Oil & Gas Phase Separation

Mohamed Abdelraof Saad
Oil
Separation
Water
GasOil
Water
Gas Oil
Water
Gas Oil
Water
GasOil
Water
Gas

Phase separation of the production stream is usually
performed as soon as is conveniently possible
because:
* It is technically easier and less costly to process the gas,
crude oil, and produced water phases separately.
* The produced water is often corrosive. Therefore, removing
the water reduces corrosion damage.
* Less energy is required to move the separated single phases;
so phase separation permits the back pressure to be lowered
and this, in turn, increases well production
INTRODUCTION

Well Production
 Rarely is clean oil, ready for
sale into a pipeline, produced
from an oil well.
Natural GasOilWaterSaltSand

Well Production

Com. St.
P1-C
Glycol
Regeneration Unit
Fuel Gas
Package
Oily Water
Treatment
Unit
Well # 4-12
D-103 A
D-103 B
D-103 C
D-105Sump
Caisson
E-101
14” Sea Line
P1-Meadia
14” Sea Line
PI-PII
PL-101
Z-111
Desander
T-101

WELL FLUIDS AND THEIR
CHARACTERISTICS

Crude Oil
Crude oil is a complex mixture of
hydrocarbons produced in liquid form.
The API gravity of crude oil can range from 6 to
50oAPI and viscosity from 5.0 to 90,000 cP at
average operating conditions.
Color varies through shades of green, yellow,
brown, and black.

Condensate
This is a hydrocarbon that may exist in the producing
formation either as a liquid or as a condensable vapor.
Liquefaction of gaseous components of the
condensate usually occurs with reduction of well-fluid
temperature to surface operating conditions.
Gravities of the condensed liquids may range from 50
to 120oAPI and viscosities from 2.0 to 6.0 cP at
standard conditions.
Color may be water-white, light yellow, or light blue.

Natural Gas
A gas may be defined as a substance that has no shape or volume of its own. It will
completely fill any container in which it is placed and will take the shape of the
container. Hydrocarbon gas associated with crude oil is referred to as natural gas and
may be found as "free" gas or as "solution" gas. Specific gravity of natural gas may
vary from 0.55 to 0.90 and viscosity from 0.011 to 0.024 cP at standard conditions.
Free Gas.
Free gas is a hydrocarbon that exists in the gaseous phase at operating pressure and
temperature. Free gas may refer to any gas at any pressure that is not in solution or
mechanically held in the liquid hydrocarbon.
Solution Gas.
Solution gas is homogeneously contained in oil at a given pressure and temperature. A
reduction in pressure and/or an increase in temperature may cause the gas to be
emitted from the oil, whereupon it assumes the characteristics of free gas.
Condensable Vapors.
These hydrocarbons exist as vapor at certain pressures and temperatures and as liquid
at other pressures and temperatures. In the vapor phase, they assume the general
characteristics of a gas. In the vapor phase, condensable vapors vary in specific gravity
from 0.55 to 4.91 (air = l.0), and in viscosity from 0.006 to 0.011 cP at standard
conditions.

Water
Water produced with crude oil and natural gas
may be in the form of vapor or liquid.
The liquid water may be free or emulsified.
Free water reaches the surface separated from
the liquid hydrocarbon.
Emulsified water is dispersed as droplets in
the liquid hydrocarbon.

Impurities and Extraneous Materials
Produced well fluids may contain such
gaseous impurities such as nitrogen, carbon
dioxide, hydrogen sulfide, and other gases that
are not hydrocarbon in nature or origin.
Well fluids may contain liquid or semi-liquid
impurities, such as water and paraffin.
They may also contain solid impurities, such
as drilling mud, sand, and salt.

CLASSIFICATION OF OIL AND
GAS SEPARATORS

Classification by Geometrical
 Vertical
 Horizontal double-barrel
 Horizontal
 Spherical

Classification by Function
 Two-phase , (vapor-liquid) .
 Three-phase (gas-oil-water) .

Classification by Operating Pressure
 Oil and gas separators can operate at pressures ranging from a
high vacuum to 4,000 to 5,000 psi.
 Most oil and gas separators operate in the pressure range of 20
to 1 ,500 psi.
 Separators may be referred to as low pressure, medium
pressure, or high pressure.
 Low-pressure separators usually operate at pressures ranging
from 10 to 20 up to 180 to 225 psi.
 Medium-pressure separators usually operate at pressures
ranging from 230 to 250 up to 600 to 700 psi.
 High-pressure separators generally operate in the wide
pressure range from 750 to 1,500 psi.

Classification by Application
 Test Separator
 A test separator is used to separate and to meter the well
fluids.
 They can be permanently installed or portable (skid or trailer
mounted).
 Production Separator
 A production separator is used to separate the produced
well fluid from a well, group of wells
 Low-Temperature Separator.
 The temperature reduction is obtained by the Joule-
Thompson effect of expanding well fluid as it flows through
the pressure-reducing choke or valve into the separator.
 Liquids thus recovered require stabilization to prevent
excessive evaporation in the storage tanks.

Classification by Application
 Metering Separator.
 The function of separating well fluids into oil, gas, and water and metering the
liquids can be accomplished in one vessel.
 These units are available in special models that make them suitable for
accurately metering foaming and heavy viscous oil.
 Foam Separator.
 Oil and gas separators that handle foaming crude oil.
 Elevated Separator
 Separators can be installed on platforms at or near tank batteries or on
offshore platforms so that the liquid can flow from the separator to storage or
to downstream vessels by gravity.
 Stage Separators
 When produced well fluid is flowed through more than one separator with the
separators in series,
 The first separator is referred to as the first-stage separator, the second
separator is called the second-stage separator, etc.

Common components
 Primary Separation Section
 Secondary or Gravity Settling Section.
 Mist Extraction or Coalescence Section.
 Vane-Type extractors
 Blade-type mist extractors
 Wire-Mesh or Fibrous mist extractors
 Liquid Accumulator Section

Primary Separation Section
 Collecting and removing the bulk of the
liquid in the inlet stream.
 Exploit the momentum of the inlet stream
either by creating centrifugal force or
change of direction (as in horizontal
separators) thus separating most of the
incoming liquid.

Secondary or Gravity Settling
Section.
 Gas velocity and turbulence is reduced so
that entrained liquid drops can settle out
by gravity.
 Internal baffling is often used to dissipate
foams, further reduce turbulence, and
accelerate drop removal.

Mist Extraction or Coalescence Section.
 Vane-Type extractors
 Blade-type mist extractors
 Wire-Mesh or Fibrous mist extractors

Liquid Accumulator Section
 Provides sufficient capacity to handle surges in liquid flow
 Adequate retention time is necessary to allow for removal of
any gas breaking out of solution
 and, in three-phase separators, for separation of free water and
oil.
 A vortex breaker may be located over the liquid outlet nozzle(s)
 Recommended minimum liquid levels are:
 A liquid level of at least two outlet nozzle diameters for gas/liquid
interfaces.
 A liquid level of at least three times the outlet nozzle diameter for
liquid/liquid interfaces.

Liquid Accumulator Section

PRIMARY FUNCTIONS OF OIL
AND GAS SEPARATORS
 Removal of Oil from Gas
 Removal of Gas from Oil
 Separation of Water from Oil

METHODS USED TO REMOVE OIL
FROM GAS IN SEPARATORS

Density Difference (Gravity Separation)
By density difference or force of gravity, settle out of the stream of gas if
the velocity of the gas is sufficiently slow.
The larger droplets of hydrocarbon will quickly settle out of the gas, but
the smaller ones will take longer time .
At standard conditions of pressure and temperature, the droplets of
liquid hydrocarbon may have a density 400 to 1,600 times that of natural
gas.
However, as the operating pressure and temperature increase, the
difference in density decreases. At an operating pressure of 800 psig,
the liquid hydrocarbon may be only 6 to 10 times as dense as the gas.
Particles of liquid hydrocarbon with diameters of 100 µm and larger will
generally settle out of the gas in most average-sized separators.
mist extractors usually are needed to remove smaller particles from the
gas.

Impingement
If a flowing stream of gas containing liquid mist is impinged
against a surface, the liquid mist may adhere to and
coalesce on the surface.
After the mist coalesces into larger droplets, the droplets will
gravitate to the liquid section of the vessel.
If the liquid content of the gas is high, or if the mist particles
are extremely fine, several successive impingement surfaces
may be required to effect satisfactory removal of the mist.

Change of Flow Direction
When the direction of flow of a gas stream containing liquid mist is
changed abruptly, inertia causes the liquid to continue in the original
direction of flow.
Separation of liquid mist from the gas thus can be effected because
the gas will more readily assume the change of flow direction and will
flow away from the liquid mist particles.
The liquid thus removed may
coalesce on a surface or fall
to the liquid section below.

Change of Flow Velocity
Separation of liquid and gas can be effected with either a sudden
increase or decrease in gas velocity.
Both conditions use the difference in inertia of gas and liquid.
With a decrease in velocity, the higher inertia of the liquid mist carries it
forward and away from the gas.
The liquid may then coalesce on some surface and gravitate to the
liquid section of the separator.
With an increase in gas velocity, the higher inertia of the liquid causes
the gas to move away from the liquid, and the liquid may fall to the
liquid section of the vessel.

Centrifugal Force
If a gas stream carrying liquid mist flows in a circular
motion at sufficiently high velocity, centrifugal force throws
the liquid mist outward against the walls of the container.
The liquid coalesces into progressively larger droplets and
finally gravitates to the liquid section below.
Efficiency of this type of mist extractor increases as the
velocity of the gas stream increases.
Thus for a given rate of throughput, a smaller centrifugal
separator will suffice.

Centrifugal Force

Centrifugal Force and impingement

Coalescence
Coalescing packs afford an
effective means of separating and
removing liquid mist from a
stream of natural gas.
The packs use a combination of
impingement, change of direction,
change of velocity, and
coalescence to separate and to
remove liquid mist from gas.
These packs provide a large
surface area for collection and
coalescence of the liquid mist .

Filtering
Porous filters are effective in the
removal of liquid mist from gas in
certain applications.
The porous material may use the
principles of:
Impingement
change of flow direction
change of velocity
Generally, filter-type mist extractors
will have the highest pressure drop
per unit volume of capacity and the
coalescing type will have the
lowest.

METHODS USED TO REMOVE GAS
FROM OIL IN SEPARATORS

Settling
Gas contained in crude oil that is not in solution in the oil will
usually separate from the oil if allowed to settle a sufficient length
of time.
An increase in retention time for a given liquid throughput
requires an increase in the size of the vessel and/or an increase in
the liquid depth in the separator.
Increasing the depth of oil in the separator may not result in
increased emission of non-solution gas from the oil because
"stacking up" of the oil may prevent the gas from emerging.
Optimum removal of gas from the oil is usually obtained when the
body of oil in the separator is thin - i.e., when the ratio of surface
area to retained oil volume is high.

Agitation
Moderate, controlled agitation is helpful in
removing non-solution gas that may be
mechanically locked in the oil by surface
tension and oil viscosity.
Agitation usually will cause the gas bubbles to
coalesce and to separate from the oil in less
time than would be required if agitation were
not used.
Agitation can be obtained by properly designed
and placed baffling.

Baffling
An inlet degassing element can be installed on the inlet of the separator
to assist in introducing the well fluid into the separator with minimum
turbulence and in removing gas from the oil.
This type of element eliminates high-velocity impingement of fluid
against the opposite wall of the separator.
The baffles placed in the separator between the inlet and the oil level
spread the oil into thin layers as it flows downward from the inlet to the
oil section.
This type of baffling is effective in handling foaming oil.
Special perforated baffles or tower packing can be used to remove non-
solution gas from crude oil.
Such baffling or packing provides slight agitation, which allows the gas
bubbles to break out of the oil as it flows through the baffles or packing.

Heat
Heat reduces surface tension and viscosity of the oil and thus
assists in releasing gas .
The most effective method of heating crude oil is to pass it
through a heated-water bath.
through the water bath affords slight agitation, which is helpful
in coalescing and separating entrained gas from the oil.
A heated-water bath is probably the most effective method of
removing foam bubbles from foaming crude oil.
A heated-water bath is not practical in most oil and gas
separators, but heat can be added to the oil by
direct or indirect fired heaters and/or heat exchangers

Chemicals
Chemicals that reduce the surface tension of
crude oil will assist in freeing non-solution gas
from the oil.
Such chemicals will appreciably reduce the
foaming tendency of the oil and thereby
increase the capacity of a separator when
foaming oil is handled.

Centrifugal Force
Centrifugal force is effective in separating gas
from oil.
The heavier oil is thrown outward against the
wall of the vortex retainer while the gas
occupies the inner portion of the vortex.

Separation of Water from Oil
In some instances it is preferable to separate and to remove
water from the well fluid before it flows through pressure
reductions, such as those caused by chokes and valves.
The water can be separated from the oil in a three-phase
separator by use of chemicals and gravity separation.
If the three-phase separator is not large enough to separate the
water adequately, it can be separated in a free-water knockout
vessel installed upstream or downstream of the separators.
If the water is emulsified, it may be necessary to use an
emulsion treater to remove it.

Centrifugal Force
If a hydrocarbon stream
carrying solids flows in a
circular motion at sufficiently
high velocity, centrifugal force
throws the solids outward
against the walls of the
container.
Efficiency of this type of sand
extractor increases as the
velocity of the hydrocarbon
stream increases.

Manifolds for stream
collecting

Separator and stage separator
Refer to a conventional oil and gas separator.
These separating vessels are normally used on a
producing lease or platform near the wellhead,
manifold, or tank battery to separate fluids produced
from oil and gas wells into oil and gas or liquid and
gas.
They must be capable of handling well fluids "slugs".
Therefore, they are usually sized to handle the highest
instantaneous rates of flow.

Separator and stage separator

Knockout vessel, drum, or trap
may be used to remove only water from the well fluid or to remove
all liquid, oil plus water, from the gas.
In the case of a water knockout for use near the wellhead, the gas
and liquid petroleum are usually discharged together, and the free
water is separated and discharged from the bottom of the vessel.
A liquid knockout is used to remove all liquid, oil plus water, from
the gas.
The water and liquid hydrocarbons are discharged together from
the bottom of the vessel, and the gas is discharged from the top.

Flash drum or vessel
Refers to a conventional oil and gas separator
operated at low pressure
With the liquid from a higher-pressure separator being
"flashed" into it.
This flash drum is quite often the second or third stage
of separation, with the liquid being discharged from the
flash drum to storage.

Expansion vessel
The first-stage separator vessel on a low-temperature
or cold-separation unit (LTS).
This vessel may be equipped with a heating coil to melt
hydrates, or a hydrate-preventive liquid (such as
glycol) may be injected into the well fluid just before
expansion into this vessel.

Expansion vessel
LTS
Glycol
Reach Glycol
Flare
D-205
Flare
Lean Glycol
Gas from
Slug catcher
LP Sales Gas

Expansion vessel
12" Gas outlet
3" Cond. outlet
2" Glycol outlet
10" Inlet
Mist
Extractor
Glycol Coil
glycol in
glycol out
5.547 M
1.6 M
Vortex
Breaker
Vortex
Breaker
Design Temp.
Design Press.
= 120 MMSCFD
= -9 oC
= 52 Kg/cm2
Capacity

Gas scrubber
may be similar to an oil and gas separator.
Usually it handles fluid that contains less liquid than that produced from
oil and gas wells.
Gas scrubbers are normally used in gas gathering, sales, and distribution
lines where they are not required to handle slugs or heads of liquid,
A "scrubber" can refer to a vessel used upstream from any gas-
processing vessel or unit (scrubbers are often used ahead of
compressors & glycol systems
Applied downstream of field separators to remove entrained and/or
condensed liquids to protect the downstream vessel or unit.

Gas scrubber
V-
301 X
SDV-3004
SDV-3005
V-302C-300 X
A-300
SDV-3009
SDV-3007
FCV-3008
Suction
C. D. D-204
Flare
Flare
Discharge
To Grid
PCV-3006

Filter (gas filter or filter/separator), dust
Scrubber, or Coalescer.
These separators are designed to remove small quantities of
mists, oil fogs, rust, scales, and dust from gases.
Typical applications are upstream of compressors, dehydration
units
Solids are trapped by the filter fibers
Liquid droplets are coalesced into large drops that are then
separated by gravity.
These filter separators are used for final "polishing" and are often
preceded or protected, by a conventional scrubber or separator.

Filter (gas filter or filter/separator), dust
Scrubber, or Coalescer.

Filter (gas filter or filter/separator), dust Scrubber, or Coalescer.
Gas inlet
Gas outlet
Filter element detail
A
A
View A-A
3 5/8" D. * 3' LG
Mist Extractor
38 Filter elements
second stage
liquid storage
First stage
liquid storage

Skimmer, liquid hydrocarbon
skimmer
normally refers to a conventional oil and
gas separator operated at low pressure
to separate a liquid from another liquid.

Skimmer, liquid hydrocarbon
skimmer

Slug catcher
a particular separator design able to
absorb large volumes at irregular
intervals.
Usually found on gas gathering system
or two-phase pipeline systems.
A slug catcher may be a single large
vessel or a manifolded system of pipes.

=
14" Emergency
=
A A B B
Section A-A Section B-B
Cond. outlet
11.766 M
2.329 M
Vortex
Breaker
14" Gas outlet
4" Cond. outlet
Vortex
Breaker
14" Inlet
Design Temp.
Design Press.
= 120 MMSCFD
= 45 oC
= 99 Kg/cm2
Capacity
Slug catcher

Slug catcher

 All of the previous separators use gravity as the separating
force.
 External force fields (electrostatic and centrifugal) can and have
been used. However, electrostatic fields are used primarily to
break water-in-crude emulsions.
 Centrifugal force (i.e., a hydrocyclone) is most useful for
separating primary oil-in-water dispersions.

SECONDARY FUNCTIONS OF
OIL AND GAS SEPARATORS

Maintain Optimum Pressure on Separator
Pressure control valve

Maintain Liquid Seal in Separator
To maintain pressure on a separator,
a liquid seal must be effected in the
lower portion of the vessel.
This liquid seal prevents loss of gas
with the oil and requires the use of a
liquid-level controller and a valve.
Local Level Controller

Slug Catcher Level Control
Slug Catcher Level Control

Summary for the Function of
Separator Internals
Purpose of Device or Situation
where Device should not be used
Internal Device
a- remove liquid mist from gas.1- Mist Pad
b- break oil-water emulsion.
c- not used where hydrate, wax, or dirt may be
present.
a- separate liquid from gas.2- Deflector Plate
b- used in all services.
a- remove liquid mist from gas.3- Coalescing
Plate b- separate oil from water.
c- not used where hydrate, corrosion, wax or dirt
present.

Separator Internals
a- remove liquid mist from gas.4- Straightening Vanes
b- separate oil from water.
c- not used where hydrate, corrosion, wax or dirt
present.
a- remove solid particles from gas or liquid.5- Filter Elements
b- separate oil from water.
c- remove mist from gas.
d- not used where wax or hydrate may be present.
a- separate oil from water.6- Coalescing Materials
b- not used where wax may be present.

Separator Internals
a- separate gas from liquid.7- Centrifugal
Devices b- not used where wax or dirt may be present.
c- not used with intermittent gas flow.
a- usually used in large gas-liquid vessels where waves
occur.
8- Horizontal
Baffles
a- should be used on all liquid outlet nozzles in gas-liquid
separators
9- Vortex Breakers
b- are not needed if vessel is full of liquid
a- should be used when internal level control float is used.10- Float Shield
a- used only when solids may be present.11- Water Jets and
Sand Cones

SELECTION AND APPLICATION OF
SEPARATORS AND SCRUBBERS

Vertical Oil and Gas Separators
Applications:
1. Well fluids having a high liquid/gas ratio.
2. Well fluids containing appreciable quantities of
sand, mud, and similar finely divided solids.
3. Installations with horizontal space limitations but
with little or no vertical height limitations
4. Upstream of other field process equipment that will
not perform properly with entrained liquid in the gas.
5- Where economics favors the vertical separator.

Horizontal Oil and Gas
Separators Applications
1. Liquid/liquid separation in three-phase separator installations
to obtain more efficient oil/water separation.
2. Separating foaming crude oil where the larger liquid/gas
contact area of the horizontal vessel .
3. Installations where vertical height limitations indicate the use of
a horizontal vessel.
4. Well fluids with a high GOR.
5. Well with relatively constant flow rate and with little or no liquid
heading or surging.
6. Where portable units (either skid or trailer mounted) are
required for either test or production use.
7. Where economics favors the horizontal separators.

Spherical Oil and gas Separators
applications
 Well fluids with high GOR's,
constant flow rate and no liquid
slugging or heading.
 Installations where both vertical
and horizontal space and height
limitations exist.
 Downstream of process units —
such as glycol dehydrators and
gas sweeteners — to scrub
expensive process fluids, such
as glycol .
 Installations where economics
favors the spherical separator.

Gas Scrubbers
Some of the uses for gas scrubbers are to clean gas:
 For fuel for healers, boilers, steam generators and
engines.
 Upstream of compressors.
 Upstream of dehydrators .
 Upstream of gas distribution systems.
 Upstream of and in gas transmission lines to remove
liquid, dust, and scale.
 Upstream and / or downstream of pressure
regulation stations.
 Downstream of gas-transmission-line compressor
stations to remove lubricating oil from the line.

POTENTIAL PROBLEMS IN OIL
AND GAS SEPARATORS

Separating Foaming Crude Oil
 When pressure is reduced on certain types of
crude oil, tiny spheres (bubbles) of gas are
encased in a thin film of oil when the gas comes
out of solution This may result in foam.
 The main factors that assist in "breaking"
foaming oil are settling, agitation (baffling), heat,
chemicals, and centrifugal force.

Paraffin
 Paraffin deposition in oil and gas separators reduces their
efficiency and may render them inoperable by partially filling
the vessel and/or blocking the mist extractor and fluid
passages.
 Paraffin can be effectively removed from separators by use of
steam or solvents.
 The best solution is to prevent initial deposition in the vessel
by heat or chemical treatment of the fluid upstream of the
separator.
 Another deterrent, successful in most instances, involves the
coating of all internal surfaces of the separator with a plastic
for which paraffin has little or no affinity.

Sand, Mud, Salt
If sand and other solids are continuously
produced in appreciable quantities with well
fluids, they should be removed before the
fluids enter the pipelines Medium grained
sand in small quantities can be removed by
settling in an oversized vertical vessel with a
conical bottom and by periodically draining
the residue from the vessel. Desander
Salt may be removed by mixing water with
the oil, and after the salt is dissolved, the
water can be separated from the oil and
drained from the system.

Corrosion
 Produced well fluids can be very corrosive and
cause early failure of equipment The two most
corrosive elements are hydrogen sulfide and carbon
dioxide .
 These two gases may be present in the well fluids in
quantities from a trace up to 40 to 50% of the gas by
volume

Flow Variations
 Separators should be sized to handle the maximum
flow rate expected during the predicted life of the
separator.
 Separators must also be capable of handling sudden
slugs of liquid.

START-UP PROCEDURE OPERATION
 If the vessel is empty, close a block valve in each liquid outlet line from the
vessel to prevent possible leakage through a control valve in the liquid line .
 If the vessel has a pressure controller, it should be set at about 75% of the
normal control pressure, and slowly bring it up to a normal pressure after
the vessel is in service.
 If the vessel has low level shutdown devices, they must be deactivated or
liquid must be added to the vessel to a point above the low level devices.
 Check the flow lines out of the vessel to see that each stream leaving the
vessel flows in the proper direction.
 Slowly open the inlet stream to the vessel.
 When the liquid level reaches the range of level controller, place level
controllers in service and open the block valves that were closed in step 1.
Adjust level and pressure controllers to stabilize their operation

SHUTDOWN PROCEDURE
 Close a valve in the inlet stream.
 2a. Close valves in liquid outlet line to prevent liquid from
leaking out.
 2b. If the vessel must be drained, open the by-pass line on
the level control valves .
 Close block valves in the liquid outlet lines after draining.
 If the vessel must be depressurized, close a block valve in
the gas outlet line.
 Depressurize the vessel by opening a valve in the line from
the vessel to the vent or blow down system.
 If possible, leave a small positive pressure on the vessel
while it is shutdown to prevent air from entering so it will
not have to be purged prior to start-up.

ROUTINE OPERATION
Routine operating checks are observing the various level,
pressure, temperature and flow control instruments to see that
they are controlling within the proper range.
Diaphragm-operated control valves should be stroked
occasionally to see that they will fully open and close without
restriction.
Gauge glasses should be drained periodically to prevent scale
from accumulating in the lines or gauge valves and causing them
to show false levels.
If the vessel has filters or coalescing chambers, the pressure drop
cross them should be observed for an increase which indicates a
build-up of solid particles, and the need to replace or clean them

MAINTENANCE
CONSIDERATIONS FOR OIL
AND GAS SEPARATORS

Periodic Inspection
 In refineries and processing plants, it is normal practice to
inspect all pressure vessels and piping periodically for
corrosion and erosion.
 In the oil fields, this practice is not generally followed, and
equipment is replaced only after actual failure.
 This policy may create hazardous conditions for operating
personnel and surrounding equipment.
 It is recommended that periodic inspection schedules for all
pressure equipment be established and followed to protect
against failures.

Installation of Safety Devices
All safety relief devices should be
installed as close to the vessel as
possible
The discharge from safety devices
should not cause danger to personnel
or other equipment.

Safety Heads (Rupture Disks)
 The discharge from a safety head should be open
and without restriction.
 A valve should not be used between the safety head
and the separator because it may inadvertently be
closed.
 Water should not be allowed to accumulate on top of
the rupture disk because ice could form and alter the
rupture characteristics of the disk.
 Pressure relief valves may corrode and leak or may
"freeze" in the closed position.
 They should be checked periodically and replaced if
not in good working condition.

Mist Extractors
 Some mist extractors in oil and gas separators require a drain or liquid
down-comer to conduct liquid from the mist extractor to the liquid section
of the separator.
 This drain will be a source of trouble when pressure drop through the mist
extractor becomes excessive.
 If the pressure drop across the mist extractor, measured in inches of oil
exceeds the distance from the oil level in the separator to the mist
extractor, the oil will flow from the bottom of the separator up through the
mist-extractor drain and out with the gas.
 This condition may be aggravated by partial plugging of the mist extractor
with paraffin or other foreign material.
 separators of advanced design have used mist extractors that do not
require drains or down-comers.

Low Temperatures
 Separators should be operated above hydrate-
formation temperatures.
 Otherwise hydrates may form in the vessel and
partially or completely plug it
 Steam coils can be installed in the liquid section of
oil and gas separators to melt hydrates that may
form there.

Corrosive Fluids
 A separator handling corrosive fluid should be checked
periodically to determine whether remedial work is required.
 Periodic hydrostatic testing is recommended, especially if the
fluids being handled are corrosive.
 ultrasonic thickness indicators calculates the maximum
allowable working pressure from the remaining metal
thickness.
 This should be done yearly offshore and every two to four
years onshore.

Paraffin
 A separator handling paraffin-based oil may
need to be steamed periodically to prevent
plugging and a resultant decrease in
capacity.
 The reduction in capacity often results in
liquid carryover in the gas or discharge of
excessive gas with the liquid.

Throttling Discharge of Liquid
 Throttling discharge of small volumes of liquid from separators
normally should be avoided.
 Throttling may cause erosion or wire drawing of the inner valves and
seats of the liquid-dump valves and may erode the dump-valve bodies
to the extent that they may burst at or below rated working pressures.
 However, throttling discharge may be necessary because processing
units, such as lower-pressure separators or stabilization units,
downstream of the separator may require relatively steady flow.
 Liquid-discharge control valves on separators should be sized for the
volume of liquid the separator must handle.
 Such valves usually should be smaller than the lines in which they are
installed.
 Reduced inner valves can be used to size the valve properly to
minimize wire drawing during throttling service.

Pressure Gauges
 Pressure gauges and other mechanical
devices on separators should be tested for
accuracy at regular intervals.
 Isolating valves should be used so that
pressure gauges can be easily removed for
testing, cleaning, repairs, or replacement.

Gauge Glasses
 Gauge glasses should be kept clean so that
the liquid level observed in the sight glass
indicates at all times the true liquid level in
the separator.
 Periodic flushing of the gauge glass or
cleaning with special solvents and swabs is
recommended.

Cleaning of Vessels
 It is recommended that all separator vessels be
equipped with man-ways, cleanout openings, and/or
washout connections so that the vessels can be
cleaned periodically.
 Larger vessels can be equipped with man-ways to
facilitate their cleaning.
 Smaller vessels can be equipped with hand-holes
and/or washout connections so that they can be
easily cleaned or washed out periodically.

Maintenance Recommendations
 Maintenance should include the following:
 Daily
 Check liquid levels.
 Check pressures and temperatures.
 Replace broken gauge glasses and pressure gauges.
 Periodically
 Lubricate valves.
 Check dump valves.
 Check level controllers.
 Check pressure controls.
 Yearly
- check pressure-relief valves.

TROUBLESHOOTING ADVICES
 Possible causes for the more common problems are listed:
 Low liquid level
Fluid dump valve opening too wide.
Drain valve open or leaking.
No fluid entering.
 High liquid level
Fluid dump valve closed or plugged.
Block valve around dump valve closed.
Inlet valve to next vessel closed.
Separator overloaded.
 Low pressure in separator
Leaking safety-relief valve.
Inlet valve closed.
 High pressure in separator
Valves downstream of separator closed.
 All the oil going out gas line
Dump valve not open.
Block valve closed on piping to tank.
Separator or piping plugged.

TROUBLESHOOTING ADVICES
 Mist going out gas line
Vessel too small.
Plugged mist extractor.
Improper liquid level ( too high or too low ).
Foaming problem.
 Free gas going out oil valve
Too low level in separator.
Dump valve not seating.
No vortex breaker or breaker plugged or damaged.
 Condensate and water not separating in 3-phase separator
Adjustable weir out of adjustment.
Not enough retention time..
Leak in adjustable weir.
 Diaphragm operated dump valve not opening
- Supply gas failure.
- Broken valve stem.
- Plugged tubing.
- Ruptured diaphragm.
- Stopped up vent in upper case

Commissioning

Manifolds for pressures up to
100 bar fully equipped

Oil & Gas Phase Separation

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