Engineering Encyclopedia

Saudi Aramco DeskTop Standards

Crude Oil Desalting

Note: The source of the technical material in this volume is the Professional
Engineering Development Program (PEDP) of Engineering Services.
Warning: The material contained in this document was developed for Saudi
Aramco and is intended for the exclusive use of Saudi Aramco’s
employees. Any material contained in this document which is not
already in the public domain may not be copied, reproduced, sold, given,
or disclosed to third parties, or otherwise used in whole, or in part,
without the written permission of the Vice President, Engineering
Services, Saudi Aramco.

Chapter : Process For additional information on this subject, contact

File Reference: CHE10406 R.A. Al-Husseini on 874-2792
Engineering Encyclopedia Process
Crude Oil Desalting

Contents Pages

INFORMATION

Principles of Crude Oil Desalting .............................................................................................. 1

Process Variables and Operating Guidelines ............................................................................. 7

Desalter Design Features ......................................................................................................... 17

Performance Evaluation and Troubleshooting ......................................................................... 26

WORK AID
Work Aid 1A: Size Basis for Saudi Aramco Desalter Vessels ........................................... 28

Work Aid 1B: Typical Density Versus Temperature Curves for Desalter
Fluids .......................................................................................................... 29

Work Aid 1C: Characteristic Temperature - Viscosity Relationship for Crude

Oils ............................................................................................................. 30

Work Aid 2: Desalter Performance Index Summary ....................................................... 31

Work Aid 3A: Troubleshooting Desalter Operating/Performance Problems:

Inadequate Salt Removal ............................................................................ 32

Work Aid 3B: Troubleshooting Desalter Operating/Performance Problems:

High Water Carryover In Desalted Oil ....................................................... 33

Work Aid 3C: Troubleshooting Desalter Operating/Performance Problems:

Oily Effluent Water (Black Water) ............................................................. 34

Work Aid 3D: Troubleshooting Desalter Operating/Performance Problems:

Wide Emulsion Band.................................................................................. 35

Work Aid 3E: Troubleshooting Desalter Operating/Performance Problems:

Voltmeter and/or Ammeter Readings Vary Widely
andContinuously......................................................................................... 36

Work Aid 3F: Troubleshooting Desalter Operating/Performance Problems:

Continuous Low Voltage and/or High Ammeter Readings ........................ 37

Work Aid 3G: Troubleshooting Desalter Operating/Performance Problems: Sharp

Increase in Current Draw (Amperage) ........................................................ 38

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GLOSSARY ............................................................................................................. 39

REFERENCES ......................................................................................................... 41

APPENDICES
Appendix A – Saudi Aramco Desalter Design Data ................................................................ 42
Appendix B – Desalting Equipment Vendors .................................................. 43

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Principles of Crude Oil Desalting

Background

Desalting is an integral part of refinery crude oil processing and can be the key to controlling
pipestill corrosion, heat exchanger fouling, furnace tube coking, and process water disposal.
Salts, which normally occur in the form of brine suspended in the crude, promote corrosion,
fouling, and coking. The primary function of a desalter is to remove this salt from the oil.
Other contaminants, such as sediment, which can promote heat exchanger fouling and
plugging, erosion, and residual product contamination, can also be removed in a desalter.
Desalters can also smooth out process variations from small slugs of water in crude oil feed to
a pipestill due to tank switching, high bottoms level, and use of previously inactive lines.

Electrostatic desalting is used to remove salts and particulates from crude oil. The crude oil-
brine mixture is contacted with wash water using a mix valve just upstream of the desalter
vessel. Salt is extracted from the brine into the wash water droplets. The electric field in the
desalter enhances water droplet coalescence so that water/oil separation requires much less
residence time, and hence a smaller vessel, than is needed for unenhanced settling. Small
quantities of desalting aids are often added to enhance contacting effectiveness, droplet
coalescence, and water separation. Desalted oil is removed from the top of the desalter vessel
and the briny water from the bottom.

The most efficient place to remove salt from crude oil is usually at the refinery. But, in
instances where removal of salt in the field is mandatory to meet marketing or pipeline
requirements, solution of the problem is left to the producer. The principles involved are the
same whether salt removal is to be accomplished at the refinery or in the field.

Refinery desalters are generally installed in the crude oil preheat exchanger train of the
atmospheric pipestill (APS). As indicated by the schematic presented in Figure 1 for a single-
stage desalting operation, chemical desalting aid (demulsifier) is typically injected at the
suction side of the crude charge pump, and wash water (fresh water) is added at the mix valve
immediately upstream of the desalter. The treated oil from the desalter (desalted product) is
fed through the remaining crude preheat exchangers before entering the APS. Some
installations include a preflash unit between the desalter and these downstream exchangers.
The waste water from the desalter (effluent water or brine) is fed to an API separator, brine
settling tanks, or other oil-water separation unit prior to any treatment required for meeting
local environmental regulations for waste water discharge. In situations where a suitable
wash water supply is inadequate, a portion of the effluent brine may be recycled to
supplement the fresh wash water available for the operation.

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SINGLE-STAGE DESALTING FLOW DIAGRAM

FIGURE 1

A typical two-stage electrostatic desalting operation is shown schematically in Figure 2.

Since large quantities of suitable wash water are unavailable at most refineries, typical two-
stage desalter operations feature countercurrent water-oil flow. In such an operation, fresh
water is added at the mix valve for the second stage desalter and the effluent water from the
second stage is used as wash water for the first stage. Demulsifier injection is required
upstream of the first stage, and depending on the nature of the demulsifier, may also be
needed upstream of the second stage as well.

Saudi Aramco production facilities typically have an electrostatic coalescer dehydrator vessel
upstream of the desalter vessel(s). GOSP desalters typically have a dehydrator stage followed
by one desalter stage. Also included are three-stage desalters in countercurrent operation
using saline (sea or well) wash water (see Figure 3). The first stage operates as an
electrostatic coalescer dehydrator which can operate with or without wash water. The second
and third stages operate as a conventional two-stage configuration. To conserve wash water,
a fresh wash water rate of ~ 1.5% and internal water recycle rates of ~ 3% of crude
throughput are typically used in each stage.

Appendix A lists Saudi Aramco desalter facilities and configurations.

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TWO-STAGE DESALTING FLOW DIAGRAM

FIGURE 2

FLOW DIAGRAM OF SAUDI ARAMCO THREE-STAGE

ELECTROSTATIC DESALTING SYSTEM

FIGURE 3

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Source of Salts and Contaminants in Crude

The salt found in crude oil originates from production, secondary or tertiary recovery, and/or
transportation and handling operations. Operating experience has shown a wide range of salt
composition from wet crude production in different parts of the world. The geologic
formations from which a crude is produced influence the brine composition and
concentration.

The water-soluble impurities in the brine produced with the crude consist primarily of sodium,
calcium, and magnesium salts that are generally chlorides. In some crudes considerable
quantities of sulfates are also found. Chlorides are the most corrosive components in the
brine. At high temperatures these salts undergo hydrolysis that liberates hydrochloric acid. In
the refinery this acid is carried overhead into the flash and fractionating towers.

Brine concentrations vary from merely brackish waters all the way to concentrated solutions.
Salt concentrations in crude oil brine have been found to vary from about 3% (close to that of
sea water) to more than 25%. The salt composition in the brine can also vary significantly
depending on source, recovery techniques, and shipping and handling procedures. This is
evidenced by the wide range of Ca/Na ratio, chloride, sulfate, and carbonate contents
measured in crude oil brines around the world. For a specific crude, salt content may
correlate with bottoms, sediment, and water (BS&W) content, but such relations are
meaningless for different crudes or for crudes from the same geologic formation that are
recovered using different production techniques.

New fields will frequently start producing clean crude containing only a few pounds of salt
per thousand barrels of crude (ptb). One ptb is equivalent to approximately 3 wppm. As well
production age increases, however, the crude salt content also rises. Water flooding and CO2
injection are the principal secondary recovery techniques for continuing crude production
from wells with declining crude flow. Crudes produced by water flooding have higher than
normal solids content and electrical conductivity, and are, therefore, more difficult to desalt.
Injection of CO2 containing gas may dissolve more calcium bicarbonate into the water with
the crude.

When secondary recovery becomes uneconomical, tertiary recovery methods are used. These
include steam injection and fireflooding. Fireflooding involves injecting air in the producing
well and igniting it to stimulate the flow of crude and increase recovery. Crudes from tertiary
recovery operations, particularly fireflooding, are notoriously difficult to desalt.

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Source of Salts and Contaminants in Crude (Cont'd)

Initial "oil treating" or dehydration of crude oil production usually takes place in the oil field
to reduce the volume of water moving through the transportation system. Most crudes can be
electrostatically dehydrated to the 0.1% to 0.5% BS&W range. Some heavier (under 20_API)
and more viscous crudes (greater than 18 cSt at operating temperature) can only be reduced to
the 0.5% to 5.0% BS&W range. Depending on the crude oil source, the amount of salt that is
acceptable for export markets is typically 10 ptb. While this is not low enough to achieve the
fouling and corrosion control desired in a refinery, it is low enough for single-stage desalting
at the refinery to achieve such desirable salt levels.

Typical Desalter Performance

Properly sized and operated single-stage desalting is capable of meeting most refinery salt-in-
crude requirements for reduced corrosion and fouling when handling lighter oils (30_API or
higher). Desalting efficiencies ranging between 85% and 95% can be expected for a properly
sized and operated unit. Efficiencies between 85% and 90% can be anticipated for heavy
crudes (20_API or lower) or crudes blended with residua that are more difficult to desalt.

Salt concentrations in the feed to a refinery desalter generally range between 10 and 100 ptb,
depending upon source, extent of field treating, and transportation and handling operations
prior to desalting. The salt content of feeds to Saudi Aramco production facility desalters is in
the range of 4,000 ptb and above. Salt concentrations in the crude leaving refinery single-
stage desalters are generally between 3 and 10 ptb. Although such salt levels are adequate for
minimizing fouling and corrosion in refinery crude preheat exchangers and pipestill
operations, salt levels below 1 ptb may be required in the heavy feeds to cat cracking units, to
reduce catalyst poisoning by sodium in the feed or ammonium chloride plugging in the cat
cracker fractionator. To achieve such low salt levels, two-stage desalting may be required.
With two-stage desalting, salt removal efficiencies approaching 99% can be achieved. Also,
large water slugs can be removed with minimal effect on a refinery pipestill operation.

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Typical Desalter Performance (Cont'd)

Refinery desalter feed oil generally contains between 0.1 and 0.5 vol% water, with values as
high as 1% occasionally reported. Feeds to Saudi Aramco production facility desalters
contain as much as 30 vol% water. Effluent oil from a single-stage desalter will generally
contain between 0.1 and 0.5 vol% water, depending on the physical properties of the oil.
Water contents of up to 0.5 vol% in the desalted oil are not uncommon when handling heavier
crudes, which are more difficult to dehydrate. A water content of 0.2 vol% is typical in most
desalted oils. The water carryover from a desalting operation can, therefore, be the same, or
even slightly higher, than the water in the feel oil. However, because of dilution with wash
water, the water carried over from the desalter has a considerably lower salt concentration
than the water in the feed. Thus, desalting efficiency can remain high even with slightly
higher water content in this treated oil.

Mechanically filterable materials in the crude that are insoluble in both oil and water are
generally classified as solids. Solids content in the crude to a desalter typically varies from 1
to 200 ptb. Vendor experience suggests desalter solids removal efficiencies of 50% to 75%
depending on the density and viscosity of the crude and the effectiveness of any desalter
chemical additive.

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Process Variables and Operating Guidelines

The primary variables in the process include oil feed quality, desalter operating temperature
and pressure, wash water amount and quality, pressure drop across the mixing valve, the
electric field, oil and water residence times in the vessel, and type and amount of chemical
additive used.

Oil Feed Quality

Oil feed type and quality have a significant influence on desalter performance. Normally,
light (high API gravity) oils are relatively easy to desalt. Heavier oils are more difficult to
desalt for several reasons. The density difference between the oil and water is small and the
oil viscosity is relatively high so that the rate of water droplet settling in the desalter is low.
Heavier oils also tend to contain more naturally occurring emulsifiers than lighter crudes.
These tend to inhibit water droplet coalescence and promote the formation of stable emulsions
in the desalter. In addition, heavier crudes often contain more sulfur and, therefore, more iron
sulfide. Iron sulfide is insoluble in oil and basic water and tends to accumulate at the
oil/water interface in the desalter, making it a very effective emulsion stabilizer. Effective
desalting of heavier crudes may require reduced throughputs or increased desalting capacity,
higher temperatures, more intense wash water/oil mixing, and/or increased chemical
demulsifier dosage.

Temperature

For every desalter installation and crude blend processed, there is an optimum desalter
operating temperature. Crude is heated to the desired desalter operating temperature by the
portion of the crude preheat exchanger train upstream of the desalter. The location in this
preheat exchanger train is determined by the desired desalter operating temperature.

High temperature is required for several reasons. The primary purpose is to lower the oil
viscosity to increase the settling rate of water droplets in the desalter. In addition, higher
temperature tends to promote coalescence of the water droplets by enhancing the drainage of
the oil-surfactant layer surrounding the water droplets. Larger water droplets thus formed
settle more rapidly in the lower viscosity oil. Production field desalters typically operate at
temperatures between 100_F and 200_F. The operating temperature range is typically 200-
300_F for refinery desalters. This temperature range is high enough to melt waxes that could
hinder coalescence and water separation from the oil.

Excessively high desalter operating temperatures can cause significant operating problems.
High desalting temperatures may increase crude conductivity, causing high current draw and
low desalting voltage that could result in poor water droplet coalescence and desalting.

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Temperature (Cont'd)

Since water solubility in the crude increases with increasing temperature, high desalter
operating temperatures can also lead to higher water content in the crude from the desalter.
Operating temperatures above 300_F should be avoided since standard desalter entrance
bushings will fail frequently in prolonged service at such temperatures.

Pressure

Desalter operating pressure must be maintained at a sufficiently high level for vaporization
not to occur. If a vapor space develops in the vessel, a safety float switch or low level switch
will automatically de-energize the electrodes and effectively shut down the desalter. Any
vaporization results in erratic operation and a loss in desalting efficiency by generating
turbulence that hinders coalesced water droplet settling in the desalter. The required pressure
depends on the desalter operating temperature and crude type. Desalters typically operate at
pressures between 65 and 300 psig.

Wash Water Rates, Quality, Injection Points, and Sources

Wash water rates between 4 and 8 vol% (10 to 12 vol% maximum) of the crude throughput
are required to maintain effective desalter performance. The wash water is normally injected
just upstream of the mixing valve. Wash water addition provides the water droplet
concentration needed to contact and rupture the protective coating surrounding the brine and
promote coalescence to form larger, more easily separated droplets with reduced salt
concentration. This water is essential for the desalting process. Insufficient wash water leads
to poor contacting with brine droplets in the oil, reduces the dilution effect on the salt
concentration in entrained water from the desalter, and reduces the effectiveness of the
desalter's electric field in promoting droplet coalescence.

In situations where a suitable wash water supply is inadequate, a portion of the effluent brine
may be recycled to supplement the fresh wash water available for the operation. In general,
because of the higher ionic content in the recycled water, water recycling does not work as as
well as fresh water addition and should be used only where there are no practical alternatives.

Wash water should have a much lower salt content than formation water or the brine in the
crude oil. Wash water that Saudi Aramco uses is not normally salt free and has high total
dissolved solids.

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Wash Water Rates, Quality, Injection Points, and Sources (Cont'd)

The wash water quality for refinery desalters is a key process consideration that not only
affects the desalting operation, but also has significant impact on preheat exchanger fouling,
furnace tube coking, and fractionator plugging. Ideally the wash water should be free of
ammonia, dissolved salts, soluble organics, and hydrogen sulfide, and also have a pH such
that the effluent brine from the desalter has a pH between 5.5 and 7.0. Raw water (filtered or
with low solids content) or stripped sour water is typically used as wash water for desalting.
The effect of using such process water as desalter wash water should be evaluated by process
calculations. Wash water acidification or caustic addition facilities may be required to meet
pH requirements.

APS and VPS condensate are excellent wash water types for refinery desalters. Boiler
feedwater is also good, if it has zero hardness and a low soluble salt content. These types of
water are preferred because they are free of dissolved oxygen. When atmospheric overhead
water is used as wash water, fluctuations in the quality of this water due to erratic overhead
system corrosion control can cause desalting problems. For example, a drop in the overhead
pH can dissolve iron. Raising the pH at the desalter can cause the iron to precipitate as solid
iron sulfide particles that stabilize emulsions in the desalter and can cause excessive water
carryover and/or oily desalter brine. Careful and stable tower blowdown is not considered
very suitable for desalter wash water because it normally contains fine solids that can stabilize
desalter emulsions. Water from cat feed Hydrofiners and FCCUs is also unsuitable as desalter
wash water because it contains very high levels of ammonia. Such water must be stripped in
a sour water stripper before use. Stripped sour water is a suitable wash water source since
much of the ammonia and hydrogen sulfide has been removed.

Wash Water/Oil Mixing

The degree of wash water/oil mixing is generally regulated by controlling the pressure drop
(DP) across a specially designed globe valve, typically a double-ported globe valve (see
Figure 4). This mixing energy must ensure that the wash water contacts all of the dispersed
brine droplets in the oil. The mixing valve is specifically designed to produce the desired
intimate mixing between the wash water and the oil. Increasing the DP increases the mixing
energy imparted to the oil charge and causes the formation of smaller water droplets. Mixing
must be sufficient to produce the desired contacting between the wash water and brine, sand,
and sediment particles in the oil, but not high enough to cause formation of a stable emulsion.

Undermixing or overmixing can occur. As indicated in Figure 5, undermixing (an insufficient

DP) results in low salt removal and low water carryover. If undermixing is a problem, the
pressure drop across the mixing valve should be increased. Too great a pressure drop across
the mixing valve (overmixing) causes the production of such small water droplets that a tight
water-in-oil emulsion is generated that cannot be readily broken by the electric field in the
desalter. Indications that overmixing is occurring include unusually low electrode voltage
and a higher than normal water carryover into the desalted oil.

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DOUBLE-PORTED GLOBE VALVE

FIGURE 4

OPTIMIZING MIXING VALVE DP

FIGURE 5

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Wash Water/Oil Mixing (Cont'd)

The DP required for optimum mixing varies according to operating temperature and crude
type. Mixing valve pressure drops between 7 psi and 25 psi are typical. Manual valve
adjustment is normally used to achieve the desired mixing DP, although diaphragm actuated
valves can be used if remote operation is needed. Accurate DP readings require use of a
differential pressure gauge rather than the difference between two separate gauges.

For heavy crude oils, desalter vendors sometimes recommend the use of variable speed in-line
dynamic mixers (see Figure 6). Such mixers are also suitable for light crudes but do not
justify the cost. Saudi Aramco does not use variable speed in-line mixers.

The effect of using a variable-speed, multistage, motor driven mixer is shown in Figure 7
which is a plot of BS&W and salt content for a desalted crude. After 5 hours of on-spec
operation, the mixer was replaced by a conventional mix valve with 40 psi pressure drop
across it. While the BS&W remained relatively stable, salt content increased to 15-20 ptb
from less than 5. After the mixer was put back in service, salt levels returned to less than
5 ptb.

VARIABLE-SPEED MULTISTAGE MIXER

With permission from Howe-Baker Engineers, Inc.

FIGURE 6

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EFFECT OF VARIABLE-SPEED, MULTISTAGE MIXER ON

DESALTED OIL BS&W AND SALT CONTENT

With permission from Howe-Baker Engineers, Inc.

FIGURE 7

Electric Field

The purpose of the electric field in the desalter is to dehydrate the water/oil dispersion after
the mixing operation. This is accomplished by polarizing the water droplets, thereby
enhancing droplet coalescence and greatly increasing the water settling rate in the desalter.
Most desalters employ ac fields with an applied voltage in the range of 15,000-25,000 V.
There are actually two electric fields in the desalter. The field between the lower electrode
and the water interface is where most of the dehydration occurs. The second field between
the two electrode grids provides a polishing action on the dispersion. The voltage gradient in
these fields is generally between 1,000 and 5,000 V/in.

With no external forces acting on it, a water droplet suspended in crude oil assumes a
spherical shape (Figure 8). When a high-voltage electric field is imposed, however, the
droplet distorts into an elliptical shape, with positive charges accumulating at the end nearest
the negative electrode of the external electric field, and negative charges at the end nearest the
positive electrode (Figure 8). The drop is an induced dipole. Two adjacent droplets in the
field have an electrical attraction for one another (Figure 8). The negative end of one droplet
is nearest the positive end of the neighboring droplet, so there is an attractive force between
the two that tends to draw them together. This force should be of sufficient magnitude to
rupture the interfacial film between the droplets upon collision, and allows them to coalesce
into one larger droplet.

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ELECTROSTATICALLY ENHANCED WATER DROPLET COALESCENCE

FIGURE 8

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Electric Field (Cont'd)

The relative effect of the variables that determine the magnitude of the attractive force
between droplets in an electric field is described by:

constant voltage gradient2 drop size 6

Force = (Eqn. 1)
distance between droplets4

As drops increase in size and become closer, the force between them becomes very great,
interfacial films can be penetrated, and coalescence is rapid. With 5% wash water in the
water/oil emulsion, the average distance between drops is about 2 diameters and the electri-
cally induced coalescence proceeds almost instantaneously. When the emulsion contains only
0.1% water, drops average about 8 diameters from each other, the dipole attraction forces are
diminished by a factor of about 250 and are insignificant. Turbulence in the electric field
results in random movement that brings fairly widely separated drops into occasional
proximity where the dipole attraction force pulls them together. Turbulence at the oil/water
interface, however, can result in re-entrainment of water droplets into the oil and should be
avoided.

Increasing the voltage gradient of the electric field cannot compensate for large distances
between droplets due to low water droplet concentration in the emulsion. A critical voltage
exists for a given water droplet size that, if exceeded, will cause the drop to disperse.

Critical Voltage Gradient≤ constant surface tension/drop size (Eqn. 2)

The relation indicates that as the drop size becomes larger, the voltage at which redispersion
occurs becomes smaller. Low values of interfacial tension between water and oil will also
increase the tendency for electrical dispersion. Practically, gradients above 12,000 V/in. have
been found to cause larger droplets to redisperse and, therefore, should be avoided in
commercial desalter operations.

Oil/Water Residence Times

The final stage in the desalting process involves removal of the coalesced water/brine droplets
from the oil by gravity settling. The higher the droplet settling rate, the less oil residence time
is required in the desalter for effective performance. An increased settling rate corresponds to
higher capacity for an existing desalter, or a smaller, less expensive grass roots installation.
The rate at which the water droplets fall out of the oil can be predicted by Stokes' law:

8.3 105 ∆SG drop size, in. 2

Settling Rate, in./min. = (Eqn. 3)
oil viscosity, cP

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Oil/Water Residence Times (Cont'd)

From this relationship, it is apparent that the settling rate is higher when the specific gravity
difference (DSG) between the aqueous droplet and the oil is high and when the oil viscosity is
low. Obviously the density difference is greatest when higher API (lower density) oils are
desalted. The density of crude oil is typically in the 0.8-0.95 specific gravity range. A 10_API
oil has approximately the same density as water. There may be some instances where the
water/oil density difference is so small that the oil must be blended with a lighter diluent to
decrease overall blend density to permit effective desalting. In the range of desalter operating
temperatures, the difference between water and oil densities is essentially independent of
temperature.

Temperature does have a significant effect on the oil viscosity. As the temperature of an oil is
increased, its viscosity decreases exponentially. Therefore, to increase the droplet settling rate, as
indicated by Stokes' law, the desalter operating temperature should be increased. This is
especially important for lower API gravity crudes where, for example, an increase in desalter
operating temperature from 200_F to 300_F can decrease viscosity by almost an order of
magnitude, resulting in an equivalent increase in the droplet settling rate.

The coalesced droplet size is the most significant factor influencing the settling rate and,
therefore, the size or capacity of the separation equipment. Stokes' law predicts that the settling
rate is proportional to the square of the drop size. This means, for example, that if the size of a
brine droplet found in a typical oilfield emulsion is increased from 1 to 100 mm, the settling rate
increases by a factor of 10,000. Electrostatic desalters, with their enhanced water droplet
coalescence, effectively enlarge water droplets, resulting in dramatic settling rate increases and
comparable sizing benefits over conventional gravity settling equipment. It is estimated that the
average brine droplet size is in the range of 1 to 10 mm entering the desalter and is enlarged to
300-600 mm by the desalter electric field.

The desalter water/oil interface level helps determine the oil and water residence times in the
desalter. Raising this interface level increases the water residence time while decreasing the oil
residence time in the vessel.

Desalter operating problems may be caused by maintaining an interface level that is either too
high or too low. If the oil/water interface is too high, the risk of water carryover is, therefore,
high. In addition, the desalter dehydration efficiency may be appreciably reduced due to
decreased crude residence time in the unit. Vendor information suggests that adequate
dehydration of most crudes requires 15 to 20 minutes oil residence time.

A low oil/water interface level may produce an oily effluent brine or "black water." With a low
interface level, the water residence time in the desalter can be reduced below that required for
settling, and lead to oil carryunder into the desalter brine. Water residence times on the order of
80 to 300 minutes have been reported. Longer water residence times produce lower oil
concentration in the effluent water. There is no guideline for the minimum water residence time
required to produce an oil-free brine.

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Chemical Additives

The final major control variable in the desalting process is the desalter chemical additive.
This additive may be referred to as a demulsifier, emulsion breaker, or surface active agent.
The desalting chemical works at the oil/water droplet interface, disrupting the emulsion
stabilizing film surrounding the droplets and allowing them to coalesce more easily. It should
be a multifunctional additive, formulated to assist in removing solids from the crude and
produce oil-free effluent water and adequately dehydrated crude. This distinguishes desalting
chemicals from oil-field demulsifiers whose sole purpose is to dewater crude oil.

Small amounts of chemical additives, in the range of 3-10 parts per million of the oil
throughput, are generally employed in electrostatic desalters to improve desalting
effectiveness. To be effective, the chemical must be able to migrate quickly through the oil
phase to the interfacial film. Because both residence time in the oil and turbulence help the
additive diffuse to the interfacial film, the chemical is usually injected into the oil upstream of
the charge pump.

Solids also tend to collect at oil/water interfaces and act to stabilize emulsions in the desalter.
It is generally better to remove these inorganic solids in the water phase rather than have them
remain as contaminants in the oil. To water wet these solids, the chemical additive molecule
has one end that is attracted to the particle, with the other end strongly attracted to water so
that it can carry the particle into the water phase for removal.

Rarely can one chemical perform all the actions desired of a desalting aid. Generally, two or
more are blended together to produce a chemical additive that meets the necessary
performance criteria. Laboratory and field studies are required to make the selection of the
most cost effective additive blend and dosage. Chemical additive vendors generally provide
assistance for such studies.

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Desalter Design Features

Conventional Low Velocity Units

The design of crude oil desalters is provided by the supplying vendor. Currently there are two
major vendors of refinery desalters, Petreco and Howe-Baker (in Europe Howe-Baker
currently markets as Howmar). Petreco and Howe-Baker also supply oil field desalters in
addition to the other major vendor of oil field units, Natco. A listing of desalting equipment
vendors is presented in Appendix B.

Conventional "low velocity" units are the most typical (see Figure 9). These units are
horizontal cylindrical pressure vessels with size related to crude oil processing rate capability.
Typical vessel diameters are 10 to 16 ft, with lengths ranging from 30 to 150 ft (T-T). Either
hemispherical or elliptical vessel heads are used.

Approximately the lower one-third of the vessel contains the aqueous phase, while the upper
portion is filled with crude oil. There are two sets of parallel horizontal electrode grids
located at or near the center of the vessel within the crude oil. The volume occupied by the
aqueous phase is needed for water settling to obtain oil-free brine. The region between the
upper electrode and the aqueous phase is the coalescence zone, where the desalting operation
takes place. The region above the electrodes is used to collect desalted crude into an outlet
header.

The electrodes are of an open grid design rather than being solid plates. They are typically
fabricated as a grating structure formed of horizontal rods spaced 4 to 6 in. apart. Oil and
water can freely flow through the electrode structure. Oil emulsion inlet distributors and oil
outlet headers are designed to achieve uniform vertical flow through the electrode region; i.e.,
oil up, coalesced water down. This flow pattern is the basis of the type designation "low
velocity."

Two designs of oil emulsion inlet are in use that reflect the differing design philosophies of
the vendors. Howe-Baker prefers a drilled pipe distributor that discharges the crude as
horizontal jets into the primary coalescence zone located above the water interface but below
the lower electrode (Figure 10). Petreco and Natco use an inverted trough flow distributor
located underneath the water-oil interface. The trough has holes on the sides that allow the
crude to trickle out (Figure 11). Conceptually, the trough design can better handle water slugs
in the crude feed. However, the trough design also requires that all oil in the feed pass
through both the water phase and water-oil interface, possibly hindering water droplet
settling.

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TYPICAL PETRECO LOW VELOCITY DESALTER

Oil/Water Interface
Transformer Control

Oil Outlet
Electrodes

Vessel

Water Outlet

Emulsion Inlet

Distributor

FIGURE 9

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DRILLED PIPE INLET DISTRIBUTOR IN COALESCENCE ZONE

FIGURE 10

INVERTED TROUGH DISTRIBUTOR IN WATER PHASE

FIGURE 11

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Conventional Low Velocity Units (Cont'd)

The two parallel horizontal electrodes in a "low velocity" unit can be energized utilizing a
number of different electrical arrangements. For three-phase power systems, the two common
arrangements are termed "single-volted" and "double-volted."

In a "single-volted" design, the upper electrode is grounded and the lower electrode is divided
into three segments, with each of the segments energized by one phase of the high voltage
power supply in a "wye" configuration (Figure 12). The voltage difference between the
electrodes, the lower electrode and the aqueous interface, and across the entrance bushings
used to bring the high voltage leads through the desalter vessel wall, is equal to the line-to-
neutral phase voltage. This voltage is normally in the 16,000 to 23,000 V range.

In a "double-volted" design, both upper and lower electrodes are divided into three segments,
with the segments located directly above/below each other being connected to line phase
voltages 120_ out of phase (Figure 13). In the "wye" configuration used, the voltage
difference between the electrode pairs is thus 1.732 times the line-to-neutral voltage, while the
voltage difference between the electrodes and aqueous interface and across the high voltage
entrance bushings is equal to line-to-neutral voltage. With a line-to-neutral voltage of 16,500
V, the voltage between electrodes is 28,600 V. This difference in voltage drops possibly
enhances coalescence in the region between the electrodes without increasing the voltage
stress on the entrance bushings. Another advantage is that a coalescence field is still
maintained across the whole desalter area even with one electrical phase out of service due to
transformer or bushing failure. A disadvantage of the double-volted design is that it draws
more power and requires larger transformers.

Electrical Components

Desalters utilize electrical components that have been developed specifically for desalter use,
based on years of operating experience and testing.

Entrance Bushings
The most critical electrical components are the entrance bushings, which carry the high
voltage leads through the steel wall of the desalter vessel (Figure 14). The electrical and
mechanical stresses on an entrance bushing are severe. The bushing must seal against
desalter pressure and temperature, while at the same time insulating very high voltages.
When a transformer entrance bushing fails, the portion of the grid receiving power through
this connection is out of service and the desalter operation can be seriously impaired.

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ELECTRICAL CONFIGURATIONS (SINGLE-VOLTED)

FIGURE 12

ELECTRICAL CONFIGURATIONS (DOUBLE-VOLTED)

FIGURE 13

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ELECTRICAL COMPONENTS
TYPICAL ENTRANCE BUSHING

FIGURE 14

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Transformers and Reactors

External transformers supply the required high-voltage electric power. Modern desalters are
equipped with 100% reactance controlled transformers. With this design, a reactor (inductor),
connected in series to the transformer, limits short circuit power to prevent damage to
electrical components. As the conductivity of the emulsion being treated increases, the
reactance automatically adjusts the high voltage downward. The voltage increases as the
emulsion conductivity decreases, without operator intervention. This electrical system
provides operating convenience in that occasional short circuits (caused by water slugs,
occasionally high conductivity, etc.) do not require immediate operator attention, and once the
upset period is over, the system automatically returns to normal operation.

Transformer sizing is a function of desalter size, operating temperature, and the specific crude
or crude blend being processed. The desalter vendors specify transformer size based on past
experience or on laboratory measurements. Transformer size is specified on a kVA basis.
The actual transformer load in kilowatts (kW) is normally 25-30% of the kVA rating. If the
operating temperature or type of crude being processed is changed, the transformer load may
also change.

Electrical Instrumentation
Normal desalter instrumentation includes transformer primary amperage and a voltage
reading from a tap on the transformer secondary. Both of these are measurements of the load
being drawn by the desalter. High amperage and low voltage are indicative of the electrodes
being shorted by emulsion. No voltage is indicative of a short circuit from bushing or
insulator failure. The desalter vendors normally supply local instrumentation with a desalting
unit. It is desirable to repeat the voltage and amperage readings in the control room so that
desalter operation can be easily monitored. Another monitoring aid is a readily visible "pilot"
light, located by each desalter transformer, which is energized from the transformer secondary
tap. A bright light indicates normal operation, while a dim light indicates high current draw
and the need for possible corrective action.

Interface Level Control

Proper desalter operation requires that the oil/water interface be maintained at the correct
level in the desalter vessel to maintain the proper electric field gradient. If the oil/water
interface is too high, the current to the desalter will increase, because the electrical path to the
ground through the water layer becomes reduced, resulting in arcing and water redispersion.
The risk of water carryover is also increased. A low oil/water interface level may produce an
oily effluent brine by reducing the water residence time below that required for settling.
Because of the reduced water residence time in the desalter, the effluent brine quality will
also be more affected by solids accumulated at the bottom of the desalter and sensitive to
level controller problems. Level control is achieved by adjusting the rate of brine removal out
of the bottom of the desalter in response to the sensed interface level.

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Interface Level Control (Cont'd)

Automatic level sensing is achieved with floats (displacers) or with capacitance probes.
Normally, the floats are installed internally in the desalter vessel. Although external floats are
easier to maintain, they are not recommended since they are subject to error if the float
temperature is not maintained at the same value as in the desalter. Even if the external
temperature is kept at a proper level, erroneous readings can occur with changes in crude type
until the external loop is purged.

Capacitance probes appear attractive since they have no moving parts and are insensitive to
oil gravity changes. Capacitance probes that employ radio frequency sensing and circuitry to
compensate for probe fouling are best.

Desalter vessels are also equipped with samplers to physically withdraw fluid from the
interface region. The use of these samplers is essential in monitoring desalter operation and
in checking the automatic level sensor readings.

Sizing

The required size of a desalter is a function of its operating temperature, the physical
properties of the crude being processed, and the crude flow rate. Desalter sizing is normally
provided by the supplying vendor. The vendors have enough past experience with major
crude oils to allow them to directly design. For new crude oils, or novel blends, the vendors
carry out desalting tests in their pilot plant facilities.

For screening purposes and to check the consistency of vendor proposals, desalter size can be
estimated from Work Aid 1A. This figure applies to conventional low velocity desalters and
was developed from the Saudi Aramco desalter design data summarized in Appendix A.

Most of the southern area GOSP desalters listed in Appendix A were originally sized based on
the criteria for a standard GOSP design. The wet crude handling facilities in these GOSP's were
sized based on a grid loading of 150 bbl/(D-ft2) as shown in Work Aid 1A.

The correlation line in Work Aid 1A for vessel loading is described by the equation:

bbl = 56.9 log ∆ρ + 64.3 for 0.04 <

∆ρ
< 50 (Eqn. 4)
10
D-ft2 µ µ

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Sizing (Cont'd)

This correlation is similar to what is typically used by the vendors. In both the equation and
Work Aid 1A, the units of the separation parameter (density difference between oil and water
divided by oil viscosity, Dr/m) are (g/cm3)/Poise. Densities and viscosity are those at desalter
operating temperature. However, if this information is not readily available, the densities can
be estimated from Work Aid 1B and the viscosities from Work Aid 1C. Especially with
viscosity, effort should be made to verify estimates from the figure with actual data. Vessel
loading in bbl/(D-ft2) is based upon the maximum horizontally projected area of the desalter
vessel, including the area contributed by the heads. Care must be taken to distinguish between
tangent-to-tangent and end-to-end vessel size specifications.

For multistage desalters, each stage would be sized as discussed above.

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Performance Evaluation and Troubleshooting

Performance Indices

Several indices have been developed to evaluate desalter performance. These indices provide
a means of monitoring the overall efficiency of the process, as well as the key individual
operations, namely mixing the crude and wash water and separating the resultant aqueous
emulsion from the oil. The indices include the desalting or overall salt removal efficiency,
dehydration efficiency, and several indices for evaluating the effectiveness of the wash
water/oil mixing. Together with the effluent water quality, they act as guides toward
determining whether the desalter is performing properly and which aspect of desalter
operation must be modified to obtain good performance.

Work Aid 2 summarizes the various performance indices. In order to quantify these indices,
reliable desalter operating data must be obtained. These data include the water entrained in
the feed and desalted oil (Wi and Wo, respectively, expressed as vol% and usually determined
by BS&W), salt content of the feed and desalted oil (Si and So, respectively, expressed as ptb
of NaCl), wash water rate (Ww, expressed as vol% of oil feed rate), and the salt content of the
wash water (Sw, expressed as ptb of NaCl). This terminology is summarized on the desalter
block flow diagram shown in Figure 15. Reliable analytical techniques are required for the
BS&W, salt, oil-in-effluent water, and solids-in-oil measurements.

DESALTER FLOW DIAGRAM ILLUSTRATING

PERFORMANCE INDEX TERMINOLOGY

FIGURE 15

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Analytical Procedures

Proper evaluation of desalter performance requires analysis for BS&W and salt in the feed
and desalted oil. The water contained in this oil, as determined by distillation, may also be
desirable to differentiate between dissolved and entrained water in the oil. Since serious
errors can be introduced in the efficiency calculations, and therefore the evaluation and
troubleshooting process, by inaccurate analytical results, it is important that reliable
procedures be carefully followed to obtain the necessary data.

BS&W should be determined by the centrifuge method, using water saturated toluene and
demulsifier. The analysis should be performed at about 140°F. A comprehensive test
procedure is described in the Manual of Petroleum Measurement Standards (MPMS). The
elevated temperature and demulsifier addition are essential to obtain reproducible results.
BS&W analyses determine only the entrained water in the sample at the analysis temperature.
Total, entrained plus dissolved, water is best determined by the distillation method from the
MPMS.

The most reliable method for determining the salt content in the oil is by the extraction of
samples with water in the presence of suitable solvents, and analysis of the aqueous extract.
The salts of most concern to the refinery are the chlorides, because they cause corrosion at
pipestill conditions. The aqueous extract is therefore analyzed for chlorides by titration with
silver nitrate solution.

Common Problems/Corrective Actions

The most commonly experienced desalter performance problems include low desalting
efficiency, oily or black effluent water, and water carryover in the desalted crude. Observed
operating difficulties include formation of a thick emulsion band in the desalter, widely
fluctuating voltage or amperage readings, low voltage, and high current draw. There can be
several possible causes for each desalter problem. Depending on the cause, different
corrective actions are required.

Common desalter performance and operating problems are indicated in Work Aids 3A to 3G,
with a list of possible causes and associated corrective measures. The appropriate action
depends on the cause of the problem.

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Work Aid 1A

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Work Aid 1B

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Work Aid 1C

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Work Aid 2: Desalter Performance Index Summary

GOOD
PERFORMANCE
INDEX SYMBOL DEFINITION VALUE
Si – So
× 100
Desalting Efficiency - Si > 90%

Ww + Wi – Wo
× 100
Dewatering Efficiency(1) - Ww + Wi > 95%

Wo Si – W
i
Mixing Efficiency(2) η So
× 100 -
Ww

Wo Si + 0.01 Ww Sw
Optimum Salt Content(3) A -
Ww + Wi
A
Mixing Index MI So > 0.90
Si – So
Process Efficiency E × 100 -
Si – A

where: Si = Salt content of crude oil charge, ptb of NaCl

So = Salt content of desalted oil, ptb of NaCl
Sw = Salt content of wash water, ptb of NaCl
Wi = Water content of crude oil charge, vol%
Wo = Water content of desalted oil, vol%
Ww = Wash water rate, vol% of crude oil charge rate

Notes: (1) WW includes recycle water, if any.

(2) Based on salt-free wash water.
(3) Use fresh water rate and salt content for WW and SW, respectively.

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Work Aid 3A: Troubleshooting Desalter Operating/Performance Problems:

Inadequate Salt Removal

POSSIBLE CAUSES CORRECTIVE ACTION

Desalter capacity exceeded by handling heavier Decrease throughput.

oil than design basis. Increase operating temperature.
Blend heavy oil with lighter oil.

Insufficient wash water rate. Increase wash water rate to between 4% and 8% of oil flow
rate.

Inadequate mixing. Increase mix valve ∆P in 1-2 psi increments to establish

optimum.

Low operating temperature. Increase temperature of untreated oil, close all unnecessary
heat exchanger bypasses.

Low electrode voltage. Check electrical system for operating problems.

Insufficient demulsifier dosage or ineffective Increase demulsifier chemical injection rate and/or change
demulsifier. type.

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Work Aid 3B: Troubleshooting Desalter Operating/Performance Problems: High

Water Carry over in Desalted Oil

POSSIBLE CAUSES CORRECTIVE ACTION

High oil/water interface level. Check water level by using interface sampling lines;
decrease level to lowest possible with good effluent water
quality and clear water at 30 in. level.

Excessive mixing valve ∆P. Open mixing valve completely, allow amperage to stabilize,
and increase mixing valve pressure drop slowly (allow
about one-half hour per adjustment) to establish optimum
setting.

Excessive water injection. Reduce wash water injection rate to between 4% and 6% of
oil flow rate.

Very high BS&W content in oil feed. Sample crude for BS&W; decrease wash water injection rate
to compensate for excess water in feed.

Electrical failure. Check voltage and amperage readings; if transformer or

entrance bushing failure identified, or power cannot be
restored immediately, discontinue wash water injection.

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Work Aid 3C: Troubleshooting Desalter Operating/Performance Problems: Oily

Effluent Water (Black Water)

POSSIBLE CAUSES CORRECTIVE ACTION

Low oil/water interface level. Check water level by using interface sampling lines; raise level until clear
water is obtained at the 30 in. level and effluent water quality is acceptable
without excessive water carryover into desalted oil.

Excessive mixing valve ∆P. Open mixing valve completely until operation stabilizes, then increase ∆P in
small increments until optimized. If wash water rate too high, decrease to
between 4% and 6% of oil flow rate.

High effluent water pH. Check effluent water pH. If greater than 7.5, reevaluate wash water
components, acidify wash water with H 2SO4 until effluent water pH is
between 5.5 and 7.0.

Sludge in desalter. Clean desalter. If not possible, try operating with higher interface levels as
long as salt removal efficiency is not impaired.

High solids concentration in Check wash water for particulates and minimize where possible. Investigate
effluent brine. (Excessive oil incorporating improved solids wetting agent in chemical additives package.
content in solids.)
Excessive asphaltenes in crude. Increase water residence time in desalter by raising interface level, providing
this does not interfere with desalting efficiency. Avoid blending light
naphtha with heavy oils.

Low operating temperature. Close any unnecessary bypasses to maximize preheat, if operating
temperature is below normal.

Insufficient or ineffective Increase chemical demulsifier dosage and/or change demulsifier.

demulsifier addition.

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Work Aid 3D: Troubleshooting Desalter Operating/Performance Problems: Wide

Emulsion Band

POSSIBLE CAUSES CORRECTIVE ACTION

Oil feed properties -- high Slug feed chemical (e.g., 2 to 4 x normal rate) for a maximum of 2 to 3
BS&W, low gravity, waxy hours -- then lower injection rate to less than 10 ppm to stabilize operation.
constituents, high particulate Investigate offsite crude handling procedures. Check for alternative
loading, emulsifiers from oil chemical additive package with more effective solids wetting agent.
field recovery.
Excessive mixing valve ∆P Open mixing valve completely, allow amperage to stabilize and slowly
increase ∆P to optimum value.

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Work Aid 3E: Troubleshooting Desalter Operating/Performance Problems:

Voltmeter and/or Ammeter Readings Vary Widely and Continuously

POSSIBLE CAUSES CORRECTIVE ACTION

Water level in desalter too high. Check water level using interface samples; decrease to lowest level that
gives good quality effluent and clear water at 30 in. level. Check interface
level controller and valve for proper operation; check sensor calibration if
necessary.

Stable emulsion formed in Increase injection rate and/or change type of demulsifier chemical.
desalter.
Excessive water injection. Check that wash water rate is between 4% and 6% of oil flow rate; stop
wash water injection if controller or water flow meter operation is
questionable.

Gas forming in desalter vessel. Operating temperature too high or back pressure insufficient. Check
backpressure valve operation.

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Work Aid 3F: Troubleshooting Desalter Operating/Performance Problems:

Continuous Low Voltage and/or High Ammeter Readings

POSSIBLE CAUSES CORRECTIVE ACTION

Stable emulsion has entered Stop wash water injection and operate without water for about 30 minutes.
desalter. If unsuccessful, decrease interface level and stop desalter operation for about
2 hours and then resume. When voltage returns to normal, resume wash
water injection with mixing valve wide open; slowly increase mixing valve
∆P to optimum. Increase injection rate and/or change type of demulsifier
chemical.

Water/oil interface too high. Check level versus setpoint using interface sampling system. Lower water
level and confirm proper operation of interface level control system.

Temperature too high. Check desalter operating temperature. Check oil conductivity-temperature
relationship with desalter vendor. Operate desalter at temperatures where oil
is less conductive.

Failed entrance bushing. Check bushing and replace if necessary. Ascertain that transformer
connected to bushing is not source of problem before checking bushing.

Failed insulator inside desalter. Take desalter out of service. Empty and purge the vessel. When entry is
permitted, enter vessel, determine which insulator has failed by visual
inspection and/or electrical resistance test, and replace it.

Energized electrode has become Shut down system, empty and purge vessel. When safe entry permitted,
grounded. inspect vessel interior and unground electrode.

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Work Aid 3G: Troubleshooting Desalter Operating/Performance Problems: Sharp

Increase in Current Draw (Amperage)

POSSIBLE CAUSES CORRECTIVE ACTION

Water slug entering with crude. Reduce wash water injection rate and check offsites crude handling
procedures.

High water level in desalter. Check level controller setting by using interface sampling system. Lower
level while retaining good effluent water quality and clear water at 30 in.
level.

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GLOSSARY
APS Atmospheric pipestill.

BS&W Basic (or bottoms) sediment and water content in crude oil expressed as
volume percent and determined by a centrifuge procedure.

desalting efficiency The percentage of the original salt removed by desalting.

dewatering efficiency The percentage of wash water plus water contained in the incoming crude
that is removed in the desalter.

kVA Kilovolt-ampere.

kW Kilowatt.

mixing efficiency The percentage of feed water used for perfect mixing.

mixing index The ratio of the optimum salt content to the actual salt content in the treated
oil.

oil-in-water emulsion Oil as the dispersed phase in a continuous water phase. The
effluent brine from the desalter may be an oil-in-water emulsion.

optimum salt content The best possible desalting obtained when all of the brine droplets are
coalesced with all of the wash water droplets dispersed into the crude during
the mixing process, and the dispersed water is reduced to the practical
minimum in the electrical dehydration step.

process efficiency The ratio of the actual to the optimum salt removal efficiencies.

ptb Salt content in oil is expressed as ptb. One ptb is one pound of salt (as NaCl)
per thousand barrels of oil, and, depending on the specific gravity of the oil,
corresponds to approximately 2.85 wppm.

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stable emulsion Either a water-in-oil or oil-in-water emulsion wherein the dispersed phase
does not coalesce or separate from the continuous phase. Stable emulsion
layers can grow in a desalter and result in excessive water and salt carryover
into the treated oil, as well as a very oily effluent brine sometimes referred to
a "black water."

water-in-oil emulsion Product of the dispersion of water (dispersed phase) into oil (continuous
phase) with the water droplets larger than colloidal size. The feed to the
desalter is a water-in-oil emulsion.

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REFERENCES

(1) Bartley, D., "Heavy Crudes, Stocks Pose Desalting Problems, Oil & Gas Journal, February 1, 1982.

(2) Non-proprietary information from the ER&E Desalter Handbook and Operating Guide, August 1986.

(3) Manual of Petroleum Measurement Standards.

(4) Non-proprietary information from EPRCo Production Operations Division Surface Facilities School,
"Crude Oil Desalting," Volume I, March 1986.

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APPENDIX A

SAUDI ARAMCO DESALTER DESIGN DATA

D30 314 D29 64B U20
Plant No. SH SH SH Plant 15 G.26 G.57 ABQ ABQ
GOSP-3 GOSP-4 GOSP-6 RT REF. Safaniya Safaniya GOSP-2 GOSP-6

Vendor Natco Natco Natco Petrolite Petreco Natco Mitsubishi Natco

Crude Oil Capacity,

1000 B/SD 330 330 330 250 162 162 165 220
(per train) (per train)
Diameter, ft 14 14 14 16 14 14 12 12
Length (T-T), ft 148 148 148 140 148 148 87 118
Operating Temp., °F 90 90 90 250 142 142 90 175
Crude Gravity,
°API at 60°F 35.3 35.3 35.3 28.1 27.7 27.7 41 35
(at cond.) (at cond.)

Crude sp.gr.at Cond. 0.8374 0.8374 0.8374 0.82 0.860 0.860 0.82 0.85
Viscosity, cP 5.4 5.4 5.4 2.62 8.75 8.75 4.3 6.4(1)
at Cond.

No. of Vessels
- in series 2(2) 2(2) 2(2) 1 3(3) 3(3) 2(2) 2(2)
- in parallel – – – – 4 4 – –
(no. of trains)

Electrical Config. single single single – single volt single – –

volt volt volt volt
Transformers
- number 3 3 3 3 3 3 3 3
- size, kVA – – – 150 100 100 75 –

Salt Content, ptb

- inlet 9963 34807 25540 3-10 20947 20947 9180 –
- outlet < 10 < 10 < 10 1 < 10 < 10 < 10 < 10

Inlet Water Content, 15 30 30 5 30 30 17.4 16.5

vol%

Notes: (1) Estimated viscosities.

(2) One electrostatic dehydrator vessel and one desalter vessel in series.
(3) One electrostatic dehydrator vessel and two desalter vessels in series.

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APPENDIX B

DESALTING EQUIPMENT VENDORS

Natco

Natco, Inc.
P. O. Box 1710
Tulsa, OK 74101
Telephone: (918) 663-9100
Telex: 49-2427
Cable: Natco Tulsa

Natco U.K. Limited

London, England
Telephone: (01) 499-9423
Telex: 25776

National Tank France

Paris, France
Telephone: 225-0167
Telex: 650225

Howe-Baker

Howe-Baker Engineers, Inc.

P.O. Box 956
Tyler, TX 75710
Telephone: (214) 597-0311
Telex: 735450 Howe-Baker Tyl
Cable: HOWBACO

Howe-Baker Engineers, Inc.

European Division
Europa House, Allum Lane
Elstree, Hertfordshire WD6 3NG, England
Telephone: (44+1) 953-7221
Telex: 23985 HOBAC G
Cable: HOWBACO ELSTREE

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DESALTING EQUIPMENT VENDORS (CONT'D)

Howe-Baker (Cont'd)

Howe-Baker (Italiana) S.r.l.

Via V. Monti, 101
20099 Sesto S. Giovanni
Milan, Italy
Telephone: (39+1) 247.09.59
Telex: 320243 HOWBAC I

HOWMAR INTERNATIONAL LIMITED

Albany Park Estate
Frimley Road
Camberly, Surrey GU15 2QQ
England
Telephone: (44+276) 681 101
Telex: 858646

Petreco

Petrolite Corporation
Petreco Division
P.O. Box 2546
Houston, TX 77001
Telephone: (713) 926-7431
Telex: 775 248

Petrolite GmbH
P.O. Box 2031
Kaiser-Friedrich-Promenade 59
6380 Bad Homburg 1, West Germany
Telephone: 49-6172-12930
Fax: 49-6172-28260

Petrolite-France S.A.
25 Rue Beranger
75003 Paris, France
Fax: 33-14-804-9337

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