17 Apr. 00
ADMA-OPCO
On-site Training Course
PROCESS
Module - D 14
CRUDE OIL DEHYDRATION &
DESALTING
Gap Elimination Program
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Process
Module - D 14
CRUDE OIL DEHYDRATION &
DESALTING
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TABLE OF CONTENTS
I.
FREE WATER SEPARATION
II.
EMULSION
III. HEATER TREATER
IV. ELECTROSTATIC TREATER PROCESS PLANT
DESCRIPTION
A.
B.
C.
D.
E.
Process Design Basis
Principles of Process
Principles of Operations
Chemical Injection
Main Control Loops
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OBJECTIVES
Upon completion of the module the developee will be able to:
¾ Define the free water and water cut.
¾ Explain the differences between free water and emulsified water.
¾ Identify the emulsifying agents.
¾ Understand the crude oil dehydration and desalting process.
¾ Describe the heater treater and identify its sections and internals.
¾ Explain the dehydration and desalting parameters and their effect on water-oil
emulsions.
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CRUDE OIL DEHYDRATION AND DESALTING
I.
Free water separation
•
The production facilities that include a treatment process, is concerned with oil and gas
separation and treatment.
•
The main reason for this is to meet the requirements and quality control.
•
In oil fields, after the initial gas-oil separation process, the oil must be treated to remove
water, salt.
•
The pipeline requirement for oil must have its water content reduce to 2% by volume.
•
All well streams contain water droplets of various sizes, it settles out as free water.
•
100 X Volume of free water = % water cut
Total volume of
liquid produced
•
Free-water knockout is a separation vessel located along the flow stream at a point of
minimum turbulence.
•
The oil and water mixture is allowed sufficient time to separate.
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II.
Emulsion
1.
Emulsion
It is one of the liquids is spread out or dispressed, through out the other in the form of
small droplets.
2.
Two Types of Emulsion
-
Water is dispressed in oil, water in oil emulsion [this the oil field emulsion].
-
Oil in water emulsion;
Flight Emulsion “difficult to break”
Loose Emulsion “easy to break”.
This depends on the type and amount of emulsifying agent present.
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WATER IN OIL EMULSION
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3.
4.
Emulsifying Agents:
-
It is the substance that promotes the formation and stability of an emulsion.
-
It is collecting on the surface of water droplets and forming tough film which keeps
the droplets from joining.
-
It includes asphalt, resins, paraffins and oil soluble organic acids.
Breaking an Emulsion:
-
To break an emulsion, the film must be neutralized or destroyed by using treatment
methods;
-
This treating is done by;
a)
Using various types of equipment.
Free-water knockouts, separators.
Heater Treaters, and Electro Static Treaters.
b)
5.
By adding chemicals to the emulsion immediately after it is produced.
Emulsion Stability:
The factors affecting Emulsion Stability are;
-
Emulsifying Agent.
-
Viscosity of Oil.
-
A.P.I. Oil Gravity.
-
Water Percentage.
-
Agitation.
-
Droplet size.
-
Age of Emulsion.
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6.
Treating Emulsion:
It may include one or more of the following:
-
Allowing Settling Time.
-
Applying Heat.
-
Injecting Chemicals.
-
Using Electricity or Mechanical Devices.
•
Setting Time:
It is affected by viscosity size of water droplets and gravity differential.
•
•
•
•
Applying Heat:
-
Heat causes water droplet to move faster, it collide, heavier droplets form.
-
Heat lowers the viscosity of oil.
-
Heat speeds up chemical action; the water droplet expand and break the film
of emulsifying agent.
-
Too much heat will;
*
Waste energy.
*
Cause greater wear on the equipment.
Adding Chemicals:
-
Emulsion breaking chemicals are injected into the well stream ahead of the
oil treatment.
-
They react with film of emulsifying agent around water droplets, allowing
the droplets to coalesce.
Using Electricity:
-
To help the coalescing of water droplets,
-
It is usually used in conjunction with heat and chemicals.
Using Mechanical Devices
The free water knock out is gravity type separator to remove excessive water
from the produced oil.
Heater treater is an example of using electricity and mechanical devices and
chemical injection
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III.
Heater Treater Components
1.
External Components
Fire Box, Gas Supply Line:
Stack, Thermometer, Thermowell Inlet Line, Gas Equalizer, Gas Dome, Gas Back –
Pressure Valve.
Oil Outlet, Oil Dump Valve.
Water Outlet, Water Dump Valve.
Interface Level Controllers, Drains.
2.
INTERNAL SECTIONS:
*
Gas Separation Section
Baffle, downcomer.
*
Free Water Knockout Section
Water wash, flow spreader
*
Heating Section and its Weir
*
Settling Section “Coalescing Section”
Flow spreader, weir, clean oil box.
*
Water Draw off Section
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IV.
Electrostatic Treater Process Plant Description
Purpose of the Elecrostatic Treater Process Plant
Water is removed from the oil initially by three phase separators and the Spheroids. The oil
then passes to the new Electrostatic Treatment Plant (ETPP) where more water and salt is
removed.
The ETPP will reduce the salt content in the effluent oil stream to 25 pounds per thousand
barrels (25 PTB) and 0.15% water.
The design oil charge rate is 295,000 BPD Umm Shaif and 378,000 Zakum plus 10%^
formation water. The total maximum rates are 324,500 Umm Shaif and 415,800 Zakum.
The produced water removed from ETPP flows to the Sour Water De-oiling Plant (SWDP).
The ETPP is supplied with fuel gas from ADGAS.
Also fuel gas can be supplied from a Gas Sweetening Unit (GSU) and from Zakum Sour Gas.
The ETPP is supplied with wash water from a Sea Water Oxygen Removal Plant (SWORP).
Section 4.2 BASIC PRINCIPLES OF PROCESS
General
Desalting is a hot water extraction process. The salt or salt solution in a crude oil is diluted
by adding wash water and then thoroughly mixing.
In practice, the mixing stage can approach 100% efficiency and then the salt content of the
desalted crude is dependent upon the amount or dilute solution left, and is given by the
formula:
Salt Content of Desalted crude in (PPM) = ( K1 X C1 ) + ( K2 X C2 ) X K3
K2 + K3 X 100
Where :
K1 is % of formation water in raw crude.
C1 is salt content of formation water (in ppm).
K2 is % of added dilution water.
C2 is salt content of dilution water (in ppm)
K3 is % of residual water in treated crude.
Note: To convert the ppm salt content of desalted crude to PTB
(Pound per Thousand Barrel) use the equation:
1 PTB = approximately 3.436 ppm
After mixing, the crude / salt water mixture enters the desalter where separation occurs.
This separation is assisted by temperature, an electric field and / or demulsifier chemicals.
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Description
The oil flow is similar for both Umm Shaif and Zakum crudes. The oil flow is pumped from
the Horton spheres by the respective crude charge pumps.
Oil and formation water enters the unit via two lines, one for each crude. The crude flows
split into a minimum of three streams with a common spare stream for either crudes.
The crude feed to each train is first heated in a tubular heat exchanger using steam as the
heating medium.
From the heat exchanger the oil flow passes through a gas fired heater.
The inclusion of the steam heater is important since this minimizes the required heat capacity
of the fired heater and reduces its gas side corrosion problems.
The outlet temperature of the oil from the gas heater is 100 degrees F.
The heated crude from each train then passes to the individual dehydration and desalting
vessels.
The crude flows through a mixing valve and into the lower section of the horizontal
dehydration vessel.
Recycled brine from the desalter is injected upstream of the mixing valve under level control
from the desalter oil / water interface by the recycle pumps.
On leaving the upper section of the dehydration vessel the crude flow then passes through
another mixing valve in the lower section of the desalting vessel.
De-oxygenated water pumped from the SWORP area is injected into the crude flow upstream
the mixing valve, under flow control. A normal injection rate is about 5.0% of the crude
flow.
The brine is drawn-off under level control and pumped to the dehydration vessel.
On leaving the top section of the desalter the crude join the other streams in a common
header and leaves the battery limits via a 30” line to the H2S stripping unit.
The pressure drop across the mixing valves is manually adjusted to ensure good mixing with
the wash water. A normal range is 7-30 psig depending on throughput.
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Desalter / Dehydrator Vessels
Each of the vessels is provided with high and low oil / water interface alarms independent of
the interface level control system.
Try cocks are provided for testing and checking the interface level.
Interface drains are used to draw off any emulsion formed and the emulsions are treated in a
separate vessel by steam heating.
Any recovered oil is pumped back to the crude oil outlet lines. Water being returned to the
SWDP.
There are 6 x 4” sand drains on each vessel that are used to draw off any solids accumulating
in the base of the vessels.
The solids are removed by water jetting and separation takes place in the desander vessel.
On the vessels there is a locally mounted panel with light signals and ammeters associated
with the dehydration and desalting operation.
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SEA WATER OXYGEN REMOVAL PLANT
Purpose of the sea water oxygen removal plant, is to provide the ETPP with
sufficient and constant stream of wash water for the treatment process.
The SWORP strips oxygen from the raw sea water and doses it wit biocide thus
limiting corrosion and bioglogical growth within the D&D system. The plant is
illustrated by attached flow diagram identifying the main four sections of
SWORP.
i)
Chlorination Section
ii)
Filtration
iii)
Oxygen Removal
iv)
Chemical Injection
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SOUR WATER DE-OILING PLANT
As the resulting effluent water contains much salt, hydrogen sulphide and
residual oil, and it is treated in the (SWDP) to remove the bulk of residual oil
before discharging to sea 1.5 km offshore.
The attached figure of (SWDP) is used to illustrate the purpose of SWDP.
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A) PROCESS DESIGN BASIS
1.
2.
3.
Crude Oil Properties
Zakum
Umm Shaif
Gravity at 600 F (API)
41.0 – 41.6
38.0 – 38.5
Viscosity at 700 F (CST)
4.1
5.7
Viscosity at 1000 F (CST)
2.9
3.8
Specific Heat (Btu / Ib / 0F)
0.47
0.47
% H2S (Wt.)
0.009 – 0.013
0.052 – 0.085
Wax point ( 0 F )
61 – 68
66 - 75
Typical Properties of Formation Water
Zakum
Umm Shaif
pH (average)
6.8
5.1
pH *range)
5.0
4.6 – 6.4
Total dissolved solids (ppm Wt.)
250,000
250,000
H2S content (Max. in ppm Wt.)
600
600
Crude Oil Charge to Gas / Oil Separators and Spheroids
Zakum
Umm Shaif
Oil Charge Rate (MSTBD)
378*
295*
Formation Water (MBD)
0 – 75.6
0 – 59
Note: * These crude production rates have been brought into line with the capacity of the
ETPP.
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4.
Crude Oil Charge to ETPP
Zakum
Umm Shaif
Oil charge rate (MSTBD)
378
295
Formation Water (MBD)
0 – 37.8
0 – 29.5
415.8
324.5
Pressure ex. Feed pumps (psig)
183
197
Pressure at ETPP inlet
(Winter* Summer **)
55* - 82**
53* - 73**
Total Rate (MBD)
Note: These crude oil flow rates are based on required average production rates plus an
allowance for curtailments due to bad weather etc…)
5.
6.
Crude Oil Charge to Crude Stripping Units ( from ETPP )
Zakum
Umm Shaif
Pressure ex. ETPP (psig)
64
75
Pressure at CSU inlet control
Valve (psig)
15
15
Temperature (0F)
90 – 100
90 - 100
Crude Oil Product Quality ( from ETPP )
Zakum
Umm Shaif
PS & W in crude (% vol.)
0.15
0.15
Salt content of crudes
(Maximum in PTB)
25
25
Where PTB is pounds per thousand barrels)
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7.
Effluent Quality ( from ETPP )
Oil content of water effluent
from ETPP (ppm vol.)
8.
Zakum
Umm Shaif
< 200
< 200
Water Removal Rates from Gas / Oil Separators and Spheroids
The rate at which the produced water will be removed at any particular stage is uncertain, but
the overall removal rate is expected to be greater than the equivalent of 10% of peak crude
production rate. Thus, the overall water removal rates are:
HP & LP separators and spheroids
actual (10% of crude) (BPD)
Zakum
Umm Shaif
37,800
29,500
Total Rates (actual)
67,300
Maximum rate at which water can be removed from each separator stage is as follows (i.e.
design bases on earlier higher production rates):
HP Separators (BPD)
33,000
39,000
LP Separators (BPD)
33,000
39,000
66,000
78,000
33,000
39,000
Total from Separators
Spheroids (BPD)
Overall Total (Design) (BPD)
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B)
PRINCIPLES OF PROCESS
Desalting is a hot water extraction process. The salt or salt solution in a crude oil is diluted by adding
wash water and then thoroughly mixing.
In practice, the mixing stage can approach 100% efficiency and then the salt content of the desalted
crude is dependent upon the amount of dilute solution left, and is given by the formula:
Salt content of desalted
crude (in PTB)
= Salinity of water in desalted crude (lbs/bbl) x 1000 x 3
1–x3
Where :
Note:
x 3 is water cut fraction (vol. %) in desalted crude.
To convert the PTB (Pound per Thousand Barrel) salt content of desalted crude to ppm, use
the conversion:
1 PTB =
approximately 3.436 ppm (part salt per million part net crude of
52 ib/ft3)
After mixing, the crude / salt /water mixture enters the desalter where separation occurs.
This separation is assisted by temperature, an electric field and / or demulsifier chemicals.
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C)
PRINCIPLES OF OPERATIONS
Dehydration & Desalting System
1.
Desalting Process
The desalting process consists of two basic steps: Dehydration & Desalting.
The first step reduces remnant water in oil to at least 0.2%.
In the second step, a fresher water dilutant is injected to lower the average salt content to an
acceptable level.
Additional dehydration reduces remnant water content to 0.1% and the salt content in the crude
to 25 pounds per thousands (25 PTB).
2.
Dehydration
The first step in the process is water removal.
Through agitation, an emulsion is created by dispersion of the water in droplet form. It is held
in this state by emulsifying agent in crude oil.
These agents are generally resins, asphalt, organic acids and solids which are produced with the
oil.
They are attracted to the surface of the water droplets and help from a tough film around them,
isolating each water droplet from the other.
This film must be weakened or broken before coalescence can take place.
Chemical aids, demulsifiers and heat are used to break the emulsion.
By increasing the oil temperature, dispersion of the emulsion is more rapid and complete.
Oil density and viscosity are decreased for more rapid gravitational settling of the water
droplets.
The final part of the dehydration phase involves coalescing small droplets into larger ones so
that gravity separation can take place.
Both the dehydrator and the desalter use the same principle of electrostatic coalescence of the
water droplets to separate the salty water from the crude oil.
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3.
Electrical
The electrostatic coalescence process may be explained as follows:
4.
-
Water molecules is neutral, but its composition is a dipole (H+OH-), under electric field
the Dipole State is induced.
-
A droplet of water suspended in oil assumes a perfectly spherical shape if there are no
external force acting upon it.
-
Once a high voltage field is applied, the droplet distorts into an elliptical shape by the
positive charges (+) in the droplet being pulled to the side nearest the negative electrode
and the negative charges (-) are pulled to the positive charge.
-
The result is a rapid pulsation, which aids the demulsifier in destroying the film of
emulsifying agent.
-
This coupled with polarized attraction of the separate droplets stimulates coalescence and
when the water droplets are heavy enough they fall to the bottom of the vessel.
-
The force field is generated from a high voltage transformer (3.3 kv1) connected to the
internal grid plates.
-
Pairs of electrode plates are charged in opposition “positive and negative charge”.
-
Water droplets entering the field between the electrode plates are elongated and attracted
to one or the other, as the droplets approach the plates they accept the charge of the one
closest to them and are repelled towards the plat of opposite charge, the process is self
repeating.
Dilution Water Injection
Wash water (De-Oxygenated seawater) is supplied to the plant via a main 8” water line from
the Sea Water Oxygen Removal Plant (SWORP).
After entering the plant, the water flow rate is measured and transmitted to the control room
and if the rate is very low, a low flow switch activates a shutdown valve on the water supply
and initiates an alarm.
Before the wash water can be sued in the process, it must be heated to approximately 100 deg.
F.
Two steam heat exchangers (one spare) have been provided for water heating.
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The wash water temperature is controlled by an indicator / controller in the Zakum Control
Room.
After heating, the water is distributed throughout the plant via the main 8” supply header and
the following branches:
-
Dilution Water
As well as the injection before the desalter mixing valves, provision is made for injection
before the dehydrator mixing valves.
-
Sand Jet Water
Some wash water is used intermittently for desanding operations on the vessels.
The emulsion treater, desander, desalters, and dehydrators are provided with internal sand
/ sludge jetting nozzles which are used to wash solids out of the vessels.
-
Miscellaneous
A small amount of water is used by the oil in water monitor for sample dilution and by
the oxygen / combustible gas analyzer on the CHF heater for sample cooling.
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5.
Recycle Water System
After the mixture dilution water / crude oil enters the desalter, the water and oil are separated.
The water is heavier than oil and it is collected at the bottom of the desalter and must be
removed.
The water which is collected in the desalter is used by the process and is pumped (recycled)
from the desalter for injection into the oil just ahead of the dehydrator.
The water / oil interface level in the desalter is controlled by an external displacer (cage) type
level instrument and as the water level in the vessel varies up or down, the water flow rate out
of the vessel is increased or decreased to maintain the constant interface level.
A mechanical position switch on the level control valve trips the pump motor and accordingly
prevents the recycle water pump from operating when the valve is nearly closed.
If the dehydrator vessel is by-passed, recycle water may be disposed to the Effluent Water
Header and then to the SWDP.
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D)
CHEMICAL INJECTION:
Two vessels have been provided for site storage of oil demulsifier chemicals.
The chemicals are pumped to the tanks from offsite through two chemical supply lines.
There is a separate supply line for each storage vessel.
The outlet of each chemical tank is led to a manifold which can supply chemical to the suction
of 16 chemical injection pumps.
Two pumps (one spare) are provided for each desalter train and the emulsion treater.
Each pump is capable of taking suction from either chemical storage tank or a calibration pot.
A ½” chemical injection line for each train runs from the pump outlet to an injection point on
the 12” crude oil line just ahead of the flow valves.
The chemical injection rate should be changed when ever the crude oil rate is changes so that a
constant ratio is maintained.
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Purpose Of The Crude Oil Chemcial Injection Facilities
Chemicals are required for injection into oil in the Dehydration and Desalting
scheme as follows:
Demulsifier to promote the separation of water from the oil phase.
Corrosion inhibitor to protect the internal surfaces of pipeline and
equipment.
Scale inhibitor to prevent the precipitation of the scale products in
water.
Bulk chemical storage facilities are provided for four streams which are:
Umm Shaif
Umm Shaif
Demulsifier
Corrosion Inhibitor
Zakum
Zakum
Demulsifier
Corrosion Inhibitor
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N.B.
For Sea Water Oxygen Removal Plant, the following chemicals are injected for the following
purpose:
Chemical Injection:
-
Oxygen Scavenger Agent:
A catalysed sulfite chemical is injected as a liquid into the oxygen removal towers, in order to
reduce the residual oxygen i.e. commercially zero.
-
Scale Inhibitor:
To overcome the problems of scale formation in both the towers and the treated water system, it
is necessary to continuously inject an inhibitor into the sea water.
Anti Foam Agent:
An anti foam agent is added to the line of the oxygen removal towers. The anti foam agent
controls the foam formation rather than eliminating it completely.
-
Organic Biocide:
Organic biocide will be injected intermittently.
This maintains sterile conditions and prevents the growth of sulfate reducing bacteria’s (SRB’s).
-
Polyelectrolyte:
Required as a filter aid for the sea water filters.
The chemical is injected downstream of the booster pump.
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E.
-
MAIN CONTROL LOOPS
After injection of the recycle water, the crude oil and water are mixed by flowing through a
pressure differential valve PDV.
The pressure drop across the valve causes the oil and water to mix and the amount of pressure
drop can by adjusting the local mounted PDIC [by experience the pressure should be about 15
psig].
-
The oil / water interface level is controlled by LC which signals LV and LAH, LAL.
-
If the pressure build up occur PAH will alarm at 175 psig & PSV will lift at 350 psig.
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