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.

Conventional Horizontal Three-Phase Separator

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.

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.

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.

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.

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

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.

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

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.

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

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.

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.

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.

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.

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.

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.

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.

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

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:

Pci: Critical pressure, psia

Tbi: Boiling point, °R

Tci: Critical temperature, °R

Where:

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).

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.

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.

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.