sec2

d = Average particle diameter, ft

Equation 900-2 is used to avoid reentrainment from the mist extractor. The K fais proportional to the drag force on a film of particle. If the K factor is too high inmist extractor, the film will not drain. A large amount of liquid is torn off the outleedge and, due to the high K factor, the particles created are smaller than normaare carried out.

Laboratory tests yield K factor curves such as shown in Figure 900-10. In ideal circumstances, the K factor is not dependent on pressure or inlet liquid load; however, this is rarely the case in actual field conditions. The curves are very stand one can easily choose a K factor value that is below all the reentrainment curves. To illustrate, select a K factor of 0.35 on the curve in Figure 900-10. Moseparators have K factor values between 0.2 and 0.8.

The gas flow of a separator is usually limited to the K factor of the mist extractoReentrainment is usually the biggest problem, not entrainment. Increasing veloincreases centrifugal and impingement catching ability, but not gravity catchingability.

A wire demister pad should not be used if wax will be present at the operating temperature. If the crude is waxy and operates at a temperature near the cloudpoint, wax may appear.

954 Serpentine VanesSerpentine vane extractors are lightweight and economical and need be only a8 inches long. See Figure 900-11. These particular vanes have natural drainagpaths that do not reduce the cross-section areas. Thus, a high K factor can be safely in horizontal flow. Serpentine vanes have also been used in a vertical flowconfiguration. Used in this way the K factor must be reduced because the perfomance is limited by the ability of the separated liquid to drain downward countecurrent to the gas flow.

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In the normal horizontal flow configuration, very high K factors can be used if sucient volume is available upstream for bulk liquid separation, and downstream tallow for settling of liquid fly-off. Fly-off is liquid which has coalesced in the mistextractor, then is blown off the trailing edge by the gas velocity. These droplets must be large enough to settle rapidly, and this limitation determines the allowavelocity, and therefore the K factor. Too high velocity of gas will prevent even threlatively large coalesced droplets from settling, and they will become reentrainin the gas stream.

If the process volume is not available upstream and downstream of the vanes, trestrictions such as lower K factor and small allowable liquid loading are necessThis is the case in some cross-flow separator designs, both vertical and horizon

Wire mesh collects paraffin, hydrates, sand, and other solid particles, causing itplug rather easily; therefore, it is not generally recommended for primary wellheapplication, but is preferred for clean relatively high GOR applications. It can beused in either vertical upflow or small horizontal configurations. Its allowable K factor in horizontal flow is lower than for serpentine vanes because of its relativpoor ability to drain itself of liquids. However, when conditions permit its use, wimesh can catch smaller particles than can the serpentine vane mist extractor.

955 Dixon PlatesA successful and widely used type of mist extractor for many years, Dixon platework on the principle of gravity separation. (See Figure 900-12.) They are usedhorizontal vessels as shown below. Reducing the area of each flow path with Dplates reduces the turbulence, permitting gravity to separate the phases.

Dixon plates are slanted at a 45° angle so that a settling liquid droplet has onlyshort distance to fall. Traditionally Dixon plates have been frequently used in foamy crude oil applications because of the large surface area which aids foam

Fig. 900-10 Example: Carryover vs K-Factor Fig. 900-11 Serpentine Vane Mist Extractor



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decay. Relative to other mist extractors now available, Dixon plates are inferior performance and are heavier and more expensive.

956 Centrifugal Mist ExtractorsThis type of mist extractor utilizes the flow-stream momentum to create a high velocity rotational flow. The resulting centrifugal acceleration causes a separatiof dense liquid from light gas. It allows high K factors, but is not as efficient as element-type mist extractor designs for removing very small droplets of liquid from gas.

Many other mist extractor designs are available, although many have poor perfmance. In general, any mist extractor that greatly reduces flow area or otherwiscauses severe turbulence should be avoided.

957 Vortex BreakersLarge amounts of carry-over and gas slippage can often occur due to poor fluidoutlet design. Vortexing can also occur at the gas or liquid outlet. When a Corioforce or a nonuniform flow distribution starts a rotation motion, the available energy at the mouth of the outlet produces and maintains a strong vortex. Excepressure drop and poor separation are indicative of vortexing. These problems,however, often are not detected. Fortunately, there are well-designed vortex breakers that dampen rotation flow. Even with proper vortex breakers, the interfcan be sucked down into the drain if the liquid height above the drain is small athe draining velocity is large. The minimum phase height needed to feed the dris a function of the drain diameter, draining velocity, and the ratio of phase densabove and below the interface.

Fig. 900-12 Parallel “Dixon” Plate Mist Extractor



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A useful guideline is to have a minimum of two times the nozzle diameter in liqudepth if the interface is gas/liquid, and three times the nozzle diameter if the intface is liquid/liquid, assuming the nozzles are sized for typical liquid velocities. these minimum dimensions are maintained and vortex breakers are installed ovthe outlet nozzles, the problem of outlet reentrainment can be minimized. Figur900-13 shows some common designs for vortex breakers. When the separator three-phase, additional considerations are necessary to control levels.

958 Weir Buckets and Interface ControlsThree types of outlet control for three-phase separators are shown in Figure 90These arrangements can be used in horizontal or vertical vessels. The weir plasimple and relatively inexpensive; however, the interface controller is activated the difference in densities of oil and water. The controller must be sensitive. If thliquids are slightly emulsified or the controller is not set properly, carry-over will result (oil-in-water or water-in-oil).

The oil bucket acts as a “U” tube, blocking the oil from reaching the weir. Waterspills over the weir as it tries to attain the same hydrostatic pressure that the oilwater height are creating on the other side of the bucket. One advantage of thisarrangement is that the controls sense the difference between liquid and gas; however, more internal structure and vessel volume are required. Making the band weir adjustable adds flexibility.

The open pipe arrangement is a simple and inexpensive dumping method. Howhere too, interface control instrumentation must be sensitive to small changes idensity. It is also a disadvantage to have such a limited oil height above the oil outlet. A slight drop in oil will cause gas to be sucked in, even with a nonvortexi

Fig. 900-13 Outlet Vortex Breaker Designs



Fig. 900-14 Three Types of Outlet Control for Three-Phase Separators

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flow. Placing a horizontal pipe on top of the outlet as shown in Figure 900-14c whelp; the bottom of the pipe is slotted, allowing the oil level to drop within a few inches of the slots without a problem. However, weir arrangements still give a greater safety margin. When foam is present, a greater safety margin is essentbecause the weight of foam distorts liquid level gage indications. A pad of emulsion and dirt may build up at the oil-water interface over a period of time distortiliquid level gage readings and controller outputs. Therefore, a drain at this intermay be specified. A toadstool interface collector is one of the better draining devices.

960 Design Principles and Process ConsiderationsTo size and design a separator, certain data and information must be known abthe process fluids and operating conditions. You need to know the service that separator is to perform and the performance requirements. Often it is helpful toknow something about the system into which the unit will fit. Special constructioand design specifications, if applicable, must be followed. Then all the informatmust be interpreted to select the best design and to correctly size the separatoOften design data are incomplete and assumptions must be made. Informationabout type of service and the relationship to the whole system can be useful in making good assumptions.

A range of different separator designs can be used or adapted to fit each need.There are vertical and horizontal designs, longitudinal or cross flow, an assortmof mist extractor types, and designs with and without slug catching sections.

961 Approximate Flash CalculationsFlash calculations are normally too involved to be done by hand. They are usuadone either on computer or in a programmable calculator. Sometimes it is neceto get a quick estimate of the volume of gas that is expected to be flashed fromoil stream at various pressures.

Figure 900-15 was developed by flashing several crude oils of different gravitiesdifferent pressure ranges. The curves are approximate. The actual shape depethe initial separation pressure, the number and pressure of intermediate flashesthe temperature.

Example: Suppose a 30° API crude with a GOR of 500 is flashed at 1,000 psia,500 psia, and 50 psia before going to a stock tank. Roughly 50% of the gas, whwill eventually be flashed from the crude, or 250 ft3/BBL will be liberated as gas in the 1,000 psia separator. Another 25% (75% to 50%), or 125 ft3/BBL will be sepa-rated at 500 psia and 23% (98% to 75%), or 115 ft3/BBL will be separated at 50 psia. The remaining 10 ft3/BBL (100% to 98%) will be vented from the stock tank.

Note that Figure 900-15 is only to be used where a quick approximation is acceable. It cannot be used for estimating gas flashed from condensate produced inwells.



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962 Process Information and Facility Design

Produced Fluid Data1. The volumes (maximum and minimum) of all fluids requiring separation

should be obtained:

a. Gas, reported in million standard cubic feet/day (MMSCFD).

b. Oil, reported in barrels/day (BPD).

c. Water, reported in barrels/day (BPD).

Define these data on an individual well stream basis and on a total facilities baspossible, the data should take the form of a detailed production forecast. See F900-16 for a typical plot of a production facilities fluids forecast. Confirm whethethe data include any additional fluids from artificial lift or pressure maintenance plans.

2. A complete laboratory analysis report of all hydrocarbon components and water components, as well as the sampling conditions, is essential to optimthe separation system.

3. Define the wellhead conditions for the following operating modes:

a. Flowing at start-up: pressure (psig); temperature (°F).

Fig. 900-15 Approximate Flash Calculation Chart. Use for approximation only



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b. Flowing at economic limit: pressure (psig); temperature (°F)

c. Shut-in pressure at start-up (psig).

These data are largely dependent on reservoir characteristics and are influenceartificial lift and reservoir pressure maintenance plans.

4. Production characteristics should include, as applicable, information regardsuch characteristics as:

a. The quantity and characteristics of wax (%).

b. The tendency of the oil to form emulsions (settling time, minutes).

c. Quantity of sand carried by the inlet fluids (lb/1000 BBL).

d. Slugging from flow imbalances or pigging operations (% of production flow rate).

e. Future reservoir composition for changing gas/oil/water ratios.

f. Quantity and composition of salts in inlet production fluids (lb/1000 BBL

g. Acidity.

Required Export CharacteristicsAll production facilities will have a product quality specification that applies specically to that facility, whether it is for natural gas, condensate, or crude oil. Thes

Fig. 900-16 Production Fluids Forecast



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specifications are important decision points that, in many cases, will be paramoin selecting the total separation system. Examples of criteria to be established

1. Gas gross heating value (Btu/ft3)

2. Gas inert components such as N2, CO2 (volume %)

3. Gas dew points for water and hydrocarbon (°F)

4. Moisture content (volume % for oil and lb/MMSCFD for gas)

5. Delivery pressure of export gas or oil (psig)

6. Oil BS&W content (%)

7. Gas sulfur content (grains/100 scf)

8. Oil vapor pressure (psia or Reid Vapor Pressure in psia)

9. Dissolved salts in crude oil (lb/1000 BBL)

10. Oil-in-water. Although it is not a product for export, the residual hydrocarbocontent in the final produced water stream must be known and should be expressed in parts per million (ppm or mg/l).

Typical export specifications might be:

1. Oil

– 1% to 3% BS&W– 20 lb salt/1000 BBL oil– 11 to 13 psia Reid Vapor Pressure (RVP)

2. Gas

– 7 lb/MMSCF, water– 0.25 grains/MMSCF, H2S– 900 to 1300 Btu/1000 ft3, lower heating value (LHV)

Obviously, however, these specifications will be site and contract specific.

Future ConditionsThe majority of production conditions can, with proper planning, be accommodato an acceptable level over the life of the facility. A common pattern for well production shows, during the early stages, a larger gas/oil ratio (GOR) and smaamount of produced water and, in the later stages, a reversal of that condition. trend will not be experienced in the application of gas lift or water-flood programwhere the requirement of those programs can usually be predicted and accounfor in the design.

System SelectionThe purpose of this section is to provide the user with a method to make initial general decisions regarding the overall separation system. The discussion is ge



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in nature and emphasizes separator plans. Final system selection should be baupon a weighted combination of field experience, process simulation, engineerijudgment, and an economic evaluation.

Selection of oil and gas treating systems generally results from optimization of facility costs, product recovery, and operational considerations. Typically, the process engineer utilizes the defined inlet stream and performs a preliminary mbalance for the system to establish: (1) the basic number of stages required to achieve mandatory product specifications, and (2) system optimization to maximoperational requirements while minimizing utility and facility costs. Preliminary equipment sizes for process vessels can be obtained in some cases. However,detailed analysis, process equipment vendors should be contacted for the propetary design aspects of such items as crude oil dehydrators or desalters. Correcareful input to the process conditions supplied to equipment vendors is essentespecially when a “process guarantee” is part of the purchase contract. Use theselection guidelines outlined in this section to establish the preliminary system.

Number of Separation StagesStage separation is the term given to the “step” reduction of pressure on the liquntil it reaches the export point. The liquid flows from the first stage separator inone or more lower stages and, finally, into the stock tank or pump station. Eachseparator is considered one stage, as is the final pressure level.

Stage separation is used for two basic purposes:

• To increase stock tank recovery by minimizing vaporization (the more stageused, the more stock tank oil produced from each barrel of reservoir oil)

• To reduce the amount of gas that the stock tank must handle

The question of how many stages (two, three, four or even five) remains to be answered; economics is the key consideration, and the law of diminishing returapplies. Actual production tests provide reliable solutions to the question. Howein the absence of actual tests, calculations provide the only means to reasonabdetermine the optimum number of stages and the optimum operating pressure each stage. This tedious operation is usually performed by computer (many flascalculations are performed until the computer converges upon the optimum solution).

A rule-of-thumb method for determining the optimum number of stages and opeating pressure is given below. The first and last stage pressures are usually detmined by other considerations. The second stage pressure equals the first stagpressure divided by the pressure ratio, and so forth for each stage. The pressuratio per stage should not exceed the following, although in all rules-of-thumb, exceptions will be found:

• 5—for gas-condensate production

• 7—for crude oil separation where the stock tank oil gravity is greater than 50° API



the

tions that

final

• 10—for crude oil separation where the stock tank oil gravity is less than 40° API

Select the number of stages so as not to exceed the pressure ratios above. Thefollowing equations are used to determine the optimum operating pressures of intermediate stages:

(Eq. 900-3)

(Eq. 900-4)

(Eq. 900-5)

where:n = Number of interstages = (number of stages -1)

R = Pressure ratio

P1 = First-stage pressure, psia

P2 = Second-stage pressure, psia

m = Arbitrary stage number

Pm = Pressure of stage m, psia

Ps = Stock tank pressure, psia

Application of the above equations to a three-stage separation problem where P1 = 400 psia and Ps = 14.2 psia gives:

(Eq. 900-6)

P2 =(14.2)(5.3)2-1 = 75.3 psia

As might be expected, there are many instances where the use of flash calculawill not agree with the results of the above equations. These equations assumethe ratio per stage should be constant, but a complete analysis of a separation problem often shows that the ratio between the last stage and the stock tank orpressure is considerably smaller than between the other stages.

RP1

Ps------

1n---

=

Pm Pm 1+ R P1 P2R=( )=

Pm PsRn m 1–( )–

=

R40014.2----------

0.55.3= =



redict

t n the

r and be P.

ra-

ater n

size

tial

The ent

ng may

When accurate oil and gas analyses are available, computer simulations can pvalues very close to the optimum; field experimentation can provide further refinement.

Flowing Wellhead Pressure (FWHP)Flowing wellhead pressure sets the maximum operating pressure of the highesstage pressure. The decline potential of the FWHP has a very great impact uponumber of separation stages. On new field developments, when the reservoir decline properties are unknown, value judgments are often made on the numbepressure levels of stage separation. Multiple stages or trains of separation maynecessary to provide different backpressures to various wells with differing FWHFWHP is set by reservoir characteristics.

Factors Affecting Number of Separation TrainsThe following factors must be considered when deciding on the number of sepation trains.

1. Throughput

2. Number of reservoirs

3. Gas/oil ratio

4. Wax content

5. Sand content

6. Turndown requirements

7. Required on-line availability

8. Deck space and weight considerations (offshore applications)

The number of separation trains is influenced by total volumetric oil, gas, and wthroughput, a function of the peak crude production, anticipated water productiowith time, and gas/oil ratio. Separator capacities may be limited by the physicaland lifting weight of the vessel. (See Figure 900-16.)

More than one separation train may be justified if the reservoir production potenis uncertain and an overdesigned topside facility has minor overall economic impact. This decision requires an informed judgment based on the direction of unproven reserves, and is beyond the scope of most engineering calculations. economic impact of two or three trains should be evaluated to provide managemwith the information to make this decision.

Number of ReservoirsThe number of separation trains is also influenced by the number of productionreservoirs. If more than one reservoir is being produced, and the available flowiwellhead pressure cannot match the other reservoir, a second separation train be needed. See Figure 900-17.



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the e.

ld

Thus,

be

l

floats ed tion.

.

soci-y

If the available FWHP from the second reservoir is sufficient to match the seconstage of separation of the first reservoir, then the second reservoir production cseparated in the second stage of a single train of production separators.

Gas/Oil Ratio (GOR)The gas/oil ratio influences the diameter of separators and also the decision to retain a single train. At a higher gas/oil ratio, vessel diameter may increase for same amount of crude produced because gas flow rates may control vessel siz

Wax ContentThe wax content may influence the number of separation trains. Production coube interrupted by shutdown of the separation train if wax buildup occurs and theseparation train vessels need to be steamed or cleaned in some other manner.if wax content is high and processing conditions require heating, upsets in the heating system could occur and more than one train of crude separation wouldfavored.

A bucket-type liquid weir should be used when waxy crudes are expected. Thebucket weir eliminates buoyancy problems of level control when there is a smaldifference in the specific gravity between the crude oil and water. Internal level devices should be used. Wax could set up in the instrument bridle and prevent and controls from working properly. If a vessel with external controls is to be usfor a waxy crude, the bridle should be heat traced to prevent waxy solids forma(See Figure 900-18.)

Sand ContentIf the sand content of the reservoir fluid is severe and not controllable by gravelpacking at the reservoir face, cleanout of the crude separators may be requiredUnder these maintenance conditions, more than one separation train would be favored to avoid interrupting crude production.

TurndownThe turndown ability of a large single train of crude separation is a concern. Although separation improves as the flow rate is reduced, control valves and asated instrumentation have a limited turndown. This problem can be overcome b

Fig. 900-17 Typical Production System for Two Reservoirs of Different Pressures



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ctor

o or ess (e.g., ers, re

in

n w).

use of dual control valves on the liquid and gas outlets sized to accommodate tfull flow range. Another method to accommodate low flow rates is to use the tesseparator as a startup separation vessel until full crude production permits the lsingle train operation.

AvailabilityEquipment components can be evaluated to determine statistical reliability, a fawhich may support the case for more than one train of separation. In the past, however, this evaluation has not been an overwhelming reason to decide for twmore trains. Other considerations, as discussed herein, will affect this decision.Usually, redundancy of vessels does not in itself improve availability of the procunless the characteristics of the fluid being processed force frequent cleanoutssand, scale clogging). However, redundancy of instruments, such as valves, filtand pumps, can improve availability, since these items have relatively high failurates.

Space/Weight ConsiderationsMultiple train concepts usually are not as space or weight efficient as single traconcepts. However, “piggy backing” of vessels minimizes this difference in restricted space applications, such as retrofit systems offshore.

Selection of Primary SeparatorsSelection of separator types for production facilities centers around configuratio(horizontal vs vertical) and the number of phase separations (as discussed belo

Fig. 900-18 Typical Horizontal Three-Phase Separator, Bucket and Weir Design



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be

l

nits a-

os ficant -

sepa-

Vertical vs HorizontalThere is relatively little difference between the total system cost of horizontal anvertical configurations because of savings in plot area or structural loadings. Thlist below compares advantages for each of these two types of separators.

• Vertical separators

– Have large liquid capacities.– Are less susceptible to malfunction due to dirt, mud, wax, etc.– Are much easier to clean out than horizontal vessels.– Liquid level is easier to control.– Are more efficient in liquid removal.– Are very versatile in operation. A properly sized vertical separator can

easily modified to almost any possible operational problem.

• Horizontal separators

– Have a much higher allowable gas velocity for the same cross-sectionaarea.

– Are less costly per unit volume of gas capacity.– Are easier to ship mounted on skid assemblies than vertical vessels.– Have more area available for settling when oil and water are being

separated.– Are easier to pipe up than vertical separators.– Allow more surface area for the coalescence of very unstable foam.– Have good flexibility.– Series stages can often be stacked to minimize plot area.– Have greater liquid/vapor interface area.– Economic ratio of length to diameter (L/D) is usually 3.5 to 1 to 4.0 to 1

but may be 5 or more to 1 if liquid viscosity is a controlling factor.

Two-Phase vs Three-PhaseTwo-phase units are used for very high gas/liquid ratios: e.g., early production uwith a “gas cap”; compressor suction and discharge scrubbers; gas/liquid applictions for final Reid Vapor Pressure (RVP) control.

Three-phase units are often operated as two-phase units when high gas/oil ratiand/or sanding problems are encountered in the early production stages. Signiadvantages may be gained from designing all primary separation units for threephase operation, because this approach provides significant flexibility for the predictable changes in gas/oil/water ratios that will be encountered during the facility life. Provided that all other technical parameters are equal, three-phase rators are larger than two-phase separators.



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970 Separation TheoryOil/gas/water production from oil wells must be treated to meet requirements fosales or safe transport. This is achieved with the use of separation systems, theof which is the separator. A separator is a pressurized vessel used for separatiooil, gas, and water. Additional equipment, such as pumps, dehydrators, etc., is required to achieve final treatment.

This section discusses basic separation theory and shows how this theory is apin the design of separation equipment. The discussion focuses on the equipmeand processes in common use in the oil-field, in plants, and in refineries.

Raw reservoir oil and gas fluids are multiple component hydrocarbon fluids whiusually are in a two-phase state (liquid and gas both present), with water and oimpurities also present. Separation of liquid and gas fluids and water removal anecessary to meet pipeline specifications for the stable, dehydrated, single-phafluids. An optimum oil/gas/water separation system is one that achieves a compmise between gas and oil product recovery at optimum operating temperaturespressures and at minimum cost. The selection of an optimum oil and gas separsystem requires an understanding of multicomponent system behavior, the prinples of oil/gas/water separation, and separation efficiency factors.

971 Mechanisms of Particle CollectionThe three basic separation methods are:

1. Gravity separation

2. Centrifugal force

3. Impingement and coalescence

For gas and liquid mixtures, the difference between the density of the two substances is most often used in process applications to effect separation. Thea number of ways density difference can be used to effect separation, such as gravity, or through centrifugal and impingement processes. The falling (or risingvelocity of a particle or droplet in a viscous medium is a function of the forces exerted on it. Whether these forces are from gravity or fluid momentum, the prinples governing particle behavior, as a function of density, are the same.

972 Gravity SeparationGravity separation is the most prevalent means of separation and takes advantthe difference in densities of the phases. A particle falling by gravity will acceleruntil drag forces balance gravitational forces. After that, it will continue to fall atconstant velocity known as the terminal or free settling velocity, as given by theequation below for rigid spherical particles.



d

atest ore

of

mal

Turbulent Flow (Newton's Law)

(Eq. 900-7)

where:C = Drag coefficient, dimensionless

Dp = Average particle diameter, ft

g = Acceleration due to gravity, 32 ft/sec2

Vt = Particle terminal velocity, ft/sec

ρ = Fluid density, lb/ft3

ρl = Density of liquid, lb/ft3

ρg = Density of gas, lb/ft3

Newton's Law defines the drag force resisting the motion of the particle during turbulent flow as the drag coefficient, C. In the turbulent flow region (500 < Re < 200,000), C has an average value of 0.44 for spheres.

Laminar Flow (Stokes' Law)If the flow is laminar (viscous), the relationship developed by Stokes applies, anEquation 900-8 defined for gas/liquid separation becomes:

(Eq. 900-8)

where:µ = Viscosity of gas, lb/ft • sec

973 Centrifugal ForceWhen a two-phase flowing stream changes direction, the phase having the gremass density tends to continue in a straight line. The resulting collision of the mdense material with the confining wall separates it from the less dense phase. Stokes' Law may be applied to this process if the flow is laminar and the effect gravity, g, is replaced by a, the acceleration due to centrifugal force.

974 Impingement and CoalescenceImpingement occurs when an entrained particle strikes an obstruction in its norflow path rather than the containing wall as in centrifugal force separation. The impinged obstruction acts as the collecting surface. As the fluid approaches an

Vt

4gDp ρ1 ρg–( )0.5

3 ρg( )C-------------------------------------------=

Vt

gDp2 ρ1 ρg–( )18µ------------------------------------=



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n of

. g to the

ater o ty of as ds.

mass u-may )

er-lets o

sily the urface ape,

impingement surface, such as a fiber, it curves around, but the momentum of thentrained droplet tends to move it straight ahead to collide with the fiber.

The term entrainment refers to the small particles carried by the gas which requmist extractor to remove. Reentrainment is liquid which has been separated frothe gas, then picked up again and carried out.

The process of impingement of liquid droplets in a gas stream onto a solid surfais used in a number of mist extractor designs (see Section 950 above). The liqudroplets, being denser than the continuous gas phase, tend to continue to travetheir direction of motion when the continuous gas phase is diverted by a solid surface. This momentum of the entrained droplets causes impingement of the lparticles onto the solid surface.

After the particles have impinged on the solid surface, surface tension holds theliquid particles onto the surface and prevents reentrainment; other particles impinging on the surface cause coalescence, with subsequent gravity separatiothe liquid. See Figure 900-2.

980 Fluid Properties

981 Formation and Characteristics of Oil-Water MixtureWater and oil are immiscible liquids, with water generally the heavier of the twoPlaced in a common container, the water easily separates from the oil by settlinthe bottom. In actual production, the water may indeed be easily separated fromoil, while in other cases separation may be very difficult. Oil-water mixtures are categorized into two general groups: free water mixtures and emulsions. Free wis water which easily separates from the oil phase. Emulsified water is difficult tseparate, and its removal is sometimes costly and complex. Actually, the stabilithe mixtures is relative. A distinction between free water and emulsified water hmeaning only in relation to the mixture's response to various dehydration metho

982 Free WaterWater produced with crude and considered “free” exists either as a continuous or slug, or as an unstable dispersion of droplets suspended in the crude by turblence. Free water may be the natural contents of the producing formation, or it be drive water from a secondary recovery scheme (i.e., water flood, steam floodwhich penetrates into the producing zone. The water remains free when the intface between the phases is sharp and the droplet size relatively large. The dropare free to move and respond readily to the separating effect of gravity; and if twdispersed droplets of water collide, they coalesce easily.

In fact, the coalesced state of the drops is the more stable condition. This is eademonstrated by studying the shape of a water droplet. The spherical shape ofdroplet in the absence of external stress has the greatest volume for the least sarea of any geometrical form. A droplet can momentarily take on some other sh



exist. y.

ipate

free

is ced f a

. ssure it is ndi-

ist rvoir

m l ream y eam. of

a -ure. with ure sive abi-

but that shape, being less stable than the spherical shape, does not continue toThe ratio of volume to surface area is, therefore, an indication of relative stabilitThis stability is explained by defining the term “free energy.” A droplet which is other than spherical in shape is said to possess free energy which tends to dissand force the droplet into a spherical shape. The coalesced state is more stablebecause it has a smaller surface area for the same volume, and therefore less energy. Two uncoalesced droplets are said to have higher “free energy.”

983 Fluid EquilibriumThe most common application for gas-liquid separation and treating equipmenton produced hydrocarbon flow streams. These hydrocarbon systems are produby withdrawing fluids from underground formations. A typical sample consists omixture of many different hydrocarbon components. Those of low molecular weight are often referred to as “light” components or “light ends.” They have higher vapor pressures than the heavier components with greater molecular weights. In the underground formation, the fluids may exist as both liquids and gases; the equilibrium is determined by the formation pressure and temperatureWhen a well is drilled and the fluids are produced, decreases in pressure in thesystem cause more of the components to vaporize. This vaporization continuesthroughout the production and processing sequence whenever the process predrops below the fluid vapor pressure. If a fluid is at or above its vapor pressure,said to be “stable” at the existing temperature and pressure, providing these cotions persist long enough to allow completion of the equilibrium and phase separation.

In cases where all or most of the produced hydrocarbons are light, they may extotally as a gas phase. The reservoir for these fluids is thought of as a gas reseand “gas wells” are drilled into it. When the components are largely heavier, theprincipal produced fluid is crude oil, although some gas is always vaporized frothe oil as it is produced. An oil well is one which produces crude oil, with naturagas as a secondary product. The ratio of gas to hydrocarbon liquid produced stcan vary from very low for a stream of heavy crude with almost no gas, to infinitfor a dry gas stream. This ratio is used frequently to describe a hydrocarbon strGas/oil ratio, abbreviated GOR, is given in English units as standard cubic feet gas per barrel of oil (scf of gas/bbl oil).

A produced oil-gas mixture flowing through a typical process system undergoesseries of pressure changes. Friction losses create a continuous drop while flowthrough valves and other restrictions result in instantaneous decreases in pressSimultaneous with these pressure variations, the fluid temperature is changing gradual ambient cooling and process heating or cooling. With changes in pressand temperature, the equilibrium between gas and oil is disturbed. With successtages, as the pressure drops, more gas will be released until the crude oil is stlized in a near gas free condition.



. In ontrol rti-. ity

f

rees

ity

m f

ced t, of be

f

e gas-

is

rs as

984 Fluid ShearIn a continuous phase, oil or water droplets exist in a relatively fragile conditionthe process of moving these fluids, pressure decreases (or increases) across cvalves or dump valves, or pumps impart energy into the flowing fluid. As the pacles in the fluid receive this energy, they break apart into many smaller particlesShear effects become significant when droplet sizes become so small that gravseparation is no longer effective.

985 Fluid Gravity vs TemperatureWhen a produced hydrocarbon liquid is made up of a relatively large number ofheavy molecules, its specific gravity will be greater than for a liquid consisting oprimarily lighter molecules. A system of characterizing hydrocarbon liquids has been developed and is in common use. Oil gravity is expressed in terms of “degAPI.” The definition for this system is:

°API = (141.5/SG) - 131.5(Eq. 900-9)

where:°API = Degrees API

SG = Specific gravity of oil at 60°F and atmospheric pressure

A light oil has a higher API gravity than a heavy oil. If a fluid has a specific gravof 1.0, its API gravity is 10° API. Crude oils most commonly are in the range of 10° to 50° API.

As a general rule, heavy oils, that is those with low API gravity, are produced frorelatively low pressure formations, have a low GOR, and often a large amount oproduced water forming a very stable emulsion. Light oils are more likely produat high pressure with a higher volume of associated gas, and less water contenwhich a smaller portion is emulsified. As a general rule, low gravity (heavy) oilsexhibit a higher viscosity at a given temperature than higher gravity oils. Figure900-19 shows typical viscosity curves for various gravities of crude oil. It shouldnoted, however, that gravity and viscosity, while exhibiting a general relational trend, are not directly related functions. The viscosities of several different oils othe same gravity may vary widely.

986 Multiphase FlowWhen gas, oil and water are present together, the stream is called a three-phasstream. When a stream is called a two-phase flow stream, the emphasis is on aliquid mixture, but does not necessarily mean no water is present with the oil. Itsimply emphasizing the presence of only gas or only liquid. Therefore a flow stream referred to as two-phase may actually be three-phase.

With two- or three-phase flow through long pipelines, bulk separation often occubetween gas and liquid. Large “slugs” of liquid separated by large “bubbles” of g



mulsi-

h an r pa-oval is al separa-er sepa-l- sary

pi- of

cause the flow to be intermittent. In very long, large lines, slug cycles of many seconds are common. This can create problems in process equipment if not accounted for in their design. On the other hand, in streams with high water content, of medium or high gravity oil, and very low flow stream velocities with little gas, water separation may occur in the line. The water may flow along the bottom of the line causing a high rate of corrosion there.

Gas affects the formation of oil-water emulsions. As gas is flashed, agitation occurs, beginning in the formation and continuing through producing and processing. This agitation can be severe, adding a great deal of energy to the efying process.

Gas also affects the separation of oil and water. If gas bubbles are rising througoil-water mixture, turbulence is created which interferes with the settling of watedroplets. For that reason gas is usually separated first, then water. If the gas serator is designed as a three-phase vessel to also remove water, that water remusually of secondary importance and is expected to be very incomplete. A typicprocess train has successive reductions in pressure and with each reduction a tion of gas. However, the amount of gas removed typically decreases at the lowpressures so that at the last step, very little free gas is present. Corresponding ration of water will be least efficient in the first stage of gas separation. The emusion treater or oil dehydrator is usually the end process. The actual dehydrationmust occur in as near to gas-free oil as possible. This process is not only necesfor performance, but is also the most economical. Because water separation tycally requires the largest process vessels, it is least expensive if the vessels arelow pressure, which is the condition that exists at the end of the process train.

Fig. 900-19 Typical Viscosity/Temperature Curves for Various Crude Oils



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fluid a

uch

fi-n all -

d ing,

990 Liquid/Liquid Separation

991 Liquid Retention TimeThe length of time a fluid particle in a flow stream remains in a vessel is called retention time. The longer the liquid retention time in the separator, the more timavailable for settling and coalescing water droplets from the oil, and the more ecient the separation. Inasmuch as increased retention time is a function of sepavolume, more separator volume may aid the ability of the separator to handle process surges and increase hold-up time ahead of downstream pumping.

The bulk average retention time of a process can be calculated by dividing the volume of the vessel by the volume flow rates of the fluid stream assuming plugflow. For a given flow rate, a long retention time will require a larger vessel thanshort retention time. It is therefore economic to decrease the retention time as mas the process performance will allow.

992 Factors That Affect Separation EfficiencyThe following factors affect separation efficiency:

1. Particle diameter

2. Retention time

3. Gas velocities in process vessel

4. Gas and liquid densities

5. Pressure

6. Temperature

7. Viscosity

8. Flow rate surges

9. Foam

10. Emulsions

11. Turbulence

12. Surface and interfacial tension

Particle diameter is one of the most important properties affecting separation efciency because it is the predominant factor in determining the settling velocity iapplications. Any design allowing high efficiency in the separation of small particles will allow a higher efficiency in the separation of larger particles if the maximum liquid handling capacity is not exceeded.

In liquid/liquid separation, techniques are being developed for determining liquiparticle size and distribution. Particle size and distribution are constantly chang



avity

or is -

s ing fi-rge d

res-

hter nsity

- the -sed in tes

al nge ave

ular lly

be

as fluid flow in pipelines and separators is a dynamic process. Separation by gris logically limited to particles of relatively large size.

An entrained liquid system is basically unstable, the particles either coalescing fragmenting if given sufficient time. The time needed to fragment or to coalesceinversely proportional to size and directly proportional to the amount of interparticle contact. Impingement separators are based upon interparticle contact.

993 Pressure and TemperatureAs the operating pressure of a production separator increases, its wall thicknesmust also increase dramatically. Thinner walled vessels may be obtained by ushigher-strength steels, by increasing the length-to-diameter ratios (not space-efcient), or simply by limiting the stage pressure. As a rule of thumb, vendors of lavessels should be able to fabricate wall thicknesses to 1.5 inches. Thicker walleseparators can be fabricated, but are expensive and need long delivery time. Psure also affects the actual flowing volume. An increase in pressure increases capacity. Both the gas and liquid densities are affected because more of the ligcomponents of the gas are driven into the liquid phase, thereby changing the deof both phases.

By Stokes' Law (Equation 900-8), the settling velocity of water particles is inversely proportional to the oil viscosity. The sensitivity to temperature of hydrocarbon viscosity suggests that raising the process temperature would decreaseviscosity, thereby increasing settling rates. Actually, heating crude oil to be separated benefits the separation process in several ways and was the earliest aid ugravitational separation of water. Here are some of the ways that heating facilitathe process:

• Higher process temperature lowers oil viscosity.

• Up to about 175°F the specific gravity difference between oil and water is increased with increasing process temperature.

994 ViscosityTo properly size a separator, the viscosities of the oil and water phases must beknown. The oil phase viscosity will typically have a much larger influence on vessel size than the water phase viscosity because oil viscosity is usually severtimes greater than water viscosity. Oil viscosities also vary over a much wider raand usually vary more with temperature. Due to these factors it is important to hgood oil viscosity data.

The best condition is to have oil viscosity versus temperature data for the particoil to be separated. Alternately, data from other wells in the same field can usuabe used without significant error. The viscosity versus temperature data may beplotted as a straight line on special ASTM graph paper. Then the viscosity maypredicted at any other temperature.



r. edict a

12 ities ses

ds u-at rent

his

If two data points are known, the Walther equation may also be used instead ofASTM graph paper. This equation plots as a straight line on ASTM graph papeThe advantage of the Walther equation is that any calculator may be used to proil viscosities without the special graph paper. To determine the oil viscosity at third temperature from two data points, the following three equations should besolved in order:

(Eq. 900-10)

B = ln [ln (µ1 + 0.7)] - (M ln T1)(Eq. 900-11)

µ3 = exp[exp(M ln T3 + B)] - 0.7(Eq. 900-12)

where:µn = Oil viscosity at Tn, centipoise, cp

Tn = Temperature corresponding to µn, °R

M = Slope of straight line

B = Intercept of straight line

For cases where only one datum point is available, Equations 900-11 and 900-may be used by assuming a value for the slope. This method predicts oil viscoswith good accuracy over small temperature ranges of 20°F to 40°F. For most cathe slope will have a value in the range of -3.5 to -4.0.

If no data are available, the oil viscosity may be estimated by a variety of methofrom the temperature and oil gravity. These methods, however, are not very accrate, as viscosity is a function of oil composition and not strictly of oil gravity. This to say, two oils with the same gravity at the same temperature may have diffeviscosities that are orders of magnitude apart.

In the absence of data, Figure 900-20 may be used to estimate oil viscosities. Tgraph plots kinematic viscosity in centistokes versus temperature in degrees Celsius. To obtain the oil viscosity in centipoise at a particular temperature in degrees Fahrenheit, the following conversions are required:

T(°C) = (5/9)(T°F-32)(Eq. 900-13)

µ = υ(SG)(Eq. 900-14)

Mln ln µ1 0.7+( )[ ] ln ln µ2 0.7+( )[ ]–

lnT1 lnT2–---------------------------------------------------------------------------------------=



his he

where:T(°C) = Temperature, °C

υ = Kinematic viscosity, centistokes, cs

The Beggs and Robinson correlation may also be used to predict oil viscosity. Tcorrelation predicts oil viscosity based on the temperature and the oil gravity. Tdata set used to develop this correlation included 460 oil systems with gravitiesbetween 16° and 58° API at temperatures between 70°F and 295°F.

µo = 10x - 1(Eq. 900-15)

where:µo = Viscosity of oil phase, cp

T = Temperature, °F

x = yT -1.163

y = 10z

z = 3.0324 - 0.02023G

G = Oil gravity, °API

Fig. 900-20 Estimate of Kinematic Viscosity (centistokes) vs Temperature (°Celsius) for Various Oils



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iquid le an

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gely

It is ting

This correlation is good for predicting dead-oil viscosities. Unfortunately, three-phase separators contain oils at their bubble point. Therefore, this correlation teto predict high oil viscosities and should only be used as a last resort.

The viscosity of the water phase may be estimated from the following equation:

(Eq. 900-16)

where:D = 0.5556 T - 26.21

T = Temperature, °F

This equation does not apply if the heavy phase in the separator is not water. Fexample, in a glycol dehydration system, the heavy phase is a glycol-water mixand the viscosity must be obtained from charts based on the mixture compositi

995 FoamFoam is a mixture of gas dispersed in a liquid and has a density less than the libut greater than the gas. One type of foam is called bubble foam. A foaming cruoil requires a greater interface area and longer retention time to remove the gasfrom the liquid.

Bubble foam may be caused by a pressure reduction which causes the lighter lcomponents of the crude oil to flash and escape from the liquid as a gas. Bubbfoam may also be formed by aeration of the liquid in the flowline. Bubble foam cbe dispersed by the use of impingement baffles and residence time.

A second type of foam is chemical foam, a phenomenon of surface tension. Thsurface tension of the bubble is so strong that the bubble will not break. This tyof foam is caused by iron sulfide particles, asphaltenes, and resins in the crude

As a general rule, all oil foams. However, oil is seldom considered to be foamy unless a separator is designed too small and carryover results. Oil producers, however, generally insist on the smallest vessel possible, and thus the space aable for natural foam decay is reduced. Generally, foam is a more serious probwhen oil viscosity is high. Therefore low and medium gravity applications, especially in relatively low temperature service, can be expected to foam. If foam is significant factor, then vertical vessels may not be advisable. Horizontal vesselspreferred in order to spread the foam layer out, decreasing foam height and givmore exposure to the free gas phase.

Sizing separators to accommodate foam is an inexact process that depends laron experience and field data. Foam may occupy a large portion of the vessel volume; in extreme cases perhaps over half the volume may be taken by foam.best to size foamy oil separators by drawing from field test results and, interprethem for the application.

1µ--- 0.021482 D 8078.4 D

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Special types of internals are often used to help break down foam. Particular attion must be given to the inlet momentum absorber and to the defoaming eleme

996 EmulsionsAn emulsified oil/water mixture consists of very tiny droplets of one phase dispersed throughout the other in a manner that makes separation difficult. Thedroplets are called the discontinuous phase and the surrounding fluid is referreas the continuous phase. In crude oil/water mixtures the oil may be either the cuous or the discontinuous phase. The oil phase depends on the volume ratio oftwo fluids and the interface chemistry. The more common emulsion produced iswater-in-oil emulsion; that is, the oil is the continuous phase. An oil-in-water emsion is referred to as a reverse emulsion. This discussion is concerned only witnormal water-in-oil emulsions.

Formation of an EmulsionWhen oil and water exist in the same producing formation they are stratified anthe water is essentially “free.” Yet when a produced oil-water mixture is examinit is often found that the water droplets are very small; and further, they seem toremain that way and can thus be defined as an emulsion.

The coalesced state of an oil-water mixture is the most stable state. Additional energy is required for an emulsion to form. Any mechanical energy input devicesuch as a pump, can therefore produce the needed energy to create an emulsialthough the necessary energy may already be present in the fluid in the form ohydraulic energy. A flow restriction, such as a valve, orifice, a bend in a pipe, orsimple viscous friction can convert some of the energy in the flow to formation energy. Forcing the fluids through the porous formation can shear the two phastogether, create new interface surfaces, and produce an emulsion even before mixture enters the well bore.

Emulsion StabilityAs mechanical energy breaks the water into increasingly smaller droplets in thethe free energy of the mixture is raised. The resulting dispersion may consist ofdroplet sizes as small as a few microns in diameter (1 micron = 10-6 meter). It is obvious that the surface-area to volume ratio of this dispersion is very large; thefore, it would appear that immediate and rapid coalescence would take place. Iother words, it would appear that this very “tight” emulsion would be unstable. Othe contrary, however, experience has demonstrated that crude oil emulsions csometimes be very stable. Several factors contribute to this stability and hindercoalescence and separation by the gravitational pull on the heavier water dropl

The interface between the phases (the surface of the water droplet) is complicaand exhibits a peculiar localization of chemical, electrostatic, and physical activThis activity is not entirely understood. When a small water droplet is torn from large one, a new interface surface is created. Initially this surface is “clean” andactually no more than the meeting of two phases. Soon, however, certain substpresent in the continuous oil phase become attracted to it. These substances c



stic

p-

e of

ith such

e

on the droplet surface and build a tough, leathery film around it, similar to a plabag filled with water. The substances that form the film around the droplet are referred to as “stabilizing” agents because they block the ability of the water drolets to return to their coalesced state. See Figure 900-21.

The ratio of the dispersed phase to the whole affects the mixture's stability. If thwater content is high, initial coalescence will be more easily achieved. As morethe water is removed from the field, coalescence becomes more difficult.

When an emulsion is first formed it is relatively unstable. Its stability increases wtime as the film around each droplet of water grows thicker and tougher. When an emulsion remains untreated for a relatively long period of time, it becomes “aged” and is much more difficult to resolve than when it was first formed.

Droplet size is a very important factor. When droplets are very small they offer agreater total surface area for the collection of stabilizing agents. The separatingforce of gravity is also less effective. A very “tight” emulsion is much more stablthan one made up of larger droplets.

To summarize, the factors primarily affecting the stability of an emulsion can becategorized as follows:

• Stabilizing agents• Electrostatic charge• Water ratio• Viscosity of continuous phase• Specific gravity difference of phases• Age of emulsion• Droplet size

Fig. 900-21 Water Droplets in an Oil Phase



ent

lems

the po- i-

flow

rnal

cter-

l ble.

tling

thin sults

These factors vary in relative importance, but the presence of the stabilizing agis always required.

Stabilizing AgentsThe common stabilizing agents responsible for an emulsion and attendant probare:

• Heavy paraffinic compounds• Heavy napthenic acids• Petroleum acids• Asphaltic compounds• Organic solids• Inorganic solids

The single most significant characteristic of all stabilizing agents, in relation to emulsion formation, is their strong attraction to the oil/water interface. Some of most stable emulsions are created by the intrusion of a foreign substance in theproduction rather than by a naturally occurring stabilizer. An example is the temrary “problem” emulsion produced immediately after a well is acidized for scaleremoval, or the tough emulsion produced from a newly drilled well which is stablized by the drilling mud.

997 Flow Rate Surge or “Slugs”Separator designs must include surge capacity to account for nonsteady-state rate which inevitably occurs in normal production operation and to provide suffi-cient liquid storage capacity to allow instruments and operators to react to exteoperational upsets.

A liquid surge volume is added to the vessel liquid capacity when required. Thissurge factor can typically be from 0% to 50% depending both on the well charaistics and the physical layout of the separation equipment.

API 14E, Design and Installation of Offshore Production Platforms, gives typicasurge factors for use in offshore service when more specific data are not availa(See Figure 900-22.)

998 TurbulenceTheoretically, good water-oil separation efficiency depends on the presence of smooth, laminar flow in the liquid region of the vessel. Excessive turbulence promotes mixing of the two liquid phases, reducing or negating the effect of setvelocity of the water droplets in the oil. Proper configuration of vessel internals helps to promote stable flow. The degree of turbulence in the flowing stream withe separator is of considerable importance. The action of excess turbulence rein carrying potentially separate liquid particles in the eddy currents. A normal measure of turbulence in any flowing stream is the dimensionless Reynolds Number, R.



ed

he

ce

of

Reynolds Number (R) = D v ρ/η(Eq. 900-17)

where:D = Four times the pipe hydraulic radius (cross-sectional area divid

by the wetted perimeter), ft

v = Gas velocity, ft/sec

ρ = Gas density, lb/ft3

η = Gas viscosity, lb/ft • sec

All other factors remaining constant, the Reynolds Number varies directly with thydraulic radius. Hence, the effect of turbulence can be minimized by inserting internal subdivisions in the separator, as illustrated in Figure 900-23.

Unless the Reynolds Number is controlled, there will be an ever wider divergenfrom reasonably “calm” flow as vessel size increases. Normally, the larger the hydraulic radius of the flow path at constant velocity the greater the magnitude

Fig. 900-22 Typical Surge Factors

Service Factor

Facility handling primary production from its own platform 20%

Facility handling primary production from another platform or remote well in less than 150 feet of water

30%

Facility handling primary production from another platform or remote well in greater than 150 feet of water

40%

Facility handling gas lifted production from its own platform 40%

Facility handling gas lifted production from another plat-form or remote well

50%

Fig. 900-23 Turbulence Control by Mechanical Subdivision of Cross Section of Separator Vessel



se hts

s

s. The

ll

ated

ddi-

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ini-

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the eddy current effect. This means that as vessel size increases, the allowablemaximum superficial velocity that would produce good separation under given conditions in a small vessel would have to be reduced, thus offsetting the increain separation capacity expected from increased size. This circumstance highligthe importance of controlling turbulence, especially in larger vessels.

999 Sour ServiceThe designation of sour crude applies when the H2S content in the oil has a partial pressure above 0.05 psia. This corresponds to an H2S content of 63 grains/100 ft3 or 0.1 mole % at 50 psia. Several processing and corrosion prevention measuremust be exercised when handling sour production. The corrosion prevention measures affect valves, piping, and steel selection for vessels. The addition of filming-type corrosion inhibitors to prevent H2S corrosion in the downhole tubularsor inlet manifold usually creates foaming conditions which must be taken into account when sizing the crude separator, as discussed above.

The processing needs for sour crude separation are related to the fact that H2S in the gas phase retains more water and raises the hydrate temperature of the gafollowing design factors must be considered when processing sour crude:

1. Foaming tendency of the crude, with the addition of corrosion inhibitors, wiincrease the diameter of the crude separation vessels.

2. The volume of water in the gas phase may require that the inlet fluid be heto prevent hydrate formation exacerbated by the H2S.

3. A H2S stripper or chemical scavenger may be required to remove H2S from the crude oil with safe disposal of the H2S gas.

4. Disposal of sour water from the crude separation stages may require the ation of a sour water stripper with safe disposal of the effluent gas.

5. Heat requirements of upstream wellhead heaters will be increased becausthe additional equilibrium water content to prevent hydrate formation.

6. Maximum velocity criteria of piping and vessel nozzles must be carefully examined to minimize corrosion/erosion.

7. Additional safety sensors and shutdown devices need to be employed to mmize risk.

Carbon dioxide is also a consideration in the design of the crude separation sysCO2 becomes corrosive at a partial pressure of approximately 10 psia. If water present, CO2 and water will form carbonic acid, a weak acid, corrosive to steel. CO2 also contributes to hydrate formation.


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