Crude oil desalting proccess in refinery
Slides Prepared by YASIR KHAN
Crude Oil Desalting Principles of Crude Oil Desalting 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.
Electrostatic desalting is used to remove salts and particulates from crude oil. The crude oilbrine 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.
As indicated by the schematic presented in Figure 1 for a single stage desalting operation, chemical desalting aid (demulsified) 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 atmospheric pipestille.
FIGURE 1:SINGLE-STAGE DESALTING FLOW DIAGRAM
A typical two-stage electrostatic desalting operation is shown schematically in Figure 2.
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.
FIGURE 2:TWO-STAGE DESALTING FLOW DIAGRAM
Process Variables and Operating Guidelines
Process Variables
Oil feed quality
Desalter operating temperature and pressure
Wash water amount and quality
Pressure drop across the mixing valve Oil and water residence times in the vessel The electric field
Type and amount of chemical additive used.
Oil Feed Quality Oil feed type and quality have a significant influence on desalter performance. Light (high API gravity) oils are relatively easy to desalt. Heavier oils are more difficult to desalt for several reasons: 1-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. 2-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.
Temperature For every desalter installation and crude blend processed, there is an optimum 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. 2-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 1000F and 2000F. The operating temperature range is typically 200- 3000F 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. 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.
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 deenergize the electrodes and effectively shut down 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 The wash water quality for refinery desalters is a key process consideration that not only affects the desalting
Troubleshooting Desalters Operating Inadequate Salt Removal POSSIBLE CAUSES Desalter capacity exceeded by handling heavier oil than design basis. Insufficient wash water rate.
Inadequate mixing. Low operating temperature.
Low electrode voltage. Insufficient demulsifier dosage or ineffective demulsifier.
CORRECTIVE ACTION Decrease throughput. Increase operating temperature. Blend heavy oil with lighter oil. Increase wash water rate to between 4% and 8% of oil flow rate. Increase mix valve DP in 1-2 psi increments to establish optimum. Increase temperature of untreated oil, close all unnecessary heat exchanger bypasses. Check electrical system for operating problems. Increase demulsifier chemical injection rate and/or change type.
Voltmeter and/or Ammeter Readings Vary Widely and Continuously POSSIBLE CAUSES CORRECTIVE ACTION Water level in desalter too Check water level using interface samples; decrease to lowest level that high. 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 desalter. type of demulsifier chemical. 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 Operating temperature too high or back pressure insufficient. Check vessel. backpressure valve operation.
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
desalter.
inside 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 Shut down system, empty and purge vessel. become grounded.
When safe entry permitted, inspect vessel interior and ungrounded electrode.
Sharp Increase in Current Draw (Amperage) POSSIBLE CAUSES
CORRECTIVE ACTION
Water slug entering with crude.
Reduce wash water injection rate and check off sites 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.
Wide Emulsion Band POSSIBLE CAUSES Oil feed properties - high BS&W, low gravity, waxy constituents, high particulate loading, emulsifiers from oil field recovery.
Excessive mixing valve
DP.
CORRECTIVE ACTION Slug feed chemical (e.g., 2 to 4 x normal rate) for a maximum of 2 to 3 hours - then lower injection rate to less than 10 ppm to stabilize operation. Investigate offsite crude handling procedures. Check for alternative chemical additive package with more effective solids wetting agent. Open mixing valve completely, allow amperage to stabilize and slowly increase DP to optimum value.
