Separation of oil, gas and water

SEPARATION OF OIL , GAS , WATER

SEPARATION
The produced well fluid is generally a mixture of oil, salt water and natural gas .
The separation of gas and liquid is the first processing step.
The separated liquid is further separated to dehydration and desalting to remove water and salt.
The pure oil is metered and then dispatched to the refinery.
The water removed from oil is known as effluent water. This water is further treated to meet the MINAS specification for
meeting the effluent disposal requirement. Then the water is disposed off.
The separated gas is further treated for dehydration, sweetening and LPG production . Then the gas is compressed before
dispatch to meet the industry requirement.
 The separation of well fluid containing oil, water and gas depends on various factors such as ;-
• Gas oil ratio (GOR)
• Pressure
• Temperature
• Flow rate
 The separation is carried out in number of stages There are two types of separation
• Flash separation
In flash separation , the vapor is kept in contact with the remaining fluid for certain retention time .
• Differential separation
In differential separation, the vapor is removed from the contact as soon as it is formed . Thus pressure decreases and
gas liberates in each stage which is instantaneously removed. This results in maximum liquid recovery.
 The total GOR is the ratio of total cumulative gas recovered from all separation stages per barrel of stock tank oil.
• The GOR varies with number of stages and is lower for more number of satges
 The stage pressure is optimized for three stage sepatartion .The 1st stages is generally kept at 215 psia , second stage at
42 psia , and the 3rd stage at 14.7 psia. The 3rd stage is generally storage tank pressure.
CLASSIFICATION OF SEPARATORS

CLASSIFICATION OF SEPARATOR
 Separators can be broadly classified as
• Two phase separator
• Three phase separator
 Two phases separator is the most common type and is used to separate gas from oil.
 Three phase separator is used to separate gas from the liquid and oil from liquid.
 Major components of a separator.
 Inlet diverter
• The diverter is used to separate gas and the liquid . The momentum of inlet stream is reduced by abrupt change in direction and velocity
with the help of baffle plates.
 Defoaming plates
• In secondary separation section the gas velocity is reduced such that entrained liquid droplets settle by gravity. Inclined bAffles are used to
reduce turbulence and for coalescence of droplets.
 Mist extractor
• This consists of a series of vanes/ wire mesh . Wire mesh type mesh is cheaper and efficient but needs cleaning from time to time. vane
type is preferred in Mumbai High because of no maintenance is required .
 Vortex breaker
• It is used at the outlet to prevent the development of vortex when control valve is open.j The vortex can suck more gas out of the vapor .
TYPES OF SEPARATOR
TYPES OF SEPARATORS
• Vertical Separator
• Horizontal Separator
• Spherical Separator
• Cyclone separator
 VERTICAL SEPARATOR
o Basic selection criteria
 For low to medium GOR streams
 When large liquid slug is expected
 When sand , wax are produced
 When plot area is limited
ADVANTAGES
a. More versatile than horizontal
b. Greater liquid surge capacity
c. It has good drain facility for liquid at the bottom.
d. Can handle sand, wax ,mud
e. It has full diameter for gas flow
DISADVANTAGES
f. Requires larger diameter for given gas capacity
g. More expensive than Horizontal
h. More difficult to service at the top
 HORIZONTAL SEPARATOR
o Basic selection criteria
 For high to medium GOR streams
 For larger volumes of gas or liquid
 For three phase separation
Trouble shooting

ADVANTAGES
 Requires a smaller gas outlet
 Cheaper than vertical
 Large liquid surface for foam dispersion
 Less turbulence
DISADVANTAGE
 Only part of shell available for Gas outlet
 Occupies large surface area
 Liquid ;level controller is very critical
 Difficult to clean sand, wax, mud from bottom.

SPHERICAL SEPARATOR (DISCUSSED IN Later SLIDES)

 This is used for separation of large volume of gas from extremely low volume liquid. It is seldom used for oil and gas separation
CYCLONE SEPARATOR
 This is a new type of separator and is not used in gas processing industry.

 TROUBLE SHOOTING
Possible causes for the most common failures are listed velow;-
• Low liquid level
• High liquid level
• Low pressure in separator
• High pressure in separator
• Gas going out from Gas line
• Foaming in separator
• Gas going out from ater outlet
• Diaphragm operated valve not opening
 SPHERICAL SEPARATORS
These separators are
occasionally used for
high pressure service
where compact size is
desired and liquid
volumes are small.
Gas-Oil ratio
 PRIMARY SEPARATION
Primary separation is accomplished by utilizing the
difference in momentum between gas and liquid. Larger
liquid droplets fail to make the sharp turn and impinge on
the inlet wall. This action coalesces finer droplets so that
they drop out quickly. Although inlet geometries vary,
most separators use this approach to knock out a major
portion of the incoming liquid.
 GRAVITY SETTLING
Gravity settling requires low gas velocities with
minimal turbulence to permit droplet fallout.

The settling calculations assume the droplets to

be rigid spheres. The terminal-settling velocity,
VT , for a sphere falling through a stagnant fluid
is governed by particle diameter, density
differences, gas viscosity and a drag coefficient
that is a function of both droplet shape and
Reynolds number.
 COALESCING
The coalescing section contains an insert that forces the
gas through a torturous path to bring small mist particles
together as they collect on the insert. These inserts can be
mesh pads, vane packs or cyclonic devices.
Mesh pads are either wire or knitted mesh, usually about
6 in. (15 cm) thick, and preferably, are mounted
horizontally with upward gas flow, but they can be
vertical.
Mesh pads tend to be more effective at mist removal than
vane packs but are subject to plugging by solids and
heavy oils.
 COALESCING
Vane packs are corrugated plates, usually spaced 1 to 1.5
inches apart, that force the gas and mist to follow a zigzag
pattern to coalesce the mist into larger particles as they hit
the plates. Coalesced drops collect and flow out the
drainage traps in the plates.
Although not as effective at removing small drops, they
are ideal for “dirty” service because they will not plug.
However, solids can collect on the back edge of the vane
and plug the drainage ports. Liquid then collects and is
re-entrained. This problem is resolved by putting
coarse filters upstream of the vane pack
 CYCLONES
Cyclones use centrifugal force to enhance separation of
condensed phases from gas. Their advantage is that they
are extremely efficient at high-gas throughput, which
means smaller vessel diameter. However, they tend to
have a narrow operating range, relatively high pressure
drop and difficulties handling liquid slugs.
 SEPARATOR SIZING
If Newton’s law is valid, the general model for sizing gas
liquid separator becomes 0.5
 L  g 
v  KS  
  
 g 
where, v = allowable gas velocity
Ks = an empirical constant referred as sizing
coefficient
The value of Ks depends on all factors that affect
separation other than density – particle size, types of
internals, vortex action, foaming, pulsating flow, presence
of solids, separation length and gas-liquid ratio.
SIZING COEFFICIENT (KS)
Separator Height or KS
Type length (m)

Vertical 3.0 or taller 0.055 - 0.107

Horizontal 3.0 0.122 - 0.152

other K3(L/3)0.56
These values were obtained on separators with L/D
ratio of about 5:1.

Ks Values from
 SIZING COEFFICIENT (KS)

• For vertical separators, with standard wire mesh or vane type mist
extractors Ks values vary from about 0.07 – 0.105m/sec.

• For horizontal separators, with standard wire mesh or vane type mist
extractors Ks values vary from about 0.07 – 0.15m/sec.
 LIQUID RETENTION TIME
Retention time is the indirect way of fixing the volume of
the separator necessary to handle the liquid flow rate.
Separator liquid volume equals the liquid flow rate times
retention time.

For some separator designs, liquid volume requirements

(set by retention time) have a greater effect on the size
than the gas flow rate. This is true particularly where the
gas-oil ratio is low. The liquid is the controlling factor.
 LIQUID RETENTION TIME
The required separator liquid volume can be calculated
from
VL = (qL t) /1440
where VL = required separator liquid volume , m3
qL = liquid throughput, m3/d
t = Retention time , min
Typical retention time for natural gas-oil separation is 1-3
minutes.
Retention time is affected by oil relative density,
composition foaming, presence of solids and emulsions.
Liquid Settling Volume, VL
For Vertical Separators
VL = 0.1399d2h
For Horizontal Separators (Single Tube)
VL = 0.1399d2(L/2)
For Horizontal Separators (Double Tube)
VL = 0.1399d2L

Vessel Design Considerations:

 L/d should be kept between 3-8.
 Minimum height of vertical separator is 6 ft
 Minimum diameter of horizontal separator is 26 in.
 DEGASSING SECTION
A second issue in sizing the liquid section is providing
sufficient cross-sectional area to degas the liquid.
For low viscosity liquids, this is not the limiting criterion
in separator design, but for viscous liquids particularly in
systems where the liquid loading is high, degassing may
be limited.
If the bubbles larger than 200-300μm are allowed to
escape to vapor phase, carryunder should be minimal.
Stoke’s law may be used to estimate the bubble rising
velocity
g D 2p   L -  g 
v
18  L
Ki Values
Ki Values
 Ki Values
If Ki for each component and the ratio of total moles of
vapor to total moles of liquid (V/L) are known, then the
moles of component i in the vapor phase (Vi) and the
moles in the liquid phase (Li) can be calculated from:
K i Fi Fi
Vi  and L i 
1 K i  V/L   1
 Ki
(V/L)

where Fi is the total moles of component i in the fluid.

 LIQUID FLOW RATE
The liquid flow rate in barrels per day can be derived
from
L MW
Ql 
350 SG
where Ql = liquid flow rate, bpd
SG = specific gravity of liquid (water = 1)
There are 350 pounds per barrel of water and 350 (SG)
pounds per barrel of liquid.
 GAS FLOW RATE
If the flow rate of the inlet stream is known in moles per
day then the number of moles per day of gas flow can be
determined from:
F
V
1
1
(V/L)
Once the mole flow rate of gas is known, then the flow
rate in standard cubic feet can be determined by recalling
that one mole of gas occupies 380 cubic feet at standard
conditions. Therefore:
380 V
Qg 
10 6
where Qg is gas flow rate, MMscfd.
OPERATING PROBLEMS
• Foaming
• Paraffin
• Sand
FOAMING
The major cause of foam in crude oil is the appearance of
impurities, other than water, which are impractical to remove before
the stream reaches the separator.

Foam presents no problem within a separator if the internal design

assures adequate time or sufficient coalescing surface for the foam
to "break”.

The amount of foam is dependent on the pressure drop to which the

inlet liquid is subjected, as well as the characteristics of the liquid at
separator conditions. In some cases, the effect of temperature may
be significant.
PROBLEMS CAUSED BY FOAMING
Foaming in a separating vessel is a threefold problem:
1. Mechanical control of liquid level is aggravated because any
control device must deal with essentially three liquid phases
instead of two.
2. Foam has a large volume-to-weight ratio. Therefore, it can
occupy much of the vessel space that would otherwise be
available in the liquid collecting or gravity settling sections.
3. In an uncontrolled foam bank, it becomes impossible to
remove separated gas or degassed oil from the vessel without
entraining some of the foamy material in either the liquid or
gas outlets.
 PARAFFIN
Separator operation can be adversely affected by an accumulation of
paraffin.

Coalescing plates in the liquid section and mesh pad mist extractors in
the gas section are particularly prone to plugging by accumulations of
paraffin. Where it is determined that paraffin is an actual or potential
problem, the use of plate-type or centrifugal mist extractors should be
considered.

Manways, handholes and nozzles should be provided to allow steam,

solvent or other types of cleaning of the separator internals. The bulk
temperature of the liquid should always be kept above the cloud point
of the crude oil.
 SAND
Sand can be very troublesome in separators by causing cutout of valve
trim, plugging of separator internals and accumulation in the bottom
of the separator.
Special hard trim can minimize the effects of sand on the valves.
Accumulations of sand can be alleviated by the use of sand jets and
drains.
Plugging of the separator internals is a problem that must be
considered in the design of the separator. A design that will promote
good separation and have a minimum of traps for sand accumulation
may be difficult to attain, since the design that provides the best
mechanism for separating the gas, oil, and water phases probably will
also provide areas for sand accumulation. A practical balance for these
factors is the best solution.
Problem
 Values of Fg
The fraction of the total area available for the gas flow is
shown in following table:

This table can be extrapolated beyond 0.55. The value

for h/d = 0.60 would be one minus the fg value at h/d =
0.40
 DEHYDRATION AND DESALTING OF OIL
DEHYDRATION OF OIL
• More than 80% of crude oil produced in the world contains various amounts of water.
• The treating of oil consists of dehydration (removal of water ), desalting by methods such as settling tank, heater treaters and desalters h as
water wash .
• The crude oil supplied to the industry should have water content less than 1 % and salinity less than 50 mg per litre ( 50 ppm ). The
treatment is basically treatment to break emulsion .
The emulsion is defined as a mixture of two immiscible liquids ,one of which is dispersed as droplets in the the other and is stabilized as
by an emulsifying agents film’s envelop around the droplet. The dispersed phase is known as internal phase.The liquid surrounding the
droplets is the continuous phase. Water in oil emulsion is dispersed phase and oil is continuous phase.
• Oil enters dehydration equipment from separators where it has been degassed .

 Commonly used methods for dehydration and desalting are :-

o Continuous water phase washing to reduce salinity
o Settling in tank to allow free water to separate. Enough time is required for the oil to allow settlement of water.
o Heating to
1. To reduce viscosity which enhances coalescence.
2. Thermal expansion ruptures film and helps coalescence
o Chemical treating
1. reduces interfacial tension
2. Increases molecular attraction and enhances separation.
o Electrical treatment
• It coalesces smaller water droplets into larger droplets
• It allows faster settling of droplets
Heater treater vessel is divided into four parts
1. Inlet degassing section
2. Heating section
3. Differential oil control chamber
4. Coalescing chamber
Heater treater

 Inlet degassing section :

Oil mixed with demulsifying chemicals enters the heater treater through degassing section above the fire tube. Free gas is liberated from the
flow streams . The degassing section is separated from baffles. The fluid travels downward and enters the heating section under the fire tubes .
 Heating section :
Heating section consists of a fire tube bent at 180O. In 8ftx20ft heater treater there are two tubes. Oil enters from this section through bottom
of degassing section and passes through heater at bottom where washing takes place . Free solids and water fall out of the oil stream. The oil
and water flow upward from the distributors around the fire tube where they attain the required temperature. Here additional gas is released.
This gas joins the free gas and is discharged from back pressure control valve .
 Differential Oil Control Chamber
The heated fluid transfer over the fixed weir into a differential oil control chamber. The fluid travels downwards to near the bottom of
differential moil control chamber where opening to coalescing section distributors are located.
 Coalescing Section (electrical chamber0
Heater yreater uses a high voltage potential on the electrodes to coalesce the water droplets in this final phase of processing.
An externally mounted high voltage transformer provides the power to the electrodes. Primary voltage is 240 volts and supplies 16,500 volts in
the secondary.The oil and entrenched water enters the coalescing chamber from the differential oil control chamber through metered
distributor. As the oil and water enter come in contact with the electriccal field ,final coalescing of the water takes place. The water falls back at
the bottom and the clean oil continues to rise to the top and is discharged through outlet control valve.