DESALTERS

SECTION 3: DESALTERS Benefits Of Crude Oil Desalting Crude oil is most often produced as a water-in-oil emulsion containing large quantities of dissolved salts and suspended solids. The salts are mostly chloride, sulfate and carbonate salts of calcium, magnesium and sodium. The solids are typically silt, sand, clay, iron oxides, and iron sulfides. Crystalline salts may also be present. The contaminants frequently found in crude oil arise from several sources: •

Brine contamination in the crude is a result of the brine associated with the oil in the ground,

•

Most minerals, clay, silt, and sand found in the oil come from the formation around the oil well bore, and

•

Iron sulfides and oxides are the result of corrosion during production, transport, and storage.

Though most of these impurities are removed in normal field treating operations there are trace quantities of water and oil-wetted solids present which are either difficult or uneconomical to remove at the production site. Crude oil can also become contaminated during shipping. For example, solids can be picked up in pipelines and terminal storage facilities or the oil can become contaminated with sea water ballast in ocean-going vessels. Waste oils and other unknown chemicals can also be added to the crude at the production site or during transportation without the refinery's knowledge. Crude oil desalting is accomplished by mixing fresh water with the incoming crude to "wash" salts and solids from the crude. The addition of fresh water does several things: •

It helps coalesce small water droplets into larger ones that are more easily removed,

•

It reduces the total salt content of the crude, and

•

In conjunction with the addition of demulsifier and/or wetting agents provides a medium for their removal.

If the contaminants are not removed before the crude oil enters the crude unit preheat system they can cause corrosion and fouling. Effective crude oil desalting can help minimize the effects of these contaminants on the crude unit and downstream operations. Proper desalter operations provide the following benefits to the refiner: Reduced Crude Unit Corrosion. At the high temperatures found in crude unit atmospheric and vacuum furnaces the chloride salts of calcium and magnesium can hydrolyze, forming gaseous hydrogen chloride (HCl). The chemistry of this process is as follows: Heat MgCl2 + 2H2O ===> Mg(OH) 2 + 2HCl Heat CaCl2 + 2H2O ===> Ca(OH) 3.1

2

+ 2HCl

The HCl gas will dissolve in water to form highly corrosive hydrochloric acid. This problem can be found in the overhead condensing systems of distillation towers, where the steam is allowed to condense. Proper desalting will minimize the amount of HCl generated, and will greatly reduce corrosion potential in the crude unit. Reduced Crude Preheat System Fouling. Solid particles can deposit in crude unit preheat exchangers or furnace tubes reducing heat transfer rates and/or cause plugging of the tubes. Also, if sodium is not removed from the crude oil it can act as a catalyst for coke formation in heat exchangers, furnace tubes and transfer lines. A good desalting operation will reduce fouling potential by removing a high percentage of crude oil solids and by minimizing the amount of sodium in desalted crude. Reduced Potential for Distillation Column Damage. Water slugs in the crude charge can cause damage in the crude distillation tower. Pressure surges created when this water is vaporized to steam often disrupt tower internals. Properly designed desalters will significantly reduce carryover of water in the incoming crude oil. Excess water in the desalted crude oil also requires more Reduced Energy Costs. energy to heat in the crude furnace. An efficient desalter will provide energy savings by minimizing the amount of water in the desalted crude. Reduced Downstream Process and Product Contamination. Certain impurities such as sodium and potassium can poison catalysts in downstream processes. Excess sodium and iron in petroleum coke can reduce its market value. A good desalting operation will reduce the amount of sodium, potassium and iron in desalted crude, minimizing the deleterious downstream effects of these contaminants. When properly operated, the desalter should provide a crude oil containing 0.1 - 04% basic sediment and water (BS&W) with a salt content often less than 1 lb of salt/1000 barrels of oil (PTB). An exception to this would be on the West Coast where many of the heavy crudes are difficult to desalt to less than 4 PTB. A refinery which is not meeting these levels at the present time provides an opportunity for an improved program using chemical demulsifiers. A single stage desalter should provide 90-95% salt removal for a typical crude oil. The efficiency of filterable solids removal is usually 50-75%. In instances where high efficiency is required, a second desalter is added after the first. Overall two-stage desalting efficiency can be as high as 98%. Two stage desalting is becoming more prevalent as refiners strive to control the contamination of downstream processes and reduce crude unit down time due to corrosion and fouling of equipment.

3.2

Description Of The Crude Oil Desalting Process Desalting of crude oil is accomplished by injecting 3% to 9% wash water into the crude, thoroughly mixing the water and crude oil, and then providing efficient separation of the two phases. The emulsification or washing step is accomplished primarily through a mixing valve which causes emulsion formation due to the high energy dissipation (pressure drop) across the valve. Separation of the water from the crude oil is accomplished in a "desalter" which is a pressure vessel. The normal gravity separation of water from the crude oil in the vessel is accelerated with the use of an electrical field, heat, and emulsion breaking chemicals. Here is a brief review of the desalting process, starting with the crude oil as it enters the refinery crude storage area.

Crude Storage Tanks Crude oil can enter the refinery via pipeline or from ships and barges. The crude oil is sent to large steel storage tanks in an area of the refinery known as the tank farm. The tank farm is a storage area for crude oil and intermediate and finished products. Figure 3.1 is a diagram of a typical refinery crude storage and single stage desalting operation.

Refine ry Cr ude O il Handling

Sys te m

Refinery Tank Farm Barge or Tanker Crude Oil

Tank 1

Pipeline Crude Oi l Tank 2

Pipeline Terminal Crude Storage

Tank Farm Crude Pump

Crude Oil Booster Pump

Tank 3

To Hot Crude Preheat Exchangers Crude Oil Desalter

B IC Emulsion Breaking Chemical

Cold Crude Preheat Exchangers

Mi x Valve Interface Level Controller

Crude Charge Pump

Desalter Effluent Water Pump

Desalter Wash Water

Figure SECTION 3: .1

Crude storage tanks vary in size from 40,000 to 500,000 bbls each. Storage tank designs also vary, but most tanks have some kind of floating roof design. In this type of tank the roof floats on the crude oil so the level of the roof rises and falls with the level of crude oil in the tank. Most floating roof tanks are external, that is there is no fixed steel roof covering the top of the tank and its floating roof. Rain water is removed from the top of the external floating roof by a drainage system that empties into a sewer outside the tank. 3.3

Crude tanks can have separate lines and nozzles for filling and removing crude oil from the tank, or there may be a common suction/fill line and nozzle. Tank suction nozzles are usually fixed at a height of 2-4 feet from the tank bottom. Occasionally a crude tank will have a floating suction line. This means that the suction line is flexible and the nozzle is suspended from the bottom of the floating roof. There are sumps and drain lines in the bottom of the tanks to allow draining of settled brine to a sewer. Some tanks have internal mixers to prevent stratification of the tank contents and to keep solids from collecting in the bottom of the tank. Some storage tanks also have internal steam coils and external insulation to keep the crude oil warm enough to pump. The way the refinery handles the crude oil in the storage area can significantly affect the quality of the crude charged to the crude unit. Some refiners will transfer oil to a tank, allow the brine to settle for a few days, drain the brine to a sewer, and then send well-dehydrated crude to the unit. Other plants may fill a tank on one side while pulling suction on the other, with all mixers on and the sump drain valve permanently closed. This operating mode will obviously result in higher BS&W levels in the crude oil sent to the crude unit.

Crude Unit Charge Pumps and Preheat Exchangers Figure 3.2 is a schematic of a single-stage desalter operation. Crude oil is transferred from the storage tank through the crude preheat exchangers and into the desalter with a centrifugal pump. These pumps can be located at the crude unit or in the tank farm. Wash water is added to the crude oil upstream of the desalter. Wash water can be injected ahead of the preheat exchanger train or the mix valve. Some operations utilize both water injection locations. The crude oil and water mixture passes through the mix valve ahead of the desalter vessel.

Single Stage Electrical Desalter Crude Oil to Hot Crude Preheat Exchangers

Crude Oil Storage Tank Transformer Emulsion Breaker

Interface Level Controller Crude Charge Pump

Mix Valve

Wash Water to Mix Valve Desalter Wash Water Wash Water to Cold Crude Preheat Exchangers

Desalter Effluent Water to Waste Water Treatment Plant

Figure SECTION 3: .2

The preheat exchangers are shell and tube heat exchangers that recover heat from various crude tower side-streams. The crude oil is usually on the tube side of these exchangers. Streams such as naphthas, top pumparound, and kerosene are typically used to heat the crude oil to the desired desalting temperature. 3.4

The desalter temperature is determined by its location in the crude preheat system. The characteristics of the crude oil that the unit was designed to process determine where in the preheat system the desalter is located. These characteristics include the amount of heat recovery anticipated from the various distillation cuts and the temperature-viscosity behavior of the oil. These effects are described in more detail in the section on emulsion breaking.

Wash Water Injection Wash Water Injection Locations Wash water is usually injected into the crude oil ahead of the mix valve. However, under certain conditions it may be beneficial to add part of the wash water upstream of the crude preheat exchangers. Many crudes contain dissolved calcium carbonate and other salts in the brine which exhibit inverse solubility. As the temperature of the crude increases, these salts can precipitate from solution and form a heavy scale in the preheat exchangers. This scaling reduces heat transfer, increases exchanger cleaning costs, and can limit crude unit capacity. Adding wash water ahead of the preheat exchangers reduces the scaling tendencies of these compounds by diluting the scale forming salts. Wash water will also help remove some particulate solids that may foul the exchanger. Adding wash water ahead of the preheat system may also be beneficial where the crude being processed is particularly sensitive to mixing. If the crude oil emulsion created by normal mix valve pressure differentials cannot be effectively resolved in the desalter, a more gentle mixing can be achieved by adding a portion of the wash water ahead of the preheat exchangers and decreasing the mix valve pressure drop. Salt removal efficiency can be maintained because of the longer water/oil contact time when water is added ahead of the preheat. Because of the higher process pressures at the front end of the preheat train, an additional wash water pump is sometimes required. Wash water should not be added to the suction of the crude charge pump because the high mixing energy created by centrifugal pumps will form a very tight emulsion that is difficult to separate. The dissolved mineral content of the wash water should be checked to make certain it will not contribute to scaling at the elevated temperatures in the preheat system. Wash Water Rates The amount of wash water used depends on the characteristics of the crude and the capabilities of the equipment on the unit. Occasionally the wash water rate is limited by the availability of suitable wash waters or by environmental constraints on the amount or quality of waste water leaving the plant. Refiners normally add 4-6 volume percent wash water to the crude oil. Lower gravity crude oils (i.e. 1524 API) typically require 6-9 volume percent wash water for optimum performance. This is because a higher droplet population density is needed to provide adequate coalescence in the more viscous lowgravity crudes. This is discussed in more detail in the section on emulsion characteristics. If too little wash water is used, desalting efficiency can be reduced. This is because the water droplets in the emulsion formed by the mix valve will be too far apart to collide with other droplets and coalesce in the electrical field. The result is less water removed from the crude. There is also less of a dilution effect on the brine that does remain in the crude. If too much wash water is used, the resulting emulsion can become conductive enough to cause current to flow between the grids, with a resulting decrease in voltage gradient. This reduces the driving force for droplet polarization, coalescence in the electrical field, and reduces desalting efficiency.

3.5

Wash Water Sources Common sources of desalter wash water include: •

stripped sour water.

•

unstripped process waters, such as preflash, atmospheric, and vacuum tower overhead condensates; and

•

municipal water (soft water only);

•

settled or filtered surface water (soft water only);

• well water;

The kind of wash water used depends on the relative quality, cost, and availability of potential wash water sources. Municipal water and treated surface waters are usually good sources of wash water because they contain few contaminants. Well waters are usually suitable but can cause brine exchanger scaling if the hardness levels are too high. Stripped and unstripped process waters are cheaper sources of wash water. These are often used to help remove contaminants such as phenols from the water. The disadvantage of using process water is that it can contain contaminants such as iron sulfide which can accumulate at the desalter interface and stabilize the emulsion. Emulsion stabilization can also occur if the pH of these process waters is high. High pHs are common in process waters due to the presence of ammonia and the addition of caustic at the sour water strippers to improve tower stripping efficiency. High pH emulsion stabilization is particularly troublesome with crudes high in naphthenic acid content. Naphthenate salts can be formed. They are strong surfactants and can cause high water carryover and oily effluent water. Some vacuum tower condensates also contain tight oil-in-water emulsions that can be diff icult to break in the desalter.

Desalter Mix Valve Purpose The mix valve is designed to provide enough shear energy to overcome the oil/water interfacial surface tension and ensure thorough contact between the wash water and the crude oil. This is accomplished by the energy dissipation (pressure drop or ∆P) taken across the valve. The higher the pressure drop the greater the mixing energy and the smaller the water droplets become. ∆ P Settings Mix valve pressure drop is an important operating parameter in the desalting system. The pressure drop or energy input directly affects the washing efficiency and the ability to separate water and oil in the desalting vessel. If the mix valve ∆P is too low, the contact between wash water and crude oil will be insufficient to achieve adequate desalting and solids removal. If the ∆P is too high, the water will be emulsified into the crude oil to such a degree that it becomes difficult to separate the oil and water phases in the desalter. Again, desalting efficiency is reduced and more oil can be present in the brine.

3.6

Desalter Vessels As mentioned earlier, desalting is a gravity separation of oil and water aided by heat, chemicals, and an electrical field. This separation occurs in the desalting vessel, which is usually an insulated horizontal cylindrical pressure vessel with hemispherical or ellipsoidal heads. These vessels are usually 10-14 feet in diameter and typically range from 20-140 feet in length. Some spherical desalters vessels are also in use. Electrical Grids Most desalters utilize an electrical field to promote the coalescence of water droplets from the emulsion layer in the desalting vessel. The effects of an electrical field in breaking crude oil emulsions are explained in Section IV of this manual under Electrical Field. In desalters, this electrical field is established between horizontal steel grids that cover most of the crosssectional area of the vessel where the grids are located. The physical size and layout of these electrodes determines the size of the treating field in each vessel. The treating field size limits the maximum effective desalting unit throughput for a given crude oil. Grid separation usually ranges between 6 and 12 inches. Each hot grid has a transformer that increases the voltage of the normal plant AC power supply (usually 440 V) to the secondary or grid voltage. This secondary voltage will reach 12 to 23 kV, depending on unit design. Voltage and amperage indicators for each grid are mounted on a panel next to the desalter and provide an indication of the condition of electrical fields within the vessel. A decrease in voltage accompanied by increased current draw is an indication that the conductivity of the crude oil between the grids is increasing. Vessel Size Each desalter vessel design provides a certain range of emulsion treating capacities, expressed as barrels per day (BPD) emulsion treated per square foot of treating area. The treating area is proportional to vessel andand diameter. maximum treatingtemperatures: capacity for a given desalter vessel is limited by treated oillength viscosity gravityThe at desalter operating 2

Vessel treating capacity, low-velocity vessels (BPD/ft )

∆d µ

= = =

45.5 log (∆d/µ) + 64.4 the difference in brine and oil density at operating temperature crude oil bulk viscosity at operating temperature

The higher the viscosity and lower the gravity, the lower the maximum treating capacity. This is why crude units (using similar desalter designs) processing lower gravity crudes need larger desalters than units charging lighter crudes at similar throughputs. This formula also shows why desalters on units changing to heavier crude slates may be within design specifications on crude rate, but can exceed design specifications on treating capacity.

Common Vessel Designs Most refinery desalters are designed by either Howe-Baker or Petreco. In Howe-Baker vessels or Petreco low velocity vessels the crude oil/wash water emulsion enters the desalting vesselof through a distribution header below the mid-line of the desalter. This header provides equal distribution the emulsion throughout the length of the vessel. The emulsion flows up through the electrical grids; dehydrated oil flows to the top of the vessel and is removed through a crude outlet header. Water droplets coalesce and fall to the bottom of the vessel. The brine is removed through the effluent water header or via effluent water nozzles on the bottom of the vessel. With Petreco high velocity designs (Cylectric and Bilectric) the emulsion is introduced horizontally between the electrical grids. These designs allow more oil to be treated per unit area of grid. The 3.7

advantage of the high velocity designs is that a smaller less expensive desalter vessel can be used. A disadvantage is higher operating cost due to the increased current flow. Some of the more important features of the various designs are summarized here. Howe-Baker Low Velocity Howe-Baker low velocity desalters utilize an emulsion distribution header that is typically located 2 ft. below the bottom grid (see Figure 3.3). This distributor consists of a pipe with holes along each side. There are two electrical grids. The bottom hot grid is located near the mid-line of the vessel. The upper grid is the ground grid. The distributor pipe can also act as a ground, providing a weak treating field below the hot grid.

Howe-Baker Desalter (Internal Design) END VIEW

DESALTED CRUDE

SIDE VIEW

DESALTED CRUDE

TRANSFORMER

HOT GRID

CRUDE OUTLET HEADER

( _)

(+)

MUD WASH HEADER

H2 O LEVEL MUD WASH

CRUDE INLET HEADER EFFLUENT WATER

EFFLUENT WATER HEADER MIX VALVE

MUD WASH

RAW RAW

EFFLUENT WATER

CRUDE

CRUDE WASH WATER WASH WATER

Figure SECTION 3: .3

These vessels tend to perform best when the emulsion layer is maintained approximately 6 inches below the level of the crude inlet distributor. Higher water levels may allow portions of the stable emulsion layer to be forced up into the grid area by the incoming crude. This can cause excessive amperage draw and reduced desalter performance. It also means that the water level in Howe-Baker vessels should be controlled to a maximum of 24-36 inches, depending on vessel diameter. Howe-Baker Tri-Electric The design of this vessel is similar to the Howe-Baker low velocity design except three grids are used to increase the size of the treating field. The top and bottom grids are hot, with a middle ground grid. Petreco Low Velocity Petreco's low velocity vessels utilize an inverted trough design for the inlet distribution header (Figure 3.4). Emulsion flows out of the distributor through holes in the sides of the trough. The bottom electrode grid is hot, and the upper grid is the ground grid. Two treating fields are provided a weak field between the upper and lower grids, and a strong field between the lower hot grid and the grounded distributor pan. 3.8

Petreco Low Velocity Desalter (Internal Design) E NV DI E W

S I DVEI E W DESALTED CRUDE

DESALTED CRUDE

GROUND GRID

TRANSFORMER

CRUDE OUTLET HEADER

( _) (+)

MUD WASH HEADER HOT GRID

H2O LEVEL

MUD WASH EFFLUENT WATER

H 2O LEVEL

CRUDE INLET DISTRIBUTOR

EFFLUENT WATER HEADER

MIX VALVE

MUD WASH

RAW RAW CRUDE

CRUDE

WASH WATER

MIX VALVE

EFFLUENT WATER WASH WATER

Figure SECTION 3: .4

Petreco recommends that the water level be maintained 6-12 inches above the top of the distributor to ensure even distribution of emulsion throughout the length of the vessel. The water level should never be lowered below the holes in the side of the distributor. Petreco claims that additional crude oil washing and emulsion coalescence are obtained by introducing the emulsion into the water phase. By carrying a higher water level in the vessel, the average water phase retention times are generally higher with Petreco designs. This fact may help these vessels maintain better effluent water quality relative to other designs, especially during upset conditions. Petreco Cylectric Cyelectric desalters use cone-shaped inlet nozzles that are designed to distribute the emulsion radially between the upper and lower electrode grids. There are typically 2-8 nozzles per vessel, depending on vessel length. Some Cylectric units use spherical vessels with a single cone distributor. Both grids are hot and are operated 180 out of phase. A flow baffle plate is located above the top grid over each distribution nozzle to help keep the emulsion flowing horizontally between the grids. There is a weak treating field below this baffle plate. The strong treating field is between the two hot grids. Additional mixing of the emulsion is provided across the gap between the inlet distributor bodies and the inside parabolic distributor cones. The spacing of this gap can be adjusted using external hand wheels. The Petreco design calls for a 3-7 psi D across the distributors. This D target can be achieved by opening all of the distributors, then closing all of them the same number of turns until 3-7 psi is measured between the mix valve and the vessel. Water levels in Cylectric desalters should be held at 12-24 inches below the bottom grid, this also provides a long water phase retention time.

3.9

Petreco Bilectric Bielectric desalters use circular plate inlet manifolds that direct the emulsion toward the walls of the vessel between upper and lower sets of grids (Figure 3.5). All three grids are energized and are operated 120 out of phase. This three-tiered electrode design doubles the effective size of the treating field for a given vessel size. In practice, Petreco claims that Bilectric desalters have about 1.75 times the treating capacity as low-velocity desalters of the same size. Water levels in Bilectric desalters should be held at 12-24" below the bottom electrode grid.

PETRECO BIELECTRIC DESALTER (INTERNAL DESIGN) END VIEW

SIDE VIEW DESALTED CRUDE TRANSFORMERS

TRANSFORMER

TRANSFORMER

LC

FLOW BAFFLE

HOT GRIDS FLOW BAFFLE

LC

DESALTED CRUDE

CRUDE OUTLET HEADER

DIST RIBUTO RHEADER

DIST RIBUT O RHEADER

MUD WASH MIX VALVE

MUDWASH HEADER

RAW CRUDE MUDWASH PUMP WASH WATER RAW CRUDE

MUD WASH HEADER

EFFLUENT WATER

EFFLUENT WATER MIX VALVE

WASH WATER

Figure SECTION 3: .5

Level Controllers Desalting vessels are operated liquid-filled, but it is important to be able to control the level of the oil/water interface in the vessel. If the level is too high, the amperage draw between the grids can increase due to the higher quantities of water. This will lower the voltage drop in the electrical field which adversely affects water droplet coalescence. Higher BS&W and salt levels in desalted crude will result. If the level is too low, excess oil may be drawn out of the vessel through the effluent water header. The interface level in the vessel is easily verified by checking the desalter trylines or by using a swing arm device. However, an interface level detection and control system must also be installed in order to provide effective automatic control of the desired interface level. Interface detection is accomplished by either displacement-type float devices, capacitance probes, or by microwave devices. Displacement devices are weighted to float at the oil/water interface and are calibrated to operate within a specific crude oil gravity range. These devices are usually used in units processing higher gravity crudes because of the relatively large density differences between the crude and the water phase. Capacitance probes work by detecting differences in electrical capacitance between water and oil. They are not affected by swings in crude oil gravity and are more often used in units processing a wider range of crude gravities. A recent technological development is microwave detectors or Agar probes, which are gaining popularity in heavy crude desalting applications. These probes measure differences in energy absorption between 3.10

oil and water. They can be tuned to detect relatively small amounts (e.g. 0.5% volume) of water in oil or oil in water. Two probes are usually used to monitor the emulsion level in a vessel. The electrical signal generated by the level detection device is sent to a transducer where it is converted to a pneumatic signal. The desalter interface level is controlled by a flow control valve installed on the effluent water outlet line. This valve will open or close depending on the level indicated. If the flow control valve is sized correctly and the reset interval on the feedback loop is set correctly, the interface level can be controlled effectively with little fluctuation in the effluent water flow rate.

Mud Wash Systems All crude oils contain a certain amount of solids such as silt, sand, clay, and iron particles. Many of these solids are removed in the desalter and leave the vessel with the effluent water. A portion of the solids can also accumulate in the bottom of the vessel to form mud or oily sludge. The sludge layer may build to a point where it plugs parts of the effluent water header or significantly decreases water phase residence time in the vessel. Many desalters utilize a mud wash system to keep this sludge from accumulating. A mud wash injection header is located in the bottom of the vessel. This header contains a number of injection nozzles that direct the flow of water down toward the bottom surface of the vessel. The water is injected through these nozzles at high velocities, stirring up the solids so they can be removed with the effluent water. The water used for mud washing is normally recirculated desalter effluent water, as shown in Figure 3.6. Some units use desalter wash water for mud washing. In some units, the wash water to the desalter must be blocked in while mud washing. The rate of water used for mud washing can be controlled manually with block valves or automatically with flow control valves. Desalter manufacturers design the mud wash system to deliver 5-10 gpm per nozzle.

Design of a Typical Desalter Mudwash System INTERFACE LEVEL IN VESSEL

MUDWASH HEADER & NOZZLES

LEVEL CONTROLLER DESALTER EFFLUENT WATER HEADER

TO SEWER & WASTE WATER TREATMENT PLANT

MUDWASH PUMP

ALTERNATE MUD WASH WATER SOURCE

Figure SECTION 3: .6

3.11

Howe-Baker recommends mud washing a minimum of three minutes per day for a typical mud washing system, while Petreco suggests mud washing for one hour once per week. However, the frequency and duration of mud washing is best determined through operating experience. The appearance of the desalter effluent water should be checked before, during, and after the mud wash procedure. In general, if the effluent water stays dirty or oily for more than 10 to 20 minutes after mud washing, the frequency of mud washing should be increased. If the effluent water stays clear or turns clear immediately after mud washing, then the frequency or duration should be decreased.

Two-Stage Desalting Some crude units use two-stage or double desalting in order to improve overall desalting efficiency. Installation of a second stage of desalting typically will increase overall desalting efficiency by 5-6%. The added expense of the extra stage can be justified based on the reduced fouling and corrosion seen in the crude unit and in lower sodium levels in residual fuel, in coke, and on FCCU catalyst. Figure 3.7 shows a schematic of a simple two-stage desalting system. Fresh desalter wash water is added ahead of the second stage mix valve. Second stage desalter effluent water is then used for wash water in the first stage of desalting. This is called a counter-current water washing process. Desalting efficiency is maximized by using the fresh water in the second stage. Desalted crude salt contents of 1 PTB or less often can be achieved with two-stage desalting.

Two Stage Electrical Desalting System DESALTED CRUDE FROM 1st STAGE

DESALTED CRUDE FROM 2nd STAGE

RAW CRUDE FEEDSTOCK 1st STAGE VESSEL

2nd STAGE VESSEL

CRUDE PREHEAT EXCHANGERS

CRUDE CHARGE PUMP BIC EMULSION BREAKING CHEMICAL

MIX VALVE

MIX VALVE

WASH WATER/ BRINE EXCHANGER

2nd STAGE EFFLUENT WATER TO 1st STAGE

FRESH DESALTER WASH WATER TO 2nd STAGE

1st STAGE EFFLUENT WATER TO SEWER

Figure SECTION 3: .7

Brine Recycle Desalter effluent water or brine can be recycled for use as desalter wash water in single-stage desalting operations. This is usually done when fresh wash water is scarce. By recycling a portion of the brine the refinery can provide the total volume of wash water needed to achieve sufficient crude oil washing and optimum water droplet coalescence in the desalter. In this way acceptable desalting and dehydration efficiencies can be maintained using fewer gallons of fresh wash water. Figure 3.8 shows the design of a typical brine recycle system. Brine from the discharge of the effluent water pump is re-routed to the main water injection line ahead of the mix valve. In this case 3% of the 3.12

total wash water used is recycled. The actual amount of brine recycled depends on the water availability and/or the volume of water that can be discharged.

Design of a Typical Brine Recycle System DESALTED CRUDE

RAW CRUDE CHARGE

LEVEL CONTROLLER

MIX VALVE

= BRINE RECYCLE RECYCLE WASH WATER FLOW INDICATOR

=

CONTROL VALVE

EFFLUENT WATER TO WASTE WATER

FRESH WASH WATER

TREATING PLANT

FLOW INDICATOR FRESH DESALTER WASH WATER

Figure SECTION 3: .8

Recycled brines have a higher salt content than fresh wash water, so the recycling of brine will cause the water droplets remaining in the desalted crude to have a higher concentration of dissolved salts. This means that after a certain level of crude washing and dehydration efficiency has been achieved, the desalted crude salt content will increase with the proportion of brine used as wash water. The costs of these incremental losses in desalting efficiency must be considered when determining the recycle rate to be used. The relationship between desalting efficiency versus percent recycle should be determined by actual experience on the crude unit.

3.13

Sample Points Several sample points are usually provided so that conditions in the desalter and the desalter performance can be monitored. All of these sample points should be located and verified when initially surveying a desalter system: 1.

raw crude;

2.

desalted crude for all vessels;

3.

desalter wash water;

4.

desalter effluent water (also called desalter brine, tailwater, or outlet water, etc.), and

5.

vessel trylines or swing arm interface sampler.

When collecting samples it is always important to flush out the sample line thoroughly so that representative samples are obtained. This is especially important with long sample lines or when common sample systems are used. Sample coolers are sometimes installed to prevent flashing of hot crude oil samples. Check the sample coolers to make sure that cooling water isn't leaking into the sample line.

Desalter Chemical Feed Points The most commonly used crude unit demulsifying chemicals are oil soluble and are added to the crude oil ahead of the desalter. Typical dosages for these desalting aids are 6 to 18 ppm with heavier crudes requiring more chemical than lighter ones. It is important that the oil-soluble demulsifiers be well-mixed into the crude oil charge. These products are usually injected into the suction of the crude charge pump because of the good mixing provided by the pump. Occasionally the crude charge pumps are located in the tank farm and not on the crude unit. If this is the case, it is preferable to inject the demulsifier at the crude unit ahead of the preheat exchangers. This will provide the crude unit operators with easier access to the chemical injection system and allow them to have better control of the chemical injection rates. The chemical injection location should be well ahead of any wash water additions so that the demulsifier will be uniformly dispersed before the wash water is emulsified into the crude charge. If the chemical is not being added to the crude pump suction, it should be fed with an injection quill into the center of the crude line to provide better dispersion. Due to the processing of heavier, higher solids, crudes and increased restrictions on oil-in-brine, many desalters now require the addition of wetting agents and polymers. The wetting agents will help deoil solids removed with the wash water. Polymers will break any reverse emulsion (oil-in-water) which may appear in the brine, giving a more consistent oil free tail water. Wetting agent dosages can vary from as little as 0.5 ppm to as high as 6 ppm based on the oil throughput. The amount required will depend on the nature and quantity of filterable solids present in the oil. Wetting agents have been traditionally injected into the wash water at rates up to 3 ppm. More recently, we have been very successful injecting higher rates into the oil. This is most often done during the mud wash cycle to aid in solids removal but can be done on a longer term basis if very high solids are present in the crude.

3.14

If added to the wash water, the wetting agent should be injected on the suction side of the wash water pump to insure adequate mixing. The injection point for adding wetting agents directly into the oil is at the crude charge pump. It can be injected with the demulsifier if pumped only a short distance after mixing, however a separate injection point is preferred. If unable to inject it at the charge pump, it can be injected downstream as long as it is mixed with crude before wash water addition. Polymer is best injected on the discharge side of the wash water pump. This will avoid any shearing of the polymer by the pump. When adding polymer to a two stage desalter it must be injected after the second stage as the water cascades to the first stage. Again the discharge side of the interstage pump is the preferred spot. In two stage desalting, polymer is normally added only to the first stage to clarify the brine prior to discharge to the sewer. While cationic emulsion polymer is typically the product of choice, cationic solution polymers have also been used successfully. It is not necessary to predilute the polymer if it can be adequately mixed with the wash water prior to contacting the crude. Do Not inject neat emulsion polymer directly into the crude oil. This has caused problems with polymer coating desalter internals necessitating unit shutdown. Typical dosages are 0.5-1.0 ppm based on the crude rate. While polymer can be fed continuously it is most often fed as needed. Chemical treatment of crude in tankage to improve desalter operation is becoming more common. This is best accomplished by adding demulsifier to the crude as it is off loaded from a tanker or to the pipeline as the crude enters the refinery tank farm. Treatment dosages will range from 4 to 25 ppm based on the quality of the crude oil. For additional information about chemical injection refer to the section titled "Desalter Program Trials".

Characteristics Of Crude Oil Emulsions The desalting process involves the formation of an emulsion of wash water in crude oil and then breaking the emulsion in the desalter. An understanding of the physical and chemical properties of emulsions will help explain the significance of the chemical and operational variables that affect desalter performance.

Definition of an Emulsion By definition, an emulsion is a stable dispersion of two immiscible liquids. Every emulsion has a continuous external phase and a dispersed internal phase. Emulsions that have oil as the continuous phase and water as the dispersed phase are called water-in-oil, W/O emulsions. The crude oil/wash water emulsion formed by the mix valve in the desalting process is an example of a water-in-oil emulsion. Emulsions where water is the continuous phase and oil is the dispersed phase are called oilin-water O/W, emulsions. An example of an oil-in-water emulsion is oily desalter effluent water where oil droplets are dispersed into a continuous water phase.

Emulsion Formation When pure water and uncontaminated oil are carefully poured into a container the two liquids will not mix together, i.e. they are immiscible. The hydrocarbon will float on top of the water because of its lower specific gravity. Due to the high interfacial tension between the oil and water it is unlikely that a stable emulsion will form under these conditions. Two conditions must occur to form an emulsion from immiscible liquids. First, some kind of mixing energy must be applied to the system to overcome the interfacial tension. Second, an emulsion stabilizing agent must be present to prevent the emulsion from separating after the mixing energy has been removed from the system. Mixing or Shear Energy In desalting applications the shear energy is provided by the mix valve located ahead of the desalter. The amount of shear energy applied to the crude oil/wash water mixture is controlled by adjusting the energy dissipation or pressure drop across the mix valve. When the crude/water mixture passes through 3.15

the high shear of the mix valve, the energy expended in the pressure drop disperses the water into small droplets. Unit operators can increase the desalter mix valve pressure drop to provide better contact between the crude oil and wash water for efficient desalting, or decrease the ∆P to prevent a stable emulsion from building in the desalter vessel. In cases where wash water is added ahead of the crude preheat train, some additional shear energy is provided as the crude/water mixture passes through pipe fittings, heat exchangers, and flow control valves. This source of mixing energy is generally not controllable. Emulsion Stabilizers The other requirement for forming a stable emulsion is the presence of emulsifying agents or emulsion stabilizers. There are several sources of these emulsifying agents in desalting systems. Crude oil contains a number of naturally occurring organic emulsifying agents such as asphaltenes, organic acids and porphyrins, plus finely divided solid materials such as clay, sand and silt. Synthetic emulsifiers such as sulfonates may also be added to the crude oil during production. Any slop oils added to the crude charge can also contain species such as suspended solids and surfactant chemicals that will stabilize the emulsion in the desalter. Surface active molecules have a lipophilic (fat-loving) portion which tends to be soluble in hydrocarbons such as crude oil, and a hydrophilic portion (water-loving) that tends to be soluble in water. The general structure of surfactant molecules is shown in Figure 3.9. These molecules tend to concentrate at the interface between the oil and water phases in the emulsion. These agents stabilize the interface making it more difficult for coalescence and separation to occur. Figure 3.10 depicts how these surface active agents are oriented in the interfacial area surrounding a water droplet suspended in a continuous oil phase. Solid particles are also shown in the stabilized film around the water droplet.

Generalized Structure of a Surfactant Molecule O I LS O L U B L E

W A T E RS O L U B L E

HYDROPHOBIC END

HYDROPHILIC END

(WATER-FEARING; RELATIVELY NON-POLAR) TYPICALLY A LINEAR OR BRANCHED HYDROCARBON FUNCTIONAL GROUP

(WATER-LOVING; RELATIVELY POLAR) CAN BE AN ANIONIC, CATIONIC OR NON-IONIC FUNCTIONAL GROUP

Figure SECTION 3: .9

3.16

Solids and Surfactant Molecules Stabilizing The Oil - Water Interface Emulsion - Stabilizing Solids

Emulsified Water Droplet

OIL Emulsion Stabilizing Molecules Figure SECTION 3: .10

Surface active agents are usually classified according to the type of hydrophilic functional groups they contain: Anionic surfactants contain functional groups that have a negative charge in polar solvents. An example is a carboxylic acid (R-COO-). Cationic surfactants contain functional groups that have a positive charge in polar solvents. An example is a quaternized amine compound (R3-NH+). Nonionic surfactants contain functional groups that have no charge but will hydrogen bond to water molecules in aqueous solutions. Among the most troublesome emulsion stabilizers in crude oil desalting applications are naphthenic acids. Naphthenic acids are naturally occurring high molecular weight organic acids that are found in varying amounts in all crude oils. Naphthenic acids are saturated five membered ring compounds containing mono-carboxylic acid side chains of varying lengths. Naphthenic acids are particularly strong surfactants when they are present as their sodium or potassium salts. These salts can be formed when the pH of the desalter wash water is above 7.5. This is why units processing crudes containing high levels of naphthenic acids can have severe emulsion problems, especially when high pH wash water is used.

Emulsion Resolution The shear or mixing energy imparted by the desalter mix valve emulsion disperses the wash water into the crude oil in the form of very small droplets. Figure 3.11 is a diagrammatic representation of the physical and chemical mechanisms involved in demulsification of the water-in-oil emulsion. The demulsification is the resolution of the emulsion to a lower free energy state where a continuous layer of a less dense fluid (oil) floats on a continuous layer of a more dense fluid (water). There are several steps 3.17

involved in splitting the W/O emulsion into two layers. In simplest terms, the small water droplets are turned into larger drops which are then able to undergo gravitational settling.

Physical Process of Emulsion Breaking

FLOCCULATION

SEDIMENTATION

COALESCENCE

COALESCENCE

SEDIMENTATION

OIL

COALESCENCE

WATER Figure SECTION 3: .11

Flocculation is the process by which individual small droplets stick together to form agglomerates containing several droplets. Coalescence occurs when droplets that are touching each other come together to form a single larger droplet. Sedimentation is the gravitational settling of the dense water droplet through the emulsion. Generally less important in desalting applications is Oswald Ripening which involves the diffusion of molecules from small drops to large drops. All of these steps hasten emulsion resolution by making bigger droplets. In this model of emulsion resolution the result of the collision between droplets is an important consideration. If the droplets bump into each other and bounce off, the emulsion will not be broken. If the droplets stick to each other (flocculate) when they collide, they can then coalesce, or form bigger drops and fall below the hydrocarbon phase. Surface active emulsifying agents can have a significant effect on the outcome of these collisions. If emulsifying agents are sufficiently stabilizing the oil/water interface around the droplets, the droplets will not coalesce and the emulsion will not be easily broken. Emulsion breaking chemicals help break crude oil emulsions by counteracting the effects of emulsion stabilizing agents at the oil/water interface.

3.18

Gravitational Force and Stokes' Law Emulsions break when water droplets settle out of the oil phase. The separation of the two liquids is best described by Stokes' Law. V = K (ρ w - ρ o) G d ηo

where:

V K ρw ρo G d ηo

= = = = = = =

2

Velocity of falling water drop Aconstant Density of water Density of oil Gravitational acceleration Diameter of water droplets Viscosity of bulk media (oil)

The velocity of the falling water droplet or the speed of the separation can be altered by changes in the physical characteristics of the liquids. Crude oil desalting units are designed to provide optimum physical conditions for fast resolution of specific crudes. This means that the desalters' electrical grids provide a high intensity electrical field to promote droplet coalescence into larger drops (increased "d"). The relatively high temperature of the unit (200-300°F) reduces crude oil viscosity (ηo).

3.19

Control Of Desalter Operational Variables As indicated throughout this manual, there are a number of factors that affect emulsion stability in a desalter. Some of the most influential factors include: Crude oil density Desalter temperature Status of electrical grids Wash water rate Wash water pH Mix valve ∆P Desalter interface level Desalter pressure Emulsion stabilizers in the crude oil or wash water Emulsion breaking chemicals The following sections discuss the impact of these key operating variables on crude oil desalter performance. Crude Oil Density Emulsions can break into separate oil and water phases because water has a higher density than crude oil. Stokes' Law shows that the greater the difference in the density between crude oil and wash water (ρw - ρo), the faster the separation. The oil/water density differential term in Stokes' Law has important implications for desalting. First, it explains why higher density or lower gravity crude oils are usually more difficult to desalt. When the density of the crude oil approaches the density of water the water droplets fall through the emulsion at a much lower velocity. Viscosity is also a factor because low gravity crudes are usually more viscous than high gravity crudes. In order to obtain the desired dehydration efficiency in the desalter, the velocity of the rising oil phase in the vessel cannot exceed the velocity of the falling water droplets. The oil phase velocity can only be decreased by reducing the rate of oil charged to the vessel or by increasing the size of the vessel. This is why crude units designed to process high density, lower gravity crudes must have larger desalting vessels than units processing low density, higher gravity crudes at equivalent throughputs. Though it has a large impact on emulsion separation, the gravity of the crude oil is usually not a variable within the control of refinery operations. However, some refiners that process very low gravity crudes add recycled light hydrocarbon into their crude charge in order to increase the oil/water density differential and the speed of the emulsion separation.

Desalter Temperature Although temperature does not appear in Stoke's Law, it does have an effect on the rate at which the emulsion breaks. The viscosity of crude decreases with increasing temperature. This relationship is shown graphically in Figure 3.12. You can see in Stokes' Law that the velocity of the falling water droplet (V) is inversely proportional to the crude oil's viscosity. As a result, lower crude viscosity makes it easier for water droplets to separate from the hydrocarbon phase.

3.20

Characteristic Temperature - Viscosity Relationship for Crude Oils 5000 S D 2000 N 1000 O C 500 E 200 S T L 100 O B Y A 60.0 S Y 45.0 IT S O C IS V 35.0 80.0 100

1200 450

10º API

120

12º API

16º API

20.0 22º API

5.5

30º API 36º API

130

210 TEMPERATURE - ºF

S E K O T IS T N E C Y T I S O C S I V

2.5 300

Figure SECTION 3: .12

Higher desalter temperatures promote emulsion breaking or more efficient droplet coalescence by: •

increasing the solubility of some naturally occurring emulsion stabilizers such as Nathenic acids in the oil phase,

•

increasing the frequency of collisions between droplets, and

•

diffusing emulsion breaking chemicals to the oil/water interface faster.

Desalter temperatures can also have an effect on the density differential between crude oil and water. The relationship between crude and water densities vs. temperature is shown in Figure 3.13. This graph shows that for crude gravities of approximately 35°API and higher, increases in desalter temperature above 200°F will increase the crude/water density differential. For crude oil gravities of about 20°API and less, increases in desalter temperature above 200°F will narrow the density differential.

3.21

Temperature - Density Relationship For Oils, Water and Brine 20,000 ptb NaCl Brine 4.5º API 10,000 ptb NaCl Brine 7.0º API FR ESH W ATER

1.00 Y IT V A R G C I F I C E P S

10º API

16º API

22º API

0.90

30º API

36º API

0.80

100

200

300

TEMPERATURE - ºF Figure SECTION 3: .13

The effect of desalter temperature on crude oil and water densities has a minimal impact on most refinery desalter operations. However, when desalting very low gravity crudes desalter temperatures above 250°F are needed to reduce crude oil viscosity to an acceptable level. In these cases it is sometimes necessary to use heavy brine for desalting to ensure that the wash water is more dense than the crude oil. Crude oil is brought up to desalter operating temperature in the crude preheat exchangers ahead of the desalter. Any decreases in the heat recovered in the crude preheat exchangers can reduce desalter performance. Decreased heat recovery can be caused by exchanger fouling, changes in tower pumparound rates, by changes in feedrates, or changes in unit feed characteristics. There are also upper limits on desalter operating temperatures. Crude oil becomes more conductive at higher temperatures. This can decrease the effectiveness of the electrical grids. High temperatures can also cause vaporization of lighter components in the crude oil. The resulting turbulence in the desalter vessel will reduce emulsion breaking efficiency.

Electrical Field The effect of the electrical field in desalters is to induce a polarization of the water droplets in the emulsion. As shown in Figure 3.14, the part of the droplet nearest the positive electrode will have a negative charge and the part near the negative electrode will have a positive charge. Since opposite charges attract, the droplets will become attracted to each other and can coalesce into larger droplets. This electrically induced flocculation and coalescence of water droplets greatly increases the rate of emulsion breaking in the desalting vessel because large droplets separate faster than small droplets. Operation of the electrical grids is typically trouble-free, though shorts can occur. Problems can usually be detected with the voltage and amperage indicators. Voltage and amperage readings will vary from unit to unit but should be nearly equal for each grid. They should not fluctuate under normal conditions.

3.22

Coalescence of Water Droplets In an Electrical Field (_)

(_)

+ + + +++ + + + +

OIL

d1

_ _ _ __ _ _

OIL

++ + + +++ +

OIL

d2

+ + + +++ + + + +

_ _ _ __ _ _ _

d1

_ _ _ __ _ _ _

OIL

LARGER DIAMETER DROPLET SETTLES FASTER THAN SMALLER DROPLETS

OIL

(+)

OIL

(+) Figure SECTION 3: .14

Wash Water Rate As mentioned in the discussion of desalting parameters, the amount of wash water added ahead of a desalter is critical to maintain good desalting efficiency. Higher volumes of fresh wash water provide a greater dilution of the crude oil salts. However, water wash rates also affect the efficiency of crude oil emulsion resolution because of the relationship between wash water rate and water droplet population density within the emulsion. The water droplet population density can be expressed in terms of d, the distance between droplets in the electrical field. The effect of d on water droplet flocculation and coalescence in an electrical field is related by the formula: F = Where F K E a d

= = = = =

2

6

KE a 4 d the force of attraction between water droplets in an electrical field, aconstant, the voltage gradient between grids, the radius of adjacent water droplets, and the distance between droplets in the electrical field.

When desalter water wash rates are low, the population density of water droplets is also low. As the distance between water droplets (d) increases, the induced polarization of the droplets in the electrical field becomes too slight to effectively promote droplet coalescence. The efficiency of emulsion separation in the desalter decreases, resulting in high desalted crude BS&W and salt content. Better droplet coalescence and emulsion separation can be achieved by increasing the water droplet population density, i.e. by increasing the wash water rate. However, if the wash water addition rate is too high, the crude emulsion can become too conductive. When this happens, the voltage cannot be maintained on the desalter electrodes and the droplets will not be effectively polarized. This will also result in high desalter crude BS&W's and salt content. 3.23

Wash Water pH Desalter wash water pH can have a significant effect on desalter performance. It is usually best to maintain desalter wash water pHs in the near-neutral range of about 5.5 to 7.5. Lower wash water pHs can result in desalter corrosion problems. However if there is a wash water pH problem it is more likely to be from high pHs. High pH wash waters are more common in most units because of the use of process waters that can contain high levels of ammonia. Sometimes caustic is added to the sour water stripper feed water in order to elevate the pH to increase ammonia stripping efficiency. Occasionally, spent caustic is injected into desalter wash water as a means of disposal and can also increase the pH of wash water. If desalter wash water pH is above 7.5 it can promote emulsion stabilization, greater oil undercarry and poor crude oil dehydration. At higher pH's naturally occurring naphthenic acids in the crude oil become ionized and form sodium or potassium naphthenate soaps which are powerful emulsion stabilizers. In some cases high pH wash waters can also cause iron sulfide formation in the desalter, resulting in increased filterable solids content in the desalted crude. If the water in the emulsion contains high levels of calcium, and magnesium carbonate or sulfate, high wash water pHs can also cause sludge buildup in the desalter and scaling in the effluent water piping and brine exchangers. The water solubility of carbonate and sulfate salts of calcium and magnesium decreases with increasing temperature and pH. Some refiners use acid injection to control the wash water pH. This reduces scaling and emulsion stabilization problems caused by high wash water pH.

Mix Valve ∆ P The mix valve setting is one of the most important operating parameters in a desalting system. Mixing energy is controlled by adjusting the desalter mix valve pressure differential or ∆P. This pressure drop is used to disperse the wash water into small droplets within the crude oil. This provides the intimate contact between the crude and wash water that is necessary for desalting. If the ∆P is too low, desalter efficiency will decrease. If the mixing energy is too high, the emulsion formed may be too stable to break. This effect can be illustrated by looking at the formulas describing the attraction between droplets in an electrical field and in Stokes' Law. In these expressions, the tendency for droplets to flocculate in an electrical field and the velocity of droplet separation by gravity are both reduced with decreasing droplet diameter. Figure 3.15 shows the relationship between mix valve pressure drop and the desalted crude salt and BS&W content. The desalter mix valve ∆P should be adjusted so that the efficiency of both salt and BS&W removal is maximized. In general, desalters processing lower gravity crudes (15-24 API) will use pressure drops of 5 to 12 psi. Emulsions of higher gravity crudes (25-45 API) are generally easier to break. As a result, higher mixing energies are used in these systems, usually in the 10 to 20 psi range.

3.24

Desalter Mix P vs. Desalted Crude Salt and BS&W Content 100

E D U R 80 C D E T 60 L A S E D 40 IN T L A 20 S %

-

% B S & W I N 1.0

SALT CONTENT

0.8

OPTIMUM MIXING PRESSURE

0.6 0.4

}

0.2

BS & W

-

0

-

-

-

-

-

-

0

D E S A L T E D C R U D E

INCREASING MIXING PRESSURE

The optimum range of mix valve pressure drops not only varies from unit to unit but will even vary on a single unit, depending on unit throughput and crude and wash water characteristics. The optimum pressure drop setting is determined by unit experience. However, it is sometimes necessary to reestablish the optimum mix valve ∆P setting due to changing process conditions or in an effort to optimize desalter performance. To do this, open the mix valve to reduce the ∆P to its minimum. After 2 hours, sample the desalted crude, test for salt and BS&W content, and check the condition of the effluent water. Increase the pressure drop in 2 or 3 psi increments, allowing at least 2 hours between changes for the system to reach equilibrium. Recheck the desalted crude and effluent water quality. Repeat these steps until a ∆P vs. BS&W profile similar to Figure 3.15 can be established. Keep increasing the pressure drop until the desalted crude BS&W and salt content both increase. Reduce the ∆P to the level where the salt and BS&W levels are minimized.

Desalter Interface Level Experience usually tells where the optimum level of the desalter should be. In Howe-Baker vessels, the water level should be held 6 to 12" below the inlet distribution header. For Petreco low-velocity desalters, the water level should be held about 6 inches above the top of the crude inlet header to ensure even distribution of emulsion in the vessel. Petreco Cylectric and Bilectric designs call for the water level to be held 12 to 24" below the bottom electrode grid. Petreco high-velocity desalters can also be operated at relatively high interface levels since most of the emulsion treating takes place between the electrical grids. Running a higher water level increases the retention time of the water phase. This can improve effluent water quality.

3.25

Desalter Pressure The operating pressure of desalter vessels is an important parameter. Most desalting vessels operate between 50 and 250 psig, depending on the crude charge pump discharge pressure and location of the vessel in the preheat train. Desalter pressure must be sufficient to prevent vaporization of the anticipated crude oil blends at the normal range of desalter operating temperatures. Howe-Baker recommends operating pressures of at least 20 psi above the vapor pressure of the crude/water mixture at the operating temperature. If vaporization does occur, the resulting turbulence in the vessel will decrease emulsion breaking efficiency and desalter performance. A high degree of vaporization can cause a vapor space to form in the top of the vessel. If this happens, the vessel's low level switch will cut power to the electrical grids, resulting in significant desalter performance problems.

3.26

Demulsifier Product Chemistry The components formulated into Baker Petrolite demulsifier products contribute to good desalter performance in many ways: 1.

Surface active components displace emulsifying agents at the oil/water interface and promote the coalescence of water droplets.

2.

Wetting agents "wet" the surface of solid particles so that they can be removed from the oil phase or the oil/water interface and be dispersed into the water. This reduces the solids content of desalted crude and promotes flocculation and coalescence of water droplets.

3.

Flocculants draw droplets and particles together to form large agglomerates. They also reduce emulsion layer volume at the oil/water interface.

4.

Some emulsion breaker components help break oil out of the wash water, thus producing cleaner tailwater.

Other demulsifier components promote more complete dehydration of the crude oil leaving the desalter. The combined effect of all these demulsifier chemistries is a reduction of oil in the desalter effluent water and lower crude salt and solids content. The quicker emulsion break afforded by use of emulsion breaking chemicals also allows the mix valve P to be held at higher settings. This increases salt removal efficiency. The major types of demulsifiers used in desalting applications are alkoxylated alkyl-phenol/formaldehyde resins. There are also several other classes of compounds commonly utilized in demulsifier formulations in lesser amounts. Just as emulsion-stabilizing agents have differing water/oil solubilities, demulsifiers must have varying solubilities to counteract these forces. Because the exact nature of the emulsifying agents present in a given crude are usually unknown, it is always necessary to conduct bench tests to select the demulsifier or blend of demulsifiers best suited to resolve a particular emulsion. The procedures used and the criterion on which to base the final product selection are discussed in the Baker Petrolite Field Emulsion Breaker Screening Procedure included in the appendix. However, demulsifier screenings and selection are best done in a laboratory setting by experienced emulsion breaking chemists using bench scale electrostatic precipitators designed for this purpose. Whenever possible, crude oil and wash water samples should be sent to Sugar Land for complete emulsion breaker testing.

3.27

Desalter Troubleshooting Most desalters experience periodic performance problems, and as chemical suppliers we are usually involved in and are often responsible for troubleshooting the problem. The problems are sometimes obvious and it pays to first check basic parameters such as chemical feed rate and desalter temperature, pressure and level. Many problems are also caused by feedstock changes, especially changes in slop oil addition rates or crude feed tank switches. This section provides some more specific troubleshooting guidelines to follow when looking for the solution to desalter operating difficulties.

3.28

Problem: High Crude BS&W PossibleCauses I.

High raw crude BS&W

RemedialMeasures 1. Check raw crude BS&W. 2. Check feed slate for changes. 3. Check desalter efficiency. 4. Check wash water rate go to VI. 5. If wash water rate is high cut-off entirely or reduce back to the normal level. 6. If necessary, reduce mix valve delta P go to III. 7. Check wash water and brine pH 8. Allow system to equilibrate. 9. Check desalter outlet crude BS&W.

II.

Chemical dosage is too low.

III. Mix valve delta p is too high

1. 2. 3. 4. 5.

Check demulsifer dosage. If necessary, increase demulsifier dosage. Allow system to equilibrate. Check desalter outlet crude BS&W. Repeat steps 1, 2, 3 & 4 until BS&W removal improves.

1. Reduce mix valve delta P by 2 psi. 2. Allow system to equilibrate. 3. Check desalter outlet crude BS&W. 4. Repeat steps 1, 2, & 3 until BS&W removal improves.

IV. Desalter interface level is too high. 1. 2. 3. 4. 5.

Verify desalter interface level. If necessary, decrease desalter interface level. Check the condition of the interface controller. Check desalter outlet crude BS&W. Repeat steps 1, 2, 3 & 4 until BS&W removal improves.

V. Emulsion layer is building.

1. Check emulsion layer with trycocks or swing arm sampler. 2. Check mix valve delta P. 3. Check demulsifer dosage. 4. Check wash water & brine pH. 5. If necessary, reduce mix valve delta P go to III. 6. If necessary, increase demulsifier dosage go to II. 7. If pH is high, identify and correct the problem. 8. Allow system to equilibrate. 9. Check desalter outlet crude BS&W.

VI. Incorrect wash water rate.

Low wash water rate. 1. If necessary, increase wash water rate. 2. Allow system to equilibrate. 3.29

Problem: High Crude BS&W PossibleCauses

RemedialMeasures 3. Check desalter outlet crude BS&W. 4. Repeat steps 1, 2, & 3 until BS&W removal improves. High wash water rate. 1. 2. 3. 4.

VII. Electrical system problem.

If necessary, decrease wash water rate. Allow system to equilibrate. Check desalter outlet crude BS&W. Repeat steps 1, 2, & 3 until BS&W removal improves.

1. Check voltage on desalter. 2. Check amperage meters. 3. If necessary, see section on electrical problems.

3.30

Problem: High Salt Content PossibleCauses 1. HighBS&W

RemedialMeasures 1. RefertoProblem:H ighCrudeBS&W.

2. Mix valve delta p is too low

1. Increase mix valve delta P by 2 psi. 2. Allow system to equilibrate. 3. Check desalter outlet crude BS&W. 4. Repeat steps 1, 2, & 3 u ntil salt efficiency removal improves.

3. Low wash water rate.

1. Increase wash water rate. 2. Allow system to equilibrate. 3. Check desalter outlet crude BS&W. 4. Repeat steps 1, 2, & 3 u ntil salt efficiency removal improves.

3.31

Problem: Oily Effluent Water PossibleCauses I.

Chemical dosage is too low.

II. Desalter interface level is too low.

RemedialMeasures 1. 2. 3.

Check demulsifer dosage. If necessary, increase demulsifier dosage. Allow system to equilibrate.

4. 5.

Check desalter effluent water quality. Repeat steps 1, 2, 3, & 4 until effluent water improves.

1. 2. 3. 4. 5.

Verify desalter interface level. Check the condition of the interface controller. If necessary, increase desalter interface level. Check desalter effluent water quality. Repeat steps 1, 3, & 4 until effluent water improves.

III. Mix valve delta p is too high

1. 2. 3. 4.

Reduce mix valve delta P by 2 psi. Allow system to equilibrate. Check desalter effluent water quality. Repeat steps 1, 2, & 3 until effluent water improves.

IV. High raw crude BS&W

1.

Check feed slate for changes. Determine if changes will be long-term requiring a change in the chemical program. Check for addition of slop oil. Stop the addition of slop oil if possible. Refer to Problem: High Crude BS&W.

2. 3. 4. V. Increased chemical emulsion stabilizers in feed.

1. 2. 3. 4.

Check feed slate for changes. Check for increased slop oil feed rate. If found, increase chemical dosage go to I. If necessary, reduce slop oil feed.

VI. Sludge accumulation in vessel

1.

Check temperature of all effluent water outlet lines. Cool lines indicate pluggage. Remove sludge from the vessel with mud wash.

2. 3. 4. 5.

Allow system to equilibrate. Check desalter outlet effluent water. Repeat steps 1, 2, 3, & 4 until effluent water improves.

3.32

Problem: High Interface Build-up PossibleCauses I.

Chemical dosage is too low.

RemedialMeasures 1. 2. 3.

Check demulsifer dosage. Increase demulsifier dosage. Allow system to equilibrate.

4. 5.

Check level. Repeatinterface steps 1, 2, 3, & 4 until interface level improves.

II.

Mix valve delta p is too high

1. 2. 3. 4.

IV.

High raw crude BS&W

1.

2. 3. 4. 1. 2. 3. 4.

Reduce mix valve delta P by 2 psi. Allow system to equilibrate. Check interface level. Repeat steps 1, 2, & 3 until interface level improves. Check feed slate for changes. Determine if changes will be long-term requiring a change in the chemical program. Check for addition of slop oil. Stop the addition of slop oil if possible. Refer to Problem: High Crude BS&W.

V.

Increased chemical emulsion stabilizers in feed.

Check feed slate for changes. Check for increased slop oil feed rate. If found, increase chemical dosage go to I. If necessary, reduce slop oil feed.

VI.

HighwashwaterpH

1. 2. 3.

CheckwashwaterpH. If high determine cause. If necessary change wash water source to correct problem.

VII.

HighbrinepH

1. 2.

CheckbrinepH. If wash water pH is normal but brine pH high, determine source in crude oil causing high pH.

3.33

Problem: Fluctuating Voltage PossibleCauses I.

II.

High water level in the vessel.

A stable emulsion layer is building.

III. Mix valve delta P is too high

RemedialMeasures 1.

Check emulsion layer with trycocks or swing arm sampler. 2. Check the condition of the interface controller. 3. 4.

If necessary, decrease desalter interface level. Repeat steps 1, 2, 3 & 4 until voltage remains steady.

1. 2. 3. 4. 5. 6. 7. 8.

Check emulsion layer thickness. Check emulsion layer water content. Check wash water pH. If overmixing is evident, go to III. Increase demulsifier dosage. Allow system to get to equilibrate. Check system voltage. Repeat steps 4, 5, & 6 until voltage remains steady.

1. Reduce mix valve delta P by 2 psi. 2. Allow system to get to equilibrate. 3. 4.

IV. High wash water rate.

Check system voltage. Repeat steps 1, 2, & 3 until voltage remains steady.

1. Check wash water rates. 2. Check water content of e mulsion after mix valve, if possible, to check water flow meter accuracy. 3. If necessary, decrease wash water rate. 4. Allow system to get to equilibrate. 5. Check system voltage. 6. Repeat steps 1, 3 & 4 until voltage remains steady.

3.34

Problem: High Current Flow PossibleCauses I.

High water level in the vessel.

RemedialMeasures 1.

Check emulsion layer with trycocks or swing arm sampler. 2. Check the condition of the interface controller. 3. If necessary, decrease desalter interface level. 4. 5.

II. A stable emulsion layer is building.

III. Mix valve delta P is too high

Check system current. Repeat steps 1, 2, 3 & 4 until current rate improves.

1. Check emulsion layer thickness. 2. Check emulsion layer water content. 3. Check wash water pH. 4. If overmixing is evident, go to III. 5. Increase demulsifier dosage. 6. Allow system to equilibrate. 7. Check system current. 8. Repeat steps 4, 5, & 6 until current rate improves. 1. Reduce mix valve delta P by 2 psi. 2. Allow system to equilibrate. 3. 4.

Check system current. Repeat steps 1, 2, & 3 until current rate improves.

IV. High wash water rate.

1. Check wash water rates. 2. Check water content of emulsion after mix valve, if possible, to check water flow meter accuracy. 3. If necessary, decrease wash water rate. 4. Allow system to equilibrate. 5. Check system current. 6. Repeat steps 1, 3 & 4 until voltage remains steady.

V. Water slug in crude charge.

1. Check raw crude BS&W. 2. Investigate the source of incoming water. 3. Monitor system to maintain the proper incoming water rate.

VI. High operating temperature.

1. Check desalter inlet crude temperature. 2. If necessary, decrease the temperature. 3. Allow system to equilibrate. 4. Check system current. 5. Repeat steps 1, 2, 3 & 4 until voltage remains steady. 3.35

Problem: High Current Flow PossibleCauses

RemedialMeasures

3.36

Problem: Electrical Failure PossibleCauses I.

Vaporization in vessel.

RemedialMeasures 1. Low level switch will shut off power to the grids. 2. Check desalter inlet crude temperature. 3. If necessary, decrease the tem perature. 4. 5. 6. 7.

Check desalter pressure. If necessary, increase pressure. Allow system to equilibrate. Repeat steps 2, 3, 4, 5, & 6 until until the system is back on spec.

II.

High water level in the vessel.

1. Check emulsion layer with trycocks or swing arm sampler. 2. Check the condition of the interface controller. 3. If necessary, decrease desalter interface level. 4. Check system current. 5. Repeat steps 1, 2, 3 & 4 until current rate improves.

III.

Water slug in crude charge.

1. Check raw crude BS&W. 2. If necessary, block in wash water. 3. Investigate the source of incoming water. 4. Monitor system to maintain the proper incoming water rate.

IV.

A stable emulsion layer is building.

1. Check emulsion layer thickness. 2. If a stable emulsion exists, turn off wash water for one hour. 3. When the voltage returns to normal levels, open the mix valve all the way. 4. Reintroduce water wash injection. 5. Slowly increase mix valve delta P by 2 psi until the desired performance levels are achieved.

V.

Interrupted flow of crude oil.

1. Low level switch will shut off power to the grids. 2. Check low level switch status. 3. Re-establish flow.

VI.

Interrupted power supply. Damage to the power transformer or entrance bushing. Failure of internal insulators. Electrical grid has grounded.

Have a plant electrician investigate these problems.

3.37

Desalter Program Trials In this section, we will discuss the three phases of a desalter trail. Phase 1:

Pre-trial preparation

Phase2:

Trial

Phase 3:

Post-trial performance evaluation

For a successful trial, all phases must be carefully thought out, planned, and executed. A trial entered into without preparation is an invitation to failure. A trial which is not executed according to accepted engineering practices is not given every chance to succeed. A trial, whether a success or a failure, may never be fully understood without a complete data base for analysis. The following are necessary steps for every trial: 1. 2. 3. 4. 5.

Develop a thorough understanding of the unit Develop a trial plan/agenda and follow it Document unit performance Document changes made to affect the unit performance Develop and adhere to contingency response plans

The following is intended to represent an outline for desalter trials.

Pre-trial Preparation Know The Unit History Desalter trials require a great deal of planning and organization prior to injecting the first quantity of chemical. A complete understanding of the historical performance of the desalter is not only good engineering practice, it is critical to analyzing the performance once the trial has started. A desalter survey form included in this manual is an extremely useful tool for assembling unit information. The performance history of a unit will be your guide to its expected performance. Refiners expect the desalter's performance during the trial to at least equal its past performance. It is imperative to thoroughly understand that past performance. How frequently do upsets occur? What causes the majority of desalter upsets? What is the operators' typical response to unit upsets? What desalter upsets cause in otherdistillation parts of the refineryand such as the waste water problems treatmentdo plant, atmospheric and preflash columns NESHAPS strippers? Answers to many of these questions will be available from the Engineering and Operations groups. Engineering can usually provide manufacturer's operating manuals and drawings of the vessel internals. These documents usually include the srcinal desalter design basis and may clarify many performance aberrations when compared to present day operating conditions. The Engineering group will also be the likely repository for historical performance data. The Operations group should be able to describe the 3.38

practical response guidelines to typically encountered operating problems. Further, the Operations group will be more familiar with the details of the frequency, duration, and severity of desalter upsets. Knowing the operating history of the desalter will allow you to prepare for events that might otherwise cause a serious unit upset. Interview the Oil Movements group to determine the tank de-watering procedures. Are any additives being added in the tank farm? Have there been any operational problems connected with any particular tanks? Understanding the answers to all of these questions will better position your trial for success. Know The Crude(s) Planning and/or Oil Movements will be able to describe the crude slates for a given crude unit. It will be essential to determine what crudes will be run during the trial and whether they represent a departure from "standard" crudes. How these crudes are handled once they have been delivered to the refinery will vary, but there will be established guidelines most refiners follow regarding blending, storage, and line-up to the crude unit. This information will allow you to prepare for difficult operating scenarios such as tank switches, changes to heavier or higher solids crudes, and tank farm water slugs. Oil Movements or the Planning group should also be able to provide crude assays. The technology group is also a good source of information on crude oil types. This information may allow you to plan and prepare for changes in crude quality that could have an effect on desalter performance or on the type and quantity of demulsifier required. It is also critical to determine the source, quality, and quantity of any slop oil being charged to the unit. Know if there is a set schedule for processing this material and how it is added to the charge. Know if it is added to the crude rundown line, or blended into the crude tanks, and if it is added at a constant rate or sporadically. Crude oil and slop oil quality should be measured first hand in advance of the trial. Analyses should include gravity, BS&W, and filterable solids. These analyses will provide confirmation of the crude assays obtained from the Oil Movements group, and will give you an idea of how running slop oil may affect desalter operation. Know The Products To Be Trailed Collect untreated representative crude samples as far in advance of the trial as possible for product selection lab testing. Do not assume that raw crude oil from the regular sample point is untreated. Trace down the demulsifier injection line and verify whether the sample you collect contains chemical. Determine when the unit is running distinct crudes and obtain samples of the different feedstocks. Try to collect your sample when typical slop oil rates and types are being processed. Also check desalter performance when your sample is collected. Is it in an upset condition? If so, this may not be a representative sample. It is crucial for the employees screening the crudes (and for the success of your trial) that adequate time for their evaluation is provided. The trial will not have the best chance to succeed without representative crude samples and adequate time for evaluation. Coordination of these activities with Technical Group is essential to ensure availability of resources to meet your objectives.

Know The Desalter Collect historical data regarding the wash water source(s), rates, standard injection locations, and quality. Determine the mud-wash frequency, duration and schedule. Obtain a copy of the actual mud-washing procedure if possible. It should contain information regarding line-up, demulsifier rate adjustment 3.39

guidelines, polymer or wetting agent practices, etc. Test the wash water and brine for pH, chlorides, and solids and note its appearance. Test the raw and desalted crude for salt, BS&W and filterable solids. Record and report a solids and salt removal efficiency. This pre-trial work will give you the basis for evaluating your products once the trial starts. Know and Practice Careful Laboratory Techniques Utilize the same laboratory procedures used by the refiner. Results from those methods will be more familiar and more readily accepted by the refiner than unfamiliar methods. Obtain the refiner's procedures and have copies available for all personnel staffing the trial. Collect sufficient quantities of all necessary laboratory equipment and reagents ahead of time. Confirm in advance adequate laboratory space will be available for your test requirements. Secure Special Supplies for the Trial Know the proper protective equipment required by the refiner. Gloves, hard hats, safety glasses, rags, glass or clear plastic measuring cups, notebooks, hand cleaner and liquid cleanser are but a few of the items which may be needed once the trial starts. Obtain these items in advance. Plan and Schedule Trial Manpower Determine what manpower will be required to adequately cover the trial. Coordinate with Technology and the district manager well in advance to make sure people resources will be available, then publish a work schedule so that everyone knows when they will be needed.

Trial It is important not to lose sight of the primary objective during the trial: 1)

Maintain control of the desalter operation,

2)

Get the unit running smoothly as soon as possible, and

3)

Optimize desalter operation only after the ability to maintain operational control and avoid upsets has been demonstrated.

The refiner has approached the supplier(s) requesting a trial with a specific objective. Understanding the objective and making every effort to demonstrate that capability will allow you to conduct a successful trial. However, first and foremost in the refiner's assessment of your performance will be the ability to control the desalter. The refiner will specify the primary objective of conducting the trial. It may be looking for a cost benefit or a performance advantage. Whatever the objective, listen closely and make every effort to provide that improvement in performance. There should be no misunderstanding what constitutes success or failure in the trial. Start of trial Adequate preparation has positioned you for a successful trial. During the trial it will be necessary to document the actions and performance of the product(s) in a way that is clear and concise. While there may be many ways of accomplishing this objective, the way which has provided consistent success is outlined as follows: 1)

Determine the product(s) to be used at the start of the trial and their initial dosages. Calculate how long it will take for the new product to get into the crude oil or wash water and into the desalter. It is critical to know exactly when the desalter can be expected to respond to changes in product chemistry.

2)

Develop a clear plan for responding to potential unit performance deterioration. This plan should include exact responses to typical upset conditions. What should be the initial response 3.40

to excessive oil in the brine? What should be the first response to an increasing rag layer? If the BS&W in the desalted crude is increasing, what should be done first? What will be the indication(s) that it may be time to try a different demulsifier or begin using a wetting agent? All of these questions should be defined, answered and agreed to in writing before starting the trial. 3)

Identify and tag all sample points clearly. Review sampling techniques with all members of the trial team. When you are two days into the trial and struggling to decipher senseless data,you don’t want to discover an inconsistency in sample points and/or techniques.

4)

Keep a continuous record of the desalter's performance and operational variables plus any changes that you make to improve any substandard or unacceptable conditions. Note the time and nature of any problems that develop and the time that any adjustments are made. One person per shift should be designated to record events and results during that shift. A "stenographer's" type spiral binder makes a good Trial Notebook. This format allows you to readily carry the notebook with you while on the unit and provides a clear data "time-line" of events and responses.

5)

Two additional data logs are attached to ensure all of the necessary data is collected. These logs are titled Desalte r Trial Laboratory Results and Desalter Tria l Operational Lo g . Again, they are not intended to be a substitute for the Trial Notebook, but rather an adjunct data collection format to enhance the Notebook.

6)

The refiner should be provided with reports (at least daily) on the status of the trial. Be sure that you highlight performance parameters that coincide with the refiner's trial objectives. At a minimum, the reports should include: 1) 2) 3) 4) 5) 6) 7) 8) 9) 1 0)

Report on the unit's stability Salt removal efficiency Solids removal efficiency BS&W in the raw and desalted crude Brine quality, appearance, and % oil Grid amps and volts Crude rates during the period Wash water source, quality and rate(s) Crude gravity and source (e.g., Tk number) Additive dosage(s)

3.41

Post-trial Evaluation Post-trial assessment of the performance should be done immediately after the trial has been concluded. Waiting any significant length of time will only diminish the accuracy of the evaluation. Assemble the data in a chronological format and plot pertinent information. Focus clearly on unit stability and accomplishing the customer's stated objectives. Where possible, provide direct comparisons to the incumbents' performance. This can be done using the performance data collected prior to the start of the trial or by comparing trial data with that supplied by the refiner. State clearly and unequivocally the performance advantages of your products and services. This is the time to highlight your value to the refiner. Present the data in a short executive summary including tables and graphs outlining the performance advantages demonstrated during the trial. The majority of the data will be included as a supplement for deeper review if the refiner is so inclined. Attach all trial data including a copy of the Trial Notebook so your efforts are evident. It is critical that your assessment of the trial's success concur with the refiner's perception. Discussing the trial with the refiner as it is being conducted will help establish this perception. As the trial is winding down, review your successes and advantages with the refiner prior to publishing your final report. There should be no divergence on the opinion of the trial's success. Once your trial is over, competitor's trials may follow. Maintain contact with the refinery personnel to monitor the competition's performance. Ask whether you can continue to sample the desalter to evaluate their performance first hand. This information will allow you to assess the competition's strengths and weaknesses, and will provide you with the data needed to sell the merits of your treatment program.

BAKER PETROLITE CRUDE UNIT DESALTER SURVEY Date: __________________

SurveyedBy: ___________________

Company: _________________

Location: _________________

Unit: ________________

DESALTER First Stage Type: Electrical

Chemical _________________

Manufacturer: Petrolite Design:

Howe-Baker

Throughput

Level Control - (Y / N)

Other ________________

MBPD API Gravity ___________________ Automatic - (Y / N) Type: Float

Capacitance

Microwave ____

Second Stage Type: Electrical

Chemical _________________

Manufacturer: Petrolite Design:

Howe-Baker

Throughput

Level Control - (Y / N)

Other ________________

MBPD API Gravity ___________________ Automatic - (Y / N) Type: Float

Capacitance

Microwave ____

Attach a process flow diagram of the desalter. Include all piping, pumps, mix valves and wash water and chemical injection points. If possible obtain a copy of the manufacturers operating manual and design specs. Crude Charge Charge Rate:

MBPD API Gravity:

Are Crudes Blended?

% Salt:

PTB Filt. Solids:

Recovered Oil Processed - (Y / N) Continuous Recovered Oil Charge: MBPD ______ C RU D E

Wash Water Charge Rate: Source(s) % pH Injection P oint(s)

MBPD

PTB

Intermittent _____

% C HA R G E

%

A PIG R A VI TY

pH

%

Spent Caustic Added - (Y / N)

High Ammonia - (Y / N)

Source

Operating Parameters Desalter Temperature

Pressure

Water Level (Inches) 1st Stage

2nd Stage

Mix Valve P (psi)

2nd Stage

1st Stage

Mud Wash: 1st Stage - (Y / N)

2nd Stage - (Y / N)

3.43

C O M M E N TS

Frequency: 1st Stage

2nd Stage

Typical Results/Test Methods BS&W(%) In

1st Stage Out

2nd Stage Out

Salts(PTB) In

1st Stage Out

2nd Stage Out

Filt. Solids(PTB) In

1st Stage Out

2nd Stage Out

Wash Water pH In

1st Stage Out

2nd Stage Out

O&G/Solids (% or PPM) Volts 1st Stage

2nd Stage

Amps 1st Stage

2nd Stage

Test Methods BS&W Heated Salts: Conductivity

Titration/Method

Potentiometric

Comments (Observation about consistency of results e.g. any seasonal variation, high water carryover, periods of oily brine, problem crudes or crude blends, etc.)________________________________________________________________________________ _______________________________________________________________________________________________________ Tank Farm Crude Receipts:

Tanker

Pipeline

Blended In:

Tank

Pipeline

Crude Tank Mixers - (Y / N) Water Drained from Tanks - ( Y / N)

Run Continuously

Tanks Vented - (Y / N) Crude Suction Fixed

Intermittent

How Often? Fixed Roof

Floating Roof

Floating

Pretreatment Program - (Y / N) Comments: (How long is crude stored ebfore it is run? How consistently is water drained?Does the refinery fill and drawfrom a tank at the same time? i.e. any observations about practices which could affect desalter operation.) __________________________________________________________________________________________________________ __________________________________________________________________________________________________________ __________________________________________________________________________________________________________ __________________________________________________________________________________________________________ Competitive Information Current Vendor_____________ Wetting Agent - (Y / N) Product Polymer - (Y / N)

Product

Product

Dosage

Continuous

Intermittent

_____

Dosage Dosage

Service Frequency

______________

Testing Performed By Competition/Frequency_________________________ _________________________ ___________________ __________________________________________________________________________________________________________ Comments: (Customer perception of results, service, local representative who will be involved in decision to award Baker Petrolite tank business, etc.) ____________________________________________ ______________________________________ ____________________________________________________________________________________________________________ ____________________________________________________________________________________________________________

3.44

FORMULAS AND CONVERSION FACTORS

Measures of Desalter Performance: % Salt Removal =

PTB saltsin -PTBsalts out x 100 PTB salts in

% Solids Removal =

PTB solids in - PTB solids out x 100 PTB solids in

Where 1 pound of salt or solids per 1000 bbls (PTB) = 2.86 ppm (or mg/liter) Desalter Mixing Efficiency E (%)

=

SR

F

X 100 SRCalc.

Where SRF = Field Salt Removal Efficiency: SRF =

Si - So Si

Si So

Raw crude salt content (PTB) Desalted crude salt content (PTB)

= =

And SRCalc.= SRCalc.

Theoretical Salt Removal Efficiency (Dehydration Efficiency): =

W wi wo

W+w i - wo W + wi = = =

Washwateradded(%) BS&W in raw crude (%) BS&W in desalted crude (%)

Other Useful Conversion Factors: Specificgravity=

141.5 API + 131.5

One petroleum barrel = 42 U.S. gallons 1.0 quart/1000 bbls = 5.95 ppm (or mg/liter) 1.0 pound per 1000 bbls (ptb) = 3 ppm 1.0 gallon per minute (gpm) = 34.3 Barrels per day (BPD) gallon of water weighs 8.33 pounds

3.45

GLOSSARY OF DESALTING TERMS

API Gravity - Used by the oil industry to refer to the specific gravity of a crude oil at 60 F. The API gravity is determined by the following formula: sp.gr.

=

141.5 131.5 + API

Bottom Grind Out - Centrifuging the bottom 50 ml of oil from laboratory bench tests to determine the quantity of water, emulsion and solids present. BS&W - Refers to the Basic Sediment and Water present in a crude. This generally includes emulsion (BS), water (W) and solids. Chemical Desalter - Unit which desalts refinery crude feedstock by the use of chemical, heat and gravity. Chemical Ratio - The amount of chemical used to resolve an emulsion. In laboratory studies, this number is expressed as p.p.m. In plant operations, it is given as qts. chemical/1000 Bbls. crude. Coalesce - to cause small water droplets to combine into larger ones. Continuous Phase - The external phase of an emulsion. Oil is the continuous phase in desalting. Crude Charge Pump - A centrifugal pump ahead of the desalter which feeds the crude to the process train. Crude Slate - Refers to the particular crude or blend of crudes a refinery is feeding to the desalter. Desalter - The first unit in the crude processing stream. Its function is to remove both soluble and insoluble impurities from the oil before it is refined. Dispersed Phase - The internal phase of an emulsion. In desalting applications, water is the dispersed phase. Distribution Header - A slotted pipe running along the bottom of the desalter. This pipe insures the incoming emulsion is evenly distributed throughout the unit. Effluent Water - The brine and solids laden water leaving the desalter. It is also referred to as tailwater. Electrical Desalter - The unit which desalts refinery feedstock by applying an electrical voltage as well as heat, chemical and residence time to aid in the separation of oil and water. Emulsion - A stable dispersion of two immiscible liquids. All emulsions contain both a continuous and a dispersed phase. Emulsion Pad - The unresolved emulsion found between the oil and water layers in a desalter. Emulsion Breaking - The resolution or separation of an emulsion into its individual components.

3.46

Glossary - Continued

Emulsifying Agent - A substance which acts to stabilize an emulsion. Typical emulsifying agents found in crude are asphaltenes, organic acids and clay, sand or silt. Filterable Solids - Any solid materials contained in a crude oil that can be removed by a filter. Filterable Solids Removal Efficiency - Efficiency of solids removal in a desalting system, expressed as: Efficiency (%) = [(Solids In Solids Out) ÷ (Solids In)] X 100 Grind Out - The centrifuging of an oil sample to determine the emulsion, water and solids content. Hydrophilic - Water soluble. Interface - The area of contact between the two components of an emulsion. Lipophilic - Oil soluble. Also referred to as hydrophobic. Mix Valve - A globe valve found ahead of the desalter. It provides the oil/water contact necessary in the desalting process. Naphthenic Acids - Mono-carboxylic acids mainly having a ring structure with side chains of varying length. The rings are predominantly C5 but C6 have been identified. They are oil soluble, water insoluble organic acids. They are found in most crude oils in a range of 0.02% to 2% by weight of the crude. Neutralization Number - Quantity (in mg) of KOH required to neutralize all the acidic components present in a 1 gram crude sample (ASTM D-664). Typical range is 0.1-0.5 for low "neut. number" crudes, 0.5-1.5 for medium neut. number crudes and 1.5-8.0 for high neut. number crudes. Also known as acid number. Potentiometric Titration - A titration using a potentiometer to determine the chloride content of a solution (used to measure salt content after an extraction procedure). The inflection points of a plot of millivolts vs volume of titrant is taken as the end point and used to calculate the salt content. Primary Desalter - The first desalter in a two stage desalter system. Residence Time - The amount of retention time the oil has in the desalting vessel. It is calculated by taking the volume in the desalter occupied by oil and dividing it by the charge rate in bbls/hour. Typical design residence times in electrical desalters are 15-30 minutes. Salt Content - The amount of chlorides contained in the oil. The results are expressed as the amount of sodium chloride in pounds/1000 bbls. crude. Salt Removal Efficiency - The efficiency of salt removal in a desalting system, expressed as: Efficiency (%) = [(Salt In - Salt Out) ÷ (Salt In)] X 100 Stabilizing Agent - See emulsifying agent.

3.47

Stokes' Law - States that the settling rate of a small droplet in a viscous fluid is inversely proportional to the viscosity of the fluid and directly proportional to both the density difference between the fluids and to the square of the droplet radius. The formula is: V = K (ρ w - ρ o) G d ηo where:

V K ρw ρo G d ηo

= = = = = = =

2

Velocity of falling water drop Aconstant Density of water Density of oil Gravitational acceleration Diameter of water droplets Viscosity of bulk media (oil)

Surface Active Agent - A material which affects surface tension properties. Also known as detergents or surfactants. Tail Water - See effluent water. Top Cut - The top portion of the oil in bench desalting studies that also may contain water, emulsion and solids. Total Solids - See filterable solids. Treating Plateau - The range in p.p.m. or qts/M bbls over which a demulsifier effectively resolves an emulsion. Wash Water - Fresh water, either potable or process, which is added to the crude to reduce the salt content. Water Level - The height of the water or interface layer in the desalter.

3.48