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Table of contents:1. PURPOSE 2. SCOPE 3. DEFINITIONS AND ABBREVIATIONS
3.1 Definitions
3.2 Abbreviations
4. DESCRIPTION
4.1 Overview Production
4.2 Product Specification
4.3 Crude Oil Processing4.3.1 Wellhead and Manifold
4.3.2 Separation Gas & Liquid
4.3.3 Crude Oil Stabilization
4.3.4 Crude Oil Dehydration and Desalting
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Crude Oil Processing on Offshore Facilities 0
1.0 PURPOSE
This design guide is prepared to providebasic information and consideration for
the process design aspect of Crude Oil Processing for typical offshore facilities. Thisdocument provides an overview of separation of crude oil from well fluid for furtherprocessing.
2.0 SCOPE
This guide covers the overall summary of processing schemes, typical crudespecification, and data to help developing a preliminary phase of design.
Specific requirements of Project / Client / Local regulations shall prevail over thecontents of this guide.
3.0 DEFINITIONS AND ABBREVIATIONS
3.1 DefinitionsAPI Gravity
API gravity is a measure of how heavy or light a petroleum liquid is compared to water.API gravity is defined by the following formula;
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Asphaltenes
Asphaltenes are molecular substances in crude oil that are insoluble in low boilinghydrocarbon liquids such as heptane and are also non-distillable. These molecules aremade up of aromatic clusters containing a polar heteroatom group. In large moleculesthe aromatic rings are interconnected by paraffinic groups and by sulphur
Cloud Point
Cloud point is the temperature at which dissolved solids are no longer completelysoluble, precipitating as a second phase giving the fluid a cloudy appearance. In thepetroleum industry, cloud point refers to the temperature below which wax in crude oilform a cloudy appearance. Cloud point is measured by ASTM D-2500 testing method.
Pour Point
Pour point is the temperature at which the crude oil becomes semi solid and ceases toflow. The pour point is measured by ASTM D-97 testing method.
Reid Vapour Pressure
Reid Vapour Pressure (RVP) is measured by ASTM D-323 testing method. The sample isplaced in a chamber at a constant temperature of 100 oF. RVP is slightly lower than theTrue Vapour Pressure (TVP) at 100 oF.
Stabilization
Crude stabilization is a process of removing volatile components from crude oil toreduce its vapour pressure.
3.2 AbbreviationsBS&W : Basic Sediment & Water
FTHP : Flowing Tubing Head Pressure
GOR : Gas Oil Ratio
PTB : Pounds of salt per thousand barrels of oil
Ppm : Part per million
RVP : Reid Vapour Pressure
TEG : Triethylene Glycol
TVP : True Vapour Pressure
4.0 DESCRIPTION
4.1 Overview ProductionThe primary function of a production facility is to separate the product from the wellsinto saleable products and dispose of the rest in an environmentally friendly manner.The product from the wells typically consists of oil; gas; associated produced water andsediment. Figure 1 shows a typical schematic of oil and gas production.
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Figure 1. Typical Oil and Gas Production Schematic
Well fluids enter a separation train where the crude oil, gas, and bulk water areseparated. The separation train may consist of several stages of separators. In theseparation train, most volatile components of the well fluid will be vaporized. Thus thecrude oil will either be stabilized or partially stabilized. Crude stabilization is performedto achieve the specified RVP
After free water removal, produced oil may contain residual emulsified water. Thecrude oil is then further processed in a dehydration unit to reduce the water content toa value that acceptable for transportation or sales. Dilution water must occasionally beadded to reduce the salt content of the residual emulsion to a suitably low level. Theaddition of dilution water and followed by dehydration is called desalting process.
Gas separated from the separation train enters the gas processing train. The trainnormally comprises of gas compression system and gas dehydration system. Gasdehydration unit is required to remove water from the gas stream to prevent hydrateand corrosion problem in the pipeline. The most common method for gas dehydrationis a TEG contactor unit which is completed with a TEG regeneration system. The TEG(liquid) absorbs water from the gas stream to achieve the specified water content of theexport gas.
Compression of the gas to pipeline pressure is normally required to allow economictransport in reasonable small diameter pipeline.
A more complex gas processing train may include gas sweetening system to removethe acid gases which are CO2 and H2S. Both gases are very corrosive when liquid water
is present. Gas sweetening usually uses aqueous solution of various chemicals.Therefore a gas sweetening, if required, is normally placed upstream of dehydrationunit. However, gas sweetening system is not common for offshore processing facilities.Generally, any sour gas produced from offshore will be further processed in onshoregas plant.
Separated water from the well fluids is directed to the produced water treatment unitto render the water suitable for disposal to the sea. Oil removal is the first treatmentfor produced water. Oil-water emulsions are difficult to clean up due to the small sizeof the particles, as well as the presence of emulsifying agents. Hydrocyclone is commonequipment for produced water de-oiling purpose.
As an alternate of disposing water into the sea, the produced water could be re-injectedinto water injection wells. Before re-injection, produced water is usually filtered andtreated with biocides. Booster pumps and injection pumps are normally installed forwater injection system.
This guideline discusses the treatment of the crude oil to meet the product
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specifications such as vapor pressure, base sediment and water, salt content, and H2Sconcentration.
4.2 Product SpecificationCrude oils vary widely in composition and physical properties. Some are almost gas-likematerials of 65o API gravity, whereas others are semisolid asphaltic material with APIgravities of less than 10o. Light crude are generally more valuable to refineries and areeasier to handle than heavy crudes. Heavy crudes are more difficult to produce andsell.
Offshore crude oil product may be stored on the platform in large tanks (i.e. FPSO, FSO)and exported by a tanker, or exported through a pipeline. Typical specifications ofcrude oil are as follow:
Maximum vapor pressure : 10 – 12 psia RVP
A low vapor pressure is important for stability of the crude during storage andtransport, especially if the crude is transported via tanker. A high vapor pressureresults in loss of volatile components in storage tanks or tankers. Gases evolved fromunstable crude are heavier than air and difficult to disperse. Consequently the risk ofexplosion is greater. To prevent the release of gas during transport or storage, thevapor pressure specification is usually from 10 to 12 psia RVP.
For pipeline export, the crude oil is sometimes partially stabilized. The true vaporpressure (TVP) of the crude is typically 6.9 Bara at 38 ◦C. This value is considered toretain a large part of C3-C4 components in the liquid stream. The crude oil will be
further stabilized at onshore terminal facilities and the C3-C4 can be converted into LPG
product. The TVP will be set in conjunction with the operating parameters of thepipelines and must be lower than the proposed arrival pressure at the delivery location.The crude oil must be pumped to ensure pipeline is liquid phase throughout.
BS & W : 0.2 – 1.0%
The presence of water in the crude oil must be limited for the following reasons;
– Shipping emulsified oil wastes costly transportation capacities occupied by water
– Mineral salts present in produced water corrode equipment, pipeline, and storagetanks.
– Dissolved sediments in water can cause plugging and scaling problems to heatexchangers and column trays in the refinery.
In the Gulf of Mexico, 1% BS & W typically meets offshore crude sales specifications.Other parts of the world require crudes with less than 0.5% water by volume, especiallyif the crude is loaded offshore to tankers.
Maximum salt concentration : 10 – 30 PTB
Salts can cause severe corrosion in tankers, pipeline, and refining equipment. Salts cakeout inside equipment, cause poor flow and plugging, reduce heat transfer rates inexchangers. Under some circumstances chlorides can hydrolyze to HCL, which isextremely corrosive. In addition, some mineral salts can poison expensive catalysts.Therefore the salt concentration in the crude oil must be limited. The salt content in thecrude product is typically specified at 10 – 30 PTB
Maximum H2S : 10 – 100 ppmw
H2S is removed from crude oil together with flash gas at each separation stage. 50 ppm
by volume can normally be achieved using simple separators and heating. Thoughnormally not used in offshore facilities, 20 ppm and lower can normally only beachieved by the use of a re-boiled stripper.
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4.3 Crude Oil Processing
Well fluids are complex mixtures of different compounds of carbon and hydrogen withdifferent densities, vapor pressure and physical characteristics. As the well fluids travelfrom the reservoir to the production facility, it experiences pressure and temperaturereduction. The characteristics of the well stream continuously changes with theevolving gas from the liquid as the pressure reduces. The separation of these phases isone of the basic operations in production, processing and treatment.
4.3.1 Wellhead and Manifold
The oil production system begins at the wellhead, which includes at the least one chokevalve, whose percentage opening determines the flowrate from the wells. Most of thepressure drop between the well flowing tubing head pressure (FTHP) and the separatoroperating pressure occur across the choke valve.
Whenever two or more wells are installed on a wellhead platform, a productionmanifold as well as test manifold should be installed to gather fluid from the wells priorto be processed in separator or exported via pipeline. The test manifold is provided toallow an individual well to be tested either via a Test Separator or MultiphaseFlowmeter (MPFM).
4.3.2 Separation Gas & Liquid
As described earlier, the well-stream may consist of crude oil, gas, condensates, waterand various contaminants. The purpose of a separator is to split the flow into desirablefractions. Primary separation of produced water from gas and oil is carried out inproduction separator. Separators work on the principle of gravity separation.
Following type of separators are generally used in the industry:
Two Phase Separator;
A two phase separator is used to separate well fluids into gas and liquid mixtures.
Three Phase Separator
This type of separator is used when the expected outlet streams are gas, oil /condensate, and water.
Figure 2. Typical Three Phase Separator with Internals
A separator can be either horizontal or vertical configuration,
Horizontal separator
Horizontal separator is preferred for low GOR well fluids and three phase separation.
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Table below shows the advantages and disadvantages of horizontal separators:
Advantages Disadvantages
Provide sufficient residence time for liquid-liquidseparation
Only part of shell available for passage of gas
Large liquid surface area for foam dispersion generallyreduces turbulence
Larger foot print / plot area
Large surge volume capacity Liquid level control is more critical
Lend themselves to skid mounting and shipping More difficult to clean produced sand, mud, wax,paraffin. etc.
Vertical separator
Vertical separator is preferred high GOR well fluids and two phase separation
Table below shows the advantages and disadvantages of vertical separators:
Advantages Disadvantages
Have full diameter for gas flow at top and oil flow atbottom
Not suitable for bulk liquid-liquid separation
Occupy smaller plot area Occupy more vertical spacing between decks inoffshore
Liquid level control is not so critical More difficult to skid mount and ship
Have good bottom drain and clean out facilities. Canhandle more sand, mud, paraffin, wax, etc.
More difficult to reach and service top-mountedinstruments and safety devices
Production separators of all types are sized according to the following parameters, tosuit product specifications:
– Fluid flow rates
– Operating Pressure and Temperature
– Oil in Water Specification (500-1000 ppm)
– Water in Oil Specification (1-3% vol)
– Liquid losses to vapor stream (subject to demister type)
– Liquid droplet size in gas outlet (150 microns and larger droplets can be removedwhen internals are not used)
In an oil system, separators are generally sized on the basis of liquid residence time.Particular attention must be given to foam and emulsion forming tendency of the crudeoil. Data can be obtained from laboratory analysis or from previous experience. Thetendency of crude oil to foam will require
– larger separator in order to maintain satisfactory vapor/liquid separation efficiency,
– chemical injection,
– specialist internals e.g. foam breaker.
Separation between water and oil is subject to the quality of emulsion and the terminalvelocity of droplets as given by Stokes’ Law. Crude oil with high viscosity and density (i.eHeavy Oil), will result in a very low droplet settling velocity and hence will require moreresidence time and consequently a large vessel size. Where emulsions are formed, de-emulsifying chemicals and heating may facilitate the water removal, although theprovision of a separate two phase (oil/water) separator may be required in severecases.
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At the design stage of crude oil separation train, an increased water production shouldbe considered. Separators must be sized for the worst operating case, or alternatively,adjustments may be made to existing separator internals and level control set points inorder to change the hold-up times of the two phases.
For sizing criteria and calculation of a separator, refer to the company developedguideline and validated spreadsheets.
4.3.3 Crude Oil Stabilization
Dissolved gas in the crude oil must be removed to meet pipeline, storage, or tanker RVPspecification. The presence of most volatile hydrocarbons increases the RVP. Removalof the dissolved natural gas components is called oil stabilization.
Crude oil can be stabilized by passing it through multiple separators in series where thevolatile components will vaporize. A stabilization column might replace the simpleflash-separation stages to achieve the required RVP, but these columns are rarelyfound offshore.
Stabilization of the crude oil often requires heat to be added or removed at certainpoints in the processing train. Crude heating may be required for:
Emulsion breaking and improved separation of oil and produced water.
Adjustments of final product vapour pressure and H2S content.
Particular attention should be given for high temperature well stream fluids, it may benecessary to cool the crude in order to avoid excessive vaporization resulting in lowerthan required RVP of the final product specification and loss of potential liquid product.
For crude oils containing wax, care must be taken in assessing skin temperature insidecoolers so that wax deposition is avoided. Skin temperatures should be at least 5oCabove the crude oil cloud point. When the cooling water supply temperature is belowthis temperature, a cooling water recycle can be incorporated to raise the cooling waterinlet to the required temperature. When the minimum cooling water temperature ismarginal for wax deposition, wax inhibitor injection may be considered instead of acooling water recycle system.
Number of Separation Stage
The well fluid pressure is often reduced in several stages of separation. If the reservoirconditions are such that the reservoir fluid can flow adequately against a wellheadpressure, separation in more than one stage will generally offer an economicadvantage. The purpose of multi stage separation is to achieve maximum hydrocarbonliquid recovery, to get the liquid stabilized, and minimize compression power requiredfor the gas stream. Multi stage separation of oil and gas involves a series of separatorsoperating at sequentially reduced pressures, with liquid flowing from first separator tothe next lower pressure separator.
When hydrocarbon liquids are removed from separator at equilibrium, the liquid is atits bubble point. With each subsequent pressure reduction, additional vapors areliberated. If the liquids were removed directly from a high pressure separator into astock tank, the resulting vaporization would cause the loss of some heavier ends.Making pressure reductions in several stages can help reducing these losses.Therefore, increasing number of separation stages can increase the volume of oilrecovered in the stock tank.
If the produced gas is to be gathered and compressed to sales transmission pressure,the allowable compression ratios and compression power requirements will usuallydetermine the pressure ratios between the various stages of separation. Therefore, theprocess engineer must evaluate the number of separation stages, compressionrequirements, and economics of each specific installation.
A process simulation program such as HYSYS is generally used to design and optimize acrude oil processing system to meet a given crude specification, usually vapour
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pressure (either TVP or RVP). Selection of a system is based on maximizing the crudeoutput whilst minimizing energy requirement (i.e. heating/cooling loads, compressionpower, etc.). Equipment size and weight is also a critical criterion.
The off gas from each separation stage can be compressed and treated for use as fuelgas, exported, or flared if quantities are minimal and applicable regulations permitflaring. In designing the oil processing system the gas compression requirementsinfluence the total energy input. Additionally the recycle of hydrocarbon condensatefrom the gas compression system must be included as this will influence theperformance of the system.
The optimum number of separation stages varies with Flowing Wellhead Pressure(FWHP), reservoir composition, off-gas compression requirement, and exportspecification for crude vapor pressure. A quick assessment of separation stagesnumber based on FWHP is given in the table below:
FWHP, Bara Number of Stage
1-20 1 or 2
20-70 2 or 3
Over 70 3 or 4
In offshore facilities, generally the numbers of separation stages are limited to threestages (HP/MP/LP) for the following reasons:
High construction, installation and maintenance cost of additional Separators andinterstage compressors.
Space limitation and weight concern.
There is a trade-off between number of stages and oil recovery. However, thenumbers of stages are optimized to achieve required RVP of oil recovered from laststage. High pressure in the first stage separator can sometimes reduce oilproduction from wells, particularly in late life.
Since the flowing tubing pressure usually decrease during the life of the field, acommon practice is to install separate production manifolds for each separator. In thiscase, wells with decreased well pressure would be rerouted to a lower pressureseparator, thus maximizing production. Figure 3 shows a typical flow scheme of 3stages separation
Figure 3. Typical 3 Stages Separation
1. 1. HP (1st Stage) Separator
The first stage Separator is generally a 3-phase separator. The separator pressure mustbe low enough to allow effective choke operation and thus control of well behavior.
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Therefore, wells with high enough flowing wellhead pressure are routed to the HPSeparator.
Gas separated from the HP Separator normally flows to the gas compression anddehydration system, and then exported through pipeline.
Bulk water in the well fluid is generally removed from the first stage separator, in orderto minimize heating/cooling of excess liquid at further processing. The removed wateris routed to the produced water treatment before it is disposed to the sea or used aswater injection.
From the first stage separator, water content in the oil stream typically reduces to 5 –10 % volume, and then flows to the 2nd stage separator.
1. 2. MP (2nd Stage) Separator
MP Separator is similar to the HP Separator but operates in lower pressure. The MPseparator receives liquid (oil) from the HP Separator, and due to pressure reduction,the light components of the liquid will vaporize. Gas separated from the MP separatornormally flows to an inter-stage compressor and then combines with the gas off fromHP separator.
The remaining water is removed from the oil, and routed to the produced watertreatment.
From the MP separator, water content in the oil stream typically reduces up to 2%volume or less, and then flows to the LP separator.
1. 3. LP (3rd Stage) Separator
LP Separator is a 2-phase (gas/liquid) separator which operates slightly aboveatmospheric pressure. The operating pressure and temperature of the final gas-oilseparation stage dictates the vapor pressure of the export crude. Generally stablecrude (10-12 psia RVP) requires a very low pressure and high temperature.
At the very low operating pressure, the last heavy gas component will flash out fromthe liquid. In some processes where the initial temperature is low, it might be necessaryto heat the liquid (in a heat exchanger) before entering the LP separator to achievegood separation of the heavy components.
Having selected an operating pressure, the required operating temperature can bechosen to meet specification. By minimizing the operating pressure, the correspondingtemperature is minimized, thus if heating is required, the heat input will reduce. In thecase of tanker quality crude, the minimum final stage pressure is fixed by the methodof gas disposal. The gas from the LP separator normally flows to flare system or feeds avapor recovery unit. The oil outlet which still contains small amount water is thenprocessed in the oil treatment facilities (i.e. dehydration, desalting) to meet the oilexport / storage specification.
4.3.4 Crude Oil Dehydration and Desalting
Crude oil dehydration and desalting are performed in electrostatic coalescers. Usuallyfor deep dehydration and desalting, a two stage process is used where the entrainedproduced water is removed in the first electrostatic coalescer. This is followed by thesecond “desalting” stage, where wash water is injected upstream, and removed in thecoalescer. The number of stages required depends on the produced water quantity, theinlet salt concentration and the salt specification required in the product crude. Theelectrostatic coalescers must be located after crude degassing is completed, andsufficient pressure maintained to prevent vaporization in the unit.
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Figure 4. Typical Dehydrator and Desalter Arrangement
1. a. Dehydration Stage
Crude oil from gravity based separators normally contains up to 2% produced water.When the product specification calls for a BS & W less than 0.5 %, electrostaticcoalescer is commonly used. In dehydration stage by electrostatic coalescer, up to 10%water in inlet oil reduces to less than 0.2% volume water in oil after coalescing.
Crude oil dehydration in electrostatic coalescer is performed based on the followingprinciples:
Destabilization of oil-water emulsion. This is accomplished by chemical injectionand/or heat treatment. The addition of a chemical in proper type and right amountwill reduce interfacial tension between the continuous (oil) phase and the dispersed(water) phase. The addition of heat to ensure the fluid temperature reduces theemulsion viscosity to 25 Cp or less, for adequate movement of the water droplet.
Coalescence of water droplets. This is achieved by introduction of electric field intothe oil–water emulsion. When the emulsion passes through the electric field, thewater droplets are electrically charged, and then dipole will be created. Dipoleattraction between water droplets causes the coalescence of droplets.
Sedimentation to separate the two phases. The allowance of adequate settling timefor the coalesced particles to separate.
The coalescer is completely filled with liquid: water at the bottom and oil on the top.Inside electrodes form an electric field to break surface bonds between conductivewater and isolating oil in an oil water emulsion. The coalescer field plates are generallysteel, sometimes covered with dielectric material to prevent short circuits. Fieldintensity and frequency as well as the coalescer grid layout are different for differentmanufacturers and oil types. Figure 5 shows typical electrostatic coalescer with theinternals
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Figure 5. Typical Electrostatic Coalescer with Internals
Electrostatic coalescer is popular offshore because the space and weight can beminimized. This type of treater can reduce chemical consumption. Electrostaticcoalescing allows the treating process to operate at lower temperatures than those ofconventional treaters. The use of lower temperature reduces fuel costs. For coldweather operation, it may be necessary to use heating element in this unit.
Design criteria for the electric grid section of the electrostatic coalescer should beclosely coordinated with the manufacturer. The manufacturers of electrostaticcoalescers consider the design techniques for their grids as proprietary information;therefore, the actual grid spacing and voltage data must be designed by themanufacturer.
Normally, a sample of the crude oil and salt water is required by the supplier for designpurposes. The sample should be taken at separator discharge (or point that will feedthe dehydrator).
1. b. Desalting Stage
Although not widely used in production facilities, desalting of crude oil in the field isrequired where produced water has a significant salt content. Refineries perform thisfunction, but they are having increasing problem disposing the salt in environmentallystringent location. Salt should be reduced below 10 to 30 pound per 1000 barrels (PTB)to prevent corrosion and/or heat exchanger fouling.
The desalting process is similar to the dehydration stage in electrostatic coalescer. Thedifference is the injection of less saline diluent water and the use of a mixing valve forcrude / diluent water contact. Desalting is a process whereby fresh water is mixed withthe crude oil. The fresh or low salinity water dissolves crystalline salt in the oil or dilutesthe entrained produced salt water. When the oil is dehydrated, any entrained water leftin the oil will be less salty, thus reducing the crude oil’s salt content (PTB) tospecification. This is the basic approach used by all field desalting system.
Desalter sizing is strongly influenced by viscosity which is dependent on the operatingtemperature. A desalter feed temperature of at least 70˚C should be allowed in thedesign of very viscous oils. Higher temperatures will decrease the size of desaltervessels, but is a trade-off of vessel cost versus heating costs.
The crude oil to a desalter is required to be below its bubble point to ensure no freevapour is liberated in the process. Desalters are designed to be ‘gas free’ since thepresence of vapour in high voltage field cause arcing which in turn leads to morevapour formation. A vapour switch is normally mounted on the top of the vessels which
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will shutdown the desalter units if vapour is detected.
Typically desalters are designed to handle maximum inlet water content of 10% withthe crude, although it is possible to design the desalter for 15% water cut.
The desalting technology might be provided with traditional AC current designs ornewer technology such as Dual Polarity (AC and DC currents). Dual Polarity technologyincreases throughput and salt removal efficiency.
Desalting basically removes harmful salts and residual entrained moisture from thecrude charge. The chemical composition of these salts varies widely with the majorportion being sodium chloride with lesser amounts of barium, calcium and magnesiumchlorides
Process Description
The first step towards efficient desalting is the preparation of a water-in-oil emulsionsufficiently dispersed to be effective but still susceptible to separation. Wash water isadded to the crude charge stream to dissolve or to wet the impurities.
The second step is the re-solution of this water-in-oil emulsion into virtually salt freecrude oil and salt rich water. The emulsion is re-solved by introducing it into a highvoltage electrical field inside the desalting vessel. The action of the field coalesces thedispersed water phase and forces its accumulation in the bottom of the vessel. Thewater which contains the various impurities removed from the crude is continuouslydischarged to the effluent system, and clean desalted crude flows from the desaltingvessel to the export pipeline or tanker
Water for Desalting
The required wash water for desalter is usually 4% to 8% by volume of the crude chargestream. The flow rate depends on quality of the crude oil being processed. For offshoreapplication, the wash water is a fresh water which normally produced from adesalination unit.
The water pressure must be high enough to enable injection upstream of the mixingvalve or pre-heat exchanger. The portion of wash water injected upstream of the crudepreheat exchangers should enter on the discharge of the crude charge pump. Injectioninto the pump suction can lead to a creation of very stable emulsions, especially in thecase of using a multi-stage pump.
Mixing Valve
Mixing valve is located immediately upstream of the desalter. The valve is provided toensure good contact between wash water and the crude oil. The valve should bedesigned properly to achieve high mixing efficiency but avoiding a tight emulsion of oiland water. Normally 25 psi pressure drop across the mixing valve and desalting unit isspecified. The desalter vendor should be consulted for the pressure drop requirement,since for some crude oils this value may be reduced.
Desalter Operating Pressure
It is not essential for desalter operation that pressure be controlled. However, forefficient operation, pressure variations of short duration should be avoided. Thepressure should be maintained at a level adequate to suppress vaporization. Theoperating pressure of the desalter is normally specified at 1 bar above the total vapourpressure of the crude oil and water at the maximum operating temperature in thedesalter.
Treated product specification
The treated crude product specification should include maximum acceptable limits forBS & W and salt content. Additionally the maximum acceptable oil content of theeffluent water must be specified. This is normally in terms of ppm and the valuedepends on the acceptable limit to any downstream effluent plant or local authorityregulation for effluent waters or injection water (in case of water is injected to reservoir
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via water injection wells)
It should be noted that if the specifications for water and sediment content of treatedcrude and oil content of effluent water are too stringent emulsifying chemical may haveto be injected to achieve the required levels.
Desalter Residence Time
A minimum residence time typically 10 – 30 minutes for preliminary desalter sizing. Itdepends on the inlet crude oil quality and operating temperature. The desalter size islargely dependent on the electric grids dimension and arrangement, hence themanufacturer shall be consulted for the final size
Two Stage Desalting
Figure 6 below is a schematic of a two-stage desalting system with dilution waterrecycling capability. This system is similar to the dehydrator and desalter systemdescribed in the previous section. The only difference is that fresh water is injectedupstream of the 2nd stage. The water removed from the 2nd stage is pumped back tothe 1st stage to extract the salt in the crude inlet of the 1st desalter. The addition of thisrecycle reduces the dilution water requirement compared to a single-stage dehydratorand desalter system. If further desalting is needed, it is possible to add more stages in asimilar manner.
Figure 6. Two Stages Desalting
Since desalter is typically operated at high temperature (above 40 oC), hence before thecrude oil is exported, it normally needs to be cooled to avoid vaporization duringtransport and storage. Stabilized crude is typically stored at ambient temperature.Figure 6 shows the oil outlet of desalter is utilized to pre-heat the inlet oil. Thisconfiguration is sometime considered to minimize the heating medium requirement ofthe main heat exchanger.
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