1. Three Phase Separator
Oil/gas/water three-phase separators are commonly used for well testing
and 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 a
water siphon arrangement.
II. Using an interface liquid-level control.
Difficult to install in spherical separators because of their limited
available internal space.In three-phase operations, 2 liquid dump valves
are required.

2. Conventional Horizontal Three-Phase Separator

3. Factors Affecting Separation
Factors 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 of
these factors will change the amount of gas & liquid leaving the separator.
An increase in operating P or a decrease in operating T increases liquid
covered in a separator. However, this is untrue for gas condensate systems.
Optimum points for both beyond which further changes won’t affect
liquid recovery.

4. Computer simulation (flash vaporization calculation) of well stream
phase behavior of allows finding optimum P & T for max. liquid recovery.
Sometimes it isn’t practical to operate at the optimum point because
storage system vapor losses becomes too great under optimum conditions.
At the wellhead separation facilities, operators tend to determine the
optimum conditions for separators to maximize revenue.
High liquid recovery is desirable as liquid H.C. product is worth more than
the gas, provided that it can be handled in the available storage system.
Operator control operating P by use of backpressure valves.

5. Pipeline requirements for Btu content of the gas should also be
considered as a factor affecting separator operation.
Usually unfeasible to lower the separator operating T without adding
expensive mechanical refrigeration equipment.
However, indirect heater can be used to heat the gas prior to pressure
reduction of pipeline P in a choke. This is applied to high P wells.
By carefully operating this indirect heater, operator can prevent
overheating the gas stream ahead of the choke.
This adversely affects T of the downstream separator.

6. Separator Design
Natural gas engineers normally don’t perform detailed designing of
separators but carry out selection of suitable separators from
manufacturers' product catalogs based on well stream conditions.
Specifications are used for separator selections are:
1) Gas Capacity.
2) Liquid Capacity.

7. 1. Gas Capacity:
Empirical equations proposed by Souders-Brown are widely used for
calculating gas capacity of oil/gas separators:
and
where
A: Total cross-sectional area of separator, ft2
ν: Superficial gas velocity based on total cross-sectional area A, ft/s
q: Gas flow rate at operating conditions, ft3/s
ρL: Density of liquid at operating conditions, lbm/ft
ρg: Density of gas at operating conditions, lbm/ft3
K: Empirical factor

8. Table 7-1 K-Values Used for Designing Separators
Also listed in the table are K-values used for other designs such as mist
eliminators & tray towers in dehydration or gas sweetening units.

9. Substituting Eq(7.1) into Eq(7.2) and applying real gas law gives:
Where:
qst: Gas capacity at standard conditions, MMscfd
D: Internal diameter of vessel, ft
P: Operation pressure, psia
T: Operating temperature, °F
Z: Gas compressibility factor

10. It should be noted that Equation (7.3) is empirical.
Height differences in vertical separators & length differences in
horizontal separators aren’t considered.
Field experience has indicated that additional gas capacity can be
obtained by increasing height of vertical separators & length of horizontal
separators.
Although 1/2 full of liquid is more or less standard for most single-tube
horizontal separators, lowering liquid level to increase the available gas
space within the vessel increases the gas capacity.

11. 2. Liquid Capacity :
Liquid retention time within vessel determines separator liquid capacity.
Adequate separation requires sufficient time to obtain an equilibrium
condition between the liquid & gas phase at T & P of separation.
separator liquid capacity relates to the retention time through the
settling volume:
qL: Liquid capacity, bbl/day
Vt: Liquid settling volume, bbl
t:Retention time, min

12. Table 7-2 Retention Time Required under Various
Separation Conditions
It is shown that T has a strong effect on three-phase separations at low P.

13. Table 7-3 through Table 7-8 present liquid-settling volumes with the
placement of liquid-level controls for typical oil/gas separators.
Experience shows for high P separators treating high gas/oil ratio well
streams, gas capacity is the controlling factor for separator selection.
However, the reverse may be true for low P separators used on well
streams with low gas/oil ratios.

14. Stage Separation :
A process in which H.C. mixtures are separated into vapor & liquid phases
by 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 is
counted as the final stage of vapor/liquid separation).
Stage separation reduces P a little at a time, in steps or stages, resulting
in a more stable stock-tank liquid.
Usually a stable stock-tank liquid can be obtained by a stage separation
of not more than 4 stages.

15. In high-pressure gas-condensate separation systems, a stepwise
reduction of P on the liquid condensate can significantly increase the
recovery of stock-tank liquids.
Prediction of the performance of various separators in multistage
separation system carried out with compositional computer models using
initial well stream composition and the operating T & P of various stages.

16. It has been generally recognized that two stages of separation plus the
stock tank are practically optimum.
The increase in liquid recovery for two-stage separation over single-stage
separation usually varies from 2 to 12 %, although 20 to 25 % increases in
liquid recoveries have been reported.
Although 3 to 4 stages of separation theoretically increase the liquid
recovery over a two-stage separation, the incremental liquid recovery
rarely pays out the cost of the additional separators.

17. The first-stage separator operating P is generally determined by the flow
line 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.

18. P at low stage separations can be determined based on equal P ratios
between the stages:
Rp: Pressure ratio
Nst: Number of stages - 1
P1: First-stage or high-pressure separator P, psia
Ps: Stock-tank P, psia
Pressures at intermediate stages can be then designed with the formula:
Pi = pressure at stage i, psia.

19. Flash Calculation :
Based on the composition of well stream fluid, quality of products from
each separation stage predicted by flash calculations, assuming phase
equilibriums are reached in the separators.
This requires knowledge of equilibrium ratio defined as:
ki: Liquid/vapor equilibrium ratio of compound i
yi: Mole fraction of compound i in the vapor phase
xi: Mole fraction of compound i in the liquid phase

20. Accurate determination of k-values requires computer simulators solving
the 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:

21. Pci: Critical pressure, psia
Tbi: Boiling point, °R
Tci: Critical temperature, °R

22. Low-Temperature Separation
Field experience & flash calculations prove that lowering the operating T
of a separator increases the liquid recovery.
Low T separation process separates water & H.C. liquids from the inlet
well 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 Joule
Thomson or throttling effect (irreversible adiabatic process in which gas
heat content remains the same across the choke but P & T are reduced).

23. Generally at least ΔP of 2,500 to 3,000 psi required from wellhead
flowing 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 steels
for lower T are usually not economical for field installations.
Low T separation units are normally operated from 0 to 20 °F.

24. 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 equations
presented in Chapter 5.
Gas expansion P for hydrate formation can be found from the chart
prepared by Katz (1945) (see Chapter 12).
Liquid & vapor phase densities can be predicted by flash calculation.

25. Following the special requirement for construction of low T separation
units, the P reducing choke is usually mounted directly on the inlet of the
high P separator.
Hydrates form in the downstream of the choke due to the low gas T and
fall to the bottom settling section of the separator.
They are heated and melted by liquid heating coils located in the bottom
of the separator.