Demulsification is the breaking of a crude oil emulsion into oil and water phases. A fast rate of separation, a low value of residual water in the crude oil, and a low value of oil in the disposal water are obviously desirable. Produced oil generally has to meet company and pipeline specifications. For example, the oil shipped from wet-crude handling facilities must not contain more than 0.2% basic sediment and water (BS&W) and 10 pounds of salt per thousand barrels of crude oil. This standard depends on company and pipeline specifications. The salt is insoluble in oil and associated with residual water in the treated crude. Low BS&W and salt content is required to reduce corrosion and deposition of salts. The primary concern in refineries is to remove inorganic salts from the crude oil before they cause corrosion or other detrimental effects in refinery equipment. The salts are removed by washing or desalting the crude oil with relatively fresh water. Oilfield emulsions possess some kinetic stability. This stability arises from the formation of interfacial films that encapsulate the water droplets.
A flare or vent disposal system collects and discharges gas from atmospheric or pressurized process components to the atmosphere to safe locations for final release during normal operations and abnormal conditions (emergency relief). In vent systems, the gas exiting the system is dispersed in the atmosphere. Gas-disposal systems for tanks operating near atmospheric pressure are often called atmospheric vents or flares, and gas-disposal systems for pressure vessels are called pressure vents or flares. A flare or vent system from a pressurized source may include a control valve, collection piping, flashback protection, and a gas outlet. A scrubbing vessel should be provided to remove liquid hydrocarbons. The actual configuration of the flare or vent system depends on the hazards assessment for the specific installation. RP 520, Part 1, Sec. 8, and RP 521, Secs. 4 and 5, cover disposal and depressuring system design.
How these and related factors affect subsea processing design are discussed below. The value of subsea processing is determined primarily by reservoir characteristics and water depth. Well productivity index (barrel per psi drawdown or PI), which is a function of reservoir permeability, is one of the keys. A high PI will leverage the reduced backpressure provided by subsea processing to higher production rates. This can have enormous economic implications for low-pressure reservoirs in deep water.
Using heat to treat crude oil emulsions has four basic benefits; It reduces viscosity, increases droplets, dissolves paraffin crystals, and increases density between oil and water. Which allows the water droplets to collide with greater force and to settle more rapidly. The chart in Figure 1 can be used to estimate crude-oil viscosity/temperature relationships. Crude-oil viscosities vary widely, and the curves on this chart should be used only in the absence of specific data. If a crude oil's viscosity is known at two temperatures, it can be approximated at other temperatures by drawing a straight line along those temperature/viscosity points on the chart.
Produced water typically enters the water-treatment system from a two- or three-phase separator, free-water knockout, gun barrel, heater treater, or other primary-separation-unit process. This water contains small concentrations (100 to 2000 mg/L) of dispersed hydrocarbons in the form of oil droplets. Because the water flows from this equipment through dump valves, control valves, chokes, or pumps, the oil-particle diameters will be very small ( 100 μm). Treatment equipment to remove dispersed oil from water relies on one or more of the following principles: gravity separation (often with the addition of coalescing devices), gas flotation, cyclonic separation, filtration, and centrifuge separation. In applying these concepts, one must keep in mind the dispersion of large oil droplets to smaller ones and the coalescence of small droplets into larger ones, which takes place if energy is added to the system. The amount of energy added per unit time and the way in which it is added will determine whether dispersion or coalescence will take place. Stokes' law, shown in Eq. 4.1, is valid for the buoyant rise velocity of an oil droplet in a water-continuous phase. Several immediate conclusions can be drawn from this equation. The third conclusion requires further elaboration. Heat is the primary mechanism in oil-treating equipment to remove small water droplets from oil. The addition of heat significantly reduces oil viscosity, which prompts more rapid settling, and heat destabilizes water-in-oil emulsions. Heat is not commonly used in water treating because the percentage change in viscosity per degree of temperature change is much less in water than in oil. Water-in-oil emulsions tend to have a higher percentage of the dispersed phase than the oil-in-water emulsions; the dispersed phase tends to have larger-diameter droplets stabilized by heat-sensitive emulsifiers, and it takes twice as much heat input to raise a barrel of water as it takes to raise a barrel of oil to the same temperature. Small oil droplets contained in the water-continuous phase are subject to the competing forces of dispersion and coalescence. An oil droplet will break apart when kinetic-energy input is sufficient to overcome the surface energy between the single droplet and the two smaller droplets formed from it. At the same time that this process occurs, the motion and collision of oil particles cause coalescence to take place.
Demulsifier selection is still considered an art that improves with experience; however, there are methods now available to eliminate some of the uncertainties involved in demulsifier screening and selection. The properties of a good demulsifier were addressed previously. How to select the best demulsifier and to optimize its usage is addressed here. Demulsifier selection should be made with the emulsion-treatment system in mind. Some of the questions to be asked include the following.
Crude oil is seldom produced alone because it generally is commingled with water. The water creates several problems and usually increases the unit cost of oil production. The produced water must be separated from the oil, treated, and disposed of properly. All these steps increase costs. Furthermore, sellable crude oil must comply with certain product specifications, including the amount of basic sediment and water (BS&W) and salt, which means that the produced water must be separated from the oil to meet crude specifications.
This article gives an overview of a pump's effect on the shearing of production fluids in the oil industry. Most of the world's oil reservoirs produce oil together with water. The liquids are subjected to shear forces through the pumps and are sheared as they pass through pressure-reducing devices in the production line. A common oil field emulsion is a dispersion of water droplets in oil. Formation of emulsions in the main separation process is a big concern for the operators.
With the exception of one-phase gas reservoirs, prolonged production will cause all reservoirs to reach saturation conditions, thus bringing about changes in the fluid composition throughout the reservoir. When this happens, there is no longer any possibility of obtaining truly representative fluid samples. Thus, although in one-phase gas reservoirs (and for a certain length of time in undersaturated reservoirs), the fluid will remain unchanged during pressure depletion--the true nature of the fluid will be unknown until samples actually have been analyzed in a laboratory--it is strongly recommended to take samples at the earliest opportunity in the life of a well. Both in openhole and in cased-hole completions, the best depth or production interval for sampling will be as far away as possible from gas/oil, gas/water, and oil/water transition zones to reduce the chances of coning. Every attempt should be made to test zones individually because commingled production may be difficult to detect and is impossible to correct in the laboratory. Problems such as the liberation of carbon dioxide (CO2) or H2S after acid treatments are possible, as is the release of other components such as metal ions, and these could affect analyses. On the other hand, sampling after an acid treatment has been properly cleaned up has the probable advantage of reduced drawdown in the near-wellbore region. Because of the enormous variety of constraints, there can be no definitive guidelines for well conditioning. The first phase of conditioning involves the cleanup, in which the well is flowed to the surface to remove any solids resulting from perforating activities, drilling mud or completion fluids in the well, and mud filtrate or workover fluids that may remain in the formation near the wellbore. Here, the production rate must provide a sufficient flow velocity in the production string to lift solids, hydrocarbon liquids, and water to the surface, but conditioning is typically performed at the maximum rate, as this reduces the total length of the cleanup period. The cleanup period typically lasts from a few hours to 24 hours, and progress is monitored by regular measurements of flowing wellhead pressure, basic sediment and water (BS&W), and other brmeters. At the end of the cleanup period, production may be diverted through the separator to check its operation. This is an ideal moment to take backup samples.