OIL AND GAS SEPARATION DESIGN MANUAL

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OIL AND GAS SEPARATIONDESIGN MANUALBYC. RICHARD SIVALLS, P.E.SIVALLS, INC.BOX 2792ODESSA, TEXAS 79760All rights reserved. This publication is fully protected bycopyright and nothing that appears in it may be printed,either wholly or in part, without special permission.Revised February 10, 2009

SIVALLS, INC.ROIL AND GAS SEPARATION - DESIGN MANUALTABLE OF CONTENTSTechnical Bulletin No. 142 – Oil and Gas Separation – Design and SizingIntroductionInternal Construction of SeparatorsSeparator TypesFactors Affecting SeparationSeparator DesignGas CapacityLiquid CapacityOther Types of Separation EquipmentConclusionExample Problems11-22-33-44-566-778-9Figure 1 Gas Capacity of Vertical L.P. SeparatorsFigure 2A & 2B - Gas Capacity of Vertical H.P. SeparatorsFigure 3 Gas Capacity of Horizontal L.P. SeparatorsFigure 4A & 4B - Gas Capacity of Horizontal H.P. SeparatorsFigure 5A & 5B - Liquid Capacity of Horizontal H.P. SeparatorsFigure 6 Gas Capacity of Spherical L.P. SeparatorsFigure 7 Gas Capacity of Spherical H.P. SeparatorsFigure 8 & 9 Vertical Oil-Gas SeparatorsFigure 10 Horizontal Oil-Gas SeparatorsFigure 11 Vertical Oil-Gas-Water SeparatorsFigure 12 Horizontal Oil-Gas-Water SeparatorsFigure 13 Spherical L.P. Oil-Gas SeparatorsFigure 14 Spherical H.P. Oil-Gas SeparatorsFigure 15 Horizontal H.P. Double Tube Table 1A & 1B - Specifications, Vertical L.P. SeparatorsTable 2A & 2B - Specifications, Vertical H.P. SeparatorsTable 3A & 3B - Specifications, Horizontal L.P. SeparatorsTable 4A & 4B - Specifications, Horizontal H.P. SeparatorsTable 5A, 5B, 5C - Specifications, Spherical Separators2728-293031-3233-34References34Technical Bulletin No. 159 – Two Stage Separation SystemIntroductionTwo Stage SeparationDescription of ProcessGas and Liquid IncreaseEconomicsFigure 1 Schematic Flow DiagramFigure 2 Gas from Flash SeparatorFigure 3 Stock Tank Liquid Increase11-222-33456

Technical Bulletin No. 162 – Filter SeparatorsGeneralProcess DescriptionHorizontal Filter SeparatorsVertical Filter SeparatorsFilter Separator SizingConclusion1111-222Table 1 & 2 Figure 1 & 2 Figure 3 & 4 Figure 5 Figure 6 Table 3 & 4 -23-45-6789Correction FactorGas Capacity of Horizontal Filter SeparatorsGas Capacity of Vertical Filter SeparatorsHorizontal Filter SeparatorsVertical Filter SeparatorsSpecifications of Filter SeparatorsTechnical Bulletin No. 163 – Low Temperature Gas Separation UnitsGeneralProcess ApplicationEquipment DescriptionEstimated RecoveriesFigure 1 Flow Diagram, Low Temperature Separation UnitFigure 2 Effect of Temperature on Liquid RecoveryReferences111-33456Technical Bulletin No. 177 – Vertical Gas ScrubbersIntroductionConstructionScrubber DesignConclusionTable 1 Correction FactorsTable 2 Specifications of Vertical Gas ScrubbersFigure 1 Gas Capacity of Vertical Gas ScrubbersFigure 2 Vertical Gas Scrubber111-223345

SIVALLS, INC.RSECTION: 300TECHNICAL BULLETINNo. 142, Rev. 7February 10, 2009OIL AND GAS SEPARATIONDESIGN AND SIZINGINTRODUCTION:Hydrocarbon streams as produced at the wellhead are composed of a mixture of gas, liquid hydrocarbonsand sometimes free water. In most cases it is desirable to separate these phases as soon as possible afterbringing them to the surface and handle or transport the two or three phases separately. This separation ofthe liquids from the gas phase is accomplished by passing the well stream through an oil-gas or oil-gaswater separator.Different design criteria must be used in sizing and selecting a separator for a hydrocarbon stream based onthe composition of the fluid mixture. In the case of low pressure oil wells, the liquid phase will be large involume as compared to the gas phase. In the case of high pressure gas-distillate wells the gas volume willbe higher as compared to the liquid volume. The liquid produced with high pressure gas is generally a highAPI gravity hydrocarbon, usually referred to as distillate or condensate. However, both low pressure oil wellsand high pressure gas-distillate wells may contain free water.Separators are used in many other locations other than wellhead production batteries, such as gasolineplants, upstream and downstream of compressors, and liquid traps in gas transmission lines. They are alsofound on inlets to dehydration units, gas sweetening units, et cetera. At some of these locations separatorsare referred to as knockouts, free liquid knockouts, and traps. Sometimes these vessels are calledscrubbers. Caution should be used when referring to a vessel required for gas/liquid separation as ascrubber. Within the gas industry there is another type of vessel often called a scrubber. This is one that isdesigned to handle a gas stream with only trace amounts of free liquid present in the gas. They are notdesigned using the same criteria as is used for gas/liquid separation where appreciable amounts of liquidare present or where liquid slugging maybe encountered.However, all of the vessels mentioned above that are designed to separate gas and free liquids serve thesame primary purpose. This technical paper is concerned primarily with the use of separators in fieldinstallations. The theory and basic design criteria will be the same no matter where they are located or theirbasic use.INTERNAL CONSTRUCTION OF SEPARATORS:The principal items of construction that should be present in a good liquid-gas separator are the sameregardless of the overall shape or configuration of the vessel. Some of these features are itemized asfollows:1. A centrifugal inlet device where the primary separation of the liquid and gas is made;2. A large settling section of sufficient length or height to allow liquid droplets to settle out of the gasstream with adequate surge room for slugs of liquid;3. A mist extractor or eliminator near the gas outlet that will coalesce small particles of liquid that willnot settle out by gravity;4. Adequate controls consisting of level controller, liquid dump valve, gas back pressure valve, safetyrelief valve, pressure gauge, level gauge, instrument gas regulator and piping.It has been found that the bulk of gas-liquid separation takes place in the inlet centrifugal separating section.-1-

Here the incoming stream is spun around the walls of a small cylinder or usually the walls of the vessel inthe case of a vertical or spherical separator. This subjects the fluids to a centrifugal force up to five hundredtimes the force of gravity. This action stops the horizontal motion of the free liquid entrained in the gasstream and forces the liquid droplets together, where they will fall to the bottom of the separator in thesettling section.The settling section is necessary to allow the turbulence of the fluid stream to subside and allow the liquiddroplets to fall to the bottom of the vessel, due to the difference in the gravity between the liquid and gasphases. A large open space in the vessel has been found adequate for this purpose. Introduction of specialquieting plates or baffles with narrow openings only complicates the internal construction of the separatorand provides places for sand, sludge, paraffin, et cetera, to collect and eventually plug up the vessel andstop the flow. It has been found that the separation of liquid and gas using the centrifugal inlet feature and alarge open settling section will produce a more stable liquid product, which can be obtained in atmosphericor low pressure storage tanks. Minute scrubbing of the gas phase by use of internal baffling or plates mayproduce more liquid to be discharged from the separator, but it will not be a stable product, since the lightends will be entrained in it, and therefore more vapor losses will be incurred from the storage system.Sufficient surge room should be allowed in the settling section to handle slugs of liquid without carry over tothe gas outlet. This can be accomplished to some extent by the placement of the liquid level controller in theseparator, which in turn determines the liquid level. The amount of surge room required is often difficult, ifnot impossible, to determine based on well test or flowing data. In most cases the separator size used for aparticular application is often a compromise between initial cost and possible surging requirements.Another major item required to effect good and complete liquid-gas separation is a mist eliminator orextractor near the gas outlet. Small liquid droplets that will not settle out of the gas stream, due to the little orno gravity difference between them and the gas phase, will be entrained and pass out of the separator withthe gas. This can be almost eliminated by passing the gas through a mist eliminator near the gas outletwhich has a large surface impingement area. The small liquid droplets will hit the surfaces, coalesce andcollect to form larger droplets which will then drain by gravity back to the liquid section in the bottom of thevessel. It is believed that the stainless steel woven wire mist eliminator is the most efficient type, and hasbeen proven by removing up to 99.9% or more of the entrained liquids from the gas stream. This type offersthe greatest surface area for the collection of liquid droplets per unit volume as compared to vane types,ceramic packing or other configurations. The vane type mist eliminators do have application in areas wherethere is entrained solid material in the gas phase that may collect and plug a wire mesh type mist eliminator.SEPARATOR TYPES:There are four major types or basic configurations of separators generally available from manufacturerswhich are as follows:1.2.3.4.Vertical;Horizontal Single Tube;Horizontal Double Tube;Spherical.A typical vertical low pressure oil-gas separator with mechanical controls and the features as previouslydescribed is illustrated in Figure 8. Figure 9 illustrates a typical vertical high pressure or low pressure oil-gasseparator with pneumatic controls. The vertical separator has the advantage that it will handle greater slugsof liquid without carry over to the gas outlet, and the action of the liquid level control is not quite as critical.Due to the greater vertical distance between the liquid level and the gas outlet there is less tendency to revaporize the liquid into the gas phase. Some disadvantages are that it is more difficult and expensive tofabricate and ship this type of separator in skid mounted assemblies, and it takes a larger diameterseparator for a given gas capacity than a horizontal vessel. From this it can be seen that this type ofseparator is most often used on fluid streams with low gas-oil ratios; in other words, handling considerablymore liquid than gas.Spherical separators offer an inexpensive and compact vessel arrangement. Figure 13 illustrates a typicallow pressure model with mechanical controls. Figure 14 illustrates a similar high pressure spherical oil-gas-2-

separator with pneumatic controls. However, this type of vessel has very limited surge space and liquidsettling section. The placement and action of the liquid level control in this type of vessel is also very critical.The horizontal separator has several different advantages particular to this type of construction. Figure 10illustrates a typical horizontal high or low pressure oil-gas separator with pneumatic controls. The horizontalhigh pressure double tube separator is illustrated by a typical example shown in Figure 15. The horizontalseparator in both the double tube and single tube configuration has several advantages over the verticalseparator as it is easier to skid mount, less piping is required for field connections, and a smaller diameter isrequired for a given gas capacity. This type of vessel also has a larger interface area between the liquid andgas phases which aids in separation. When gas capacity is a design criterion, the horizontal vessel is moreeconomical in high pressure separators, due the increased wall thickness required with larger diameters.However, the liquid level control placement is more critical than in a vertical separator and the surge spaceis somewhat limited.The double tube separator offers a slight advantage over a single tube in that the liquid section is separatedfrom the gas space, and there is less chance for disturbance of the liquid and re-entrainment of any liquidsinto the gas phase. But, the double tube configuration is more expensiveThree phase, or oil-gas-water separation, can be easily accomplished in any type of separator by installingeither a special internal baffling to construct a water leg or water siphon arrangement, or by use of aninterface liquid level control. A three phase feature is difficult to install in a spherical due to the limitedinternal space available. With three phase operation two liquid level controls and two liquid dump valves arerequired. Figure 11 illustrates a typical high or low pressure separator equipped for oil-gas-water threephase operation. Figure 12 is an illustration of a typical horizontal high pressure or low pressure oil-gaswater separator.From an evaluation of the advantages and disadvantages of the various types of separators, the horizontalsingle tube separator has emerged as the one that gives the most efficient operation for initial investmentcosts for high pressure gas distillate wells with high gas-oil ratios. For high liquid loadings, either lowpressure or high pressure, vertical type separators should be considered.FACTORS AFFECTING SEPARATION:There are several basic factors which will affect the operation and separation between the liquid and gas1phases in a separator.1. Separator operating pressure;2. Separator operating temperature;3. Fluid stream composition.Changes in any one of these factors on a given fluid well stream will change the amount of gas and liquidleaving the separator. In most applications the well stream composition is a fact of nature and cannot becontrolled by the operator. Only in plants or where several streams are mixed can the fluid streamcomposition can be varied, affecting the oil and gas separation. Generally speaking, an increase inoperating pressure or decrease in operating temperature will increase the liquid recovered in a separator.However, there are optimum points in both cases beyond which further changes will not aid in liquidrecovery. In fact, storage system vapor loses may become too great before these points can be reached.In the case of wellhead separation equipment an operator generally wants to determine the optimumconditions for a separator to produce the maximum income. Again, generally speaking, the liquid recoveredis worth more than the gas. So high liquid recovery is a desirable feature, providing it can be held in theavailable storage system. Also, pipeline requirements for the BTU content of the gas may be another factoraffecting the separator operation. Without the addition of expensive mechanical refrigeration equipment it isoften not feasible to try to affect the operating temperature of a separator. However, on most high pressurewells an indirect heater is used to heat the gas prior to pressure reduction in a choke to pipeline pressure.By careful operation of this indirect heater the operator can prevent overheating of the gas stream prior tochoking, more than what is required, and therefore affect the temperature of the separator downstream fromthe indirect heater.-3-

The operator can also control the operating pressure to some extent with the use of back pressure valveswithin the limitation of the flowing characteristics of the well against a set pressure head and thetransmission line pressure requirements. As previously mentioned, higher operating pressure will generallyresult in higher liquid recovery.An analysis can be made using the well stream composition to find the optimum temperature and pressureat which a separator should operate to give the maximum liquid and/or gas phase recovery. Thesecalculations, known as “Flash Vaporization Calculations,” require a trial-and-error solution and are moregenerally adapted to solution by a programmed computer. However, an operator can also make trial settingswithin the limitations of the equipment to find the best operating conditions to result in the maximum amountof gas or liquids that are desired. In the case where separators are used as scrubbers or knockouts aheadof other treating equipment or compressors, it is generally desired to remove the maximum amount of liquid2from the gas stream to prevent operational damage to the equipment downstream from the scrubber.SEPARATOR DESIGN – GAS CAPACITY:The gas capacity of oil-gas separators has been calculated for many years from the following empiricalrelationship proposed by Souders-Brown: ρL ρ g v K ρ g 12qvThenA Wherev Superficial gas velocity based on the cross-sectional area of the vesselavailable for vapor flow, ft/sec2A Cross-sectional area of the separator available for vapor flow, ft3q Gas flow rate at operating conditions, ft /sec3ρL Density of liquid at operating conditions, lb/ft3ρg Density of gas at operating conditions, lb/ftK Empirical factorVertical SeparatorVertical SeparatorHorizontal SeparatorHorizontal SeparatorK Factors for Separators5’ high10’ high10’ longOther lengths“L” in ft.Spherical SeparatorVertical ScrubbersBubble Cap Tray ColumnsBubble Cap Tray ColumnsValve Tray ColumnsValve Tray ColumnsK Factors for Columns24” spacing18” spacing24” spacing18” spacing-4-K 0.12 to 0.24, avg. 0.18K 0.18 to 0.35, avg. 0.265K 0.40 to 0.50, avg. 0.450.56 L K 0.45 10 K 0.2 to 0.35, avg. 0.275K 0.35K 0.16K 0.12K 0.18K 0.11

3Mesh PadVane PackVane PackK Factors for Mist EliminatorsGenerally, the lower capacitiescorrespond to the mesh paddesigns with the highest dropletremoval efficiencies.Horizontal FlowVertical Up-flowThe higher capacities aregenerally associated withpocketed vane designs.K 0.22 to 0.39K 0.9 to 1.0K 0.4 to 0.53As given in the Engineering Data Book published by the Gas Processors Suppliers Association, the Kcapacity factor for mesh mist extractors is often derated as given in the following table for higherpressure operation to compensate for the reduction in surface tension of the liquids that occurs withincreasing pressure.Adjustment of K Factor for PressurePressure, psigPercent of Design ValueAtmospheric100150903008560080115075The above relationship is based on a superficial vapor velocity through a vessel; and the vapor or gascapacity is then in relationship to the diameter of the vessel. The formula is also used for other designs,such as trayed towers in dehydration or gas sweetening units and for the sizing of mist eliminators.Therefore, the “K” factor for these is presented above, along with the factors for vertical and horizontalseparators, so that the relationship one bears with the other can be seen.2.40(D)2 (K )(P ) ρ L ρ g Q Z(T 460 ) ρ g 12Where: Q Gas capacity at std. conditions, MMSCFD*D Internal diameter of the vessel, ft.P Operating pressure, psiaT Operating Temperature, FZ Compressibility factorAll other items as defined above*For Horizontal single tube separators partially full of liquid, an equivalent I.D. must be determinedfor the vapor area available or the gas capacity must be reduced by multiplying by the ratio of theactual cross sectional area available for vapor flow to the cross sectional area of the vessel.Since the above equation is empirical, perhaps a better determination of separator capacity should be madefrom actual manufacturers’ field test data. Figures 1 through 4, 6 and 7 are gas capacity charts for variousstandard size separators based on operating pressure. These actual manufacturers’ gas capacity chartstake into consideration height differences in horizontal separators which add to the gas capacity of theseparators. As can be seen, height and length differences are not taken into account in the above SoudersBrown equation. But, field experience has proven

Different design criteria must be used in sizing and selecting a separator for a hydrocarbon stream based on the composition of the fluid mixture. In the case of low pressure oil wells, the liquid phase will be large in volume as compa

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