Three Phase SeparatorOil/gas/water three-phase separators are commonly used for well testingand in instances where free water separates from the oil or condensate.Can be accomplished in any type of separator by:I. Installing either special internal baffling to construct a water leg or awater siphon arrangement.II. Using an interface liquid-level control.Difficult to install in spherical separators because of their limitedavailable internal space.In three-phase operations, 2 liquid dump valvesare required.
Factors Affecting SeparationFactors that affect separation of liquid and gas phases include:separator operating P, separator operating T & fluid stream composition.For a given fluid well stream in a specified separator, changes in any ofthese factors will change the amount of gas & liquid leaving the separator.An increase in operating P or a decrease in operating T increases liquidcovered in a separator. However, this is untrue for gas condensate systems.Optimum points for both beyond which further changes won’t affectliquid recovery.
Computer simulation (flash vaporization calculation) of well streamphase behavior of allows finding optimum P & T for max. liquid recovery.Sometimes it isn’t practical to operate at the optimum point becausestorage system vapor losses becomes too great under optimum conditions.At the wellhead separation facilities, operators tend to determine theoptimum conditions for separators to maximize revenue.High liquid recovery is desirable as liquid H.C. product is worth more thanthe gas, provided that it can be handled in the available storage system.Operator control operating P by use of backpressure valves.
Pipeline requirements for Btu content of the gas should also beconsidered as a factor affecting separator operation.Usually unfeasible to lower the separator operating T without addingexpensive mechanical refrigeration equipment.However, indirect heater can be used to heat the gas prior to pressurereduction of pipeline P in a choke. This is applied to high P wells.By carefully operating this indirect heater, operator can preventoverheating the gas stream ahead of the choke.This adversely affects T of the downstream separator.
Separator DesignNatural gas engineers normally don’t perform detailed designing ofseparators but carry out selection of suitable separators frommanufacturers product catalogs based on well stream conditions.Specifications are used for separator selections are:1) Gas Capacity.2) Liquid Capacity.
1. Gas Capacity:Empirical equations proposed by Souders-Brown are widely used forcalculating gas capacity of oil/gas separators:andwhereA: Total cross-sectional area of separator, ft2ν: Superficial gas velocity based on total cross-sectional area A, ft/sq: Gas flow rate at operating conditions, ft3/sρL: Density of liquid at operating conditions, lbm/ftρg: Density of gas at operating conditions, lbm/ft3K: Empirical factor
Table 7-1 K-Values Used for Designing SeparatorsAlso listed in the table are K-values used for other designs such as misteliminators & tray towers in dehydration or gas sweetening units.
Substituting Eq(7.1) into Eq(7.2) and applying real gas law gives:Where:qst: Gas capacity at standard conditions, MMscfdD: Internal diameter of vessel, ftP: Operation pressure, psiaT: Operating temperature, °FZ: Gas compressibility factor
It should be noted that Equation (7.3) is empirical.Height differences in vertical separators & length differences inhorizontal separators aren’t considered.Field experience has indicated that additional gas capacity can beobtained by increasing height of vertical separators & length of horizontalseparators.Although 1/2 full of liquid is more or less standard for most single-tubehorizontal separators, lowering liquid level to increase the available gasspace within the vessel increases the gas capacity.
2. Liquid Capacity :Liquid retention time within vessel determines separator liquid capacity.Adequate separation requires sufficient time to obtain an equilibriumcondition between the liquid & gas phase at T & P of separation.separator liquid capacity relates to the retention time through thesettling volume:qL: Liquid capacity, bbl/dayVt: Liquid settling volume, bblt:Retention time, min
Table 7-2 Retention Time Required under VariousSeparation ConditionsIt is shown that T has a strong effect on three-phase separations at low P.
Table 7-3 through Table 7-8 present liquid-settling volumes with theplacement of liquid-level controls for typical oil/gas separators.Experience shows for high P separators treating high gas/oil ratio wellstreams, gas capacity is the controlling factor for separator selection.However, the reverse may be true for low P separators used on wellstreams with low gas/oil ratios.
Stage Separation :A process in which H.C. mixtures are separated into vapor & liquid phasesby multiple equilibrium flashes at consecutively lower pressures.A two-stage separation requires 1 separator & storage tank, and a three-stage separation requires 2 separators & storage tank. (Storage tank iscounted as the final stage of vapor/liquid separation).Stage separation reduces P a little at a time, in steps or stages, resultingin a more stable stock-tank liquid.Usually a stable stock-tank liquid can be obtained by a stage separationof not more than 4 stages.
In high-pressure gas-condensate separation systems, a stepwisereduction of P on the liquid condensate can significantly increase therecovery of stock-tank liquids.Prediction of the performance of various separators in multistageseparation system carried out with compositional computer models usinginitial well stream composition and the operating T & P of various stages.
It has been generally recognized that two stages of separation plus thestock tank are practically optimum.The increase in liquid recovery for two-stage separation over single-stageseparation usually varies from 2 to 12 %, although 20 to 25 % increases inliquid recoveries have been reported.Although 3 to 4 stages of separation theoretically increase the liquidrecovery over a two-stage separation, the incremental liquid recoveryrarely pays out the cost of the additional separators.
The first-stage separator operating P is generally determined by the flowline P and operating characteristics of the well.The P usually ranges from 600 to 1,200 psi.In situations where the flow line P > 600 psi, it is practical to let the first-stage separator ride the line or operate at the flow line P.
P at low stage separations can be determined based on equal P ratiosbetween the stages:Rp: Pressure ratioNst: Number of stages - 1P1: First-stage or high-pressure separator P, psiaPs: Stock-tank P, psiaPressures at intermediate stages can be then designed with the formula:Pi = pressure at stage i, psia.
Flash Calculation :Based on the composition of well stream fluid, quality of products fromeach separation stage predicted by flash calculations, assuming phaseequilibriums are reached in the separators.This requires knowledge of equilibrium ratio defined as:ki: Liquid/vapor equilibrium ratio of compound iyi: Mole fraction of compound i in the vapor phasexi: Mole fraction of compound i in the liquid phase
Accurate determination of k-values requires computer simulators solvingthe Equation of State (EoS) for hydrocarbon systems.For P <1,000 psia, a set of equations presented by Standing (1979)provides an easy and accurate means of determining ki values.According to Standing, ki can be calculated by:
Low-Temperature SeparationField experience & flash calculations prove that lowering the operating Tof a separator increases the liquid recovery.Low T separation process separates water & H.C. liquids from the inletwell stream and recovers liquids from gas more than normal T separators.It’s efficient means of handling high P gas & condensate at the wellhead.Low T separation unit consists of: high P separator, P reducing chokes &various pieces of heat exchange equipment.When P is reduced by a choke, fluid T decreases due to the JouleThomson or throttling effect (irreversible adiabatic process in which gasheat content remains the same across the choke but P & T are reduced).
Generally at least ΔP of 2,500 to 3,000 psi required from wellheadflowing P to pipeline P to pay out in increased liquid recovery.The lower the separator operating T, the lighter the liquid recovery . The lowest operating T recommended is usually around -20 °F.This is constrained by carbon steel embitterment, and high-alloy steelsfor lower T are usually not economical for field installations.Low T separation units are normally operated from 0 to 20 °F.
The actual T drop per unit P drop is affected by several factors including:gas stream composition, gas and liquid flow rates, bath T & ambient T.T reduction in the process can be estimated using the equationspresented in Chapter 5.Gas expansion P for hydrate formation can be found from the chartprepared by Katz (1945) (see Chapter 12).Liquid & vapor phase densities can be predicted by flash calculation.
Following the special requirement for construction of low T separationunits, the P reducing choke is usually mounted directly on the inlet of thehigh P separator.Hydrates form in the downstream of the choke due to the low gas T andfall to the bottom settling section of the separator.They are heated and melted by liquid heating coils located in the bottomof the separator.