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Emulsion treating subsystems
Subsystems consist of power supplies, insulators, electrodes, liquid distribution systems, instrumentation and safety systems, solids removal systems, mixing devices, level controllers and gauges; as well as, water in oil detectors.
- 1 Power supplies
- 2 Insulators
- 3 Electrodes
- 4 Liquid distribution systems
- 5 Instrumentation and safety systems
- 6 Solids removal systems
- 7 Mixing devices
- 8 Level controllers and gauges
- 9 Water in oil detectors
- 10 Nomenclature
- 11 References
- 12 Noteworthy papers in OnePetro
- 13 External links
- 14 See also
- 15 Category
Transformers used in dehydrator and desalter power supplies must be capable of sustaining a short-circuited output without damage or overheating. This protection normally is derived by including a saturable core reactor sized commensurately to the reactance of the transformer winding in series with the primary winding of the transformer. As the primary current increases, the voltage drop across the reactor increases; therefore, failures in the vessel electrical components or process upsets causing high conductivity will not damage the transformer. Transformers in this service also experience high mechanical stresses from rapidly fluctuating loads and must be constructed with cores and windings that are mechanically solid and highly resistant to vibration.
A weakness of electrostatic coalescers has been their means of protecting the electrical system in the event of excessive power requirements during short-term upsets. Unfortunately, the reactor-based protection scheme described above effectively reduces power input to the vessel precisely when it is most needed.
To counteract this, an electronic controller was developed that can sense the load demand and modify the power input to the transformer. This voltage controller differs from the reactor in that it reduces power on the basis of time rather than by uniformly diminishing output. Short bursts of high-intensity energy are applied to the emulsion, and the duration of the pulses is limited to maintain an average power output within the rating of the transformer. This action continues to provide coalescing energy even during times of process upset.
The voltage controller also assists with the necessary compromise between field strength required for adequate translation of small drops and field strength sufficient to produce subdivision of large drops. As drop size increases and the surface-to-bulk ratio decreases, surface tension becomes unable to maintain rigidity of the drop, and viscous drag on the moving drop causes deformation. As velocity or drop size increases, this deformation, in concert with electrically induced perturbations, becomes sufficient to cause the drop to shatter. At any given field strength, there is a range of stable drop sizes that is limited at the lower end by the ability of the field to transport the drop, and at the upper end by what drop size can be transported without shattering. An ideal arrangement would be a field with a high-intensity zone for coalescence of very small drops, followed by gradually decreasing field strength for shifting the equilibrium drop size range to large values. To accomplish this, the controller varies the transformer output voltage to create time-based field decay. In addition to providing optimum field strength for coalescence of a wide range of drop sizes, the controller also can be used to provide high-intensity fields that are suitable for both mixing (in the case of counterflow desalters) and dehydration.
Entrance bushings are insulated pressure-sealing devices that conduct high voltage into the desalter vessel. Bushings are constructed of perfluorocarbon because of its superior resistance to fouling by foreign substances such as suspended solids or precipitated organic materials. If such materials collect on the surface of the insulator, a resistive electrical path will form that will conduct a small current and produce localized heating. This heating can cause the formation of a carbonized track along the insulator surface that ultimately will cause insulator failure. The perfluorocarbon portion of the bushings must remain submerged during operation to avoid plasma erosion of the insulator material.
Electrode hangers are insulating devices that mechanically support the electrostatically charged elements inside the treater or desalter vessel. They are available in two designs:
- standard hangers
- high-temperature hangers
Standard hangers use a 1-in. diameter perfluorocarbon rod with threaded end caps that are attached to swivels and J-hooks. They are widely used on oilfield treaters and desalters that operate at temperatures < 250°F. Loading is adjusted on the basis of temperature. Cast virgin perfluorocarbon is strongly recommended for this service. If extruded rod is used, ensure that “poker chip” discontinuities in density do not occur in the rod.
High-temperature hangers are used in applications with temperatures of up to 300°F. These are made of 2-in.-diameter cast virgin perfluorocarbon rod.
Electrodes are devices that provide direct contact between the electrical system and the process fluids. Often these are referred to as “grids” because of the nature of the electrodes that originally were used in AC field treaters and desalters. Several types of electrodes now are in general use.
Bar grating, or grids
Electrodes made of rectangular arrays of perpendicular steel rods or small-diameter pipes were the original grids of electrostatic treaters, and they remain in widespread use in AC field devices. Generally, several of these are hung in vertically separated horizontal planes above the longitudinal centerline of the vessel to increase liquid retention time in the most intense electrostatic field. The spacing between electrodes might be adjustable. These electrodes are inexpensive to construct and easy to carry into the vessel through a manway; however, the openings that are required to provide sufficient electrical clearance through each grid for the supports for the underlying grids can allow a portion of the process flow to bypass the intense area of the electrostatic field.
Arrays of vertically hung, parallel plates with a plate-to-plate spacing of approximately 6 in. and a plate height of 6 to 10 in. may be used in an electrostatic vessel to achieve high retention time in the intense zone of the electrostatic field. Similar plates also are used to provide the combination AC/DC field.
Electrostatic coalescence generally proceeds through a mechanism of drop polarization, alignment of the polarized drops, and chaining of these drops along the lines of force of the electrostatic field. These conductive chains lead to frequent electrical discharges or arcing between the electrodes. The arcs are a normal part of the process and, because they are submerged in oil, do not produce any damage; however, a steel electrode array is momentarily discharged by an arc, and if the arcs occur frequently enough (as in a wet emulsion), the electrodes might be discharged long enough to allow slippage of process fluids that have not had adequate exposure to the field.
Composite plate electrodes may be used to increase the water tolerance of the system under such conditions. These electrodes consist of plates of composite (fiber-reinforced plastic) construction with graphite fibers embedded in the central portion of the plate to impart conductivity along the length of the plate. The remainder of the plate contains filler materials that adsorb a layer of water on the plate surface. This adsorbed water layer then becomes the conductive medium along the height of the plate. Because such an adsorbed layer is highly resistive, any arcing that occurs is quenched quickly. As a result, only the immediate vicinity of the arc is discharged, and slippage is almost eliminated. Composite plates are used in all counterflow desalters, as well as on AC/DC processes for increased water tolerance.
Liquid distribution systems
A common type of inlet spreader is an inverted trough with distributor holes in the upper part of the trough (Fig. 1). Flow into the trough depresses the oil/water interface inside the trough to provide a hydrostatic head for creating uniform flow distribution. Changes in flow are reflected in changes in hydrostatic head, allowing for uniform distribution over a wide range of flow rates. Another advantage of the inverted trough is its ability to discharge free water and heavy solids directly out the bottom, without passing them through the shear of the orifices. The spreader is designed according to Eq. 1:
q = flow, ft3/sec
A = the area of diffuser holes, ft2
Co = the orifice factor (0.6 to 0.7)
g = gravitational constant = 32.2 ft/sec2
h = head, ft
γw = the specific gravity of brine
γo = the specific gravity of oil
Another common spreader configuration uses perforated pipes as the inlet distributor (Fig. 2). Pipe spreaders are preferable when vessel motion might be a factor (e.g., in floating production systems). The number, size, and distribution of the orifices are chosen so as to achieve uniform distribution across the vessel. In recent years, application of computational-fluid-dynamics (CFD) techniques to spreader design have enabled the design of highly efficient spreaders. Commonly used pressure drop across distributor orifices is 5 to 6 in. of water column for inverted troughs and 0.5 to 1.0 psi for perforated pipes.
Most vessel designs provide for a treated-oil collector in the upper part of the vessel. This collector is either a perforated pipe or a channel with perforations, and is designed according to Eq. 2:
D = hole diameter, in.
n = number of holes
Dilution water spreaders
Counterflow desalters incorporate a header/lateral spreader system for injecting dilution water above the electrodes. The electrostatic field provides some distribution of the counterflowing dilution water, and the size and spacing of the orifices are adjusted to assure uniform distribution.
Instrumentation and safety systems
Safety grounding floats
Safety grounding floats are floats that are mechanically linked to grounding switches inside the electrostatic-treating vessel. These devices ground the electrical systems inside the vessel upon loss of liquid level. They ensure that no electrically energized components are exposed to the gas phase and that the electrodes are not energized accidentally during personnel entry into the vessel.
Low level shutdowns
Shutdown switches may be installed to shut off transformer power in the event of liquid-level loss, or to shut down the process in the event of high or low interface level. These switches may be located in external cages or inserted through nozzles.
Several types of interface control are available, including:
- weighted floats
- capacitance probes
- conductivity probes
- radio frequency (RF) probes
What control is selected for an application depends on:
- crude oil characteristics
- compatibility with central control systems
- operator preference
Many installations now use the RF probes. They can be used for:
- interface control
- high- and low-level interface alarms
- bottom-sediment detection
- upstream anticipation of feed-stream changes
Solids removal systems
Because dehydrator and desalter vessels are designed to promote sedimentation, suspended solids in the feed stream also tend to settle out of the liquid stream. If the solids are water-wetted and heavy, they tend to settle through the interface and collect on the bottom of the vessel. In an oilfield situation, these solids often consist primarily of fine sand, whereas in a refinery, they usually are fine silts. Corrosion products might be present in both. If the solids are oil-wetted or are of a density between that of oil and water, they tend to collect as a sludge layer at the oil/water interface and usually are accompanied by poorly resolved emulsions. Either case eventually requires removal of the solids from the vessel to prevent process upsets.
- other impurities that are produced with crude oil and accompanying water
When present in small quantities, these impurities add little to the treating problem; however, when present in appreciable quantities, they might make the treating problem difficult and expensive, and might require the use of special equipment and techniques.
It is good practice to equip all treating vessels with cleanout openings and/or washout connections so that the vessels can be drained and cleaned periodically. Larger vessels should be equipped with manways to facilitate cleaning them. Steam cleaning might be required periodically, and acidizing may be necessary to remove calcium carbonate or similar deposits that cannot be removed by hot water or by steam cleaning.
One of the most likely causes of difficulty in operating fired emulsion-treating vessels is the deposition of solids on fire tubes and nearby surfaces. If such deposits cannot be prevented, these surfaces should be cleaned periodically. The deposits insulate the fire tube, reducing heating capacity and efficiency. They also can cause accelerated corrosion and failure of the heater tubes.
Of the salts commonly found in oilfield waters, predominant are:
- chlorides, sulfates, and bicarbonates of sodium
The most prevalent of the chlorides is NaCl, followed by calcium and magnesium chloride. These salts can be found in nearly all water associated with crude oil. Salts seldom are found in the crude oil; when they are present, they are mechanically suspended, not dissolved, in it. An exception to this is organic salts (e.g., naphthenates).
Scaling and coking
Emulsion heating equipment is particularly susceptible to scaling and coking. These depositional processes are distinct, but might occur simultaneously. Also, one can hasten the other.
Calcium, magnesium carbonates, calcium, and strontium sulfates
Calcium, magnesium carbonates, calcium, and strontium sulfates readily precipitate on heating surfaces in emulsion-treating equipment by decomposition of their bicarbonates and the resultant reduced solubility in the water carrying them. They are deposited:
- in pipes, tubes, and fittings
- on the inside surface of treating vessels
Maximum deposition occurs on the hottest surfaces, e.g.:
- heating coils
- fire tubes
Scale deposition also might occur when pressure on the fluid is reduced. This is the result of release of CO2 from the bicarbonates in salt water, which forms insoluble salts that tend to adhere to surfaces of equipment that contain the fluid.
Coke generally is not a primary fouling material; however, when deposits of salt, scale, or any other fouling material build up, coking begins as soon as the insulating effect of the fouling material causes the skin temperature of the heating surface (fire tube or element) to reach 600 to 650°F. The coke that forms aggravates fouling and reduces heat transfer. Once coking starts, a burnout of the fire tube might follow quickly.
In areas where fluids cause considerable scaling or coking, such deposits can be minimized by decreasing the treating temperature or by using chemical inhibitors, properly designed spreader plates, and favorable fluid velocities through the equipment. Arranging the internals of the equipment so that all surfaces are as smooth and continuous as possible also will reduce such deposits. For trouble-free operation of equipment over a long time, the operator periodically should inspect the equipment internally and clean its surfaces as required.
Mud wash or Sand jet systems
Mud Wash or Sand Jet Systems. It is common to shut down and drain vessels periodically for cleaning. Sand can be removed from the unit with rakes and shovels or with a vacuum truck. Although it is very difficult to eliminate sand buildup in large-diameter tanks, the problem of sand and silt in emulsion-treating vessels can be eliminated or minimized by the use of:
- sand pans
- automated water jets
- drain systems
A sand pan is a special perforated or slotted box or enclosure that is located in the bottom portion of a vessel or tank. Sand pans are designed to cover the area of the vessel that the flow of discharging water will clean. Often they are designed to work with a set of water jets. The sand pans for horizontal vessels usually consist of elongated, inverted V-shaped troughs that are parallel with and on the bottom of the vessels and that straddle the vertical centerline of the vessel. In the design in Fig. 2, the sand pans have sides that make a 60° angle with the horizontal. The bottom edges of the sloping sides are serrated with 2-in. V-shaped slots and are welded to the interior of the shell of the treater. Most sand pans used in horizontal vessels are 5 to 10 ft long.
Sand pans without a water-jet system might satisfactorily remove sand from some vessels; however, vessels should be equipped with a water-jet system, in addition to sand pans, to assist sand removal from the vessel. Fig. 3 illustrates typical sand pans with a water-jet system.
In vertical vessels, the sand pan can be a flanged and dished head approximately one-third the diameter of the vessel in which it is concentrically located. The sand pan usually is serrated around the periphery, where it is welded to the bottom head of the vertical vessel concentric with the water outlet.
Water jets usually are designed to flow 12 to 20 U.S. gal/min of water through each jet with a differential pressure of 35 to 100 psi. Standard jets are available for this service that have a 60° flat fan jet pattern. The jets usually are spaced on 12- to 24-in. centers. The water jet header is U-shaped so that the vessel is cleaned on both sides of the sand pan simultaneously. The water jets and sand-dump valves can be programmed to operate all at the same time or in sequential cycles.
One problem in removing sand from vessels is that very few, if any, water-discharge-control valves can withstand for long the abuse of sand-cutting during the water-discharge period. A partial solution is to arrange the instrumentation to open and close the water-discharge control valve on clean, sand-free water and to use special slurry-type valves.
Programmable logic controllers
The most sophisticated sand-removal systems use programmable logic controllers to select the proper time intervals between dumps and to automatically control the length of the water/sand-discharge period. The timing must be coordinated with the water-jet system and the normal water-dump controller. A properly designed sand-removal system with proper water jetting and water/sand dumping can operate for many years without needing to be shut down to clean out sand or to repair or replace the dump valve.
Most emulsion-treating systems that handle large volumes of sand should not rely on hand or nonprogrammed operation for sand removal. If the operator fails to activate the dump valve often enough, sand will cover the sand pans and plug or partially plug the water outlet, and the drains will become inoperative. With sand pans in the treater but without a programmer, large volumes of sand usually will cause trouble by plugging or partially plugging the water outlets and/or by cutting or wearing away the drain valve.
Because the amount and type of sand vary greatly, the length and frequency of the water jetting and dumping cycles must vary to suit local conditions. Most of the coarser sand will settle out in the inlet end of the treater; the fine sand will settle out near the outlet end of the treater. It might be necessary to cycle the water jets and drain valves near the inlet end of the treater three to four times more frequently than those near the outlet end. Many timers are set for 30 minutes between jetting and dumping cycles and for 20- to 60-second jetting and dumping periods.
In refinery settings, sand jets usually are referred to as mud-wash systems.
Interface sludge drains
Interfacial buildup, sometimes referred to as sludge, is material that can collect at or near the oil/water interface of emulsion-treating tanks and vessels. Interfacial buildup can contain:
- other impurities mixed with unresolved emulsion
It can be removed from the vessel through a drain installed at the interface or by closing the water-dump valve and floating it out to a bad-oil tank for further processing or disposal. Interfacial buildup also can be discharged with the water by opening the water-drain valve, but this can create problems in the water-treatment plant.
Interface-sludge drains are collectors at the oil/water interface that are connected to discharge valves. Interface sludge tends to collect irregularly and often reaches an equilibrium depth that does not impair operation seriously; therefore, the need for draining interface sludge is best determined by regular monitoring of the interface depth and condition, using samples from the trycocks. The presence of a continuously increasing interface layer or one that contains a high concentration of suspended solids indicates a need for draining.
Draining must be done very slowly and must be carefully monitored to avoid drawing excess oil or water into the collectors. For this reason, it is best done manually. Properly used, interface-sludge drains can reduce the load on the downstream water-treatment facilities by redirecting the high-oil- and high-solid-content material into a slop-oil system, where it can be batch treated more effectively with heat and chemicals.
An important facet of desalting is achieving contact between the entrained water in the crude oil and the dilution water that is used to wash the oil.
Typically, the dilution water is added to the oil upstream of a valve. The water is injected into the oil flow line through a distributor. The differential pressure across the valve then is used to shear the water drops and mix the two phases.
Typical differential pressures are 5 to 20 psi. Although mixing valves generally are satisfactory, they do have some disadvantages. Mixing efficiency generally is low at extremes of phase ratio, so that using small quantities of dilution water (< 2%) might not be feasible; likewise, turndown in flow rate will require adjustment of the valve to maintain contact efficiency. More serious disadvantages include the requisite compromise between mixing efficiency and excessive emulsification and the energy wasted on shear of the continuous phase. Because very small drops act as rigid spheres following flow streamlines, it is unlikely that they will achieve sufficient energy to participate in mechanically induced collisions; therefore, their contribution to the salt content of a crude oil represents a fraction unreachable by means of mixing valves.
Mixing efficiency can be improved by adding static-mixer elements downstream of the mixing valve to achieve a more homogeneous blend of brine drops and dilution-water drops (Fig. 4). Static mixers are series of short, helical baffles mounted in a pipe, with adjacent baffles that have reverse twists. They continually blend the stream at low shear. Because increasing mixing efficiency by increasing the shear rate can lead to emulsification problems, the use of low-shear devices for blending the stream can be an asset, particularly with difficult crude oils. At best, a mixing valve/desalter combination can function as a single-stage mixer/settler.
The electrostatic field also can be used as a mixing device if it is programmed to exceed the critical voltage gradient during a portion of the treating cycle. This is the technique used to achieve mixing under counterflow conditions in the counterflow desalter.
Level controllers and gauges
Many liquid-level controllers are available for liquid/gas control and for oil/water-interface control in light-crude-oil (> 20°API) systems. For interfacial controllers in light crude oils, floats that sink in the oil but float in the water normally are used.
For heavy crude oils, electronic interface controllers have been used very successfully. They operate on the principle of the differences between:
- oil and water electrical conductivity
- electrical capacitance
- radio frequency (RF) absorption
The most common type, capacitance probes, use the dielectric strength of the fluid in which they are immersed.
Standard-gauge glasses (reflex or transparent) are used on 20°API and higher crude oil. Reflex gauges normally are used for liquid/gas levels, and transparent gauges are used for oil/water levels. Pressure vessels normally use armored-gauge glasses, and tanks use tubular-gauge glasses. Some operators use the tubular-gauge glasses on low-pressure treating equipment. Tubular-gauge glasses normally are furnished on standard low-pressure vessels unless armored gauges are specified.
For American Petroleum Institute (API) gravities below 20°API, gauge glasses are not recommended, particularly for interfacial service, because they are difficult or impossible to read. In lieu of gauge glasses, a system of sample valves (often called trycocks) is used, with the sample lines all piped to a single point just above a sample box. Generally, the lines are insulated to keep them warm. A nameplate clamped on each sample valve designates the elevation it represents in the treater. The sample box is fitted with a drain line piped to the sump.
Water in oil detectors
Several companies manufacture BS&W monitors, devices for detecting and measuring the water content of crude oil. BS&W monitors typically are analog instruments that measure dielectric strength and are designed specifically for determining the water content of crude oil that contains a low percentage of water. They do not operate satisfactorily on streams that contain free water. The monitor provides a water reading that corresponds to the water content of the oil. It can be made to alert the operator, record the reading, and control the BS&W content level if the detected percentage exceeds the field-selectable preset limit.
|A||=||the area of diffuser holes, ft2|
|Co||=||the orifice factor (0.6 to 0.7)|
|g||=||gravitational constant = 32.2 ft/sec2|
|γw||=||the specific gravity of brine|
|γo||=||the specific gravity of oil|
|D||=||hole diameter, in.|
|n||=||number of holes|
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