2. Dispersion system
• Dispersion system is a heterogeneous system containing one or two
substances in the form of particles spread in the medium made of
another substance
• Dispersion system consists of a dispersed phase (DP) and a dispersion
medium (DM)
• The dispersed phase is a split substance
• The dispersion medium is a medium where this split substance is
spread
3. Dispersion system
• Dispersion means splitting
• Every substance can exist both in the form of a monolith and a split
substance flour, small bubbles, small drops
4. Dispersion system
• To characterize the dispersion system there is used the
following values:
• 1. The transverse size of the dispersed phase:
• For spherical particles - a sphere diameter (d)
• For particles having a shape of a cube - edge of the cube (ℓ)
• 2. The substance splitting of a dispersed phase is
characterized by the degree of dispersion (δ) which is
opposite to the medium diameter (d) of the spherical
particles or the medium length of the edge of the cube (ℓ)
• δ = 1/d, m-1 or δ = 1/ℓ, m-1
• Dispersed phase has the degree of dispersion
• The degree of dispersion is greater and the particle size is less
5. The Classification of Dispersion Systems
• I. According to the dispersion degree of particles of the dispersed
phase
• II. According to the aggregative state of the phase and the medium
• III. According to the kinetic properties of the dispersed phase
• IV. According to the character of interaction between the dispersed
phase (DP) and the dispersion medium (DM)
6. The Classification of Dispersion Systems
• I. According to the dispersion degree of particles of the dispersed phase
• 1. Coarsely dispersed systems
• These are the systems in which the particles have the size of 10-7m –10-4 m
suspensions
• 2. Colloid-dispersed systems
• The size of particles is 10-7m – 10-9 m
• The mixture is also called a colloidal solution
• Colloidal particles consist of molecules, ions, or can have the form of a
macromolecule
• 3. Systems with the particle size less than 10-9 m are not referred to as
dispersed ones
• Such particles form molecular (particle diameter 10-10 m) and ionic (10-11 m) solutions
known as true solutions
7. The Classification of Dispersion Systems
• II. According to the aggregative state of the phase and the medium
• Depending on the aggregative state of a dispersed phase and the dispersion
medium we can divide all dispersion systems into 8 types:
8. Types of dispersion systems
Aggregativ
e state of
the DM
Type of the
system
Aggregative
state of the
DP
Symbolic
notation of
the system
Examples of systems
Gas Aerosol Liquid
Solid
L/G
S/G
Mist
Fumes, dust, powder
Liquid Lyosol Gas
Liquid
Solid
G/L
L/L
S/L
Foam
Emulsions (oil, milk)
Slurries, suspensions, colloid solutions
Solid Hard sol Gas
Liquid
Solid
G/S
L/S
S/S
Hard foams (pumice, bread)
Capillary systems (liquids in porous objects, soil,
ground),
Hard systems (minerals, alloys, concrete)
9. The Classification of Dispersion Systems
• III. According to the kinetic properties of the dispersed phase
• Dispersion systems can be differed according to the degree of interaction of particles in the
dispersed phase
• If DP particles are not connected with each other and are able to move
independently in DM under the influence of thermal motion or force of gravity,
such systems are called free-dispersion systems
• These are solutions, aerosols, rather diluted suspensions and emulsions
• If the particles are bonded together by the intermolecular interaction forces and
form spatial patterns (lattices, nets, etc), such systems are called bound-
dispersion systems
• These are gels, concentrated suspensions (creams, pastes) and concentrated aerosols
10. The Classification of Dispersion Systems
• IV. According to the character of interaction between DP and DM
• There are distinguished lyophilic and lyophobic systems
• Lyophilic systems are those where DP particles are very similar to those of DM
• Lyophobic systems are those with little similarity of DP and DM particles
• If water is taken as DM, then we should use the terms ‘hydrophilic and hydrophobic
dispersion systems’
• The particles in a lyophilic system have a great affinity for the solvent, and
are readily solvated and dispersed, even at high concentrations
• In a lyophobic system the particles resist solvation and dispersion in the
solvent, and the concentration of particles is usually relatively low
• The examples of a hydrophilic system can be high-molecular compounds (HMC) like
proteins, polysaccharides, nucleic acids
• Most of dispersion systems are lyophobic (hydrophobic)
• For example, solutions of АgCl, ВаSО4 salts
11.
12.
13. Surface and interfacial tension
• Surface tension is a measure of the force acting at a boundary between
two phases.
• If the boundary is between a liquid and a solid or between a liquid and a
gas (air) the attractive forces are referred to as surface tension, but the
attractive forces between two immiscible liquids are referred to as
interfacial tension.
• Temperature and molecular weight have a significant effect on surface
tension.
• In the normal hydrocarbon series, a rise in temperature leads to a decrease in the
surface tension, but an increase in molecular weight increases the surface tension.
• A similar trend, that is, an increase in molecular weight causing an increase
in surface tension, also occurs in the acrylic series and, to a lesser extent, in
the alkylbenzene series.
14. Surface and interfacial tension
• The surface tension of petroleum and petroleum products has been studied for many
years.
• The narrow range of values (approximately 24–38 dynes/cm) for such widely diverse
materials as
• gasoline (26 dynes/cm),
• kerosene (30 dynes/cm), and
• the lubricating fractions (34 dynes/cm)
• has rendered the surface tension of little value for any attempted characterization.
• Nonhydrocarbon materials dissolved in an oil reduce the surface tension: polar
compounds, such as soaps and fatty acids, are particularly active.
• The effect is marked at low concentrations up to a critical value beyond which further
additions cause little change; the critical value corresponds closely with that required for
a monomolecular layer on the exposed surface, where it is adsorbed and accounts for
the lowering.
15. Surface and interfacial tension
• A high proportion of the complex phenomena shown by emulsions
and foams can be traced to these induced surface tension effects.
• Dissolved gases, even hydrocarbon gases, lower the surface tension of
oils, but the effects are less dramatic, and the changes probably result
from dilution.
• The matter is presumably of some importance in petroleum
production engineering in which the viscosity and surface tension of
the reservoir fluid may govern the amount of oil recovered under
certain conditions.
16. Surface and interfacial tension
• Petroleum products show little variation in surface tension, within a narrow
range, the interfacial tension of petroleum, especially of petroleum products,
against aqueous solutions provides valuable information (ASTM D971).
• Thus, the interfacial tension of petroleum is subject to the same constraints as
surface tension, that is, differences in composition, molecular weight, and so on.
• When oil–water systems are involved, the pH of the aqueous phase influences
the tension at the interface; the change is small for highly refined oils, but
increasing pH causes a rapid decrease for poorly refined, contaminated, or
slightly oxidized oils.
• A change in interfacial tension between oil and alkaline water has been proposed
as an index for following the refining or deterioration of certain products, such as
turbine and insulating oils.
17.
18. Surface and interfacial tension
• When surface or interfacial tensions are lowered by the presence of solutes, which tend to concentrate on
the surface, time is required to obtain the final concentration and hence the final value of the tension.
• In such systems, dynamic and static tension must be distinguished; the first concerns the freshly exposed
surface having nearly the same composition as the body of the liquid; it usually has a value only slightly less
than that of the pure solvent. The static tension is that existing after equilibrium concentrations have been
reached at the surface.
• The interfacial tension between oil and distilled water provides an indication of compounds in the oil that
have an affinity for water. The measurement of interfacial tension has received special attention because of
its possible use in predicting when an oil in constant use will reach the limit of its serviceability. This interest
is based on the fact that oxidation decreases the interfacial tension of the oil. Furthermore, the interfacial
tension of turbine oil against water is lowered by the presence of oxidation products, impurities from the air
or rust particles, and certain antirust compounds intentionally blended in the oil. Thus, a depletion of the
antirust additive may cause an increase in interfacial tension, whereas the formation of oxidation products
or contamination with dust and rust lowers the interfacial tension.
• In following the performance of oil in service, a decrease in interfacial tension indicates oxidation, if it is
known that antirust additives and contamination with dust and rust are absent. In the absence of
contamination and oxidation products, an increase in interfacial tension indicates a depletion trend in the
antirust additive. Very minor changes over appreciable periods of time signify satisfactory operating
conditions. The addition of makeup oil to a system introduces further complications in following the effects
of service on the interfacial tension of a particular charge of oil.
19. Emulsion is
• Emulsion is mixture of two or more liquids in which one is present as droplets, of
microscopic or ultramicroscopic size, distributed throughout the other.
• Emulsions are formed from the component liquids either spontaneously or, more
often, by mechanical means, such as agitation, provided that the liquids that are
mixed have no (or a very limited) mutual solubility.
• Emulsions are stabilized by agents that form films at the surface of the droplets
(e.g., soap molecules) or that impart to them a mechanical stability (e.g., colloidal
carbon or bentonite).
• Unstable emulsions eventually separate into two liquid layers.
• Stable emulsions can be destroyed by inactivating or destroying the emulsifying
agent—e.g., by adding appropriate third substances or also by freezing or
heating.
• Some familiar emulsions are milk (a dispersion of fat droplets in an aqueous
solution) and butter (a dispersion of droplets of an aqueous solution in fat).
20. Formation of emulsion
• Emulsions can be formed and used in various situations:
• - Several organisms produce emulsions, the prime example being the milk excreted by female
mammals. Milk contains small oil droplets dispersed in an aqueous liquid. The function of the
droplets is to transport substances that do not, or insufficiently, dissolve in water: this includes
the transport of a large quantity of edible energy in a limited volume without increasing the
osmotic pressure.
• - Most types of emulsions encountered in daily life are man-made. Their most common function
is the transport of water-insoluble substances in a stable, and hence finely dispersed form, but
other, more specific functions are also involved. Such products include a range of foodstuffs,
pharmaceuticals, cosmetics, pesticide formulations, paints, lubricants, and finishing agents.
• - Emulsions can be used in intermediate stages in manufacturing processes. This may concern
extraction in a stirred tank or a column. Another example is the formation of latices by emulsion
polymerization1) .
• - Emulsions can also be a nuisance, since they can be formed inadvertently during some
processes, and then have to be broken. An example is crude oil, which is often obtained as a
water in oil emulsion.
21. Emulsions
• Emulsions may be either oil-in-water or
water-in-oil.
• Technically, when generating oil-in-water vs.
water-in-oil emulsions, one phase (known as
the dispersed phase) is mixed into the other
(the continuous phase).
• In other words, one liquid serves as a sort of
base into which another liquid is added.
• When an emulsion is “oil-in-water,” oil is the
dispersed phase that is distributed into the
continuous phase, water.
• In a water-in-oil emulsion, the roles are
switched.
• Milk is an example of an oil-in-water emulsion,
while butter is water-in-oil.
23. Demulsification
• Demulsification is a process where emulsions are broken down, most typically by the
addition of chemicals. Demulsification is especially important in oil industry where stable
oil-water emulsions are formed during oil production.
• Demulsification is especially important in oil industry
• Emulsion stability is often discussed in various industries such as food and cosmetics. But
as important as the stability of the emulsions is for those products, the possibility to
destabilize the emulsion can be such as essential.
• During oil production, very stable water-in-oil (W/O) emulsions are formed. These
emulsions are stabilized by the naturally occurring ingredients in oil, such as asphaltenes
and resins. These molecules behave as surfactants and adsorb at the oil-water interface,
preventing coalescence of water droplets and making the emulsions extremely difficult
to break.
• In oil production, the emulsions are problematic as the high water content will cause
problems in the refinery through pipeline corrosion. The water needs to thus be
removed prior transportation to the refinery.
24. Demulsification
• Rate of the speed at which the separation process takes place
• Amount of water left in the crude oil after separation
• Quality of the separated water for disposal
• These factors dictate the time it takes to destabilize the emulsion as well as the quality of both,
the produced crude oil as well as the wastewater.
• Demulsifiers are used to destabilize emulsions
• The stability of the emulsion arises from the formation of the interfacial film at oil-water
interface. To separate the emulsion, this film needs to rapture for the coalescence of the droplets
to happen. In oil industry, chemical demulsifiers are used to help in this process.
• Demulsifier is a surfactant used to break the oil-water emulsions. Typically, water-soluble
demulsifiers are used to destabilize oil-in-water emulsions and oil-soluble demulsifiers are used to
break water-in-oil emulsions. To break the emulsions, the water droplets should flocculate and
eventually coalescence to form two separate phases, i.e. oil and water. For destabilization to
happen the demulsifier must adsorb to the interface, remove, and break up the asphaltene
aggregates. Also, they should reduce the interfacial tension between the oil and water phases to
facilitate the droplet coalescence.
25.
26.
27. Preparing of the crude oil.
• The oil and gas process is the process equipment that takes the
product from the wellhead manifolds and delivers stabilized
marketable products, in the form of crude oil, condensates or gas.
• Components of the process also exist to test products and clean
waste products such as produced water.
• The well-stream may consist of crude oil, gas, condensates, water and
various contaminants.
• The purpose of the separators is to split the flow into desirable
fractions.
28. Preparing of the crude oil.
• An example process for the Statoil Njord floater:
• medium-size platform
• with one production train and
• a production of 40-45,000 bpd of actual production after the separation of
water and gas.
• The associated gas and water are used for onboard power generation
and gas reinjection.
• There is only one separation and gas compression train.
• The water is treated and released (it could also have been
reinjected).
• This process is quite representative of hundreds of similar sized
installations, and only one more complete gas treatment train for gas
export is missing to form a complete gas production facility.
• Njord sends the oil via a short pipeline to a nearby storage floater.
• On gravity base platforms, floating production and storage
operations (FPSO) and onshore plants, storage a part of the main
installation if the oil is not piped out directly.
Photo: Statoil ASA
29.
30. Test separators and well test
• Test separators are used to separate the well flow from one or more wells for analysis and detailed
flow measurement.
• In this way, the behavior of each well under different pressure flow conditions can be defined.
• This normally takes place when the well is taken into production and later at regular intervals
(typically 1-2 months) and will measure the total and component flow rates under different
production conditions.
• Undesirable consequences such as slugging or sand can also be determined.
• The separated components are analyzed in the laboratory to determine hydrocarbon composition of
the gas oil and condensate.
• Test separators can also be used to produce fuel gas for power generation when the main process
is not running.
• Alternatively, a three-phase flow meter can be used to save weight.
31. Production separators
• The main separators are gravity types.
• First stage separators pressure reduced to about 3-5 MPa
(30-50 times atmospheric pressure).
• Inlet temperature is often in the range of 100-150 ºC.
• The pressure is often reduced in several stages.
• Three stages are used to allow the controlled separation of volatile
components.
• The idea is to achieve maximum liquid recovery and stabilized oil and gas,
and to separate water.
• A large pressure reduction in a single separator will cause flash
vaporization, leading to instability and safety hazards.
32. Production separators
• The retention period - 5 minutes,
• allowing gas to bubble out,
• water to settle at the bottom and
• oil to be taken out in the middle.
• The water cut (percentage water in the well flow) is almost 40%,
which is quite high.
• In the first stage separator, the water content is typically reduced to
less than 5%.
• At the crude entrance, there is a baffle slug catcher that will reduce
the effect of slugs (large gas bubbles or liquid plugs).
• Some turbulence is desirable as this will release gas bubbles faster than a
laminar flow.
33. Production separators
• At the end, there are barriers up to a certain level
to keep back the separated oil and water.
• The main control loops are the oil level control loop (EV0101 20
above) controlling the oil flow out of the separator on the right, and
the gas pressure loop at the top (FV0105 20, above).
• The loops are operated by the control system.
• Another important function is to prevent gas blow-by, which happens
when a low oil level causes gas to exit via the oil output, causing high
pressure downstream.
• There are generally many more instruments and control devices
mounted on the separator.
34. Production separators
• The liquid outlets from the separator will be
equipped with vortex breakers
to reduce disturbance on the liquid table inside.
• This is basically a flange trap to break any vortex formation and
ensure that only separated liquid is tapped off and not mixed
with oil or water drawn in through these vortices.
• The gas outlets are equipped with demisters, essential filters
that remove liquid droplets in the gas.
• Emergency valves (EVs) are sectioning valves that separate the process components and
blow-down valves, allowing excess hydrocarbons to burn off in the flare. These valves are
operated if critical operating conditions are detected or on manual command from a
dedicated emergency shutdown system.
35. Production separators
• A 45,000 bpd design production with gas and 40% water cut
will give about 10 cubic meters from the wellheads per minute.
• There also needs to be enough capacity to handle normal slugging from
wells and risers.
• This means the separator has to be about 100 cubic meters, e.g., a
cylinder 3m in diameter and 14m in length at the rated operating pressure.
This means a very heavy piece of equipment, typically around 50 tons for
this size, which limits the practical number of stages.
• Other types of separators, such as vertical separators or cyclones
(centrifugal separation), can be used to save weight, space or improve
separation (to be discussed later).
• There must also be a certain minimum pressure difference between each
stage to allow satisfactory performance in the pressure and level control
loops.
36. Second stage separator
• The second stage separator is quite similar to the first stage HP separator.
• The pressure on second stage separator is around 1 MPa (10 atmospheres)
and temperature below 100ºC.
• The water content will be reduced to below 2%.
• An oil heater can be located between the first and second stage separator
to reheat the oil/water/gas mixture.
• This makes it easier to separate out water when initial water cut is high and
temperature is low.
• The heat exchanger is normally a tube/shell type where oil passes though
tubes in a heating medium placed inside an outer shell.
37. Third stage separator
• The final separator is a two-phase separator, also called a flash drum.
• The pressure is reduced to atmospheric pressure of around 100 kPa,
the last heavy gas components can boil out.
• In some processes where the initial temperature is low, it might be
necessary to heat the liquid again (in a heat exchanger) before the
flash drum to achieve good separation of the heavy components.
• The level and pressure controlled by loops.
• As an alternative, when production is mainly gas, and remaining liquid
droplets have to be separated out, the two-phase separator can be a
knockout drum (K.O. drum).
38. Coalescer
• After the third stage separator, the oil can go to a coalescer for final
removal of water.
• In this unit, water content can be reduced to below 0.1%.
• The coalescer is completely filled with liquid: water at the bottom and oil
on top.
• Internal electrodes form an electric field to break surface bonds between
conductive water and isolating oil in an oil-water emulsion.
• The coalescer field plates are generally steel, sometimes covered with
dielectric material to prevent short-circuits.
• The critical field strength in oil is in the range of 0.2 to 2 kV/cm.
• Field intensity and frequency as well as the coalescer grid layout are
different for different manufacturers and oil types.
39. Electrostatic desalter
• If the separated oil contains unacceptable amounts of salts, they can
be removed in an electrostatic desalter.
• The salts, which may be sodium, calcium or magnesium chlorides,
come from the reservoir water and are also dissolved in the oil.
• The desalters will be placed after the first or second stage separator
depending on GOR (gas oil ratio from the well) and water cut.
40. Water treatment
• Water cut is high, there will be a huge amount of water produced.
• A water cut of 40% gives water production of about 4,000 cubic meters per
day (4 million liters) that must be cleaned before discharge to sea. Often, this water contains sand particles bound to the
oil/water emulsion.
• The environmental regulations in most countries are quite strict.
• F.e., in the Northeast Atlantic, the OSPAR convention limits oil in water discharged to sea to 40 mg/liter (ppm).
• It also places limits on other forms of contaminants.
• This still means that the equivalent of up to one barrel of oil per day in contaminants from the above production is
discharged into the sea, but in this form, microscopic oil drops are broken down quickly by natural bacteria.
• Water from the separators and coalescers first goes to a sand cyclone, which removes most of the sand.
• The sand is further washed before it is discharged.
• The water then goes to a hydrocyclone, a centrifugal separator that removes oil drops.
• The hydrocyclone creates a standing vortex where oil collects in the middle and water is forced to the side.
• Finally the water is collected in the water de-gassing drum.
• Dispersed gas slowly rises and pulls remaining oil droplets to the surface by flotation.
• The surface oil film is drained, and the produced water can be discharged to sea.
• Recovered oil in the water treatment system is typically recycled to the third stage separator.
Produced water treatment
41. Crude Oil Desalting
• When the crude oil enters the unit, it carries with it some brine in the form
of very fine water droplets emulsified in the crude oil.
• The salt content of the crude measured in pounds per thousand barrels
(PTB) can be as high as 2000. Desalting of crude oil is an essential part of
the refinery operation.
• The salt content should be lowered to between 5.7 and 14.3 kg/1000 m3
(2 and 5 PTB). Poor desalting has the following effects:
• Salts deposit inside the tubes of furnaces and on the tube bundles of heat
exchangers creating fouling, thus reducing the heat transfer efficiency;
• Corrosion of overhead equipment; and,
• The salts carried with the products act as catalyst poisons in catalytic cracking units.
42. Types of Salts in Crude Oil
• Salts in the crude oil are mostly in the form of dissolved salts in fine water droplets emulsified in the crude
oil. This is called a water-in-oil emulsion, where the continuous phase is the oil and the dispersed phase is
the water.
• The water droplets are so small that they cannot settle by gravity. Furthermore, these fine droplets have on
their surfaces the big asphaltene molecules with the fine solid particles coming from sediments, sands or
corrosion products.
• The presence of these molecules on the surface of the droplets acts as a shield that prevents the droplets
from uniting with each other in what is called coalescence.
• The salts can also be present in the form of salts crystals suspended in the crude oil. Salt removal requires
that these salts be ionized in the water. Hence, wash water is added to the crude to facilitate the desalting
process.
• Salt types are mostly magnesium, calcium and sodium chlorides with sodium chloride.
• These chlorides, except for NaCl, hydrolyze at high temperatures to hydrogen chloride:
• NaCl does not hydrolyze. Hydrogen chloride dissolves in the overhead system water, producing hydrochloric
acid, an extremely corrosive acid.
43. • The process is accomplished through the following steps:
• Water washing: Water is mixed with the incoming crude oil through a
mixing valve. The water dissolves salt crystals and the mixing distributes the
salts into the water, uniformly producing very tiny droplets. Demulsifying
agents are added at this stage to aide in breaking the emulsion by removing
the asphaltenes from the surface of the droplets.
• Heating: The crude oil temperature should be in the range of 48.9–54.4 C
(120–130 F) since the water–oil separation is affected by the viscosity and
density of the oil.
• Coalescence: The water droplets are so fine in diameter in the range of 1–10
mm that they do not settle by gravity. Coalescence produces larger drops
that can be settled by gravity. The force of attraction between the water
droplets is given by:
• where E is the electric field, d is the drop diameter and s is the distance between
drops centers and K is a constant.
• Settling. According to Stock’s law the settling rate of the water droplets after
coalescence is given by
• where ρ is the density µ is the viscosity, d is the droplet diameter and k is a constant.
Desalting Process
44. DEWATERING AND DESALTING
An electrostatic desalting unit.
• Thus, the first step in petroleum processing, even before the crude oil enters the
refinery, occurs at the wellhead. It is at this stage that fluids from the well are separated
into crude oil, natural gas, and water phases using a gas–oil separator.
• The separators can be horizontal, vertical, or spherical and are generally classified into
two types based on the number of phases to separate:
• (1) two-phase separators, which are used to separate gas from oil in oil fields or gas from water for
gas fields,
• (2) three-phase separators, which are used to separate the gas from the liquid phase and water
from oil.
• The liquid (oil, emulsion) leaves at the bottom through a level control or an exit valve.
The gas leaves the vessel at the top, passing through a mist extractor to remove the
small liquid droplets in the gas. Separators can also be categorized according to their
operating pressure:
• (1) low-pressure units can tolerate pressures on the order of 10–180 psi, (0,68-12,25 atm)
• (2) medium pressure separators operate from 230 to 700 psi, (15,65-47,63 atm) and
• (3) high-pressure units can tolerate pressures of 975–1500 psi (66,34-102,07 atm).
46. Two-stage desalting
• The desalter of this design achieves 90% salt removal. However, 99% salt removal is
possible with two-stage desalters.
• A second stage is also essential since desalter maintenance requires a lengthy amount of
time to remove the dirt and sediment which settle at the bottom. Therefore, the crude
unit can be operated with a one stage desalter while the other is cleaned.
47.
48.
49. • The salt or brine suspensions may be removed from crude oil by heating
(90°C–150°C, 200°F–300°F) under pressure (50–250 psi) that is sufficient to
prevent vapor loss and then allowing the material to settle in a large vessel.
• Alternatively, coalescence is aided by passage through a tower packed with
sand, gravel, and the like.
• The desalter temperature is therefore quite critical, and normally a bypass
is provided around at least one of the exchangers so that the temperature
can be controlled. The optimum temperature depends upon the desalter
pressure and the quantity of light material in the crude, but is normally
approximately 120°C (250°F), 100°C (212°F), being lower for low pressures
and light crude oils. The average water injection rate is 5% of the charge.
50. • Good desalter control is indicated by the chloride content of the overhead receiver water and should be on
the order of 10–30 ppm chlorides. If the desalter operation appears to be satisfactory but the chloride
content in the overhead receiver water is greater than 30 ppm, then caustic should be injected at the rate of
1–3 lb per 1000 barrels of charge to reduce the chloride content to the range of 10–30 ppm. Salting out will
occur below 10 and severe corrosion above 30 ppm. Another controlling factor on the overhead receiver
water is pH. This should be controlled between pH 5.5 and 6.5.
• Ammonia injection into the tower top section can be used as a control for this. In addition to electrical
methods for desalting, desalting may also be achieved by using the concept of a packed column that
facilitates the separation of the crude oil and brine through the agency of an adsorbent.
• Finally, flashing the crude oil feed can frequently reduce corrosion in the principal distillation column. In the
flashing operation, desalted crude is heat exchanged against other heat sources that are available to recover
maximum heat before crude is charged to the heater, which ultimately supplies all the heat required for
operation of the atmospheric distillation unit. Having the heater transfer temperature offset, the flow of fuel
to the burners allows control of the heat input. The heater transfer temperature is merely a convenient
control, and the actual temperature, which has no great significance, will vary from 320°C (610°F) to as high
as 430°C (805°F), depending on the type of crude oil and the pressure at the bottom of the fractionating
tower.
