【導(dǎo)讀】hopefully!formations;

　　

【正文】 rained away from the upper section into the lower. This allows a higher velocity gas flow through the upper baffled section. Spherical separators are much less mon than vertical or horizontal types. They tend to have lower installation and maintenance costs. They are more pact, but lack the capacity for high gas rates or liquid surges. Separators are sized according to the expected oil and gas production rates, the necessary operating pressure and temperature, and the oil and gas properties. For example, a vertical separator about 2 ft (.61 m)in diameter and 10 ft () high, with a retention time of one minute, will handle about 1300 bbl/D (207 m3/d) of typical crude oil. A single barrel horizontal separator 2 ft (.61m) in diameter and 10 ft () long will handle about Wellhead and Christmas tree for a dual tubing pletion utilizing clamptype connection. From Gray Tool Company PART II Petroleum Technology 68 2020 bbl/D (318 m3/d ) and a 3 ft (.91m) diameter spherical separator about 1100 bbl/D (175 m3/d). For parison, 100 to 200 bbl/D (16 to 32 m3/d) is about the output of a normal garden hose. It is important to remember that the physical and chemical characteristics of the crude oil and gas entering the separator help determine the degree of separation possible at a given operating temperature and pressure. Separating the gas held as bubbles in the oil, or oil entrained as droplets in the gas, can be acplished by manipulating the fluid stream. However, the operating temperature and pressure of the separators will dictate the degree to which solution gas and condensate are separated. In general, a greater degree of a separation occurs as the pressure is lowered and the temperature is increased for a given hydrocarbon mixture. Fluid properties are discussed in greater detail in section ., Basic Properties of Reservoir Rocks and Fluids. When gas is removed from contact with the liquid as it is separated, the process is called differential separation. This process results in the highest volume of oil being recovered where the oil contains a relatively small amount of gas. Because most operators are concerned with maximizing the oil volume, this approach is preferred. A long series of separators, each operating at a slightly lower pressure and allowing for the removal of the liberated gas from each stage, would provide the highest oil yield in such a case. Although this type of progression is not economically feasible, multistage separation with three or four separators can approach the yield of plete differential recovery. The gas that is removed at each stage is referred to as highpressure, mediumpressure, or lowpressure gas, depending on the stage at which it is removed. Field production facilities will often have a highpressure gas system and a lowpressure gas system. The lowpressure system is often used for fuel to operate the treating facilities. Oil Treatment In many oil fields, following the initial gasoil separation process, the oil must be treated to remove water, salt, or H2S. Most pipeline quality oil must have its water content reduced to the to 2 by volume range. Because salt water is generally associated with oil in the reservoir, its production along with the oil is not unusual. Almost all well streams contain water droplets of various sizes. If, because of their higher density, they collect together and settle out within a reasonably short time they are called free water. The water cut measured on one or several samples of the well stream normally refers to free water, and is expressed as the volume of water relative to the total volume of liquid. c ut w a t e r %l i qui d produc t i on of vol um et ot a l w a t e rfre e of vol um e100 ?? PART II Petroleum Technology 69 The sample is assumed to be representative. A freewater knockout (Figure ) is a simple separation vessel located along the flow stream at a point of minimum turbulence, where the oil and water mixture is allowed sufficient time for its density differences to act to separate the phases. A more difficult separation problem arises when the oil and water are produced as an emulsion. Most oilfield emulsions are the waterinoil type, where individual water particles are dispersed in a continuous body of oil. An inverted, or oilinwater, emulsion can also occur, especially when the ratio of water to oil is very high. Two things are necessary to produce an emulsion of water and oil: agitation and an emulsifying agent. As well fluids move through the formation, through the perforations and pletion equipment, up the tubing and through a choke, turbulence and mechanical mixing provide the agitation necessary to disperse the droplets of water throughout the oil phase, or droplets of oil throughout the water phase. Many crude oils also contain carbonates, sulfates, and finely divided solids, which may act as emulsifying agents. These agents increase the stability of the interfacial films separating the dispersed and continuous phases. In order to “break” the emulsion and separate the oil from the water, a variety of processes have been developed. Treating vessels, which utilize more than one treating process to attack particularly stable or “tight” emulsions, are mon. Chemical treatment uses chemical action to rupture the tough film surrounding the dispersed droplets. The selection of the most effective chemical demulsifier for a given crude oilwater emulsion is usually a trialanderror process. Chemicals are normally added continuously to the produced fluids, as far upstream from the treating or separation facilities as possible. Heat Schematic of a low pressure freewater knockout PART II Petroleum Technology 70 treatment to reduce the viscosity of the emulsion a