Crude Oil Desalting

Engineering Encyclopedia Saudi Aramco DeskTop Standards

CRUDE OIL DESALTING

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

Chapter : Chemical File Reference: CHE-104.06

For additional information on this subject, contact PEDD Coordinator on 874-6556

Engineering Encyclopedia

Process Separation and Vessel Design Crude Oil Desalting

Section

Page

INFORMATION ............................................................................................................... 4 INTRODUCTION............................................................................................................. 4 PRINCIPLES OF CRUDE OIL DESALTING ................................................................... 5 Background ..................................................................................................... 5 Source of Salts and Contaminants in Crude ................................................... 6 Contaminant Tests .......................................................................................... 8 Desalting Process ......................................................................................... 10 Theory ........................................................................................................... 14 Typical Desalter Performance ....................................................................... 19 DETERMINING desalter Process Variables and OPTIMUM Operating CONDITIONS. 21 Oil Feed Quality ............................................................................................ 21 Temperature.................................................................................................. 21 Pressure........................................................................................................ 22 Wash Water Rates, Quality, Injection Points, and Sources........................... 23 Wash Water/Oil Mixing.................................................................................. 24 Electric Field.................................................................................................. 28 Oil/Water Residence Times........................................................................... 32 Chemical Additives........................................................................................ 34 DESALTER DESIGN FEATURES................................................................................. 36 Conventional Low Velocity Units ................................................................... 36 Natco Dual Polarity ....................................................................................... 41 Petreco Bielectric Design .............................................................................. 42 Howe-Baker Edge Design ............................................................................. 45 Mud Wash System ........................................................................................ 46 Electrical Components .................................................................................. 47 Entrance Bushings................................................................................... 47 Transformers and Reactors ..................................................................... 49 Electrical Instrumentation......................................................................... 50 Interface Level Control .................................................................................. 51

Saudi Aramco DeskTop Standards

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ESTIMATE THE SIZE OF A DESALTER ...................................................................... 55 DESALTER PERFORMANCE EVALUATION............................................................... 57 Performance Indices ..................................................................................... 57 Analytical Procedures ................................................................................... 58 Shutdown/Startup Procedures ...................................................................... 58 TROUBLESHOOTING CRUDE OIL DESALTING EQUIPMENT .................................. 59 SUMMARY.................................................................................................................... 60 WORK AIDS.................................................................................................................. 63 Work Aid 1: Graph for Determining Optimum Operating Condition .............. 63 Work Aid 2: Resources for Estimating the Size of a Desalter....................... 64 Work Aid 4: Resources for Troubleshooting Desalter Operation .................. 71 GLOSSARY .................................................................................................................. 79 REFERENCES.............................................................................................................. 81 ADDENDUMS ............................................................................................................... 84 Addendum E: Water Solubility in Crude Oil E-94...................................... 84 Addendum A: Desalter Shutdown and Start Up Instructions ........................ 85 Addendum B: Desalting Equipment Vendors ............................................... 89 Addendum C: Typical Chemical Analysis of Sea & Aquifer Water .............. 91 Addendum D: Relative Desaltability of Various Crudes .............................. 92 Addendum D:

Relative Desaltability of Various Crudes ............................. 92

Addendum D:

Relative Desaltability of Various Crudes ............................. 93

Addendum E: Water Solubility in Crude Oil................................................. 94

Table of Figures Figure 1. Basic Sediment and Water............................................................................. 9 Figure 2. Single-Stage Desalting Flow Diagram .......................................................... 11 Figure 3. Two-Stage Desalting Flow Diagram ............................................................. 12 Figure 4. Three-Stage Electrostatic Desalting System ................................................ 13


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Figure 5. Solution Versus Mixture ............................................................................... 14 Figure 8. Surfactants ................................................................................................... 18 Figure 9. Double-Ported Globe Valve - Mix Valve ...................................................... 25 Figure 10. Optimizing Mixing Valve ∆P ...................................................................... 26 Figure 11. Variable-Speed Multistage Mixer ............................................................... 27 Figure 12. Variable-Speed Multistage Mixer Effect on Desalted Oil ............................ 28 Figure 13. Electrostatically Enhanced Water Droplet Coalescence ............................ 30 Figure 14. Typical Petreco Low Velocity Desalter ....................................................... 37 Figure 15. Drilled Pipe Inlet Distributor in Coalescence Zone ..................................... 38 Figure 16. Inverted Trough Distributor in Water Phase ............................................... 39 Figure 17. Electrical Configurations (Single-Volted) .................................................... 40 Figure 68. Electrical Configurations (Double-Volted) ................................................... 41 Figure 19. Natco Dual Polarity Design ........................................................................ 42 Figure 20. Bielectric Desalter ...................................................................................... 44 Figure 21. Howe-Baker Edge Design .......................................................................... 45 Figure 22. Mud Wash System ..................................................................................... 47 Figure 23. Typical Entrance Bushing ........................................................................... 48 Figure 24. Howe-Baker’s Double Protection Bushing ................................................. 49 Figure 25. Agar Desalter Controls ............................................................................... 53 Figure 26. Trycock Interface Sampler ......................................................................... 54 Figure 27. Desalter Flow Diagram ............................................................................... 57 Figure 1A. ..................................................................................................................... 63 Figure 2B. ..................................................................................................................... 66 Figure 2C. .................................................................................................................... 67 Figure 2D. .................................................................................................................... 68 Figure 3D. Desalter Flow Diagram .............................................................................. 70

Table

Table 1. Emulsion/Demulsification Factors ................................................................. 15


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INFORMATION INTRODUCTION This module addresses the importance of desalting in crude oil production and refining. Crude oil desalting involves the process separation of salt, sediment, and slugs of water. The module begins by covering the principles of crude oil desalting. This section provides some background on the desalting process, the source of salts and contaminants in crude oil, and typical desalter performance. The second section covers the various process variables affecting crude oil desalting and operating guidelines. These variables are: oil feed quality, temperature, pressure, wash water rates and quality, wash water/oil mixing, electric field, gravity settling, and chemical additives. The third section covers desalter design features. A description of conventional low velocity units, electrical components, and interface level control is presented. A procedure to estimate the size of desalters based on Saudi Aramco data is also presented. The fourth section covers performance evaluation and troubleshooting. The various performance indices and analytical techniques are discussed. Common performance problems and operating difficulties are described along with associated corrective measures.


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PRINCIPLES OF CRUDE OIL DESALTING Background Contrary to what many people think, a refinery's desalting unit is one of its most valuable assets. The desalter removes watersoluble contaminants and oil-insoluble particulates. It provides more protection to refinery equipment than any other single piece of process hardware. Crude oil is a mixture of many different hydrocarbon molecules. It is extracted from formations beneath the earth's surface and transported to refineries. During this time, many opportunities exist for contaminants to enter the crude oil. The crude oil can accumulate contaminants from brine in the oil formation, formation stimulation programs, polymer injections to reduce formation particle entrainment, chemicals to enhance the operation of necessary machinery, additives to reduce paraffin build-up, corrosion inhibitors, polymers injected into pipelines to reduce drag coefficients, and many others. The desalter makes possible: •

Greatly reduced corrosion and fouling problems (contaminants contribute to fouling and coking of refinery equipment)

•

Protection from small slugs of water in crude oil feed due to tank switching, high bottoms level, and use of previously inactive lines.

•

Greater throughput

•

Extended runs (less downtime)

•

More stable plant operation

•

Optimum operating temperatures with minimum fuel requirements

•

Consistent production of on-spec products

•

Overall reduced operating costs


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The desalter achieves this by removing: •

Brine

•

Sediment (sand, silt and drilling mud). Sediment usually refers to particles that are larger than about 20 microns, a somewhat arbitrary cut-off point. These particles are large enough to be centrifuged from the oil and they will usually settle out given enough time.

•

Suspended solids (mostly corrosion products such as metal sulfides and oxides). These particles are usually smaller than 20 microns and too small to settle out. They are also hard to detect by centrifuging. The best measurement technique is filtration, which captures these particles along with sediment as "filterable solids".

Desalting is an integral part of refinery crude oil processing but desalters have a limited capability to remove contaminants. Export crude oil specifications limit the amount of salt and sediment so that refinery desalters can provide adequate protection of refinery equipment. Field/GOSP desalters are often required to meet these crude oil specifications.

Source of Salts and Contaminants in Crude The salt found in crude oil originates from production, secondary or tertiary recovery, and/or transportation and handling operations. Operating experience has shown a wide range of salt composition from wet crude production in different parts of the world. The geologic formations from which a crude is produced influence the brine composition and concentration. The water-soluble impurities in the brine produced with the crude consist primarily of sodium, calcium, and magnesium salts that are generally chlorides. In some crudes considerable quantities of sulfates are also found. Chlorides are the most corrosive components in the brine. At high temperatures these salts undergo hydrolysis that liberates hydrochloric acid. In the refinery this acid is carried overhead in the flash and fractionating towers.


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The three common salts found in crude oil and their typical compositions are: Volume %

Salt Sodium Chloride (NaCl)

75%

Magnesium Chloride (MgCl2)

15%

Calcium Chloride (CaCl2)

10%

Brine concentrations vary from merely brackish waters all the way to concentrated solutions. Salt concentrations in crude oil brine have been found to vary from about 3% (close to that of sea water shown in Addendum C) to more than 25%. The salt composition in the brine can also vary significantly depending on source, recovery techniques, and shipping and handling procedures. This is evidenced by the wide range of Ca/Na ratio, chloride, sulfate, and carbonate contents measured in crude oil brines around the world. For a specific crude, salt content may correlate with bottoms, sediment, and water (BS&W) content, but such relations are meaningless for different crudes or for crudes from the same geologic formation that are recovered using different production techniques. New fields will frequently start producing clean crude containing only a few pounds of salt per thousand barrels of crude (ptb). One ptb is equivalent to approximately 3 wppm (weight part per million) dependent on the crude gravity as shown below. Crude Gravity, ÁAPI

wppm/ptb

45

3.56

35

3.36

25

3.04

10

2.85

As well production age increases, however, the crude salt content also rises. Water flooding and CO2 injection are the principal secondary recovery techniques for continuing crude production from wells with declining crude flow. Crudes produced by water flooding have higher than normal solids content and electrical conductivity, and are, therefore, more difficult to desalt. Injection of CO2 containing gas may dissolve more calcium bicarbonate into the water with the crude.


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

Contaminant Tests Refineries classify contaminants into four major groups: water, salt, sediment, and metals. It is the function of the desalter to remove as much of these contaminants as possible. Poor removal of these contaminants cause upsets throughout the refinery. For instance, slugs of water can blow out crude tower trays and reduce the effective tower pressure which can lead to off-spec products. Salts cause exchanger fouling, furnace coking and corrosion especially in the crude unit. Sediments can cause fouling and erosion in high velocity areas such as piping bends. Metals can poison catalysts. Laboratory monitoring methods include the following: Contaminant

Laboratory Test

Water

1. Distillation, 2. Centrifuge (BSW)

Salt Conductivity

1. Titration, 2. Chromatography, 3.

Sediment

1. Centrifuge (BSW), 2. Filtration

Metals

Spectroscopy


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Water and sediment is usually determined by a BS&W test in which a crude sample is placed in a graduated centrifuge tube and spun at speeds up to 3600 RPM. The resulting levels of water and sediment are read for the tube as indicated in Figure 1. the result is expressed as a percent BS&W.

Figure 1. Basic Sediment and Water

Metals are not usually monitored in crude oil but are monitored in refinery feed stocks to other units.


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Desalting Process Initial "oil treating" or dehydration of crude oil production usually takes place in the oil field to reduce the volume of water moving through the transportation system. Most crudes can be electrostatically dehydrated to the 0.1% to 0.5% BS&W. Some heavier (under 20Á API) and more viscous crudes (greater than 18 cSt at operating temperature) can only be reduced to the 0.5% to 5.0% BS&W range. Depending on the crude oil source, the amount of salt that is acceptable for export markets is typically 10 ptb. While this is not low enough to achieve the fouling and corrosion control desired in a refinery, it is low enough for single-stage desalting at the refinery to achieve acceptable salt levels. Electrostatic desalting is used to remove salts and particulates from crude oil. The crude oil-brine mixture is contacted with wash water using a mix valve just upstream of the desalter vessel. Salt is extracted from the brine into the wash water droplets. The electric field in the desalter enhances water droplet coalescence so that water/oil separation requires much less residence time, and hence a smaller vessel, than is needed for unenhanced settling. Small quantities of desalting aids are often added to enhance contacting effectiveness, droplet coalescence, and water separation. Desalted oil is removed from the top of the desalter vessel and the briny water from the bottom. The most efficient place to remove salt from crude oil is usually at the refinery because the desalting can be done at the optimum temperature. Field desalters do not often have much control over the operating temperature because heating the crude adds a significant cost. Heating the crude for refinery desalting adds no additional cost since the crude must be heated to process it in the atmospheric crude column (Atm. Col.).


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Refinery desalters are generally installed in the crude oil preheat exchanger train of the atmospheric crude column. As indicated by the schematic presented in Figure 2 for a singlestage desalting operation, chemical desalting aid (demulsifier) is typically injected at the suction side of the crude charge pump, and wash water (fresh water) is added at the mix valve immediately upstream of the desalter. The treated oil from the desalter (desalted product) is fed through the remaining crude preheat exchangers before entering the Atm Col. Some installations include a preflash unit between the desalter and these downstream exchangers. The wastewater from the desalter (effluent water or brine) is fed to an API separator, brine settling tanks, or other oil-water separation unit prior to any treatment required for meeting local environmental regulations for wastewater discharge. In situations where a suitable wash water supply is inadequate, a portion of the effluent brine may be recycled to supplement the fresh wash water available for the operation.

Figure 2. Single-Stage Desalting Flow Diagram


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A typical two-stage electrostatic desalting operation is shown schematically in Figure 3. Since large quantities of suitable wash water are unavailable at most refineries, typical two-stage desalter operations feature countercurrent water-oil flow. In such an operation, fresh water is added at the mix valve for the second stage desalter and the effluent water from the second stage is used as wash water for the first stage. Demulsifier injection is required upstream of the first stage, and depending on the nature of the demulsifier, may also be needed upstream of the second stage as well. Saudi Aramco production facilities typically have an electrostatic coalescer dehydrator vessel upstream of the desalter vessel(s). GOSP desalters typically have a dehydrator stage followed by one desalter stage.

Figure 3. Two-Stage Desalting Flow Diagram

GOSP desalters may be three-stage desalters in countercurrent operation using saline (sea or well) wash water (see Figure 4). The first stage operates as an electrostatic coalescer dehydrator which can operate with or without wash water. The second and third stages operate as a conventional two-stage configuration. To conserve wash water, a fresh wash water rate of ~ 1.5% and internal water recycle rates of ~ 3% of crude throughput may be used in each stage to supply the necessary 4.5% water in this case.


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Figure 4. Three-Stage Electrostatic Desalting System

Work Aid 1 lists Saudi Aramco field/GOSP desalter facilities and configurations.


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Theory When two or more substances come in contact with one another, they may: •

React to form a new compound

•

Dissolve to form a stable liquid phase

•

Become a homogeneous mixture or two distinct phases

•

Precipitate out of solution

Reactions and precipitations are not normally encountered in desalter operations and will not be discussed. When a substance is dissolved in solution, the molecules separate from each other. In a mixture, the solute molecules are grouped together as shown in Figure 5.

Figure 5. Solution Versus Mixture

A mixture has been described as two or more intermingled substances with no constant percent composition and with each component retaining its essential properties.


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A general rule of thumb is that "likes dissolve likes". For instance, a hydrocarbon mixed with a hydrocarbon will usually form a stable solution but a hydrocarbon mixed with water will form a mixture, In desalter applications energy is added through mix valves, mixers or pumps to disperse the water as very small droplets. A stable water/oil mixture is called an emulsion or rag layer. In any separator there may be an emulsion or rag layer (water/oil mixture) between the oil phase and the water phase. Factors that influence the forming of an emulsion (emulsification) or the breaking up of an emulsion (demulsification) are shown in Figure 6.

MACROSCOPIC Factor/Property

Favors Demulsification

Favors Emulsification

density

large density difference

small density difference

time

long retention time

short retention time

vessel size

large vessel

small vessel

flowrates

low flowrates

light flowrates

temperature

high temperature

low temperature

pressure

--

--

droplet size

large size

small size

droplet attraction

opposite charges

same charges

MICROSCOPIC Factor/Property

Favors Demulsification

Favors Emulsification

surfactants

small to none

large quantities

surface charge

little to no charge

high charge

contaminants

small to none

large quantities

pH

acidic to neutral in

basic in most systems

most systems Table 1. Emulsion/Demulsification Factors


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The rate at which water droplets dispersed in oil will settle is defined by Stokes law in a desalter as shown in equation 1. 8.3 x105 (SG water V= µoil Where:

SGoil ) d2

SG

= specific gravity

µ d V

= viscosity = diameter of droplet = settling velocity

Eqn. 1

From this equation, it can be seen that large density differences increase the settling velocity and favors demulsification. As temperature is increased, the viscosity decreases which also favors demulsification. Sufficient pressure is necessary to keep the oil from vaporizing as the temperature is increased. In general, any factor that increases the droplet diameter will greatly increase demulsification. Coalescence which combines water droplets increases droplet diameter. A similar equation can be written for oil droplets in the water phase. In order to understand why electrostatic fields increase coalescence, it is necessary to examine droplets on a microscopic scale. A typical water droplet is shown in Figure 7.

Figure 6. Neutral Solution Saudi Aramco DeskTop Standards

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The water droplet has no net charge. When this water droplet is placed in an electrostatic field, the droplet distorts (elongates). In addition, the ions in solution migrate to one side as shown fin Figure 8.

Figure 7. Electrical (Dipole) Coalescence

This gives each half of the droplet a net positive or negative charge. Coalescence will be encouraged since opposite charges attract. The attractive force is described by the following equation.

Where:


F=

K E2 r 6 a4

K E r a

= = = =

Eqn. 2

dielectric constant for oil voltage gradient droplet radius distance between droplets

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As with settling velocity, the droplet size plays an important role in the rate of coalescence. The attractive force between 10 micron droplets is a million times that between 1 micron drops. As drops become closer the force increases. With 5% wash water, the distance between drops is 2 diameters and coalescence occurs in 0.1 seconds. With only 0.1% wash water, the distance between drops is 8 diameters which reduces the force 250 fold and coalescence becomes insignificant. A large voltage gradient cannot compensate for large distances between drops caused by use of inadequate amount of wash water. A surfactant is a material that migrates to the oil-water interface. It generally has a hydrophobic end (no water affinity) and/or a hydrophillic end (strong water affinity). It can have catonic, anionic or neutral tails. The hydrophilic end of the surfactant will align itself with the water droplet as shown in Figure 9.

Figure 8. Surfactants


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The hydrophobic ends of the surfactants inhibit water droplet contact. When these surfactants have a net charge (surface charge), the coalescence inhibition is amplified. The function of desalter chemicals is to remove these surfactants from the interface so that water droplets can coalesce. In addition to surfactants, other contaminants can also hinder desalter operation. For instance, amines and high pH can have a detrimental effect on coalescence. Amines will form salts by reacting with an organic acid in the crude. The polar end of the hydrocarbon salt will migrate to the oil-water interface and become a surfactant. High water pH can increase the formation of organic salts formed due to contaminants. A consistent source of high quality wash water for the desalter will minimize the large detrimental effects of surfactants and contaminants.

Typical Desalter Performance Properly sized and operated single-stage desalting is capable of meeting most refinery salt-in-crude requirements for reduced corrosion and fouling when handling lighter oils (30Á API or higher). Desalting efficiencies ranging between 90% and 95% can be expected for a properly sized and operated unit. Efficiencies between 85% and 90% can be anticipated for heavy crudes (20Á API or lower) or crudes blended with residua that are more difficult to desalt. New desalter designs for heavy crudes may have desalting efficiencies as high as 95%. Salt concentrations in the feed to a Saudi Aramco Refinery desalter are about 10 ptb, depending upon source, extent of field treating, and transportation and handling operations prior to desalting. The salt content of feeds to Saudi Aramco production facility desalters is in the range of 4,000 ptb and above. Salt concentrations in the crude leaving desalters are generally between 1 ptb in the refinery and 10 ptb at GOSP. Although such salt levels are adequate for minimizing fouling and corrosion in refinery crude preheat exchangers and crude unit operations, salt levels below 1 ptb may be required in the heavy feeds to cat cracking units, to reduce catalyst poisoning by sodium in the feed or ammonium chloride plugging in the cat cracker fractionator. To achieve such low salt levels, two-stage desalting may be required. With two-stage desalting, salt removal efficiencies of about 99% can be achieved. Also, large water slugs can be removed in a two-stage desalter with minimal effect on downstream operation. Saudi Aramco DeskTop Standards

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Saudi Aramco Refinery desalter feed oil generally contains between 0.05 and 0.5 vol% water, with values as high as 1% occasionally reported. Feeds to Saudi Aramco production facility desalters contain as much as 30 vol% water. Effluent oil from a single-stage desalter will generally contain between 0.05 and 0.5 vol% water, depending on the physical properties of the oil. Water contents of up to 0.5 vol% in the desalted oil are not uncommon when handling heavier crudes, which are more difficult to dehydrate. A water content of 0.1 vol% is typical in most desalted oils. The water carryover from a desalting operation can, therefore, be the same, or even slightly higher, than the water in the feed oil. However, because of dilution with wash water, the water carried over from the desalter has a considerably lower salt concentration than the water in the feed. Thus, desalting efficiency can remain high even with slightly higher water content in this treated oil. Mechanically filterable materials in the crude that are insoluble in both oil and water are generally classified as solids. Solids content in the crude to a desalter typically varies from 1 to 200 ptb. Vendor experience suggests desalter solids removal efficiencies of 50% to 90% depending on the density and viscosity of the crude and the effectiveness of any desalter chemical additive.


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

Oil Feed Quality Oil feed type and quality has a significant influence on desalter performance. Oil from secondary and tertiary recovery is usually more difficult to desalt. Normally, light (high API gravity) oils are relatively easy to desalt. Heavier oils are more difficult to desalt for several reasons. The density difference between the oil and water is smaller and the oil viscosity is relatively higher so that the rate of water droplet settling in the desalter is low. Heavier oils also tend to contain more naturally occurring emulsifiers than lighter crudes. These tend to inhibit water droplet coalescence and promote the formation of stable emulsions in the desalter. In addition, heavier crudes often contain more sulfur and, therefore, more iron sulfide. Iron sulfide is insoluble in oil and basic water (over 7 pH) and tends to accumulate at the oil/water interface in the desalter, making it a very effective emulsion stabilizer. Effective desalting of heavier crudes may require reduced throughputs or increased desalting capacity, higher temperatures, more intense wash water/oil mixing, and/or increased chemical demulsifier dosage.

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


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High temperature is required for several reasons. The primary purpose is to lower the oil viscosity to increase the settling rate of water droplets in the desalter. In addition, higher temperature tends to promote coalescence of the water droplets by enhancing the drainage of the oil-surfactant layer surrounding the water droplets. Larger water droplets thus formed settle more rapidly in the lower viscosity oil. Production field/GOSP desalters typically operate at temperatures between 60ÁF and 200ÁF. The operating temperature range is typically 200300ÁF 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 increase crude conductivity, and may cause 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 as shown in Addendum E, high desalter operating temperatures can also lead to higher water content in the crude from the desalter. Operating temperatures above 300ÁF should be avoided since standard desalter entrance bushings will fail frequently in prolonged service at such temperatures.

Pressure Desalter operating pressure must be maintained at a sufficiently high level to prevent vaporization. If a vapor space develops in the vessel, a safety float switch or low level switch will automatically de-energize the electrodes and effectively shut down the desalter. Any vaporization results in erratic operation and a loss in desalting efficiency by generating turbulence that hinders coalesced water droplet settling in the desalter. The required pressure depends on the desalter operating temperature and crude type. Desalters typically operate at pressures between 65 and 300 psig.


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Wash Water Rates, Quality, Injection Points, and Sources Wash water rates between 4 and 8 vol% (10 to 12 vol% maximum) of the crude throughput are required to maintain effective desalter performance. The wash water is normally injected just upstream of the mixing valve. Wash water addition provides the water droplet concentration needed to contact and rupture the protective coating surrounding the brine and promote coalescence to form larger, more easily separated droplets with reduced salt concentration. This water is essential for the desalting process. Insufficient wash water leads to poor contacting with brine droplets in the oil, reduces the dilution effect on the salt concentration in entrained water from the desalter, and reduces the effectiveness of the desalter's electric field in promoting droplet coalescence because the water droplets are too far apart. In situations where a suitable wash water supply is inadequate, a portion of the effluent brine may be recycled to supplement the fresh wash water available for the operation. In general, because of the higher ionic content in the recycled water, water recycling does not work as well as fresh water addition and should be used only where there are no practical alternatives. Wash water should have a much lower salt content than formation water or the brine in the crude oil. Raw water that Saudi Aramco uses is not normally salt free and has high total dissolved solids as indicated for aquifer water in Addendum C. The wash water quality for refinery desalters is a key process consideration that not only affects the desalting operation, but also has significant impact on preheat exchanger-fouling, furnace tube coking, and fractionator plugging. Ideally the wash water should be essentially free of oxygen, ammonia, dissolved salts (total hardness), soluble organics, and hydrogen sulfide, and also have a pH such that the effluent brine from the desalter has a pH between 5.5 and 7.0. Raw water (filtered or with low solids content) or stripped sour water is typically used as wash water for desalting. The effect of using such process water as desalter wash water should be evaluated by process calculations. Wash water acidification or caustic addition facilities may be required to meet pH requirements.


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Crude unit atmospheric and vacuum column condensates are good wash water types for refinery desalters. Boiler feed water is also good, if it has zero hardness and a low soluble salt content. These types of water are preferred because they are free of dissolved oxygen. When atmospheric crude column overhead water is used as wash water, fluctuations in the quality of this water due to erratic overhead system corrosion control can cause desalting problems. For example, a drop in the overhead pH can dissolve iron. Raising the pH at the desalter can cause the iron to precipitate as solid iron sulfide particles that stabilize emulsions in the desalter and can cause excessive water carryover and/or oily desalter brine. Cooling tower blow down is not considered very suitable for desalter wash water because it normally contains fine solids that can stabilize desalter emulsions. Water from cat feed Hydrofiners and FCCUs is also unsuitable as desalter wash water because it contains very high levels of ammonia. Such water must be stripped in a sour water stripper before use, to less than 200 ppm ammonia. Stripped sour water is a suitable wash water source since much of the ammonia and hydrogen sulfide has been removed.

Wash Water/Oil Mixing The degree of wash water/oil mixing is generally regulated by controlling the pressure drop ( P) across a specially designed globe valve, typically a double-ported globe valve (see Figure 10). This mixing energy must ensure that the wash water contacts all of the dispersed brine droplets in the oil. The mixing valve is specifically designed to produce the desired intimate mixing between the wash water and the oil. Increasing the P increases the mixing energy imparted to the oil charge and causes the formation of smaller water droplets. Mixing must be sufficient to produce the desired contacting between the wash water and brine, sand, and sediment particles in the oil, but not high enough to cause formation of a stable emulsion.


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Figure 9. Double-Ported Globe Valve - Mix Valve

Under mixing or over mixing can occur. As indicated in Figure 11, under mixing (an insufficient P) results in low salt removal and low water carryover. If under mixing is a problem, the pressure drop across the mixing valve should be increased. Too great a pressure drop across the mixing valve (over mixing) causes the production of such small water droplets that a tight water-in-oil emulsion is generated that cannot be readily broken by the electric field in the desalter. Indications that over mixing is occurring include unusually low electrode voltage and a higher than normal water carryover into the desalted oil.


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Figure 10. Optimizing Mixing Valve ∆P

The P required for optimum mixing varies according to operating temperature and crude type. Mixing valve pressure drops between 7 psi and 25 psi are typical. Manual valve adjustment is normally used to achieve the desired mixing P, although diaphragm actuated valves can be used if remote operation is needed. Accurate P readings require use of a differential pressure gauge rather than the difference between two separate gauges. For heavy crude oils, desalter vendors sometimes recommend the use of variable speed in-line dynamic mixers (see Figure 12). Such mixers are also suitable for light crudes but do not justify the cost. Saudi Aramco does not use variable speed inline mixers.


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With permission from Howe-Baker Engineers, Inc.

Figure 11. Variable-Speed Multistage Mixer

The effect of using a variable-speed, multistage, motor driven mixer is shown in Figure 13 which is a plot of BS&W and salt content for a desalted crude. After 5 hours of on-spec operation, a conventional mix valve replaced the mixer with 40 psi pressure drop across it. While the BS&W remained relatively stable, salt content increased to 15-20 ptb from less than 5. After the mixer was put back in service, salt levels returned to less than 5 ptb.


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With permission from Howe-Baker Engineers, Inc.

Figure 12. Variable-Speed Multistage Mixer Effect on Desalted Oil

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


28



With no external forces acting on it, a water droplet suspended in crude oil assumes a spherical shape (Figure 14). When a high-voltage electric field is imposed, however, the droplet distorts into an elliptical shape, with positive charges accumulating at the end nearest the negative electrode of the external electric field, and negative charges at the end nearest the positive electrode (Figure 14). The drop is an induced dipole. Two adjacent droplets in the field have an electrical attraction for one another (Figure 14). The negative end of one droplet is nearest the positive end of the neighboring droplet, so there is an attractive force between the two that tends to draw them together. This force should be of sufficient magnitude to rupture the interfacial film between the droplets upon collision, and allows them to coalesce into one larger droplet.


29



Figure 13. Electrostatically Enhanced Water Droplet Coalescence

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


K E2 r 6 a4

Eqn. 3

30



Where: F

=

attractive force

K

=

dielectric constant for oil

E

=

voltage gradient

r

=

droplet radius

a

=

distance between droplets

As drops increase in size and become closer, the force between them becomes very great, interfacial films can be penetrated, and coalescence is rapid. With 5% wash water in the water/oil emulsion, the average distance between drops is about 2 diameters and the electrically induced coalescence proceeds almost instantaneously. When the emulsion contains only 0.1% water, drops average about 8 diameters from each other, the dipole attraction forces are diminished by a factor of about 250 and are insignificant. Turbulence in the electric field results in random movement that brings fairly widely separated drops into occasional proximity where the dipole attraction force pulls them together. Turbulence at the oil/water interface, however, can result in re-entrainment of water droplets into the oil and should be avoided. Increasing the voltage gradient of the electric field cannot compensate for large distances between droplets due to low water droplet concentration in the emulsion. A critical voltage exists for a given water droplet size that, if exceeded, will cause the drop to disperse. CVG ≤ k σ/r

Eqn. 4

Where: CVG =

critical voltage gradient

k

=

constant

σ

=

surface tension

r

=

droplet radius


31



The relation indicates that as the drop size becomes larger, the voltage at which redispersion occurs becomes smaller. Low values of interfacial tension between water and oil will also increase the tendency for electrical dispersion. Practically, gradients above 12,000 V/in. have been found to cause larger droplets to redisperse and, therefore, are usually avoided in commercial desalter operations. Some desalter designs use high voltage gradients to promote mixing to replace some or all of the mixing valve function.

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

8.3 x10 5 (SG water V= µ oil

SG oil ) d 2

Eqn. 1

Where: SG

=

specific gravity

µ

=

viscosity, cP

d

=

diameter of droplet, in.

V

=

settling velocity, in./min.

and 8.3 X 105 is a combination of the gravitational constant and unit conversions.


32



From this relationship, it is apparent that the settling rate is higher when the specific gravity difference between the aqueous droplet and the oil is high and when the oil viscosity is low. Obviously the density difference is greatest when higher API (lower density) oils are desalted. The density of crude oil is typically in the 0.8-0.95 specific gravity range (45-17 ÁAPI). A 10Á API oil has approximately the same density as water. There may be some instances where the water/oil density difference is so small that the oil must be blended with a lighter diluent to decrease overall blend density to permit effective desalting. In the range of desalter operating temperatures, the difference between water and oil densities is essentially independent of temperature. Temperature has a significant effect on the oil viscosity. As the temperature of oil is increased, its viscosity decreases exponentially which increases the settling velocity as shown in Stoke's law. This is especially important for lower API gravity crudes where, for example, an increase in desalter operating temperature from 200ÁF to 300ÁF can decrease viscosity by almost an order of magnitude, resulting in an equivalent increase in the droplet-settling rate. The coalesced droplet size is the most significant factor influencing the settling rate and, therefore, the size or capacity of the separation equipment. Stokes' law predicts that the settling rate is proportional to the square of the drop size. This means, for example, that if the size of a brine droplet found in a typical oil field emulsion is increased from 1 to 100 microns, the settling rate increases by a factor of 10,000. Electrostatic desalters, with their enhanced water droplet coalescence, effectively enlarge water droplets, resulting in dramatic settling rate increases and comparable sizing benefits over conventional gravity settling equipment. It is estimated that the average brine droplet size is in the range of 1 to 10 microns entering the desalter and is enlarged to 300-600 microns by the desalter electric field. The electrostatic coalescence takes about 0.1 seconds to complete. The desalter water/oil interface level helps determine the oil and water residence times in the desalter. Raising this interface level increases the water residence time and decreases the oil residence time in the vessel.


33



Maintaining an interface level that is either too high or too low may cause desalter-operating problems. If the oil/water interface is too high, the risk of water carryover is, therefore, high. In addition, the desalter dehydration efficiency may be appreciably reduced due to decreased crude residence time in the unit. Vendor information suggests that adequate dehydration of most crudes requires 15 to 20 minutes oil residence time in a low velocity unit. A low oil/water interface level may produce an oily effluent brine or "black water." With a low interface level, the water residence time in the desalter can be reduced below that required for settling, and lead to oil carry under into the desalter brine. Water residence times on the order of 80 to 300 minutes have been reported. Longer water residence times produce lower oil concentration in the effluent water. There is no guideline for the minimum water residence time required to produce oil-free brine. A low oil/water interface level in a low velocity unit also reduces the voltage gradient for coalescence since the water phase is the ground leg of the circuit. The oil/water interface should be maintained at the vendor suggested level unless there is indicated shorting of the grids due to an emulsion/rag layer. An emulsion/rag layer between the oil and water phases will result in a false interface level reading. The interface level indicator will indicate the interface level that would exist if the emulsion/rag layer were demulsified.

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


34



Small amounts of chemical additives, in the range of 3-10 parts per million of the oil throughput, are generally employed in electrostatic desalters to improve desalting effectiveness. To be effective, the chemical must be able to migrate quickly through the oil phase to the interfacial film. Because both residence time in the oil and turbulence help the additive diffuse to the interfacial film, the chemical is usually injected into the oil upstream of the charge pump. Sometimes chemical additives are added to both the wash water and the oil or just to the wash water. Solids also tend to collect at oil/water interfaces and act to stabilize emulsions in the desalter. It is generally better to remove these inorganic solids in the water phase rather than have them remain as contaminants in the oil. To water wet these solids, the chemical additive molecule has one end that is attracted to the particle, with the other end strongly attracted to water so that it can carry the particle into the water phase for removal. Rarely can one chemical perform all the actions desired of a desalting aid. Generally, two or more are blended together to produce a chemical additive that meets the necessary performance criteria. Laboratory and field studies are required to make the selection of the most cost effective additive blend and dosage. Chemical additive vendors generally provide assistance for such studies.


35



DESALTER DESIGN FEATURES Conventional Low Velocity Units The supplying vendor provides the design of crude oil desalters. Currently there are three major vendors of refinery desalters, Petreco, Howe-Baker (in Europe Howe-Baker currently markets as Howmar) and Natco. Petreco and Howe-Baker also supply oil field desalters in addition to the other major vendor of oil field units, Natco. A listing of desalting equipment vendors is presented in Addendum B. Conventional "low velocity" units are the most typical (see Figure 15). These units are horizontal cylindrical pressure vessels with size related to crude oil processing rate capability. Typical vessel diameters are 10 to 16 ft, with lengths ranging from 30 to 150 ft (T-T). Either hemispherical or elliptical vessel heads are used. Approximately the lower one-third of the vessel contains the aqueous phase, while the upper portion is filled with crude oil. There are two sets of parallel horizontal electrode grids located at or near the center of the vessel within the crude oil. The volume occupied by the aqueous phase is needed for water settling to obtain oil-free brine. The region between the upper electrode and the aqueous phase is the coalescence zone, where the desalting operation takes place. The region above the electrodes is used to collect desalted crude into an outlet header. The electrodes are of an open grid design rather than being solid plates. They are typically fabricated as a grating structure formed of horizontal rods spaced 4 to 6 in. apart. Oil and water can freely flow through the electrode structure. Oil emulsion inlet distributors and oil outlet headers are designed to achieve uniform vertical flow through the electrode region; i.e., oil up, coalesced water down. This flow pattern is the basis of the type designation "low velocity."


36



Oil/Water Interface Control

Transformer Oil Outlet Electrodes

Vessel

Water Outlet Emulsion Inlet Distributor

Figure 14. Typical Petreco Low Velocity Desalter


37



Two designs of oil emulsion inlet are in use that reflects the differing design philosophies of the vendors. Howe-Baker prefers a drilled pipe distributor that discharges the crude as horizontal jets into the primary coalescence zone located above the water interface but below the lower electrode (Figure 16). Petreco and Natco use an inverted trough flow distributor located underneath the water-oil interface. The trough has holes on the sides that allow the crude to trickle out (Figure 17). Conceptually, the trough design can better handle water slugs in the crude feed. However, the trough design also requires that all oil in the feed pass through both the water phase and wateroil interface, possibly hindering water droplet settling.

Desalted Crude Outlet

Upper Electrode Lower Electrode

Secondary Coalescence Region

Oil

Water Crude Emulsion Inlet

Primary Coalescence Region

Brine Outlet

Figure 15. Drilled Pipe Inlet Distributor in Coalescence Zone


38



Desalted Crude Outlet

Upper Electrode

Secondary Coalescence Region

Lower Electrode Primary Coalescence Region Crude Emulsion Inlet

Brine Outlet

Figure 16. Inverted Trough Distributor in Water Phase

The two parallel horizontal electrodes in a "low velocity" unit can be energized utilizing a number of different electrical arrangements. For three-phase power systems, the two common arrangements are termed "single-volted" and "doublevolted." In a "single-volted" design, the upper electrode is grounded and the lower electrode is divided into three segments, with each of the segments energized by one phase of the high voltage power supply in a "wye" configuration (Figure 18). The voltage difference between the electrodes, the lower electrode and the aqueous interface, and across the entrance bushings used to bring the high voltage leads through the desalter vessel wall, is equal to the line-to-neutral phase voltage. This voltage is normally in the 16,000 to 23,000 V range.


39



Transformers

wyo Secondary

Delta Primary Upper Electrode 3-Segment Lower Electrode

AV Electrodes – DV Bushings

Figure 17. Electrical Configurations (Single-Volted)

In a "double-volted" design, both upper and lower electrodes are divided into three segments, with the segments located directly above/below each other being connected to line phase voltages 120Á out of phase (Figure 19). In the "wye" configuration used, the voltage difference between the electrode pairs is thus 1.732 times the line-to-neutral voltage, while the voltage difference between the electrodes and aqueous interface and across the high voltage entrance bushings is equal to line-to-neutral voltage. With a line-to-neutral voltage of 16,500 V, the voltage between electrodes is 28,600 V. This difference in voltage drops possibly enhances coalescence in the region between the electrodes without increasing the voltage stress on the entrance bushings. Another advantage is that a coalescence field is still maintained across the whole desalter area even with one electrical phase out of service due to transformer or bushing failure. A disadvantage of the double-volted design is that it draws more power and requires larger transformers.


40



Transformers “wye” Secondary

“Delta” Primary

?V Electrode = 1.732 ?V Bushings

3-Segment Electrodes

Figure 68. Electrical Configurations (Double-Volted)

Natco Dual Polarity The Natco low velocity desalter uses solid vertical electrode plates instead of a horizontal grid as shown in Figure 20. The inlet distributor is in the oil phase like the Howe-Baker design. Coalescence occurs as the mixture flows between the vertical electrodes where there is a DC voltage gradient as well as between the electrodes and the water phase where there is an AC voltage gradient. Wash water is added upstream of the mix valve and at the top of the desalter vessel. Natco claims that this design gives a 25% higher flux loading with an equivalent performance to a two-stage unit. Natco also claims that this design can give equivalent performance to a two-stage low velocity unit with less mixing and a lower temperature.


41



Figure 19. Natco Dual Polarity Design

Petreco Bielectric Design


42



The Bielectric desalter feeds dual streams of oil-water emulsion (feed) between three electrode grids. The dual feed nozzles feed are planar and direct flow horizontally between the electrode grids as shown in Figure 21. As coalescence proceeds, water droplets grow large enough to overcome the viscosity of the crude and fall due to gravity. They descend in a rain-like pattern out of the flowing oil into the non-turbulent pool of water below. The Bielectric desalter increases water residence time by allowing a higher water level than conventional low velocity desalters. Power units furnish high voltage electricity 120Á out of phase to each of three electrodes. With this phasing, dual-treating fields will remain effective even if power to one of the electrodes is lost.


43



Figure 20. Bielectric Desalter

Conventional low velocity units can be revamped to the Bielectric design to give about twice the capacity or increase performance to a two-stage unit in a single vessel. The Bielectric design is limited to feeds with no more than 15% water so it may not be applicable for GOSP desalters.


44



Howe-Baker Edge Design Figure 22 shows a comparison of the Edge design to the original 2-grid low velocity unit.

Figure 21. Howe-Baker Edge Design

The principle differences between the original designs include: 1. A larger water layer giving a longer water residence time. The distributor has been raised. 2. A 3-grid design giving a high intensity field between grids, which are double volted (see Figure 19). 3. A lower intensity field between the lower grid and the water layer, which is grounded. 4. Special design non-loading transistors supply secondary voltages of 12KV, 16KV or 20KV to the desalter internals. The voltage level can be changed via an external off-load tap-changer to optimize dehydration / desalting efficiency when charging a variety of crudes.


45



5. High voltage entrance bushings provide "double protection" to prevent damage to expensive transformers in the event of an entrance bushing leak or failure. The Edge design is claimed to have increased capacity, process heavier crudes, process higher water contents, improved efficiency, and reduce water requirements. Existing units can be revamped to the Edge design. The Shaybah field dehydrator/desalter to be completed in 1998 will use Edge technology.

Mud Wash System The mud wash (sediment wash) is a sparger intended to agitate the water phase in the desalter to suspend the solids accumulated on the vessel bottom. The solids are then removed from the vessel with the effluent water. The sparger consists of a header typically 12 to 18" off the vessel floor with nozzles positioned about every 6' of vessel length. The mud wash should be operated once or twice a week for 30 minutes to 2 hours. On a second stage desalter, once or twice a month is sufficient if the wash source is clean. For a closed recirculation loop and wash system, the water source is effluent water as shown in Figure 23. A portion of the effluent brine is pumped to the mud wash header for distribution. The water draw to the mud wash pump is normally ahead of the effluent brine exchanger and level control so that the desalter level and temperature are not altered when mud washing. During the mud wash cycle the interface should be maintained at the normal level. If the water level rises into the electrical grids, water carryover can occur. A level that drops too low can result in poor dehydration and oily water effluent. A rapid increase or decrease in interface level can cause the crude rate to swing, thus affecting downstream operations. Variations in the mud wash system include use of steam instead of water to provide agitation and mud washing as a continuous process.


46



Figure 22. Mud Wash System

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

The most critical electrical components are the entrance bushings, which carry the high voltage leads through the steel wall of the desalter vessel (Figure 24). The electrical and mechanical stresses on an entrance bushing are severe. The bushing must seal against desalter pressure and temperature, while at the same time insulating very high voltages. When a transformer entrance bushing fails, the portion of the grid receiving power through this connection is out of service and the desalter operation can be seriously impaired.


47



Figure 23. Typical Entrance Bushing


48



Howe-Baker’s Double Protection extreme bushing design is shown in Figure 25.

Figure 24. Howe-Baker’s Double Protection Bushing

Transformers and Reactors

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


49



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

Electrical Instrumentation

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


50



Interface Level Control Proper desalter operation requires that the oil/water interface be maintained at the correct level in the desalter vessel to maintain the proper electric field gradient in low velocity desalters. If the oil/water interface is too high, the current to the desalter will increase, because the electrical path to the ground through the water layer becomes reduced, resulting in arcing and water redispersion. The risk of water carryover is also increased. A low oil/water interface level will reduce the voltage gradient and thereby reduce coalescence. A low oil/water interface may produce oily effluent brine by reducing the water residence time below that required for settling. Because of the reduced water residence time in the desalter, the effluent brine quality will also be more affected by solids accumulated at the bottom of the desalter and sensitive to level controller problems. Level control is achieved by adjusting the rate of brine removal out of the bottom of the desalter in response to the sensed interface level. Normally automatic level sensing is achieved with floats (displacers) or with capacitance probes. The floats are usually installed internally in the desalter vessel. Although external floats are easier to maintain, they are not recommended since they are subject to error if the float temperature is not maintained at the same value as in the desalter. Even if the external temperature is kept at a proper level, erroneous readings can occur with changes in crude type until the external loop is purged. Capacitance probes appear attractive since they have no moving parts and are insensitive to oil gravity changes. Capacitance probes that employ radio frequency sensing and circuitry to compensate for probe fouling are best. In general, the best experience has been with capacitance probes for interface level control. Microwave (Agar Controls) level sensing was tried unsuccessfully in Safaniya. Interface level is detected by the difference between the signal sent and received by using the principle that microwaves are absorbed by water and not by oil. Safaniya found that iron sulfide at the interface also absorbed microwaves and gave a false interface level indication.


51



Agar Controls claims great success in automating refinery desalters using microwave probes as shown in Figure 26. Some failures have also been reported in refineries using the Agar control system with microwave probes. One probe measures the interface level and controls the brine outlet flow. Another probe measures the formation of a rag or cuff layer and controls chemical addition. For a bottom-injected desalter (inverted trough), the cuff probe is in the oil layer above the interface. For a top injected desalter (drilled pipe, bielectric), the cuff probe is in the water layer. A capacitance probe in the inlet crude line also warns of a water slug.


52



Figure 25. Agar Desalter Controls


53



All interface level measurements will give a false reading if a stable emulsion (rag layer or cuff) is between the oil and water phases. The level indication will be for the interface level that would exist if the emulsion were resolved into oil and water. Desalter vessels are also equipped with trycock samplers to physically withdraw fluid from the interface region as shown in Figure 27. The use of these samplers is essential in monitoring desalter operation for interface emulsion (rag layer or cuff) and in checking the automatic level sensor readings.

Figure 26. Trycock Interface Sampler


54



ESTIMATE THE SIZE OF A DESALTER The required size of a desalter is a function of its operating temperature, the physical properties of the crude being processed, and the crude flow rate. The supplying vendor normally provides desalter sizing. The vendors have enough past experience with major crude oils to allow them to design directly. For new crude oils, or novel blends, the vendors carry out desalting tests in their pilot plant facilities. For screening purposes and to check the consistency of vendor proposals, desalter size can be estimated from Work Aid 2A. This figure applies to conventional low velocity desalters and was developed from the Saudi Aramco desalter design data summarized in Work Aid 1. Most of the southern area GOSP desalters listed in Addendum A were originally sized based on the criteria for a standard GOSP design. The wet crude handling facilities in these GOSP's were sized based on a grid loading of 150 BPD/ft2 as shown in Work Aid 2A. The correlation line in Work Aid 2A for vessel loading is described by the equation:  ∆ρ  BPD + 64.3 = 56.9 log 10  µ  ft 2

for 0.04 ∠

 ∆ρ  ∠50  µ  Eqn. 6

Where: BPD =

bbl/day feed rate

ft2

=

horizontal projected cross sectional area, ft2

∆ρ

=

density difference between water and oil, grm/ cm3

µ

=

oil viscosity at operating temperature, Poise

log10 =

logarithm to the base 10

∆ρ/µ =

separation parameter, (grm/ cm3)/Poise


55



This correlation and Work Aid 2A is similar to what is typically used by the vendors. Densities and viscosity are those at desalter operating temperature. However, if this information is not readily available, the densities can be estimated from Work Aid 2B and the viscosities from Work Aid 2C. Especially with viscosity, effort should be made to verify estimates from the figure with actual data. Vessel loading in BPD/ft2 is based upon the maximum horizontally projected area of the desalter vessel, including the area contributed by the heads. Care must be taken to distinguish between tangent-to-tangent and end-to-end vessel size specifications. For multistage desalters, each stage would be sized as discussed above. The relative desaltability of various crudes is illustrated in Addendum D (Parts 1 & 2). Addendum D (Part 1) shows the relative desaltability as vessel loading for various crudes at 250ÁF and Addendum D (Part 2) shows vessel loading as a function of temperature for Saudi Arabian Crudes.


56



DESALTER PERFORMANCE EVALUATION Performance Indices Several indices have been developed to evaluate desalter performance. These indices provide a means of monitoring the overall efficiency of the process, as well as the key individual operations, namely mixing the crude and wash water and separating the resultant aqueous emulsion from the oil. The indices include the desalting or overall salt removal efficiency, dehydration efficiency, and several indices for evaluating the effectiveness of the wash water/oil mixing. Together with the effluent water quality, they act, as guides toward determining whether the desalter is performing properly and which aspect of desalter operation must be modified to obtain good performance. Work Aid 3 summarizes the various performance indices. In order to quantify these indices, reliable desalter operating data must be obtained. These data include the water entrained in the feed and desalted oil (Wi and Wo, respectively, expressed as vol% and usually determined by BS&W), salt content of the feed and desalted oil (Si and So, respectively, expressed as ptb of NaCl), wash water rate (Ww, expressed as vol% of oil feed rate), and the salt content of the wash water (Sw, expressed as ptb of NaCl). This terminology is summarized on the desalter block flow diagram shown in Figure 28. Reliable analytical techniques are required for the BS&W, salt, oil-in-effluent water, and solids-in-oil measurements.

Figure 27. Desalter Flow Diagram


57



Analytical Procedures Proper evaluation of desalter performance requires analysis for BS&W and salt in the feed and desalted oil. The water contained in this oil, as determined by distillation, may also be desirable to differentiate between dissolved and entrained water in the oil. Since serious errors can be introduced in the efficiency calculations, and therefore the evaluation and troubleshooting process, by inaccurate analytical results, it is important that reliable procedures be carefully followed to obtain the necessary data. BS&W should be determined by the centrifuge method, using water saturated toluene and demulsifier. The analysis should be performed at about 140ÁF. A comprehensive test procedure is described in the Manual of Petroleum Measurement Standards (MPMS). The elevated temperature and demulsifier addition are essential to obtain reproducible results. BS&W analyses determine only the entrained water in the sample at the analysis temperature. Total, entrained plus dissolved, water is best determined by the distillation method from the MPMS. The most reliable method for determining the salt content in the oil is by the extraction of samples with water in the presence of suitable solvents, and analysis of the aqueous extract. The salts of most concern to the refinery are the chlorides, because they cause corrosion at crude unit conditions. The aqueous extract is therefore analyzed for chlorides by titration with silver nitrate solution.

Shutdown/Startup Procedures Typical startup and shutdown procedures are shown in Addendum A.


58



TROUBLESHOOTING CRUDE OIL DESALTING EQUIPMENT The most commonly experienced desalter performance problems include low desalting efficiency, oily or black effluent water, and water carryover in the desalted crude. Observed operating difficulties include formation of a thick emulsion band in the desalter, widely fluctuating voltage or amperage readings, low voltage, and high current draw. There can be several possible causes for each desalter problem. Depending on the cause, different corrective actions are required. Common desalter performance and operating problems are indicated in Work Aids 4A to 4G, with a list of possible causes and associated corrective measures. The appropriate action depends on the cause of the problem. Work Aid 4H shows a Petreco troubleshooting guide.


59



SUMMARY This module addressed the importance of desalting in crude oil production and refining. The first section covered principles of crude oil desalting. The following key points were discussed: •

Process separations accomplished by crude oil desalting:

•

Salt removal.

•

Sediment removal.

•

Removal of slugs of water.

The second section covered process variables affecting crude oil desalting and operating guidelines. The following key points were discussed: •

•

•

Primary process variables: -

Oil field quality.

-

Temperature.

-

Pressure.

-

Wash water rate and quality.

-

Wash water/oil mixing.

-

Electric field.

-

Oil/water residence times.

-

Chemical additives.

Variables that determine the magnitude of the attractive force between droplets in an electric field: -

Voltage gradient.

-

Drop size.

-

Distance between droplets (wash water rate).

Desalter voltage. -


Typical voltage AC field:

15,000 to 25,000 V. 60



•

•

-

Typical voltage gradient:

1,000 to 5,000 V/in.

-

Critical voltage gradient:

> 12,000 V/in.

Variables that determine the rate at which water droplets settle from oil: -

Water/oil density difference.

-

Drop size.

-

Oil viscosity.

Typical desalter residence times. -

Oil:

15 to 20 minutes.

-

Water:

80 to 300 minutes.

The third section covered desalter design features. The following key points were discussed: •

•

Zones in a desalter. -

Lower one-third contains aqueous phase for settling to obtain oil-free brine.

-

Coalescence zone between upper electrode and aqueous phase.

-

Zone above electrodes collects desalted crude into outlet header.

Variables used for estimating desalter size. -

Water/oil density difference.

-

Oil viscosity.

The fourth section covered performance evaluation and troubleshooting. The following key points were discussed: •

Analytical measurements required to evaluate desalter performance.


61



•

•

-

BS&W in feed and desalted oil.

-

Salt in feed and desalted oil.

Desalter performance indices monitor: -

Salt removal efficiency.

-

Dehydration efficiency.

-

Efficiency of wash water/oil mixing.

Common desalter operating/performance problems. -

Inadequate salt removal.

-

High water carryover in desalted oil.

-

Oily effluent water (black water).

-

Wide emulsion band.

-

Fluctuating voltmeter/ammeter readings.

-

Continuous low voltage and/or high ammeter readings.

-

Sharp increase in current draw (amperage).


62



WORK AIDS Work Aid 1:

Graph for Determining Optimum Operating Condition

Figure 1A.


63



Work Aid 2: Work Aid 2A:

Resources for Estimating the Size of a Desalter Existing Saudi Aramco Desalter Design Data

D30

314

D29

SH GOSP-3

SH GOSP-4

SH GOSP-6

Plant 15

G.26

G.57

RT REF.

Safaniya

Natco

Natco

Natco

Petrolite

1000 B/SD

330

330

330

250

Diameter, ft

14

14

14

16

Plant No.

Vendor Crude Oil Capacity,

64B

U20

Safaniya

ABQ GOSP-2

ABQ GOSP-6

Petreco

Natco

Mitsubishi

Natco

162

162

(per train)

(per train)

165

220

14

14

12

12

Length (T-T), ft

148

148

148

140

148

148

87

118

Operating Temp., ÁF

90

90

90

250

142

142

90

175

ÁAPI at 60ÁF

35.3

35.3

35.3

28.1

27.7

27.7

Crude sp.gr.at Cond.

0.8374

0.8374

0.8374

0.82

0.860

5.4

5.4

5.4

2.62

2(2)

2(2)

2(2)

–

–

single volt

Crude Gravity,

Viscosity, cP at Cond.

41

35

(at cond.)

(at cond.)

0.860

0.82

0.85

8.75

8.75

4.3

6.4(1)

1

3(3)

3(3)

2(2)

2(2)

–

–

4

4

–

–

single volt

single volt

–

Single volt

–

–

3

3

3

3

3

3

3

3

–

–

–

150

100

100

75

–

9963

34807

25540

3-10

20947

20947

9180

–

< 10

< 10

< 10

1

< 10

< 10

< 10

< 10

15

30

30

0. 5

30

30

17.4

16.5

No. of Vessels - in series - in parallel (no. of trains) Electrical Config.

single volt

Transformers - number - size, kVA Salt Content, ptb - inlet - outlet Inlet Water Content, vol%

Notes: (1) Estimated viscosities. (2) One electrostatic dehydrator vessel and one desalter vessel in series. (3) One electrostatic dehydrator vessel and two desalter vessels in series.


64



Refinery

Jeddah

Rabigh

Ras Tanura

Riyadh #1

Riyadh #2

Yanbu

Plant No.

CDU-2

5300

15

RCD

R110

J103

Vendor

Petreco

Petrolite

Petreco

Howe-Baker

Howe-Baker

Petreco

Crude Capacity, (MBD)

42

82 x 4

275

60

100 (1)

85 x 2 (2)

Vessel Diameter (feet)

12

10

14

12

12

12

Vessel Length (T-T), (feet)

36

80

86

60

100

61

No of Vessels

1

1

1

2

2

2

- in series

1

1

1

2

2

2

- in parallel (no. of trains)

-

4

-

-

-

2

Single

Single

Dual

Single

Single

Single

- No. per Vessel

2

3

3

3

3

3

- size, kVA

60

60

75

40

60

60

- Fahrenheit

220-240

230

280-310

185

195

255-275

- Celsius

105-116

232

138-155

85

90

125-135

Crude Gravity, (ÁAPI at 60ÁF)

32

33

34

33

33

33

Crude Gravity, (S.G. at Op T)

0.85

0.86

0.746-0.8

0.845

0.845

0.859

Crude Viscosity, (cP at Op T)3

1.3

1.2

0.94

1.9

1.7

1.0

- Inlet (Arab Light)

2-6

1-3

2

2-6

2-6

2-6

- Outlet (Arab Light)

1-3

0.2-0.8

1

1-2

1-3

1-4

- Inlet (Arab Extra Light)

–

–

4-10

–

–

–

- Outlet (Arab Extra Light)

–

–

1-2

–

–

–

- Crude Charge

0.05

0.05

2

0.5

0.5

0.05-0.1

- Wash Water

4-5

4.5-6

5

2-3

3-5

3-4.5

- Crude Outlet

0.2-0.4

0.1-0.2

0.05

0.1

0.1

0.2-0.4

Electrical Configuration Transformers

Operating Temp., ÁF

Salt Content, (ptb)

Water Content, (Volume %)

Notes: (1) Design capacity 100 MBD Operating capacity 146 MBD. (2) Design capacity 85 X 2 MBD Operating capacity ranges from 60 x 2 MBD to 110 x 2 MBD. (3) Viscosities are approximate.


65



Work Aid 2B:

Size Basis for Saudi Aramco Desalter

Figure 2B.


66



Work Aid 2C:

Typical Density Versus Temperature Curves for Saudi Aramco Desalter Fluids

Figure 2C.


67



Work Aid 2D:

Characteristic Temperature-Viscosity Relationship for Saudi Aramco Crude Oils

Figure 2D.


68



Work Aid 3:

Equations for Evaluating Desalter Performance

Index

Desalting Efficiency Dewatering Efficiency(1)

Symbol

Definition

-

Si − So x 100 Si

> 90%

-

W w + Wi − Wo x 100 Ww + Wi

> 95%

Mixing Efficiency(2) Optimum Salt Content(3) Mixing Index

Process Efficiency

Good Performance Value

A

S Wo  i  − 1  So  x 100 W W o (S i + 0.01 W w S w Ww + Wi

MI

A So

E

Si − So x 100 Si − A

-

)

> 0.90

-

Where: Si = Salt content of crude oil charge, ptb of NaCl So = Salt content of desalted oil, ptb of NaCl Sw = Salt content of wash water, ptb of NaCl Wi = Water content of crude oil charge, vol% Wo = Water content of desalted oil, vol% Ww = Wash water rate, vol% of crude oil charge rate Notes: (1)

Ww includes recycle water, if any.

(2)

Based on salt-free wash water.

(3)

Use fresh water rate and salt content for Ww and Sw, respectively.


69



Figure 3D. Desalter Flow Diagram


70



Work Aid 4: Work Aid 4A:

Resources for Troubleshooting Desalter Operation Troubleshooting Desalter Problem of Inadequate Salt Removal

Possible Causes

Desalter capacity exceeded by handling heavier oil than design basis.

Corrective Action

Decrease throughput. Increase operating temperature. Blend heavy oil with lighter oil.

Insufficient wash water rate.

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

Inadequate mixing.

Increase mix valve P in 1-2 psi increments to establish optimum.

Low operating temperature.

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

Low electrode voltage.

Check electrical system for operating problems.

Insufficient demulsifier dosage or ineffective demulsifier.

Increase demulsifier chemical injection rate and/or change type.


71



Work Aid 4B:

Troubleshooting Desalter Problem of High Water Carryover in Desalted Oil

Possible Causes

Corrective Action

High oil/water interface level.

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

Excessive mixing valve

Open mixing valve completely, allow amperage to stabilize, and increase mixing valve pressure drop slowly (allow about onehalf hour per adjustment) to establish optimum setting.

P.

Excessive water injection.

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

Very high BS&W content in oil feed.

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

Electrical failure.

Check voltage and amperage readings; if transformer or entrance bushing failure identified, or power cannot be restored immediately, discontinue wash water injection.


72



Work Aid 4C:

Troubleshooting Desalter Problem of Oily Effluent Water (Black Water)

Possible Causes

Corrective Action

Low oil/water interface level.

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


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

P.

High effluent water pH.

Check effluent water pH. If greater than 7.5, reevaluate wash water components, acidify wash water with H2SO4 until effluent water pH is between 5.5 and 7.0.

Sludge in desalter.

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

High solids concentration in effluent brine. (Excessive oil content in solids.)

Check wash water for particulates and minimize where possible. Investigate incorporating improved solids wetting agent in chemical additives package.

Excessive asphaltenes in crude.

Increase water residence time in desalter by raising interface level, providing this does not interfere with desalting efficiency. Avoid blending light naphtha with heavy oils.

Low operating temperature.

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

Insufficient or ineffective demulsifier addition.

Increase chemical demulsifier dosage and/or change demulsifier.


73



Work Aid 4D:

Troubleshooting Desalter Problem of a Wide Emulsion Band

Possible Causes

Corrective Action

Oil feed properties -- high BS&W, low gravity, waxy constituents, high particulate loading, emulsifiers from oil field recovery.

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 P to optimum value.

P


74



Work Aid 4E:

Troubleshooting Desalter Problem of Voltmeter and/or Ammeter Readings Varying Widely and Continuously

Possible Causes

Corrective Action

Water level in desalter too high.

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

Stable emulsion formed in desalter.

Increase injection rate and/or change 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 vessel.

Operating temperature too high or back pressure insufficient. Check backpressure valve operation.


75



Work Aid 4F:

Troubleshooting Desalter Problem of Continuous Low Voltage and/or High Ammeter Readings

Possible Causes

Corrective Action

Stable emulsion has entered desalter.

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

Water/oil interface too high.

Check level versus set point using interface-sampling system. Lower water level and confirm proper operation of interface level control system.

Temperature too high.

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

Failed entrance bushing.

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

Failed insulator inside desalter.

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

Energized electrode has become grounded.

Shut down system, empty and purge vessel. When safe entry permitted, inspect vessel interior and ungrounded electrode.


76



Work Aid 4G:

Troubleshooting Desalter Problem of Sharp Increase in Current Draw (Amperage)

Possible Causes

Corrective Action

Water slug entering with crude.

Reduce wash water injection rate and check offsite 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.


77



Work Aid 4H:

Petreco Troubleshooting Guide


78



GLOSSARY Atm. Col.

Atmospheric column in Crude Unit.

APS

Atmospheric pipe still.

BS&W

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

Demulsification/

breaking an emulsion

Demulsifying Desalting Efficiency

The percentage of the original salt removed by desalting.

dewatering efficiency

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

Emulsification/

creating an emulsion

Emulsifying kVA

Kilovolt-ampere.

kW

Kilowatt.

Mixing Efficiency

The percentage of feed water used for perfect mixing.

Mixing Index

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


79



Oil-In-Water Emulsion

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

Optimum Salt Content

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

Process Efficiency

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

ptb

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

Stable Emulsion

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

Water-In-Oil Emulsion

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


80



REFERENCES (1)

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

(2)

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

(3)

Manual of Petroleum Measurement Standards.

(4)

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

(5)

Vendor Brochures.


81



ADDENDUMS Section ...................................................................................................................... Page

Addendum A: Desalter Shutdown and Start Up Instructions ....................................A-85 Addendum B: Desalting Equipment Vendors............................................................B-89 Addendum C: Typical Chemical Analysis of Sea & Aquifer Water .......................... C-91 Addendum D: Relative Desaltability of Various Crudes........................................... D-92 Addendum E: Water Solubility in Crude Oil..............................................................E-94


84



Addendum A: Desalter Shutdown and Start Up Instructions The following sections summarize typical desalter shutdown, inspection/maintenance preparation, and start-up instructions, which are similar to those provided by the equipment manufacturer. These sections are not designed to be used in place of existing operating instructions. Therefore, detailed operating instructions supplied by the equipment manufacturer should be used whenever possible. Typical Desalter Start-Up Instructions 1.

Make a thorough inspection of the drum before it is closed up. Check all instrument taps to be sure they are not plugged.

2.

Check that all mechanical work is complete.

3.

Check that man way cover has been installed and all blinds removed.

4.

Steam to atmosphere for at least one hour to remove air and warm up.

5.

Pressure test with steam pressure.

6.

Open safety valve.

7

Fully open mix valve.

8.

Vent desalter at high point; slowly fill with crude. When full, open inlet valve wideopen and close vent valve. Vent valve control may have to maintain a minimum pressure in the desalter to prevent vaporization.

CAUTION: Fill Desalter slowly so as not to interrupt feed to Crude Unit.


85



9.

Open outlet valve slowly and let operations stabilize.

10. Slowly close desalter bypass and let pressures and temperature stabilize.

11. Turn on electrodes.

12. Start wash water to Desalter and start Desalter Water Booster Pump to preheat train.

13

Close mix valve to give the desired pressure drop for optimum desalting.


86



Typical Desalter Shutdown Instructions

1.

Open the Desalter bypass valve and when pressure and temperature stabilize, close the Desalter inlet valve.

2.

Stop water to Desalter (shutdown Desalter Water Booster Pump).

3.

Displace brine water from Desalter to the oily water sewer. Monitor this closely to prevent putting oil to the sewer.

4.

Turn off electrodes.

5.

Close Desalter outlet valve and pump the crude out through the pump out system. Do not pump water into the pump out system. Vent steam into the Desalter while pumping out to prevent pulling a vacuum.

6.

After all oil is pumped out, steam to Oily Water Sewer for about two hours.

7.

Block off Safety Valve to isolate vessel from Hot Flash Drum.

8.

Open high point vent and steam to the atmosphere for two hours.

9.

Lock out electrical power to electrodes.


87



Typical Desalter Inspection/Maintenance Preparation 1.

Install blinds in inlet and outlet lines, safety valve line, steam line, water line, and pump out line..

2.

Open man way for visual inspection from outside for cleanliness.

3.

Wash and clean as necessary for entry.


88



Addendum B: Desalting Equipment Vendors

Natco

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

Natco U.K. Limited London, England Telephone: (01) 499-9423 Telex: 25776

National Tank France

Paris, France Telephone: 225-0167 Telex: 650225

Howe-Baker

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

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

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


89



Howmar International Limited Albany Park Estate Frimley Road Camberly, Surrey GU15 2QQ England Telephone: (44+276) 681 101 Telex: 858646 Petreco Petrolite Corporation

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

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

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


90



Addendum C: Typical Chemical Analysis of Sea & Aquifer Water

Symbol

Seawater, ppm

Aquifer, ppm

Sodium

(Na+)

12,600

696

Calcium

(Ca++)

545

222

Magnesium

(Mg++ )

1,660

82

Sulfate

(SO 4--)

3,260

418

(Cl-)

22,800

1,280

(HCO3-)

164

195

Silica

(Si)

2.8

12.9

Boron

(B)

8.2

0.72

Strontium

(Sr)

9.6

5.5

Copper

(Cu)

<0.5

< 0.5

Zinc

(Zn)

<0.5

0 - 11

Manganese

(Mn)

<0.5

< 0.5

Barium

(Ba)

<0.5

< 0.5

Lead

(Pb)

0.76

< 0.5

(TDS)

41,000

2,890

7.9

7.0

1.0315

1.0024

Ions

Chloride Bicarbonate

Total Dissolved Solids pH Specific Gravity


91



Addendum D: Relative Desaltability of Various Crudes

PART 1:


92



Addendum D:

Relative Desaltability of Various Crudes

PART 2: Relative Desaltability of Various Crudes As A Function of Temperature


93



Addendum E: Water Solubility in Crude Oil


94

Crude Oil Desalting

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