900 Production Separators

900 Production Se Separators Abstract This section presents design principles, process considerations, and sizing for production separators, including common oilfield separators and separator internal components and their functions. It discusses flash calculations, separation theory, fluid properties, and liquid/liquid separation. Also included is a discussion of the input data needed for the PC “Bookware” programs for sizing separators.

Contents

Chevron Corporation

Page

910

Introduction

900-4

911

Objectives

912 912

Gene Genera rall Back Backgr grou ound nd

920

Design of Production Separators

921

Introduction

922

Gas Plant Plant Proc Process ess Vesse Vessels ls and Compr Compress essor or Knockou Knockoutt Drums Drums

923

Oilf Oilfie ield ld Produ Product ction ion Sepa Separa rator torss

924 924

Crud Crudee Oil Oil Dehy Dehydr drat atio ion n

930

PC Based Programs

931

Compa Compari rison son with with Com Compa pany ny Desig Design n Proce Procedur duree

932 932

Inpu Inputt to the the Boo Bookw kwar aree Prog Progra rams ms

933

Progr ogram Outpu utputt

934

Cauti Cautions ons on Usin Using g the the Book Bookwa ware re Pro Progra grams ms

940

Common Oilfield Separators

941

Scrubbers

942 942

Gas Gas Tra Traps ps and and San Sand d Tra Traps ps

943

Three Three-Ph -Phase ase Horiz Horizont ontal al Separ Separato ators rs

944

Test Se Separ parators ors

945

Filte Filterr Separ Separato ators rs (Coal (Coales esce cers rs))

946

Slug Ca Catchers

900-4

900-5

900-1

900-8

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900 Production Separators

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Pressure Vessel Manual

947

Steam Sepa Separrato ators

948

Flash Sep Separa arators tors

949

Flare Flare Knock Knockou outt or Vent ent Scrub Scrubber berss

950

Separator Internal Components and Functions

951

Primar Primary y Separa Separation tion Section Section and Inlet Inlet Div Diverte erters rs

952

Seconda Secondary ry Separa Separation tion and Vessel essel Interv Intervals als

953

Mist ist Extr xtracto actorrs

954 954

Serp Serpen enti tine ne Vanes anes

955

Dixon Plates

956 956

Cent Centri rifu fuga gall Mist Mist Ext Extra ract ctor orss

957 957

Vorte ortex x Brea Break kers ers

958

Weir Buck Buckets ets and Inter Interfa face ce Cont Contro rols ls

960

Design Principles and Process Considerations

961

Approx Approxima imate te Flash Flash Calcu Calculat lation ionss

962

Proce Process ss Info Inform rmati ation on and and Facil Facility ity Desi Design gn

970

Separation Theory

971

Mech Mechani anism smss of Part Particl iclee Col Collec lectio tion n

972 972

Gra Gravity vity Sepa Separa rati tion on

973 973

Cent Centri riffugal ugal Force orce

974 974

Impi Imping ngem emen entt and and Coale Coalesc scen ence ce

980

Fluid Properties

981

Format Formation ion and and Charac Character teristi istics cs of Oil-W Oil-Water ater Mixture Mixture

982

Free Water

983 983

Flui Fluid d Equi Equili libr briu ium m

984

Fluid Sh Shear

985

Fluid Fluid Grav Gravity ity vs Temper emperat ature ure

986

Multi ultiph phaase Flow

990

Liquid/Liquid Separation

991 991

Liqu Liquid id Ret Reten enti tion on Tim Timee

992

Factors Factors That Affect Affect Separat Separation ion Efficie Efficiency ncy

993 993

Pres Pressu sure re and and Tem Tempe pera ratu ture re

994

Viscosity

995

Foam

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900-21

900-31

900-33

900-2

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996

Emulsions

997 997

Flow Flow Rate Rate Sur Surge or “Slu “Slugs gs””

998

Turbulence

999

Sour Service

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910 Introduction This section presents general guidelines for the selection of oil/gas/water separation systems. In upstream oilfield operations, separators are the primary process elements in production systems. They separate the components of reservoir fluid into segregated gas, crude oil, and water streams for further processing. A review of the factors affecting production separation efficiency is presented along with sizing procedures 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 information in this section is not intended to be used for final separator design, although it will allow reasonable verifications of vendor's quotations.

911 Object ectives The objectives of this section are: 1.

To acquaint acquaint the engine engineer er with the the factors factors that that go into planni planning ng a crude crude oil sepaseparation system.

2.

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

3.

To provide provide procedur procedures es for selectin selecting g overall overall dimension dimensionss for two- and threethreephase separators.

912 912 Gene Genera rall Back Backgr grou ound nd Historically, vendors and engineering contractors perform much of the sizing for pressure vessels. In many cases, vendors and contractors use proprietary vessel design equations or programs to size vessels. To a large degree, most of these programs are based on theoretical equations with limited field data to verify the basic mathematical model. All crudes are different, and good modeling of performance involves knowledge not only of vessels but of crude characteristics. Information 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 theory presented below is the best current information, although empirical.

9200 Desi 92 Design gn of Prod Produc ucti tion on Sepa Separa rato tors rs 921 921 Intr Introd oduc ucti tion on This section discusses several methods for sizing horizontal and vertical separators.

922 Gas Plant Plant Process Process Vess Vessels els and and Compresso Compressorr Knockout Knockout Drums Drums The Company Design Procedure as outlined in Sectio Section n 300 is 300 is well suited for compressor knockout and process vessel design where quality phase separation is

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considered essential. This method uses a conservative design approach that generally accommodates variations in either process fluctuations or nominal flowrate increases. It is recommended that this design method be used first when comparing vessel sizes with other design approaches.

923 Oilfield Production Separators For oilfield production separators, less conservative design methods are commonly used to provide adequate sizing of vessels, such as production gas traps or “pool” traps. Methods similar to API 12J using K factors are generally employed for these less critical bulk separation processes. In these applications the engineer is generally designing for rapid separation of gas and liquids, typically in the 1 to 3 minute liquid hold-up range. The separator sizing computer programs discussed in Section 930 can be used for initial sizing. Final calculation is vessel-specific and must take local operating experience into account. The PC sizing programs presented in Section 930 require that you know certain process information that is key to obtaining a good separator design. In the event that process data are not available, program supplied default values can be used as guidelines to arrive at a “first pass” separator size. Most certainly the best design technique is to use field data (retention time, BS&W, etc.) to determine input to the PC programs. With field data, the program should provide a good method to predict comparative separator performance. All methods should be used in conjunction with foam prediction methods. Foam generation, 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 Dehydration Oil dehydration is a complex subject that does not always lend itself to a simple discussion of retention time vs oil gravity. It will not be covered in this manual; however, additional design information can be obtained by contacting: Chevron Research and Technology Company (CRTC), Production & Process Facilities Group.

930 PC Based Programs The “Production Facility Bookware Series” is a series on PC Based Programs for sizing separators. Module 101 is for two-phase separators; Module 102 is for threephase separators. Each module contains a personal computer program for designing or rating a vertical or horizontal separator. Module 101 and 102 can be obtained by contacting Chevron Research and Technology Company, Production & Process Facilities Group. (See Reference 9 in the Reference section of this manual for more information.)

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931 Comparison with Company Design Procedure The main difference between the “Bookware” method discussed here and the method recommended in Section 300 is in the correlations used for allowable vapor velocity. Bookware uses a theoretical, droplet terminal settling velocity correlation for vapor-liquid separation. The development is similar to that shown in Section 334 for liquid-liquid separation where the correlation used is based on data from operating units (Equation 300-1 or 300-2). For a vertical separator designed for 100 psig, specifying a liquid droplet diameter of 250 microns causes the Bookware method to use about the same vapor velocity as 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 needed. For a horizontal separator, the allowable vapor velocity criterion applies despite the fact 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 to the height of the vapor space and the residence time of the vapor in the separator. In other words, vapor moves in “plug flow” from the inlet end of the horizontal vessel to the outlet end. A certain liquid droplet, moving at the horizontal velocity of the vapor, settles from the top of the vapor space toward the vapor-liquid interface. If it reaches the interface before reaching the outlet end, then all droplets of that size will be removed by the separator. See the cautions below regarding using Bookware for horizontal separators. Liquid-liquid separation methods are similar in the Company and Bookware procedures. The Bookware procedures do not include demisters, coalescers, feed inlet shrouds, baffles, and water boots.

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

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•

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 weight

933 Program Output The program develops a set of vessels of “standard” dimensions that satisfy the separation and retention time requirements. Standard diameters are multiples of 6 inches; standard length increments are 1 foot. L/D varies from maximum to minimum. For each vessel, the program gives a measure of the excess capacity it provides. That excess may be in terms of gas or liquid rate, retention time, or droplet size separated.

934 Cautions on Using the Bookware Programs The following precautions should be observed when using the Bookware Programs:

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•

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 the vapor-liquid interface shall be equal to the residence time of the vapor within the vessel. This does not rule out use of a small fraction of vessel cross section for 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 higher than 5.0 can result in reentrainment; this advice is not very specific. The user of the program should apply the criteria of Section 351 to determine the cross section for vapor flow, even if the Bookware program then indicates that the vessel is oversized for vapor.

•

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

•

The programs do not adjust the fraction of horizontal vessel volume occupied by 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 capacity for vapor and liquid and adjust the liquid level appropriately.

•

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

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940 Common Oilfield Separators Separators are used for many different applications. A few of the most common services are described in this section. Figure 900-1 is a flow chart showing a typical field separation plant. Fig. 900-1

Typical Field Separation Plant

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

941 Scrubbers A 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.) Scrubbers are usually two-phase, vertical vessels, although in larger applications horizontal scrubbers are not uncommon.

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Fig. 900-2


Impingement and Droplet Growth in a Typical Filter Coalescer

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

942 Gas Traps and Sand Traps Gas Traps A 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.

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Fig. 900-3


Typical Two-Phase Vertical Separator (Gas Trap)

Sand Traps A sand trap is a device for removing sand from a produced well-stream. Sand traps are typically used on high pressure gas wells, where sand production is common.

943 Three-Phase Horizontal Separators A three-phase horizontal separator is the primary component used for oil/water bulk separation. See Figure 900-4.

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Chevron Corporation


Fig. 900-4


Typical Three-Phase Horizontal Separator

944 Test Separators A test separator is also called an Automated Well Test Unit (AWT), clean-up separator, or a gage trap. A test separator determines the oil, water, and gas volumes of each producing reservoir or well, and monitors well performance if the facility is owned and operated by a single company. If the producing field has several coowners, the field may be “unitized” and the test separator may also be used to determine relative revenue payment to each co-owner. A minimum test separator would separate the liquid and gas and measure both phases. The density of the liquids can be measured by an accurate densimeter after the oil and water are completely separated in a test container. A conventional test separator may be horizontal or vertical. The test separator is sized for the maximum “best” full well potential and anticipated gas and water rates. The operating pressure of the test separator would be the same operating pressure as the first stage separator. The size of the test separator is normally fixed by the 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 contaminants from a gas or liquid stream when particle size is too small to be removed by a conventional separator. See Figure 900-5.

946 Slug Catchers A slug catcher, or surge drum is a separator designed to separate bulk liquid-gas flow streams which are surging or slugging (see Section 970). The slug catcher may also serve as a production separator, in which case further processing is generally required. Properly designed, slug catchers should smooth out the intermittent flow.

Chevron Corporation

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March 1990



Fig. 900-5

Typical Filter Separator (Coalescer)

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

948 Flash Separators A 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 in conjunction with an electrostatic coalescer or desalter where no free gas can be tolerated. The fluid is first degassed in a flash separator which is elevated above the coalescer so that once degassed the fluid will remain gas-free.

949 Flare Knockout or Vent Scrubbers Flare scrubbers or vent scrubbers are placed in gas outlet streams from production separators to remove any residual liquids left or any condensates that may have formed in the line, prior to flaring or venting.

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

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1.

Primary phase separation of predominantly liquid hydrocarbons from those that are predominantly gaseous.

2.

Refine primary separation by removing the entrained hydrocarbon mist from the gas.

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3.

Further refine the separation by removal of entrained bubbles from the liquid phase so that, ideally, the liquid contains no more gas than would exist at equilibrium 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 allowing an opportunity for reentrainment of one into the other.

The physical properties used to achieve these processes are gravity, centrifugal force, and impingement. The effective combination of these properties, and their governing principles, leads to efficient separator design. A description and explanation of a horizontal two-phase separator illustrates how these physical properties and principles are employed. (See Figure 900-6.) Fig. 900-6

Basic Two-Phase Separator

The separator consists of three basic sections plus the controls, which correspond with the four processes noted above. These are: 1.

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

2.

A secondary separation section (mist extraction or coalescing section) which minimizes turbulence in the gas section.

3.

A liquid collecting and removal section which prevents reentrainment of the separated phases.

951 Primary Separation Section and Inlet Diverters The 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 separating vessel, which has a much larger diameter than the flow line, the natural velocity for the same continuous flow rate is much less. Therefore, the inertia effects entering the vessel must be quickly and effectively overcome so that natural gravity

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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 deceleration of the incoming fluids. This device is usually referred to as a “momentum absorber.” Downstream of the momentum absorber, liquid material with much entrained gas separates generally downward. Above the liquid layer is a predominantly gaseous material with much entrained liquid, moving either upward in a vertical separating vessel or longitudinally in a horizontal vessel. The configuration of the inlet device can take many shapes and should be given careful consideration. Structural channel iron usually provides optimum results, but angle iron, flat plates or dished heads have been considered optimum for certain applications. Vertical vessels often employ a centrifugal inlet device. See Figure 900-7 for typical configurations of inlet devices. Fig. 900-7

Typical Configurations of Inlet Devices

952 Secondary Separation and Vessel Intervals The secondary separation section of a separator is important for efficient separator design. Here the properties of gravity separation and impingement are combined with the control of turbulence to achieve the required quality of liquid droplet separation from the gas phase, and oil from water. In two-phase separators, the primary function of the liquid retention section is to allow free gas bubbles to separate from the liquid. This is accomplished by providing sufficient residence time, free of excessive turbulence, to permit gravity separation to occur. Typically no special internals are required for “degassing” the liquid.

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A second function of the liquid retention section in three-phase separators is to separate 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 separation by gravity.

953 Mist Extractors The stainless steel wire mesh mist extractor, an impingement type extractor, is perhaps the most common mist extractor. Most wire mesh mist extractor manufacturers furnish charts depicting proper velocity design. A common pad of wire mesh used in production separators is 4 inches to 8 inches thick, having a density of 9 lb/ft3 (0.011 inch diameter stainless steel wire). (See Figure 900-8.) Fig. 900-8

Wire Mesh Mist Extractor Configurations

Gas velocities entering a mist extractor usually are in the turbulent flow range, so Newton'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 extractor has no difficulty catching 10 micron particles. Mist extractors of poor design are on the market that allow even 1000 micron particles to pass. Most arrangements of angle iron pieces make poor mist extractors. Fig. 900-9

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Liquid Particle Characteristics

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The gas velocity for Newton's Law can be expressed as:

VG = K

ρL – ρG ------------------ρG

0.5

(Eq. 900-1)

where: K = C (1.74 gd ) (Eq. 900-2)

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 factor is proportional to the drag force on a film of particle. If the K factor is too high in a mist extractor, the film will not drain. A large amount of liquid is torn off the outlet edge and, due to the high K factor, the particles created are smaller than normal and are 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 steep and 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. Most separators 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 extractor. Reentrainment is usually the biggest problem, not entrainment. Increasing velocity increases centrifugal and impingement catching ability, but not gravity catching ability. 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 cloud point, wax may appear.

954 Serpentine Vanes Serpentine vane extractors are lightweight and economical and need be only about 8 inches long. See Figure 900-11. These particular vanes have natural drainage paths that do not reduce the cross-section areas. Thus, a high K factor can be used safely in horizontal flow. Serpentine vanes have also been used in a vertical flow configuration. Used in this way the K factor must be reduced because the performance is limited by the ability of the separated liquid to drain downward countercurrent to the gas flow.

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Fig. 900-10 Example: Carryover vs K-Factor


Fig. 900-11 Serpentine Vane Mist Extractor

In the normal horizontal flow configuration, very high K factors can be used if sufficient volume is available upstream for bulk liquid separation, and downstream to allow for settling of liquid fly-off. Fly-off is liquid which has coalesced in the mist extractor, 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 allowable velocity, and therefore the K factor. Too high velocity of gas will prevent even these relatively large coalesced droplets from settling, and they will become reentrained in the gas stream. If the process volume is not available upstream and downstream of the vanes, then restrictions such as lower K factor and small allowable liquid loading are necessary. This is the case in some cross-flow separator designs, both vertical and horizontal. Wire mesh collects paraffin, hydrates, sand, and other solid particles, causing it to plug rather easily; therefore, it is not generally recommended for primary wellhead application, but is preferred for clean relatively high GOR applications. It can be used in either vertical upflow or small horizontal configurations. Its allowable K factor in horizontal flow is lower than for serpentine vanes because of its relatively poor ability to drain itself of liquids. However, when conditions permit its use, wire mesh can catch smaller particles than can the serpentine vane mist extractor.

955 Dixon Plates A successful and widely used type of mist extractor for many years, Dixon plates work on the principle of gravity separation. (See Figure 900-12.) They are used in horizontal vessels as shown below. Reducing the area of each flow path with Dixon plates reduces the turbulence, permitting gravity to separate the phases. Dixon plates are slanted at a 45° angle so that a settling liquid droplet has only a short distance to fall. Traditionally Dixon plates have been frequently used in foamy crude oil applications because of the large surface area which aids foam

Chevron Corporation

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

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

956 Centrifugal Mist Extractors This type of mist extractor utilizes the flow-stream momentum to create a high velocity rotational flow. The resulting centrifugal acceleration causes a separation of 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 performance. In general, any mist extractor that greatly reduces flow area or otherwise causes severe turbulence should be avoided.

957 Vortex Breakers Large amounts of carry-over and gas slippage can often occur due to poor fluid outlet design. Vortexing can also occur at the gas or liquid outlet. When a Coriolis force or a nonuniform flow distribution starts a rotation motion, the available energy at the mouth of the outlet produces and maintains a strong vortex. Excessive pressure 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 interface can be sucked down into the drain if the liquid height above the drain is small and the draining velocity is large. The minimum phase height needed to feed the drain is a function of the drain diameter, draining velocity, and the ratio of phase densities above and below the interface.

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A useful guideline is to have a minimum of two times the nozzle diameter in liquid depth if the interface is gas/liquid, and three times the nozzle diameter if the interface is liquid/liquid, assuming the nozzles are sized for typical liquid velocities. If these minimum dimensions are maintained and vortex breakers are installed over the outlet nozzles, the problem of outlet reentrainment can be minimized. Figure 900-13 shows some common designs for vortex breakers. When the separator is three-phase, additional considerations are necessary to control levels. Fig. 900-13 Outlet Vortex Breaker Designs

958 Weir Buckets and Interface Controls Three types of outlet control for three-phase separators are shown in Figure 900-14. These arrangements can be used in horizontal or vertical vessels. The weir plate is simple and relatively inexpensive; however, the interface controller is activated by the difference in densities of oil and water. The controller must be sensitive. If the liquids 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. Water spills over the weir as it tries to attain the same hydrostatic pressure that the oil and water height are creating on the other side of the bucket. One advantage of this arrangement is that the controls sense the difference between liquid and gas; however, more internal structure and vessel volume are required. Making the bucket and weir adjustable adds flexibility. The open pipe arrangement is a simple and inexpensive dumping method. However, here too, interface control instrumentation must be sensitive to small changes in density. 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 nonvortexing

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

(a) Weir Plate

(b) Oil Bucket and Weir Plate

(c) Open Pipe

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flow. Placing a horizontal pipe on top of the outlet as shown in Figure 900-14c will help; 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 essential because 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 distorting liquid level gage readings and controller outputs. Therefore, a drain at this interface may be specified. A toadstool interface collector is one of the better draining devices.

960 Design Principles and Process Considerations To size and design a separator, certain data and information must be known about the process fluids and operating conditions. You need to know the service that the separator is to perform and the performance requirements. Often it is helpful to know something about the system into which the unit will fit. Special construction and design specifications, if applicable, must be followed. Then all the information must be interpreted to select the best design and to correctly size the separator. Often design data are incomplete and assumptions must be made. Information about 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 assortment of mist extractor types, and designs with and without slug catching sections.

961 Approximate Flash Calculations Flash calculations are normally too involved to be done by hand. They are usually done either on computer or in a programmable calculator. Sometimes it is necessary to get a quick estimate of the volume of gas that is expected to be flashed from an oil stream at various pressures. Figure 900-15 was developed by flashing several crude oils of different gravities at different pressure ranges. The curves are approximate. The actual shape depends on the initial separation pressure, the number and pressure of intermediate flashes, and the 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, which will eventually be flashed from the crude, or 250 ft 3 /BBL will be liberated as gas in the 1,000 psia separator. Another 25% (75% to 50%), or 125 ft3 /BBL will be separated 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 acceptable. It cannot be used for estimating gas flashed from condensate produced in gas wells.

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

962 Process Information and Facility Design Produced Fluid Data 1.

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 basis. If possible, the data should take the form of a detailed production forecast. See Figure 900-16 for a typical plot of a production facilities fluids forecast. Confirm whether the 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 optimize the separation system.

3.

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

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

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Chevron Corporation



Fig. 900-16 Production Fluids Forecast

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 influenced by artificial lift and reservoir pressure maintenance plans. 4.

Production characteristics should include, as applicable, information regarding such 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 Characteristics All production facilities will have a product quality specification that applies specifically to that facility, whether it is for natural gas, condensate, or crude oil. These

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

2.

Oil –

1% to 3% BS&W

–

20 lb salt/1000 BBL oil

–

11 to 13 psia Reid Vapor Pressure (RVP)

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 Conditions The majority of production conditions can, with proper planning, be accommodated to 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 smaller amount of produced water and, in the later stages, a reversal of that condition. This trend will not be experienced in the application of gas lift or water-flood programs, where the requirement of those programs can usually be predicted and accounted for in the design.

System Selection The 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 general

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in nature and emphasizes separator plans. Final system selection should be based upon a weighted combination of field experience, process simulation, engineering judgment, 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 molbalance for the system to establish: (1) the basic number of stages required to achieve mandatory product specifications, and (2) system optimization to maximize operational requirements while minimizing utility and facility costs. Preliminary equipment sizes for process vessels can be obtained in some cases. However, for detailed analysis, process equipment vendors should be contacted for the proprietary design aspects of such items as crude oil dehydrators or desalters. Correct and careful input to the process conditions supplied to equipment vendors is essential, especially when a “process guarantee” is part of the purchase contract. Use the selection guidelines outlined in this section to establish the preliminary system.

Number of Separation Stages Stage separation is the term given to the “step” reduction of pressure on the liquid until it reaches the export point. The liquid flows from the first stage separator into one or more lower stages and, finally, into the stock tank or pump station. Each separator 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 stages used, 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 returns applies. Actual production tests provide reliable solutions to the question. However, in the absence of actual tests, calculations provide the only means to reasonably determine the optimum number of stages and the optimum operating pressure of each stage. This tedious operation is usually performed by computer (many flash calculations are performed until the computer converges upon the optimum solution). A rule-of-thumb method for determining the optimum number of stages and operating pressure is given below. The first and last stage pressures are usually determined by other considerations. The second stage pressure equals the first stage pressure divided by the pressure ratio, and so forth for each stage. The pressure ratio per stage should not exceed the following, although in all rules-of-thumb, exceptions will be found:

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•

5—for gas-condensate production

•

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

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•


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. The following equations are used to determine the optimum operating pressures of the intermediate stages: 1 --n

R =

 P 1  -   ---- P s 

(Eq. 900-3)

P m = P m + 1R ( P1 = P2 R ) (Eq. 900-4)

P m = Ps R

n – (m – 1 )

(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 P 1 = 400 psia and Ps = 14.2 psia gives:

R =

400  0.5  --------- 14.2

= 5.3 (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 calculations will not agree with the results of the above equations. These equations assume that the 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 or final pressure is considerably smaller than between the other stages.

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When accurate oil and gas analyses are available, computer simulations can predict values 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 highest stage pressure. The decline potential of the FWHP has a very great impact upon the number of separation stages. On new field developments, when the reservoir decline properties are unknown, value judgments are often made on the number and pressure levels of stage separation. Multiple stages or trains of separation may be necessary to provide different backpressures to various wells with differing FWHP. FWHP is set by reservoir characteristics.

Factors Affecting Number of Separation Trains The following factors must be considered when deciding on the number of separation 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 water throughput, a function of the peak crude production, anticipated water production with time, and gas/oil ratio. Separator capacities may be limited by the physical size and lifting weight of the vessel. (See Figure 900-16.) More than one separation train may be justified if the reservoir production potential is 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. The economic impact of two or three trains should be evaluated to provide management with the information to make this decision.

Number of Reservoirs The number of separation trains is also influenced by the number of production reservoirs. If more than one reservoir is being produced, and the available flowing wellhead pressure cannot match the other reservoir, a second separation train may be needed. See Figure 900-17.

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

If the available FWHP from the second reservoir is sufficient to match the second stage of separation of the first reservoir, then the second reservoir production can be separated 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 the same amount of crude produced because gas flow rates may control vessel size.

Wax Content The wax content may influence the number of separation trains. Production could be interrupted by shutdown of the separation train if wax buildup occurs and the separation train vessels need to be steamed or cleaned in some other manner. Thus, 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 would be favored. A bucket-type liquid weir should be used when waxy crudes are expected. The bucket weir eliminates buoyancy problems of level control when there is a small difference 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 floats and controls from working properly. If a vessel with external controls is to be used for a waxy crude, the bridle should be heat traced to prevent waxy solids formation. (See Figure 900-18.)

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

Turndown The 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 associated instrumentation have a limited turndown. This problem can be overcome by

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

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

Availability Equipment components can be evaluated to determine statistical reliability, a factor which 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 two or more trains. Other considerations, as discussed herein, will affect this decision. Usually, redundancy of vessels does not in itself improve availability of the process unless the characteristics of the fluid being processed force frequent cleanouts (e.g., sand, scale clogging). However, redundancy of instruments, such as valves, filters, and pumps, can improve availability, since these items have relatively high failure rates.

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

Selection of Primary Separators Selection of separator types for production facilities centers around configuration (horizontal vs vertical) and the number of phase separations (as discussed below).

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Vertical vs Horizontal There is relatively little difference between the total system cost of horizontal and vertical configurations because of savings in plot area or structural loadings. The list 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 be easily modified to almost any possible operational problem.

Horizontal separators –

Have a much higher allowable gas velocity for the same cross-sectional area.

–

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-Phase Two-phase units are used for very high gas/liquid ratios: e.g., early production units with a “gas cap”; compressor suction and discharge scrubbers; gas/liquid applications for final Reid Vapor Pressure (RVP) control. Three-phase units are often operated as two-phase units when high gas/oil ratios and/or sanding problems are encountered in the early production stages. Significant advantages 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 separators are larger than two-phase separators.

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970 Separation Theory Oil/gas/water production from oil wells must be treated to meet requirements for sales or safe transport. This is achieved with the use of separation systems, the heart of which is the separator. A separator is a pressurized vessel used for separation of oil, gas, and water. Additional equipment, such as pumps, dehydrators, etc., is often required to achieve final treatment. This section discusses basic separation theory and shows how this theory is applied in the design of separation equipment. The discussion focuses on the equipment and processes in common use in the oil-field, in plants, and in refineries. Raw reservoir oil and gas fluids are multiple component hydrocarbon fluids which usually are in a two-phase state (liquid and gas both present), with water and other impurities also present. Separation of liquid and gas fluids and water removal are necessary to meet pipeline specifications for the stable, dehydrated, single-phase fluids. An optimum oil/gas/water separation system is one that achieves a compromise between gas and oil product recovery at optimum operating temperatures and pressures and at minimum cost. The selection of an optimum oil and gas separation system requires an understanding of multicomponent system behavior, the principles of oil/gas/water separation, and separation efficiency factors.

971 Mechanisms of Particle Collection The 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. There are a number of ways density difference can be used to effect separation, such as by gravity, or through centrifugal and impingement processes. The falling (or rising) velocity 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 principles governing particle behavior, as a function of density, are the same.

972 Gravity Separation Gravity separation is the most prevalent means of separation and takes advantage of the difference in densities of the phases. A particle falling by gravity will accelerate until drag forces balance gravitational forces. After that, it will continue to fall at a constant velocity known as the terminal or free settling velocity, as given by the equation below for rigid spherical particles.

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Turbulent Flow (Newton's Law) 0.5

4gD p ( ρ 1 – ρ g ) V t = ------------------------------------------3( ρg) C

(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, and Equation 900-8 defined for gas/liquid separation becomes: 2

gD p ( ρ 1 – ρ g ) V t = -----------------------------------18 µ (Eq. 900-8)

where:

µ

= Viscosity of gas, lb/ft • sec

973 Centrifugal Force When a two-phase flowing stream changes direction, the phase having the greatest mass density tends to continue in a straight line. The resulting collision of the more dense 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 of gravity, g, is replaced by a, the acceleration due to centrifugal force.

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

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impingement surface, such as a fiber, it curves around, but the momentum of the entrained 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 require a mist extractor to remove. Reentrainment is liquid which has been separated from the gas, then picked up again and carried out. The process of impingement of liquid droplets in a gas stream onto a solid surface is used in a number of mist extractor designs (see Section 950 above). The liquid droplets, being denser than the continuous gas phase, tend to continue to travel in their direction of motion when the continuous gas phase is diverted by a solid surface. This momentum of the entrained droplets causes impingement of the liquid particles onto the solid surface. After the particles have impinged on the solid surface, surface tension holds the liquid particles onto the surface and prevents reentrainment; other particles impinging on the surface cause coalescence, with subsequent gravity separation of the liquid. See Figure 900-2.

980 Fluid Properties 981 Formation and Characteristics of Oil-Water Mixture Water and oil are immiscible liquids, with water generally the heavier of the two. Placed in a common container, the water easily separates from the oil by settling to the bottom. In actual production, the water may indeed be easily separated from the oil, while in other cases separation may be very difficult. Oil-water mixtures are categorized into two general groups: free water mixtures and emulsions. Free water is water which easily separates from the oil phase. Emulsified water is difficult to separate, and its removal is sometimes costly and complex. Actually, the stability of the mixtures is relative. A distinction between free water and emulsified water has meaning only in relation to the mixture's response to various dehydration methods.

982 Free Water Water produced with crude and considered “free” exists either as a continuous mass or slug, or as an unstable dispersion of droplets suspended in the crude by turbulence. Free water may be the natural contents of the producing formation, or it may be drive water from a secondary recovery scheme (i.e., water flood, steam flood) which penetrates into the producing zone. The water remains free when the interface between the phases is sharp and the droplet size relatively large. The droplets are free to move and respond readily to the separating effect of gravity; and if two dispersed droplets of water collide, they coalesce easily. In fact, the coalesced state of the drops is the more stable condition. This is easily demonstrated by studying the shape of a water droplet. The spherical shape of the droplet in the absence of external stress has the greatest volume for the least surface area of any geometrical form. A droplet can momentarily take on some other shape,

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but that shape, being less stable than the spherical shape, does not continue to exist. The ratio of volume to surface area is, therefore, an indication of relative stability. This 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 dissipate and force the droplet into a spherical shape. The coalesced state is more stable because it has a smaller surface area for the same volume, and therefore less free energy. Two uncoalesced droplets are said to have higher “free energy.”

983 Fluid Equilibrium The most common application for gas-liquid separation and treating equipment is on produced hydrocarbon flow streams. These hydrocarbon systems are produced by withdrawing fluids from underground formations. A typical sample consists of a mixture 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 temperature. When a well is drilled and the fluids are produced, decreases in pressure in the system cause more of the components to vaporize. This vaporization continues throughout the production and processing sequence whenever the process pressure drops below the fluid vapor pressure. If a fluid is at or above its vapor pressure, it is said to be “stable” at the existing temperature and pressure, providing these conditions 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 exist totally as a gas phase. The reservoir for these fluids is thought of as a gas reservoir and “gas wells” are drilled into it. When the components are largely heavier, the principal produced fluid is crude oil, although some gas is always vaporized from the oil as it is produced. An oil well is one which produces crude oil, with natural gas as a secondary product. The ratio of gas to hydrocarbon liquid produced stream can vary from very low for a stream of heavy crude with almost no gas, to infinity for a dry gas stream. This ratio is used frequently to describe a hydrocarbon stream. Gas/oil ratio, abbreviated GOR, is given in English units as standard cubic feet of gas per barrel of oil (scf of gas/bbl oil). A produced oil-gas mixture flowing through a typical process system undergoes a series of pressure changes. Friction losses create a continuous drop while flowthrough valves and other restrictions result in instantaneous decreases in pressure. Simultaneous with these pressure variations, the fluid temperature is changing with gradual ambient cooling and process heating or cooling. With changes in pressure and temperature, the equilibrium between gas and oil is disturbed. With successive stages, as the pressure drops, more gas will be released until the crude oil is stabilized in a near gas free condition.

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

985 Fluid Gravity vs Temperature When a produced hydrocarbon liquid is made up of a relatively large number of heavy molecules, its specific gravity will be greater than for a liquid consisting of primarily lighter molecules. A system of characterizing hydrocarbon liquids has been developed and is in common use. Oil gravity is expressed in terms of “degrees API.” 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 gravity of 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 from relatively low pressure formations, have a low GOR, and often a large amount of produced water forming a very stable emulsion. Light oils are more likely produced at high pressure with a higher volume of associated gas, and less water content, of which a smaller portion is emulsified. As a general rule, low gravity (heavy) oils exhibit a higher viscosity at a given temperature than higher gravity oils. Figure 900-19 shows typical viscosity curves for various gravities of crude oil. It should be noted, however, that gravity and viscosity, while exhibiting a general relational trend, are not directly related functions. The viscosities of several different oils of the same gravity may vary widely.

986 Multiphase Flow When gas, oil and water are present together, the stream is called a three-phase stream. When a stream is called a two-phase flow stream, the emphasis is on a gasliquid mixture, but does not necessarily mean no water is present with the oil. It is simply 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 occurs between gas and liquid. Large “slugs” of liquid separated by large “bubbles” of gas

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

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 emulsifying process. Gas also affects the separation of oil and water. If gas bubbles are rising through an oil-water mixture, turbulence is created which interferes with the settling of water droplets. For that reason gas is usually separated first, then water. If the gas separator is designed as a three-phase vessel to also remove water, that water removal is usually of secondary importance and is expected to be very incomplete. A typical process train has successive reductions in pressure and with each reduction a separation of gas. However, the amount of gas removed typically decreases at the lower pressures so that at the last step, very little free gas is present. Corresponding separation of water will be least efficient in the first stage of gas separation. The emulsion treater or oil dehydrator is usually the end process. The actual dehydration must occur in as near to gas-free oil as possible. This process is not only necessary for performance, but is also the most economical. Because water separation typically requires the largest process vessels, it is least expensive if the vessels are of low pressure, which is the condition that exists at the end of the process train.

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990 Liquid/Liquid Separation 991 Liquid Retention Time The 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 time available for settling and coalescing water droplets from the oil, and the more efficient the separation. Inasmuch as increased retention time is a function of separator volume, 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 fluid volume of the vessel by the volume flow rates of the fluid stream assuming plug flow. For a given flow rate, a long retention time will require a larger vessel than a short retention time. It is therefore economic to decrease the retention time as much as the process performance will allow.

992 Factors That Affect Separation Efficiency The 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 efficiency because it is the predominant factor in determining the settling velocity in all applications. 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 liquid particle size and distribution. Particle size and distribution are constantly changing,

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as fluid flow in pipelines and separators is a dynamic process. Separation by gravity is logically limited to particles of relatively large size. An entrained liquid system is basically unstable, the particles either coalescing or fragmenting if given sufficient time. The time needed to fragment or to coalesce is inversely proportional to size and directly proportional to the amount of interparticle contact. Impingement separators are based upon interparticle contact.

993 Pressure and Temperature As the operating pressure of a production separator increases, its wall thickness must also increase dramatically. Thinner walled vessels may be obtained by using higher-strength steels, by increasing the length-to-diameter ratios (not space-efficient), or simply by limiting the stage pressure. As a rule of thumb, vendors of large vessels should be able to fabricate wall thicknesses to 1.5 inches. Thicker walled separators can be fabricated, but are expensive and need long delivery time. Pressure also affects the actual flowing volume. An increase in pressure increases capacity. Both the gas and liquid densities are affected because more of the lighter components of the gas are driven into the liquid phase, thereby changing the density of 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 decrease the viscosity, thereby increasing settling rates. Actually, heating crude oil to be separated benefits the separation process in several ways and was the earliest aid used in gravitational separation of water. Here are some of the ways that heating facilitates the 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 Viscosity To properly size a separator, the viscosities of the oil and water phases must be known. The oil phase viscosity will typically have a much larger influence on vessel size than the water phase viscosity because oil viscosity is usually several times greater than water viscosity. Oil viscosities also vary over a much wider range and usually vary more with temperature. Due to these factors it is important to have good oil viscosity data. The best condition is to have oil viscosity versus temperature data for the particular oil to be separated. Alternately, data from other wells in the same field can usually be used without significant error. The viscosity versus temperature data may be plotted as a straight line on special ASTM graph paper. Then the viscosity may be predicted at any other temperature.

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If two data points are known, the Walther equation may also be used instead of ASTM graph paper. This equation plots as a straight line on ASTM graph paper. The advantage of the Walther equation is that any calculator may be used to predict oil viscosities without the special graph paper. To determine the oil viscosity at a third temperature from two data points, the following three equations should be solved in order: ln [ ln ( µ 1 + 0.7 ) ] – ln [ ln ( µ 2 + 0.7 ) ] M = -------------------------------------------------------------------------------------- ln T 1 – lnT 2 (Eq. 900-10)

B = ln [ln (µ1 + 0.7)] - (M ln T 1) (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 900-12 may be used by assuming a value for the slope. This method predicts oil viscosities with good accuracy over small temperature ranges of 20°F to 40°F. For most cases the 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 methods from the temperature and oil gravity. These methods, however, are not very accurate, as viscosity is a function of oil composition and not strictly of oil gravity. That is to say, two oils with the same gravity at the same temperature may have different viscosities that are orders of magnitude apart. In the absence of data, Figure 900-20 may be used to estimate oil viscosities. This graph 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)

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

where: T(°C) = Temperature, °C

υ

= Kinematic viscosity, centistokes, cs

The Beggs and Robinson correlation may also be used to predict oil viscosity. This correlation predicts oil viscosity based on the temperature and the oil gravity. The data set used to develop this correlation included 460 oil systems with gravities between 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

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Chevron Corporation



This correlation is good for predicting dead-oil viscosities. Unfortunately, threephase separators contain oils at their bubble point. Therefore, this correlation tends to 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: 1 2 0.5 --- = 0.021482 [ D + ( 8078.4 + D ) ] – 1.2

µ

(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. For example, in a glycol dehydration system, the heavy phase is a glycol-water mixture, and the viscosity must be obtained from charts based on the mixture composition.

995 Foam Foam is a mixture of gas dispersed in a liquid and has a density less than the liquid but greater than the gas. One type of foam is called bubble foam. A foaming crude oil requires a greater interface area and longer retention time to remove the gas from the liquid. Bubble foam may be caused by a pressure reduction which causes the lighter liquid components of the crude oil to flash and escape from the liquid as a gas. Bubble foam may also be formed by aeration of the liquid in the flowline. Bubble foam can be dispersed by the use of impingement baffles and residence time. A second type of foam is chemical foam, a phenomenon of surface tension. The surface tension of the bubble is so strong that the bubble will not break. This type of foam is caused by iron sulfide particles, asphaltenes, and resins in the crude oil. 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 available for natural foam decay is reduced. Generally, foam is a more serious problem when oil viscosity is high. Therefore low and medium gravity applications, especially in relatively low temperature service, can be expected to foam. If foam is a significant factor, then vertical vessels may not be advisable. Horizontal vessels are preferred in order to spread the foam layer out, decreasing foam height and giving more exposure to the free gas phase. Sizing separators to accommodate foam is an inexact process that depends largely on 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. It is best to size foamy oil separators by drawing from field test results and, interpreting them for the application.

Chevron Corporation

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

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

Formation of an Emulsion When oil and water exist in the same producing formation they are stratified and the water is essentially “free.” Yet when a produced oil-water mixture is examined, it is often found that the water droplets are very small; and further, they seem to remain 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 device, such as a pump, can therefore produce the needed energy to create an emulsion, although the necessary energy may already be present in the fluid in the form of hydraulic energy. A flow restriction, such as a valve, orifice, a bend in a pipe, or simple 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 phases together, create new interface surfaces, and produce an emulsion even before the mixture enters the well bore.

Emulsion Stability As mechanical energy breaks the water into increasingly smaller droplets in the oil, the free energy of the mixture is raised. The resulting dispersion may consist of droplet 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; therefore, it would appear that immediate and rapid coalescence would take place. In other words, it would appear that this very “tight” emulsion would be unstable. On the contrary, however, experience has demonstrated that crude oil emulsions can sometimes be very stable. Several factors contribute to this stability and hinder coalescence and separation by the gravitational pull on the heavier water droplets. The interface between the phases (the surface of the water droplet) is complicated and exhibits a peculiar localization of chemical, electrostatic, and physical activity. This activity is not entirely understood. When a small water droplet is torn from a large one, a new interface surface is created. Initially this surface is “clean” and is actually no more than the meeting of two phases. Soon, however, certain substances present in the continuous oil phase become attracted to it. These substances collect

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Chevron Corporation



on the droplet surface and build a tough, leathery film around it, similar to a plastic bag 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 droplets to return to their coalesced state. See Figure 900-21. Fig. 900-21 Water Droplets in an Oil Phase

The ratio of the dispersed phase to the whole affects the mixture's stability. If the water content is high, initial coalescence will be more easily achieved. As more of the water is removed from the field, coalescence becomes more difficult. When an emulsion is first formed it is relatively unstable. Its stability increases with time as the film around each droplet of water grows thicker and tougher. When such 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 a greater total surface area for the collection of stabilizing agents. The separating force of gravity is also less effective. A very “tight” emulsion is much more stable than one made up of larger droplets. To summarize, the factors primarily affecting the stability of an emulsion can be categorized as follows:

Chevron Corporation

•

Stabilizing agents

•

Electrostatic charge

•

Water ratio

•

Viscosity of continuous phase

•

Specific gravity difference of phases

•

Age of emulsion

•

Droplet size

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

Stabilizing Agents The common stabilizing agents responsible for an emulsion and attendant problems are: •

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 the most stable emulsions are created by the intrusion of a foreign substance in the production rather than by a naturally occurring stabilizer. An example is the temporary “problem” emulsion produced immediately after a well is acidized for scale removal, or the tough emulsion produced from a newly drilled well which is stabilized by the drilling mud.

997 Flow Rate Surge or “Slugs” Separator designs must include surge capacity to account for nonsteady-state flow rate which inevitably occurs in normal production operation and to provide sufficient liquid storage capacity to allow instruments and operators to react to external operational upsets. A liquid surge volume is added to the vessel liquid capacity when required. This surge factor can typically be from 0% to 50% depending both on the well characteristics and the physical layout of the separation equipment. API 14E, Design and Installation of Offshore Production Platforms, gives typical surge factors for use in offshore service when more specific data are not available. (See Figure 900-22.)

998 Turbulence Theoretically, 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 settling velocity 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 within the separator is of considerable importance. The action of excess turbulence results in carrying potentially separate liquid particles in the eddy currents. A normal measure of turbulence in any flowing stream is the dimensionless Reynolds Number, R.

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Chevron Corporation



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 platform or remote well

50%

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

where: D = Four times the pipe hydraulic radius (cross-sectional area divided 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 the hydraulic radius. Hence, the effect of turbulence can be minimized by inserting internal subdivisions in the separator, as illustrated in Figure 900-23. Fig. 900-23 Turbulence Control by Mechanical Subdivision of Cross Section of Separator Vessel

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

Chevron Corporation

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900 Production Separators

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