The term separator in oilfield terminology designates a pressure vessel used for separating well fluids produced from oil and gas wells into gaseous and liquid components. A separator for petroleum production is a large vessel designed to separate production fluids into their constituent components of oil, gas and water. A separating vessel may be referred to in the following ways: Oil and gas separator, Separator, Stage separator, Trap, Knockout vessel (Knockout drum, knockout trap, water knockout, or liquid knockout), Flash chamber (flash vessel or flash trap), Expansion separator or expansion vessel, Scrubber (gas scrubber), Filter (gas filter). These separating vessels are normally used on a producing lease or platform near the wellhead, manifold, or tank battery to separate fluids produced from oil and gas wells into oil and gas or liquid and gas. An oil and gas separator generally includes the following essential components and features:
A vessel that includes (a) primary separation device and/or section, (b) secondary "gravity" settling (separating) section, (c) mist extractor to remove small liquid particles from the gas, (d) gas outlet, (e) liquid settling (separating) section to remove gas or vapor from oil (on a three-phase unit, this section also separates water from oil), (f) oil outlet, and (g) water outlet (three-phase unit). Adequate volumetric liquid capacity to handle liquid surges (slugs) from the wells and/or flowlines. Adequate vessel diameter and height or length to allow most of the liquid to separate from the gas so that the mist extractor will not be flooded. A means of controlling an oil level in the separator, which usually includes a liquid-level controller and a diaphragm motor valve on the oil outlet. A back pressure valve on the gas outlet to maintain a steady pressure in the vessel. Pressure relief devices.
Separators work on the principle that the three components have different densities, which allows them to stratify when moving slowly with gas on top, water on the bottom and oil in the middle. Any solids such as sand will also settle in the bottom of the separator. The functions of oil and gas separators can be divided into the primary and secondary functions which will be discussed later on.
Classification of oil and gas separators
By operating configuration Oil and gas separators can have three general configurations: vertical, horizontal, and spherical. Vertical separators can vary in size from 10 or 12 inches in diameter and 4 to 5 feet seam to seam (S to S) up to 10 or 12 feet in diameter and 15 to 25 feet S to S. Horizontal separators may vary in size from 10 or 12 inches in diameter and 4 to 5 feet S to S up to 15 to 16 feet in diameter and 60 to 70 feet S to S. Spherical separators are usually available in 24 or 30 inch up to 66 to 72 inch in diameter. Horizontal oil and gas separators are manufactured with monotube and dual-tube shells. Monotube units have one cylindrical shell, and dual-tube units have two cylindrical parallel shells with one above the other. Both types of units can be used for two-phase and three-phase service. A monotube horizontal oil and gas separator is usually preferred over a dual-tube unit. The monotube unit has greater area for gas flow as well as a greater oil/gas interface area than is usually available in a dual-tube separator of comparable price. The monotube separator will usually afford a longer retention time because the larger single-tube vessel retains a larger volume of oil than the dual-tube separator. It is also easier to clean than the dual-tube unit. In cold climates, freezing will likely cause less trouble in the monotube unit because the liquid is usually in close contact with the warm stream of gas flowing through the separator. The monotube design normally has a lower silhouette than the dual-tube unit, and it is easier to stack them for multiple-stage separation on offshore platforms where space is limited. It was illustrated by Powers et al (1990)Powers, Maston L., 1990. Analysis of Gravity Separation in Freewater Knockouts. SPE Production Engineering, [e-journal]5(1). Available through OnePetro database [Accessed 5 April 2011] that vertical separators should be constructed such that the flow stream enters near the top and passes through a gas/liquid separating chamber even though they are not competitive alternatives unlike the horizontal separators.
By function The three configurations of separators are available for two-phase operation and three-phase operation. In the two-phase units, gas is separated from the liquid with the gas and liquid being discharged separately. Oil and gas separators are mechanically designed such that the liquid and gas components are separated from the hydrocarbon steam at specific temperature and pressure according to Arnold et al (2008).Arnold, Steward, 2008. Surface Production Operations. Design of Oil handling Sysytems and Facilities. Oxford: Gulf Professional Publishing. In three-phase separators, well fluid is separated into gas, oil, and water with the three fluids being discharged separately. The gas–liquid separation section of the separator is determined by the maximum removal droplet size using the Souders–Brown equation with an appropriate K factor. The oil-water separation section is held for a retention time that is provided by laboratory test data, pilot plant operating procedure, or operating experience. In the case where the retention time is not available, the recommended retention time for three-phase separator in API 12J is used. The sizing methods by K factor and retention time give proper separator sizes. According to Song et al (2010),Joon H. Song, B. E. Jeong, H.J. Kim, S. S. Gil, 2010. Three-Phases Separator Sizing Using Drop Size Distribution. In: Offshore Technology Conference, 3–6 May 2010. Houston: Dawoo Shipbuilding & Marine Engineering Co., LTD. engineers sometimes need further information for the design conditions of downstream equipment, i.e., liquid loading for the mist extractor, water content for the crude dehydrator/desalter or oil content for the water treatment.
By operating pressure Oil and gas separators can operate at pressures ranging from a high vacuum to 4,000 to 5,000 psi. Most oil and gas separators operate in the pressure range of 20 to 1,500 psi. Separators may be referred to as low pressure, medium pressure, or high pressure. Low-pressure separators usually operate at pressures ranging from 10 to 20 up to 180 to 225 psi. Medium-pressure separators usually operate at pressures ranging from 230 to 250 up to 600 to 700 psi. High-pressure separators generally operate in the wide pressure range from 750 to 1,500 psi.
By application Oil and gas separators may be classified according to application as test separator, production separator, low temperature separator, metering separator, elevated separator, and stage separators (first stage, second stage, etc.).
Test separator A test separator is used to separate and to meter the well fluids. The test separator can be referred to as a well tester or well checker. Test separators can be vertical, horizontal, or spherical. They can be two-phase or three-phase. They can be permanently installed or portable (skid or trailer mounted). Test separators can be equipped with various types of meters for measuring the oil, gas, and/or water for potential tests, periodic production tests, marginal well tests, etc. Production separator A production separator is used to separate the produced well fluid from a well, group of wells, or a lease on a daily or continuous basis. Production separators can be vertical, horizontal, or spherical. They can be two-phase or three-phase. Production separators range in size from 12 in. to 15 ft in diameter, with most units ranging from 30 in. to 10 ft in diameter. They range in length from 6 to 70 ft, with most from 10 to 40 ft long. In small onshore oilfield applications, a production separator can be integrated in a vapor-tight tank package. Low-temperature separator A low-temperature separator is a special one in which high-pressure well fluid is jetted into the vessel through a choke or pressure reducing valve so that the separator temperature is reduced appreciably below the well-fluid temperature. The temperature reduction is obtained by the Joule–Thomson effect of expanding well fluid as it flows through the pressure-reducing choke or valve into the separator. The lower operating temperature in the separator causes condensation of vapors that otherwise would exit the separator in the vapor state. Liquids thus recovered require stabilization to prevent excessive evaporation in the storage tanks. Metering separator The function of separating well fluids into oil, gas, and water and metering the liquids can be accomplished in one vessel. These vessels are commonly referred to as metering separators and are available for two-phase and three-phase operation. These units are available in special models that make them suitable for accurately metering foaming and heavy viscous oil.
Primary functions of oil and gas separators
Separation of oil from gas may begin as the fluid flows through the producing formation into the well bore and may progressively increase through the tubing, flow lines, and surface handling equipment. Under certain conditions, the fluid may be completely separated into liquid and gas before it reaches the oil and gas separator. In such cases, the separator vessel affords only an "enlargement" to permit gas to ascend to one outlet and liquid to descend to another.
Removal of oil from gas
Difference in density of the liquid and gaseous hydrocarbons may accomplish acceptable separation in an oil and gas separator. However, in some instances, it is necessary to use mechanical devices commonly referred to as "mist extractors" to remove liquid mist from the gas before it is discharged from the separator. Also, it may be desirable or necessary to use some means to remove non solution gas from the oil before the oil is discharged from the separator.
Removal of gas from oil
The physical and chemical characteristics of the oil and its conditions of pressure and temperature determine the amount of gas it will contain in solution. The rate at which the gas is liberated from a given oil is a function of change in pressure and temperature. The volume of gas that an oil and gas separator will remove from crude oil is dependent on (1) physical and chemical characteristics of the crude, (2) operating pressure, (3) operating temperature, (4) rate of throughput, (5) size and configuration of the separator, and (6) other factors.
Agitation, heat, special baffling, coalescing packs, and filtering materials can assist in the removal of nonsolution gas that otherwise may be retained in the oil because of the viscosity and surface tension of the oil. Gas can be removed from the top of the drum by virtue of being gas. Oil and water are separated by a baffle at the end of the separator, which is set at a height close to the oil-water contact, allowing oil to spill over onto the other side, while trapping water on the near side. The two fluids can then be piped out of the separator from their respective sides of the baffle. The produced water is then either injected back into the oil reservoir, disposed of, or treated. The bulk level (gas–liquid interface) and the oil water interface are determined using instrumentation fixed to the vessel. Valves on the oil and water outlets are controlled to ensure the interfaces are kept at their optimum levels for separation to occur. The separator will only achieve bulk separation. The smaller droplets of water will not settle by gravity and will remain in the oil stream. Normally the oil from the separator is routed to a coalescer to further reduce the water content.
Separation of water from oil