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Crude Oil Processing on Offshore Facilities

1.0 PURPOSE

This design guide is prepared to provide basic information and consideration for the process design aspect of Crude Oil Processing for typical offshore facilities. This document provides an overview of separation of crude oil from well fluid for further processing.

2.0 SCOPE

This guide covers the overall summary of processing schemes, typical crude specification, and data to help developing a preliminary phase of design.

Specific requirements of Project / Client / Local regulations shall prevail over the contents of this guide.

3.0 DEFINITIONS AND ABBREVIATIONS

3.1 Definitions

API 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;

deg-api

Asphaltenes

Asphaltenes are molecular substances in crude oil that are insoluble in low boiling hydrocarbon liquids such as heptane and are also non-distillable. These molecules are made up of aromatic clusters containing a polar heteroatom group. In large molecules the aromatic rings are interconnected by paraffinic groups and by sulphur

Cloud Point

Cloud point is the temperature at which dissolved solids are no longer completely soluble, precipitating as a second phase giving the fluid a cloudy appearance. In the petroleum industry, cloud point refers to the temperature below which wax in crude oil form 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 to flow. 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 is placed in a chamber at a constant temperature of 100 oF. RVP is slightly lower than the True Vapour Pressure (TVP) at 100 oF.

Stabilization

Crude stabilization is a process of removing volatile components from crude oil to reduce its vapour pressure.

3.2 Abbreviations

BS&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 Production

The primary function of a production facility is to separate the product from the wells into 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 and sediment. Figure 1 shows a typical schematic of oil and gas production.

Typical Oil and Gas Production Schematic

Figure 1. Typical Oil and Gas Production Schematic

Well fluids enter a separation train where the crude oil, gas, and bulk water are separated. The separation train may consist of several stages of separators. In the separation train, most volatile components of the well fluid will be vaporized. Thus the crude oil will either be stabilized or partially stabilized. Crude stabilization is performed to achieve the specified RVP

After free water removal, produced oil may contain residual emulsified water. The crude oil is then further processed in a dehydration unit to reduce the water content to a value that acceptable for transportation or sales. Dilution water must occasionally be added to reduce the salt content of the residual emulsion to a suitably low level. The addition of dilution water and followed by dehydration is called desalting process.

Gas separated from the separation train enters the gas processing train. The train normally comprises of gas compression system and gas dehydration system. Gas dehydration unit is required to remove water from the gas stream to prevent hydrate and corrosion problem in the pipeline. The most common method for gas dehydration is 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 the export gas.

Compression of the gas to pipeline pressure is normally required to allow economic transport in reasonable small diameter pipeline.

A more complex gas processing train may include gas sweetening system to remove the 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 dehydration unit. However, gas sweetening system is not common for offshore processing facilities. Generally, any sour gas produced from offshore will be further processed in onshore gas plant.

Separated water from the well fluids is directed to the produced water treatment unit to render the water suitable for disposal to the sea. Oil removal is the first treatment for produced water. Oil-water emulsions are difficult to clean up due to the small size of the particles, as well as the presence of emulsifying agents. Hydrocyclone is common equipment for produced water de-oiling purpose.

As an alternate of disposing water into the sea, the produced water could be re-injected into water injection wells. Before re-injection, produced water is usually filtered and treated with biocides. Booster pumps and injection pumps are normally installed for water injection system.

This guideline discusses the treatment of the crude oil to meet the product specifications such as vapor pressure, base sediment and water, salt content, and H2S concentration.

4.2 Product Specification

Crude oils vary widely in composition and physical properties. Some are almost gas-like materials of 65o API gravity, whereas others are semisolid asphaltic material with API gravities of less than 10o. Light crude are generally more valuable to refineries and are easier to handle than heavy crudes. Heavy crudes are more difficult to produce and sell.

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 of crude oil are as follow:

  • Maximum vapor pressure : 10 – 12 psia RVP

A low vapor pressure is important for stability of the crude during storage and transport, especially if the crude is transported via tanker. A high vapor pressure results in loss of volatile components in storage tanks or tankers. Gases evolved from unstable crude are heavier than air and difficult to disperse. Consequently the risk of explosion is greater. To prevent the release of gas during transport or storage, the vapor pressure specification is usually from 10 to 12 psia RVP.

For pipeline export, the crude oil is sometimes partially stabilized. The true vapor pressure (TVP) of the crude is typically 6.9 Bara at 38 ◦C. This value is considered to retain 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 the pipelines 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 storage tanks.

– Dissolved sediments in water can cause plugging and scaling problems to heat exchangers 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, especially if 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 cake out inside equipment, cause poor flow and plugging, reduce heat transfer rates in exchangers. Under some circumstances chlorides can hydrolyze to HCL, which is extremely 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 the crude 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. Though normally not used in offshore facilities, 20 ppm and lower can normally only be achieved by the use of a re-boiled stripper.

4.3 Crude Oil Processing


Well fluids are complex mixtures of different compounds of carbon and hydrogen with different densities, vapor pressure and physical characteristics. As the well fluids travel from the reservoir to the production facility, it experiences pressure and temperature reduction. The characteristics of the well stream continuously changes with the evolving gas from the liquid as the pressure reduces. The separation of these phases is one 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 choke valve, whose percentage opening determines the flowrate from the wells. Most of the pressure drop between the well flowing tubing head pressure (FTHP) and the separator operating pressure occur across the choke valve.

Whenever two or more wells are installed on a wellhead platform, a production manifold as well as test manifold should be installed to gather fluid from the wells prior to be processed in separator or exported via pipeline. The test manifold is provided to allow an individual well to be tested either via a Test Separator or Multiphase Flowmeter (MPFM).

4.3.2 Separation Gas & Liquid

As described earlier, the well-stream may consist of crude oil, gas, condensates, water and various contaminants. The purpose of a separator is to split the flow into desirable fractions. Primary separation of produced water from gas and oil is carried out in production 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.

Three Phase Separator with Internals

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.

Table below shows the advantages and disadvantages of horizontal separators:

Advantages

Disadvantages

Provide sufficient residence time for liquid-liquid separation

Only part of shell available for passage of gas

Large liquid surface area for foam dispersion generally reduces 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 at bottom

Not suitable for bulk liquid-liquid separation

Occupy smaller plot area

Occupy more vertical spacing between decks in offshore

Liquid level control is not so critical

More difficult to skid mount and ship

Have good bottom drain and clean out facilities. Can handle more sand, mud, paraffin, wax, etc.

More difficult to reach and service top-mounted instruments and safety devices

Production separators of all types are sized according to the following parameters, to suit 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 removed when 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 crude oil. Data can be obtained from laboratory analysis or from previous experience. The tendency 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 terminal velocity of droplets as given by Stokes’ Law. Crude oil with high viscosity and density (i.e Heavy Oil), will result in a very low droplet settling velocity and hence will require more residence time and consequently a large vessel size. Where emulsions are formed, de-emulsifying chemicals and heating may facilitate the water removal, although the provision of a separate two phase (oil/water) separator may be required in severe cases.

At the design stage of crude oil separation train, an increased water production should be 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 in order to change the hold-up times of the two phases.

For sizing criteria and calculation of a separator, refer to the company developed guideline and validated spreadsheets.

4.3.3 Crude Oil Stabilization

Dissolved gas in the crude oil must be removed to meet pipeline, storage, or tanker RVP specification. The presence of most volatile hydrocarbons increases the RVP. Removal of the dissolved natural gas components is called oil stabilization.

Crude oil can be stabilized by passing it through multiple separators in series where the volatile components will vaporize. A stabilization column might replace the simple flash-separation stages to achieve the required RVP, but these columns are rarely found offshore.

Stabilization of the crude oil often requires heat to be added or removed at certain points 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 be necessary to cool the crude in order to avoid excessive vaporization resulting in lower than 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 inside coolers so that wax deposition is avoided. Skin temperatures should be at least 5oC above the crude oil cloud point. When the cooling water supply temperature is below this temperature, a cooling water recycle can be incorporated to raise the cooling water inlet to the required temperature. When the minimum cooling water temperature is marginal for wax deposition, wax inhibitor injection may be considered instead of a cooling water recycle system.

Number of Separation Stage

The well fluid pressure is often reduced in several stages of separation. If the reservoir conditions are such that the reservoir fluid can flow adequately against a wellhead pressure, separation in more than one stage will generally offer an economic advantage. The purpose of multi stage separation is to achieve maximum hydrocarbon liquid recovery, to get the liquid stabilized, and minimize compression power required for the gas stream. Multi stage separation of oil and gas involves a series of separators operating at sequentially reduced pressures, with liquid flowing from first separator to the next lower pressure separator.

When hydrocarbon liquids are removed from separator at equilibrium, the liquid is at its bubble point. With each subsequent pressure reduction, additional vapors are liberated. If the liquids were removed directly from a high pressure separator into a stock 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 oil recovered 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 usually determine the pressure ratios between the various stages of separation. Therefore, the process engineer must evaluate the number of separation stages, compression requirements, and economics of each specific installation.

A process simulation program such as HYSYS is generally used to design and optimize a crude oil processing system to meet a given crude specification, usually vapour pressure (either TVP or RVP). Selection of a system is based on maximizing the crude output whilst minimizing energy requirement (i.e. heating/cooling loads, compression power, 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 fuel gas, exported, or flared if quantities are minimal and applicable regulations permit flaring. In designing the oil processing system the gas compression requirements influence the total energy input. Additionally the recycle of hydrocarbon condensate from the gas compression system must be included as this will influence the performance of the system.

The optimum number of separation stages varies with Flowing Wellhead Pressure (FWHP), reservoir composition, off-gas compression requirement, and export specification for crude vapor pressure. A quick assessment of separation stages number 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 three stages (HP/MP/LP) for the following reasons:

  • High construction, installation and maintenance cost of additional Separators and interstage compressors.
  • Space limitation and weight concern.
  • There is a trade-off between number of stages and oil recovery. However, the numbers of stages are optimized to achieve required RVP of oil recovered from last stage. High pressure in the first stage separator can sometimes reduce oil production from wells, particularly in late life.

Since the flowing tubing pressure usually decrease during the life of the field, a common practice is to install separate production manifolds for each separator. In this case, wells with decreased well pressure would be rerouted to a lower pressure separator, thus maximizing production. Figure 3 shows a typical flow scheme of 3 stages separation

3 Stages 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 must be low enough to allow effective choke operation and thus control of well behavior. Therefore, wells with high enough flowing wellhead pressure are routed to the HP Separator.

Gas separated from the HP Separator normally flows to the gas compression and dehydration system, and then exported through pipeline.

Bulk water in the well fluid is generally removed from the first stage separator, in order to minimize heating/cooling of excess liquid at further processing. The removed water is routed to the produced water treatment before it is disposed to the sea or used as water 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 MP separator 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 separator normally flows to an inter-stage compressor and then combines with the gas off from HP separator.

The remaining water is removed from the oil, and routed to the produced water treatment.

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 above atmospheric pressure. The operating pressure and temperature of the final gas-oil separation stage dictates the vapor pressure of the export crude. Generally stable crude (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 from the liquid. In some processes where the initial temperature is low, it might be necessary to heat the liquid (in a heat exchanger) before entering the LP separator to achieve good separation of the heavy components.

Having selected an operating pressure, the required operating temperature can be chosen to meet specification. By minimizing the operating pressure, the corresponding temperature is minimized, thus if heating is required, the heat input will reduce. In the case of tanker quality crude, the minimum final stage pressure is fixed by the method of gas disposal. The gas from the LP separator normally flows to flare system or feeds a vapor recovery unit. The oil outlet which still contains small amount water is then processed in the oil treatment facilities (i.e. dehydration, desalting) to meet the oil export / storage specification.

4.3.4 Crude Oil Dehydration and Desalting

Crude oil dehydration and desalting are performed in electrostatic coalescers. Usually for deep dehydration and desalting, a two stage process is used where the entrained produced water is removed in the first electrostatic coalescer. This is followed by the second “desalting” stage, where wash water is injected upstream, and removed in the coalescer. The number of stages required depends on the produced water quantity, the inlet salt concentration and the salt specification required in the product crude. The electrostatic coalescers must be located after crude degassing is completed, and sufficient pressure maintained to prevent vaporization in the unit.

Dehydrator and Desalter Arrangement

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 %, electrostatic coalescer 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 following principles:

  • Destabilization of oil-water emulsion. This is accomplished by chemical injection and/or heat treatment. The addition of a chemical in proper type and right amount will reduce interfacial tension between the continuous (oil) phase and the dispersed (water) phase. The addition of heat to ensure the fluid temperature reduces the emulsion 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 into the oil–water emulsion. When the emulsion passes through the electric field, the water droplets are electrically charged, and then dipole will be created. Dipole attraction between water droplets causes the coalescence of droplets.
  • Sedimentation to separate the two phases. The allowance of adequate settling time for 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 conductive water and isolating oil in an oil water emulsion. The coalescer field plates are generally steel, sometimes covered with dielectric material to prevent short circuits. Field intensity and frequency as well as the coalescer grid layout are different for different manufacturers and oil types. Figure 5 shows typical electrostatic coalescer with the internals

Electrostatic Coalescer with Internals

Figure 5. Typical Electrostatic Coalescer with Internals

Electrostatic coalescer is popular offshore because the space and weight can be minimized. This type of treater can reduce chemical consumption. Electrostatic coalescing allows the treating process to operate at lower temperatures than those of conventional treaters. The use of lower temperature reduces fuel costs. For cold weather operation, it may be necessary to use heating element in this unit.

Design criteria for the electric grid section of the electrostatic coalescer should be closely coordinated with the manufacturer. The manufacturers of electrostatic coalescers consider the design techniques for their grids as proprietary information; therefore, the actual grid spacing and voltage data must be designed by the manufacturer.

Normally, a sample of the crude oil and salt water is required by the supplier for design purposes. The sample should be taken at separator discharge (or point that will feed the dehydrator).

  1. b. Desalting Stage

Although not widely used in production facilities, desalting of crude oil in the field is required where produced water has a significant salt content. Refineries perform this function, but they are having increasing problem disposing the salt in environmentally stringent 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. The difference is the injection of less saline diluent water and the use of a mixing valve for crude / diluent water contact. Desalting is a process whereby fresh water is mixed with the crude oil. The fresh or low salinity water dissolves crystalline salt in the oil or dilutes the entrained produced salt water. When the oil is dehydrated, any entrained water left in the oil will be less salty, thus reducing the crude oil’s salt content (PTB) to specification. This is the basic approach used by all field desalting system.

Desalter sizing is strongly influenced by viscosity which is dependent on the operating temperature. A desalter feed temperature of at least 70˚C should be allowed in the design of very viscous oils. Higher temperatures will decrease the size of desalter vessels, 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 free vapour is liberated in the process. Desalters are designed to be ‘gas free’ since the presence of vapour in high voltage field cause arcing which in turn leads to more vapour formation. A vapour switch is normally mounted on the top of the vessels which will shutdown the desalter units if vapour is detected.

Typically desalters are designed to handle maximum inlet water content of 10% with the crude, although it is possible to design the desalter for 15% water cut.

The desalting technology might be provided with traditional AC current designs or newer technology such as Dual Polarity (AC and DC currents). Dual Polarity technology increases throughput and salt removal efficiency.

Desalting basically removes harmful salts and residual entrained moisture from the crude charge. The chemical composition of these salts varies widely with the major portion being sodium chloride with lesser amounts of barium, calcium and magnesium chlorides

Process Description

The first step towards efficient desalting is the preparation of a water-in-oil emulsion sufficiently dispersed to be effective but still susceptible to separation. Wash water is added 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 free crude oil and salt rich water. The emulsion is re-solved by introducing it into a high voltage electrical field inside the desalting vessel. The action of the field coalesces the dispersed water phase and forces its accumulation in the bottom of the vessel. The water which contains the various impurities removed from the crude is continuously discharged to the effluent system, and clean desalted crude flows from the desalting vessel 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 charge stream. The flow rate depends on quality of the crude oil being processed. For offshore application, the wash water is a fresh water which normally produced from a desalination unit.

The water pressure must be high enough to enable injection upstream of the mixing valve or pre-heat exchanger. The portion of wash water injected upstream of the crude preheat exchangers should enter on the discharge of the crude charge pump. Injection into the pump suction can lead to a creation of very stable emulsions, especially in the case of using a multi-stage pump.

Mixing Valve

Mixing valve is located immediately upstream of the desalter. The valve is provided to ensure good contact between wash water and the crude oil. The valve should be designed properly to achieve high mixing efficiency but avoiding a tight emulsion of oil and water. Normally 25 psi pressure drop across the mixing valve and desalting unit is specified. 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, for efficient operation, pressure variations of short duration should be avoided. The pressure should be maintained at a level adequate to suppress vaporization. The operating pressure of the desalter is normally specified at 1 bar above the total vapour pressure of the crude oil and water at the maximum operating temperature in the desalter.

Treated product specification

The treated crude product specification should include maximum acceptable limits for BS & W and salt content. Additionally the maximum acceptable oil content of the effluent water must be specified. This is normally in terms of ppm and the value depends on the acceptable limit to any downstream effluent plant or local authority regulation for effluent waters or injection water (in case of water is injected to reservoir via water injection wells)

It should be noted that if the specifications for water and sediment content of treated crude and oil content of effluent water are too stringent emulsifying chemical may have to be injected to achieve the required levels.

Desalter Residence Time

A minimum residence time typically 10 – 30 minutes for preliminary desalter sizing. It depends on the inlet crude oil quality and operating temperature. The desalter size is largely dependent on the electric grids dimension and arrangement, hence the manufacturer shall be consulted for the final size

Two Stage Desalting

Figure 6 below is a schematic of a two-stage desalting system with dilution water recycling capability. This system is similar to the dehydrator and desalter system described in the previous section. The only difference is that fresh water is injected upstream of the 2nd stage. The water removed from the 2nd stage is pumped back to the 1st stage to extract the salt in the crude inlet of the 1st desalter. The addition of this recycle reduces the dilution water requirement compared to a single-stage dehydrator and desalter system. If further desalting is needed, it is possible to add more stages in a similar manner.

Two Stages Desalting

Figure 6. Two Stages Desalting

Since desalter is typically operated at high temperature (above 40 oC), hence before the crude oil is exported, it normally needs to be cooled to avoid vaporization during transport 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. This configuration is sometime considered to minimize the heating medium requirement of the main heat exchanger.

5 comments

  1. very useful information ,
    thanks

  2. coming into a new role, this information has been very useful – just needed a baseline of understanding and I got more! Thank you.

  3. Thanks a lot. Very valuable information

  4. Thanks so very much for your efforts. 2 yrs in O&G industry, and this info is very valuable to me.

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