Research on the design of insulators and their components

1. Design of oil and gas separators
A. General Description and Principles
B. AFPC Separators
Prepared By :
NASSER KALF AZIZ
Petroleum Engineering

2. 2
SEPARATION AND SEPARATORS
GENERAL DESCRIPTION PRINCPLES
SEPARATION AND SEPARATORS
The well flow stream emerging from the wellhead is basically a mixture of the
produced reservoir fluids of the crude oil, gas and water with possibly, some solids
such as silt/sand intrained in the well stream.
Depending on reservoir characteristics, fluid properties and flowing conditions,
another type of mixture, consists mainly of oil and water forms which is referred to as
an EMULSION. Some emulsions, specially the tight ones are of complex nature and
are not to be broken out or separated by the conventional type separators.
Treating of emulsions may include one or more of the following techniques
and/or procedures:
 Allowing settling time
 Applying heat
 Injecting chemicals (Emulsifiers)
 Using electricity
 Operating MECHANICAL devices
However, these techniques/procedures and/or a combination of two or more of
them will be overview at the following emulsion treatment section of this module.
A. Purpose of Oil and Gas Separation :
1) To allow oil to be stored on the lease and the liquid free of gas to be sold to
a transmission line.
2) To effect a "day" gas measurement .
3) To give the producer the most dollar value from his well effluent by:
a) Making the oil gas free as possible
b) Making the gas as free as possible
B. Single Stage Separation:
1) A stage of separation is defined as :
A condition at which the oil and gas reach Equilibrium at the existing
pressure and temperature within the vessel.
2) Equilibrium is defined as:
A condition at which no more gas evolves (Liberated/Flashed off from the oil
and more liquid condenses from the gas.
3) Factors affecting equilibrium.
A condition at which the oil and gas reach Equilibrium at the existing
pressure and temperature within the vessel.

3. 3
a) Retention time.
1) Gravity
2) Viscosity.
3) Surface area exposed.
4) Depth of liquid.
5) Entrained solids in the oil.
6) Scrubbing of the liquid.
b) Separator liquid capacity should be based upon sufficient retention time,
not valve capacity or capacity before carry-over.
C. Multi-stage Separation is defined as:
A process in which the oil-gas mixture, flowing from the producing well, is
separated into liquid and vapor phases by two or more equilibrium flashes at
consecutively lower pressure.
1) Pressure reduction is necessary for more oil from wellhead to storage with
inherent "flash loss" or shrinkage.
2) Flash gases will "strip" or remove heavy stable fraction of oil.
3) Ideal pressure reduction would be "Differential Liberation".
4) Approach to "Differential Liberation" can come from one or more separators
in series using " Flash Liberation".
5) Purpose of multi-stage separation: to increase recovery of oil and/or allow
gas to be sold to a transmission line.
6) Usually only three stages can be justified, occasionally four.
7) Generally:
a) Lower gravity and small volumes indicate less advantage from multi-
stage separation.
b) Higher gravity and large volumes indicate less advantage from multi-
stage separation.
7) Flash calculations necessary for accurate determination of number of stages
and stage pressure. These are carried out by petroleum engineers and/or
separator train manufacturer.
D. Types of separators
1) Basic types.
 Two phase separators
 Three phase separators
These two basic types of separators should be of either one of the following
configuration designs:

4. 4
 Vertical
 Horizontal
 Spherical
Other equipment/ vessels belongs to the separation process-family even
though they are not named separator (s):
 Water knockouts (FWKO-Drums)
 Water-oil knockouts
 Gas scrubbers
 Gas filter separators
 De-watering/Desalting/Dehydration/Settling tanks/wash tanks and/or
Gunbarrels
 Degassing Vesels
 Surge Drums
TWO PHASE SEPARATOR
The word "separator" may be applied to a wide variety of equipment used to
separate a mixture into two or more phases. Mixtures which require separation may
consist of a gas phase and a liquid phase, a gas phase and a solid phase two
immiscible liquid phases (oil and water), a gas phase and two liquid phases, or any
combination of the above. The term "two-phase separator" is used in the oil and gas
production industry to refer to a device used to separate a gas and a liquid phase.
The purpose of this module is to explain the different types of two-phase separators,
to describe how the work.
The oil and gas production industry deals with wellhead fluids which are a
mixture of hydrocarbon compounds, water, and impurities. As the well stream flows
from the reservoir to the surface it experiences pressure and temperature changes.
The physical character of the well stream changes with the lighter hydrocarbons
tending to evolve from the liquid phase to the gas phase and the heavier
hydrocarbons tending to evolve from the gas to the liquid phase. The flowing
velocities the tubing cause turbulence such that the phases are constantly mixed.
Due to the mixing action, the gas phase contains suspended liquid droplets and the
liquid phase contains gas bubbles.

5. 5
Schematic of a horizontal separator
In two-phase separator design, the gas and liquid phases of a fluid stream are
mechanically separated at a specific temperature and pressure, proper separator
design is important because a separation vessel is normally the initial processing
vessel in any facility. Improper design of this process component can bottleneck and
reduce the capacity of the entrie facility.
Horizontal Separators
Separators are designed in either horizontal, vertical, or spherical
configurations. Figure1 is a schematic of a horizontal separator. The fluid enters the
separator and hits an inlet diverter causing a sudden change in momentum. The
initial gross separation of liquid and vapor occurs at the inlet diverter. The force of
gravity cause the liquid to fall out of the gas stream to the bottom of the vessel where
it is collected. This liquid-collection section provides the retention time required to let
entrained gas evolve out of the oil and rise to the vapor space. It also provides a
surge volume, if necessary, to handle intermittent slugs of liquid. The liquid then
leaves the vessel through the liquid dump valve which is regulated by a level
controller.
The level controller senses changes in liquid level and controls the dump valve
accordingly. Normally, horizontal separators are operated half-full of liquid to
maximize the surface area of the gas-liquid interface.
The gas flows over the inlet diverter and the horizontally through the gravity-
settling section above the liquid. As the gas flows through this section, small drops of
liquid that were entrained in the gas and not separated by the inlet diverter are
separated out by gravity settling and fall to the gas-liquid interface.
Some of the drops are of such a small diameter that they are not easily
separated in the gravity settling section. Before the gas leaves the vessel it passes
through a coalescing section or mist extractor. This section uses elements of vanes,
wire mesh, or plates to coalesce and remove the very small droplets of liquid in one
final separation step before the gas leaves the vessel.
The pressure in the separator is maintained by a pressure controller. The
pressure controller senses changes in the pressure within the separator and sends a
signal either to open or close the pressure-control value accordingly. By controlling
the rate at which gas leaves the vapor space of the vessel, the pressure in the vessel
is maintained.
Vertical Separators
The figure is a schematic of a vertical separator. In this configuration, the inlet
flow enters the vessel through the side. As in the horizontal separator, the inlet
diverter provides the initial gross separation. The liquid flows down to the liquid
collection section of the vessel. Liquid continues to flow downward through this
section to the liquid outlet. As the liquid reaches equilibrium, gas bubbles flow
counter to the direction of the liquid flow and eventually migrate to the vapor space.
The level controller and liquid dump valve operate the same as in a horizontal
separator.

6. 6
The gas flows over the inlet diverter and then vertically upward toward the gas
outlet. In the gravity-settling section, the liquid drops fall vertically downward counter
to the gas flow. Gas goes through the mist extractor before it leaves the vessel.
Pressure is maintained as in a horizontal separator.
Schematic of a Vertical Separator
Spherical Separators and Other Configurations
A typical spherical separator is shown in figure. The same four section can be
found in this vessel. Spherical separator are a special case of a vertical separator
where there is on cylindrical shell between the two heads. They may be very efficient
for pressure containment but because they have limited liquid-surge capability and
they exhibit fabrication difficulties they, are not commonly used in the oil industry. For
this reason, spherical separators will not be discussed any further.
Two-barrel separator are commonly used for low liquid flow rate application. In
this type of separator, the gas and liquid chambers are separated as shown in figure.
The flow stream enters the vessel in the upper barrel and strikes the inlet diverter.
The free liquids fall to the lower barrel through a flow pipe. The gas flows through the
gravity-settling section and encounters a mist extractor in route to the gas outlet. The
liquid drain through a flow pipe into the lower barrel. Small amounts of gas entrained
in the liquid are liberate in the liquid collection barrel and flow up through the flow
pipes. In this manner, the liquid accumulation is separated from the gas stream so
that there is no chance of high gas velocities re-entraining liquid as it flows over the
interface. Two-barrel separators are typically used as gas scrubbers on the inlet to
compressors, glycol contact towers, and gas treating system when the liquid flow rate
is extremely low relative to the gas flow rate.

7. 7
Schematic of a Spherical Separator
A special case of a two-barrel separator is a single-barrel separator with a
liquid sump at the outlet end as shown in figure. The main body of the separator
operates essentially dry as in a two-barrel separator. The small amount of liquid in
the bottom flow to the sump at the end which provides the liquid-collection section.
These vessels are less expensive than two barrel separators, but contain less liquid-
handling capability.
Another type of separator that is frequently used in some high gas/low liquid
flow applications is a filter separator. These separators may be either horizontal or
vertical in configuration. A horizontal two-barrel filter separator is shown in figure.
Filter tubes in the initial separation cause coalescence of any liquid mist into larger
droplets as the gas passes through the tubes. A secondary section of vanes or other
mist-extractor elements removes these coalesced droplet. In addition to promoting
coalescence, the filter tubes can be used to remove small solid particles. This type of
vessel can remove 100 percent of all particles larger than two microns and 99
percent of those down to about 1/2 micron. Filter separators are commonly used on
compressor inlets in field compressor stations, final scrubbers upstream of glycol
contract towers and instrument/fuel-gas applications. The design of filter separators
is proprietary and dependent upon the type of filter element employed.

8. 8
Some separators are designed to operate by centrifugal force. This type of
separator is becoming more common, particularly offshore, but is used primarily for
liquid solid separation not gas-liquid separation. Although such designs can result in
significantly smaller space requirements, they are not commonly used in production
operations because their design is rather sensitive to flow rate and they require
greater pressure drop than the standard configurations.

9. 9
VESSEL INTERNALS
Inlet Diverters
There are many types of inlet diverters. Figure shown two basic types of
devices that are commonly used. The first is a deflector baffle. This can be a
spherical dish, flat plate, angle iron, cone, or just about anything that will accomplish
a rapid change in direction and velocity of the fluids. The rapid change of the fluid
velocity disengages the liquids from the due to kinetic energy differences. At the
same velocity, the higher density liquid possesses more kinetic energy and therefore
does not change direction or velocity as easily as the gas. Thus, the gas tends to
flow around the diverter while the liquid strikes the diverter and then falls to the
bottom of the vessel. The design of the deflector is governed principally by the
structural support required to resist the impact-momentum load. The advantage of
using devices such as a half-sphere or cone is that they create less disturbance than
plates or angle iron, cutting down on re-entertainment or emulsifying problems.
The second device shown in figure is a cyclone inlet that uses centrifugal force
to disengage the oil and gas. This inlet can have a cyclonic chimney, or may use a
tangential fluid race around the walls. These devices are proprietary but generally
use an inlet nozzle sufficient to create a fluid velocity of about 20 ft/s (6.096 m/s)
around a chimney whose diameter is no large than two-thirds that of the vessel
diameter.
Wave Breakers
In large horizontal vessels, wave breakers may be used to limit wave
propagation in the vessel. The waves may result from surges of liquid entering the
vessel. The wave breakers consist of plates perpendicular to the flow located at the
liquid level. On floating or compliant structure where internal waves may be caused
by the motion of the foundation, wave breakers may also be required parrel to the
flow direction. The wave action in the vessel must be minimized so level control, level
switches, and weirs may perform properly.
Two basic types of inlet diverters

10. 01
Stilling Wells
Even where wave breakers are not needed, it may be beneficial to install a
stilling well around any internal float for level control. The stilling well is a slotted pipe
which protection he float from currents, waves, etc., which could cause it to sense an
incorrect level.
A schematic of defaming plates
Defoaming Plates
Foam at the interface may occur when gas bubbles are librated from the
liquid. This foam can be stabilized with the addition of chemical at the inlet. Many
times a more effective solution is to force the foam to pass through a series of
inclined parallel plates or tubes as shown in figure so as to aid in coalescence of the
bubbles.
Three views of a typical vortex breaker

11. 00
Vortex Breakers
It is normally a good idea include a simple vortex breaker as shown in figure to
keep a vortex from developing when the level control valve is open. A vortex could
suck some gas out from the vapor space and re-entrain it in the liquid outlet ( a case
of blow-by).
Arch Plates
Schematic of two types of mist extractors
A common mist-extraction device using vanes

12. 02
Mist Extractors
Figures show two of the most common mist-extraction devices: wire-mesh
pads, and vans. Wire-mesh pads are made of finely woven mats of stainless steel
wire wrapped into, a tightly packed cylinder. The liquid droplets impinge on the
matted wires and coalesce. The effectiveness of wire mesh depends largely on the
gas being in the proper velocity range. If the velocities are low the vapor just drifts
through the mesh pad without the droplets impinging and coalescing. Alternately high
velocity gas can strip liquid droplets from the wire mesh and carry the droplets out
the gas outlet.
Vane-type mist extractors force the gas flow to be laminar between parallel
plates, which contain direction changes. Droplets impinge on the plate surface where
they coalesce and fall to a liquid-collection area where they are routed to the liquid-
collection section of the vessel. Vane-type mist extractors are size by their
manufacturers to assure both laminar and a certain minimum pressure drop.
Wire-Mesh Pads
THREE PHASE SEPARATORS
Three-phase separators are used in the oil and gas production industry to
separate gas, oil and water phases. The design concepts related to separating the
gas and liquid are described in two-phase separators and will not be discussed in this
module. Three-phase separation involves gas/liquid separation like tow-phase
separation but also involves liquid/liquid separation. This module emphasize on the
design concepts involved in liquid/liquid separation.
When oil and water are mixed with some intensity and then allowed to settle, a
layer of relatively clean free water will appear at the bottom. The growth of this water
layer with time will follow a curve as shown in figure. After a period of time, ranging
anywhere from three to twenty minutes, the change in the water height will be
negligible. The water fraction, obtained from gravity settling, is called free-water. It is
normally beneficial to separate the free water before attempting to treat the remaining
oil and emulsion layers.

13. 03
Schematic and plot showing growth of water layer with time
Three-phase separators, also called free water knockouts (FWKO), are
designed to separate the free-water phase from the oil . Flow to the separator may
be directly from a producing well or wells. In this case, significant amounts of gas
may be present and the separator will typically be called a three-phase separator. If
the flow to the separator originates in upstream separators operating at higher
pressures, then the three-phase separator will only need to handle the flash gases.
Separators in the service are often called free-water knockouts.
The basic design aspects of three-phase separation are identical to those
discussed for two-phase separation. The only additions are that more concern is
placed in liquid/liquid settling rates; and that some means of removing the water must
be added.
Horizontal Separators
Three-phase separators are designed as either horizontal or vertical pressure
vessels. A schematic of a horizontal separator. The fluid enters the separator and
hits an inlet diverter. This sudden change in momentum provides the initial gross
separation of liquid and vapor. In most designs, the inlet diverter contains a down
comer which directs the liquid flow the gas/oil interface and to the vicinity of the
oil/water interface. The liquid-collecting section of the vessel provides sufficient time
so the oil and emulsion from a layer or oil pad above the free water. Illustrates a
typical horizontal separator with an interface controller and weir.
The weir maintains the oil level and the interface controller maintains the water
level. The oil is skimmed over the weir. Beyond the weir, the oil level is controlled by
a level controller which operates the oil dump valve.
The produced or free water flows from a nozzle in the vessel located upstream
of the oil weir. Am interface level controller senses the height of the oil/water
interface. The controller sends a signal to the water dump valve thus allowing the

14. 04
correct amount of water to leave the vessel so that the oil/water interface is
maintained at the design height.
The gas flows horizontally and out through a mist extractor to a pressure
control valve which maintains constrant vessel pressure. The level of gas/oil
interface can vary from half the diameter to seventy-five percent of the diameter
depending on the relative importance of gas/liquid separation.
Simplified schematic of a typical horizontal three-phase separator
An alternate configuration known as a bucket-and-water design. This design
eliminates the need for liquid interface controller. Both the oil and water flow over
weirs. Level control is accomplished by simple displaced floats. The oil overflows the
oil weir into an oil bucket where its level is controlled by a level controller which
operates the oil dump valve. The water flows under the oil bucket and then over a
water weir. The level after this weir is controlled by level controller which operates the
water dump valve.
Simplified schematic of a typical horizontal three-phase separator with a bucket-and-weir
design
The third method uses two weirs, which eliminates the needs for an interface
float. Interface level is controlled by the height of the external water weir relative to
the oil weir. This similar to the bucket-and-weir design of horizontal separators. The
advantage of this system is that it eliminates the interface level control. The
disadvantage is that requires additional external piping and space.

15. 05
Vessel Internals
Coalescing Plates
It is possible to use various plate or pipe coalescer designs to aid in the
coalescing of oil droplets in the water and water droplets in the oil. Recent test using
C.E. Natco's performer plates indicate that some savings in vessel size are possible.
Because of potential plugging problems, it is recommended that coalescers only be
used to extend three-phase separators or where three are severe space limitations.
Cutaway schematic showing sand jets and piping inside horizontal separator Triangular
cover prevents plugging of drains
INLET MANIFOLD
The function of the inlet manifold is to receive via the flowlines the flowing and
pumped crude oil from the wellheads and distribute it to the process train at the
Central Production Facility (CPF).
An inlet manifold usually consists of a single bulk header and a single test
header, but as there are two types of wells it will be made up of the following
components:
1. HP Bulk Header. This receives sweet crude oil from Rutbah flowlines and
distributes it to the HP bulkine.
2. LP Bulk Header. This receives sour crude oil from the Miocene flowline and
distributes it to the LP bulkine.
3. High Flow Test Header. Is capable of receiving crude from either the Rutbah
or Miocene flowlines. Only one well would be flowing into this header at one
time. From the high flow test header the crude oil flows to the High Flow test
separator.
4. Low Flow Test Header. Is capable of receiving crude from Both Miocene and
Rutbah flowlines. Only one well would be flowing into this header at any one
time. Form the low test header the crude oil flows to the LP test separator.

16. 06
Note :
In this particular case, under normal operating conditions, when a well is to be
tested, a Rutbah well is diverted to the High flow test separator via the high flow test
header and a Miocene well is diverted to the low flow test separator via the low flow
test header.
Each manifold is fitted with a drain valve, which allows the manifold to be
drained into the closed drain header.
A shutdown valve is fitted, on each outlet from the inlet manifold follows:
Located on the LP bulkline at the outlet from the LP bulk header. When shut it
cuts off the flow of crude to the downstream process train system components.
Located on the HP bulkline at the outlet from the HP bulk header. When shut it
cuts off the flow of crude oil to the downstream process train system components.
Located on the high flow test separator inlet from the high flow test header.
When shut it cits off the flow of crude oil to the high flow test separator.
The bulk arrival manifold takes all inputs collectively to the bulk separator. The
test arrival manifold takes one input individually to the test separator.

17. 07
INLET MANIFOLD
( TO DEGASSING STATION)

18. 08

19. 09
Lsolating Valves (BV'S)
The two isolating valves are manually operated ball-block valves. These are
fitted one on each of the two branch pipe which connect the flowline to the bulk and
test manifolds.
In usual operations, one branch is open and the other is closed, thus the
flowline is connected to the bulk manifold or to the test manifold. When re-directing
the flow from one to the other, an operator should be aware that incorrect valve
sequencing could block the oil flow and cause the line pressure to rise high enough
to trigger an automatic closure at the wellhead (SSV) . To avoid this, open the closed
valve before closing the open valve and turn both of them evenly, slowly and
simultaneously.
Check Valve
The check valve is one way/none return-valve serves to prevent back flow
opposite to the normal flow direction for a number of reasons in a given system.
Chemical Injection Point
This enables injection of emulsifiers into the oil stream at a point which will
ensure adequate mixing before separation begins. Only one or two points are in use
at any one time in a multi-input flowline group.
Instruments
A pressure gauge and a temperature indicator are fitted for routine conditions
checks.
SAFETY RELIEF VALVE
Each manifold, header and each collector line is fitted with a separate relief valve.
Each SRV is preset at a specific pressure to function when this high pressure limit is
reached. The discharge is piped to the burning pit or flash drum and will continue as
long as the high pressure exists. When normal pressure is restored the valve will be
kept closed automatically.
Emergency Shut-Down Valve (ESDV)
An emergency shutdown valve (ESD/Disaster valve) is located in the collector
line close to its junction with the inlet manifold.
Each collector has a separate ESD-valve which serves to automatically block
the input from the flowline if an, uncontrollable upset or dangerous condition arises
within the station. The ESDV-actuators are pneumatic, using air or gas at a pressure
of 7 kg/cm2 from an independent supply. If this independent supply fails, because of
pipe bursts, compressor loss, etc., the actuators will fail-safe i.e., automatically block
the input. This prevents the development of any emergency conditions whilst the
ESDV lacks its normal motive pressure.

20. 21
Pressure Safety Relief Valve
Each actuator is under the control of a separate circuit with pneumatic
switches which monitor critical conditions of the process in the separator train i.e.,
levels and pressures of the liquids and gas phases.
There are several types of ESDV available. One is the pressure balanced
piston see Figure 2.11. A pneumatically operated piston is mounted in a cylinder
fixed at right angles to the valve body. A gear is attached to the lower end of the
piston rod which engages with a worm fitted to the valve. Pneumatic air or gas is fed
to the top and bottom of the piston. The valve can also be operated manually by
using a handwheel.
Figure 2.10 illustrates the principle of operation inside the body there is a
piston with pressure against its lower face and spring compress against its upper
face. If the pressure force is greater than the spring force then the piston is lifted from
its seat and pressure is relieved. When the pressure has fallen then the spring will
force the piston back on its seat and the discharge will stop automatically.
Pneumatic pressure is fed into the lower chamber of the cylinder to force the
piston upwards against the upper spring force. So as the pressure is maintained then
the piston will be held at its upper position and the valve will be open. Whilst the plant
conditions are normal the pressure , will be maintained ,but an abnormal condition
will cause the pressure to be bled down, thus allowing the upper spring to force the
piston down and to close the valve.

21. 20
External Switching Circuit
The circuits which control the actuator use pneumatic and/or electrical switch
units which are located on, or near to) the separator vessels to monitor the conditions
which are considered critical. Also, each actuator has its own separate circuit. Thus,
it is possible to block collector lines individually.
In each circuit there is a manual override of the monitoring action in case it
should itself malfunction at a time when a process condition is dangerous. This
override is a small lever or toggle on a switching unit close to the actuator. Moving
the lever across will cause an immediate bleed-off of the actuator pressure and a
closure of the valve. It must be returned to the original position for the actuator to be
put back into service.