690:, the droplets of liquid hydrocarbon may have a density 400 to 1,600 times that of natural gas. However, as the operating pressure and temperature increase, the difference in density decreases. At an operating pressure of 800 psig, the liquid hydrocarbon may be only 6 to 10 times as dense as the gas. Thus, operating pressure materially affects the size of the separator and the size and type of mist extractor required to separate adequately the liquid and gas. The fact that the liquid droplets may have a density 6 to 10 times that of the gas may indicate that droplets of liquid would quickly settle out of and separate from the gas. However, this may not occur because the particles of liquid may be so small that they tend to "float" in the gas and may not settle out of the gas stream in the short period of time the gas is in the oil and gas separator. As the operating pressure on a separator increases, the density difference between the liquid and gas decreases. For this reason, it is desirable to operate oil and gas separators at as low a pressure as is consistent with other process variables, conditions, and requirements.
761:
effective methods of separating liquid mist from gas. However, according to
Keplinger (1931), some separator designers have pointed out a disadvantage in that a liquid with a free surface rotating as a whole will have its surface curved around its lowest point lying on the axis of rotation. This created false level may cause difficulty in regulating the fluid level control on the separator. This is largely overcome by placing vertical quieting baffles which should extend from the bottom of the separator to above the outlet. Efficiency of this type of mist extractor increases as the velocity of the gas stream increases. Thus for a given rate of throughput, a smaller centrifugal separator will suffice.
866:
time. Calibration can be defined as the process of referencing signals of known quantity that has been predetermined to suit the range of measurements required. Calibration can also be seen from a mathematical point of view in which the flowmeters are standardized by determining the deviation from the predetermined standard so as to ascertain the proper correction factors. In determining the deviation from the predetermined standard, the actual flowrate is usually first determined with the use of a master meter which is a type of flowmeter that has been calibrated with a high degree of accuracy or by weighing the flow so as to be able to obtain a gravimetric reading of the mass flow.
857:(CFD) simulator. These were then used to carry out a detailed experimentation on the three-phase separator. The experimental and CFD simulation results were suitably integrated with the mechanistic model. The simulation time for the experiment was 20 seconds with the oil specific gravity as 0.885, and the separator lower part length and diameter were 4-ft and 3-inches respectively. The first set of experiment became a basis through which detailed investigations were used to carry out and to conduct similar simulation studies for different flow velocities and other operating conditions as well.
1009:
According to
Francis (1951), low-temperature controls in separators is another tools used by gas producers which finds its application in the high-pressure gas fields, usually referred to as "vapour-phase" reservoirs. Low temperatures obtainable from the expansion of these high-pressure gas streams are utilized to a profitable advantage. A more efficient recovery of the hydrocarbon condensate and a greater degree of dehydration of the gas as compared to the conventional heater and separator installation is a major advantage of low-temperature controls in oil and gas separators.
659:
separated from by a demisting device. Until recently the main technologies used for this application were reverse-flow cyclones, mesh pads and vane packs. More recently new devices with higher gas-handling have been developed which have enabled potential reduction in the scrubber vessel size. There are several new concepts currently under development in which the fluids are degassed upstream of the primary separator. These systems are based on centrifugal and turbine technology and have additional advantages in that they are compact and motion insensitive, hence ideal for
940:(ESD). ESD valves typically stay in open position for months or years awaiting a command signal to operate. Little attention is paid to these valves outside of scheduled turnarounds. The pressures of continuous production often stretch these intervals even longer. This leads to build up or corrosion on these valves that prevents them from moving. For safety critical applications, it must be ensured that the valves operate upon demand.
873:(1989), transfer meters have been proven to be less accurate if the operating conditions are different from its original calibrated points. According to Yoder (2000), the types of flowmeters used as master meters include turbine meters, positive displacement meters, venturi meters, and Coriolis meters. In the U.S., master meters are often calibrated at a flow lab that has been certified by the
845:, (P&ID). Some of these flow instruments include the Flow Indicator (FI), Flow Transmitter (FT) and the Flow Controller (FC). Flow is of paramount importance in the oil and gas industry because flow, as a major process variable is essentially important in that its understanding helps engineers come up with better designs and enables them to confidently carry out additional research. Mohan
22:
332:. 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,
706:, mist is impinged against a surface, the liquid mist may adhere to and coalesce on the surface. After the mist coalesces into larger droplets, the droplets will gravitate to the liquid section of the vessel. If the liquid content of the gas is high, or if the mist particles are extremely fine, several successive
1051:
Over the life of a production system, the separator is expected to process a wide range of produced fluids. With break through from water flood and expanded gas lift circulation, the produced fluid water cut and gas-oil ratio is ever changing. In many instances, the separator fluid loading may exceed
1008:
controls may be installed on separators to shut in the unit, to open or to close a bypass to a heater, or to sound a warning should the temperature in the separator become too high or too low. Such temperature controls are not normally used on separators, but they may be appropriate in special cases.
304:
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
147:(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).
881:
process have been certified by NIST or are causally linked back to standards that have been approved by NIST. However, there is a general belief in the industry that the second method which involves the gravimetric weighing of the amount of fluid (liquid or gas) that actually flows through the meter
972:
separators should be installed at a safe distance from other lease equipment. Where they are installed on offshore platforms or in close proximity to other equipment, precautions should be taken to prevent injury to personnel and damage to surrounding equipment in case the separator or its controls
249:
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
240:
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
235:
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
550:
Today, oil fields produce greater quantities of water than they produce oil. Along with greater water production are emulsions and dispersions which are more difficult to treat. The separation process becomes interlocked with a myriad of contaminants as the last drop of oil is being recovered from
546:
and most recently to the
Performax Matrix Plate Coalescer, an enhanced gravity settling separator. The history of water treating for the most part has been sketchy and spartan. There is little economic value to the produced water, and it represents an extra cost for the producer to arrange for its
454:
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
403:
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
1149:
Sand and other solids from upstream will tend to settle out in the bottom of the separators. If allowed to accumulate the solids reduce the volume available for oil/gas/water separation reducing efficiency. The vessel may be taken offline and drained down and the solids removed by digging out by
1072:
and erosion. In the oil fields, this practice is not generally followed (they are inspected at a predetermined frequency, normally decided by an RBI assessment) and equipment is replaced only after actual failure. This policy may create hazardous conditions for operating personnel and surrounding
760:
mist flows in a circular motion at sufficiently high velocity, centrifugal force throws the liquid mist outward against the walls of the container. Here the liquid coalesces into progressively larger droplets and finally gravitates to the liquid section below. Centrifugal force is one of the most
743:
can be effected with either a sudden increase or decrease in gas velocity. Both conditions use the difference in inertia of gas and liquid. With a decrease in velocity, the higher inertia of the liquid mist carries it forward and away from the gas. The liquid may then coalesce on some surface and
915:
with pressure controller. Although the use of controls is expensive making the cost of operating fields with separators so high, installations has resulted in substantial savings in the overall operating expense as in the case of the 70 gas wells in the Big Piney, Wyo sighted by Fair (1968). The
889:
In ascertaining a proper correction factor, there is often no simple hardware adjustment to make the flowmeter start reading correctly. Instead, the deviation from the correct reading is recorded at a variety of flowrates. The data points are plotted, comparing the flowmeter output to the actual
865:
As earlier stated, flow instruments that function with the separator in an oil and gas environment include the flow indicator, flow transmitter and the flow controller. Due to maintenance (which will be discussed later) or due to high usage, these flowmeters do need to be calibrated from time to
810:
bath affords slight agitation, which is helpful in coalescing and separating entrained gas from the oil. A heated-water bath is probably the most effective method of removing foam bubbles from foaming crude oil. A heated-water bath is not practical in most oil and gas separators, but heat can be
658:
Effective oil-gas separation is important not only to ensure that the required export quality is achieved but also to prevent problems in downstream process equipment and compressors. Once the bulk liquid has been knocked out, which can be achieved in many ways, the remaining liquid droplets are
515:
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
726:
mist is changed abruptly, inertia causes the liquid to continue in the original direction of flow. Separation of liquid mist from the gas thus can be effected because the gas will more readily assume the change of flow direction and will flow away from the liquid mist particles. The liquid thus
520:
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
287:
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
805:
that is hydraulically retained in the oil. The most effective method of heating crude oil is to pass it through a heated-water bath. A spreader plate that disperses the oil into small streams or rivulets increases the effectiveness of the heated-water bath. Upward flow of the oil through the
1250:(P&ID) illustrates the direction of flow in and around an Oil and Gas Separator. It likewise shows the connectivity of other instruments e.g. valves, level controller, level indicator, flow indicator, flow transmitter, pressure indicator, pressure transmitter, etc. around the separator.
916:
wells with separators were located above 7,200 ft elevation, ranging upward to 9,000 ft. Control installations were sufficiently automated such that the field operations around the controllers could be operated from a remote-control station at the field office using the
487:
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.
621:
on each separator or with one master backpressure valve that controls the pressure on a battery of two or more separators. The optimum pressure to maintain on a separator is the pressure that will result in the highest economic yield from the sale of the liquid and gaseous
994:
High- and low pressure controls are installed on separators to prevent excessively high or low pressures from interfering with normal operations. These high- and low-pressure controls can be mechanical, pneumatic, or electric and can sound a warning, actuate a shut-in
583:
and water. The water can be separated from the oil in a three-phase separator by use of chemicals and gravity separation. If the three-phase separator is not large enough to separate the water adequately, it can be separated in a free-water knockout vessel installed
1141:. Some operators determine separator shell and head thickness with ultrasonic thickness indicators and calculate the maximum allowable working pressure from the remaining metal thickness. This should be done yearly offshore and every two to four years onshore.
537:
with oil continues to be a problem for engineers and the oil producers. Since 1865 when water was coproduced with hydrocarbons, separation of valuable hydrocarbons from disposable water has challenged and frustrated the oil industry. According to Rehm
1493:
Sadoun Mutar Bezea Al-Khaledi, Naser
Abdulaziz, Dwaipayan Bora, 2011. Replacement of Existing ESD Valves with New SIL Rated ESD Valves: A Case Study of Production Optimization and Enhancement of Process Safety and Integrity in Kuwait Oil Company.
1240:– This shows how the Defoaming Internals, Coalescing Internals, Demister Internals – Wiremesh Demister, Vane Mist Eliminators, Desanding Internals, Vortex Breakers and other internal components of a typical separator are arranged in the separator.
575:
which can be referred to as being a chemical reactions that occurs whenever a gas or liquid chemically attacks an exposed metallic surface. Corrosion is usually accelerated by warm temperatures and likewise by the presence of acids and salts.
350:
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
270:
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
292:(2010), 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.
254:(1990) 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.
241:
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
355:, 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
792:
that may be mechanically locked in the oil by surface tension and oil viscosity. Agitation usually will cause the gas bubbles to coalesce and to separate from the oil in less time than would be required if agitation were not used.
1052:
the original design capacity of the vessel. As a result, many operators find their separator no longer able to meet the required oil and water effluent standards, or experience high liquid carry-over in the gas according to Power
1037:
in the separator exceeds a predetermined value. This is usually from 1 1/4 to 1% times the design pressure of the separator vessel. The safety head disk is usually selected so that it will not rupture until the safety relief
744:
gravitate to the liquid section of the separator. With an increase in gas velocity, the higher inertia of the liquid causes the gas to move away from the liquid, and the liquid may fall to the liquid section of the vessel.
425:
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
819:
Centrifugal force which can be defined as a fictitious force, peculiar to a particle moving on a circular path, that has the same magnitude and dimensions as the force that keeps the particle on its circular path (the
1109:
to open or the safety head to rupture. Steam coils can be installed in the liquid section of oil and gas separators to melt hydrates that may form there. This is especially appropriate on low-temperature separators.
828:
from oil. The heavier oil is thrown outward against the wall of the vortex retainer while the gas occupies the inner portion of the vortex. A properly shaped and sized vortex will allow the gas to ascend while the
882:
into or out of a container during the calibration procedure is the most ideal method for measuring the actual amount of flow. Apparently, the weighing scale used for this method also has to be traceable to the
385:
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.
780:, and other reasons, it is important to remove all nonsolution gas from crude oil during field processing. Methods used to remove gas from crude oil in oil and gas separators are discussed below:
801:
Heat as a form of energy that is transferred from one body to another results in a difference in temperature. This reduces surface tension and viscosity of the oil and thus assists in releasing
1023:
separators. These valves normally are set at the design pressure of the vessel. Safety relief valves serve primarily as a warning, and in most instances are too small to handle the full rated
877:, (NIST). NIST certification of a flowmeter lab means that its methods have been approved by NIST. Normally, this includes NIST traceability, meaning that the standards used in the flowmeter
430:
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.
682:
if the velocity of the gas is sufficiently slow. The larger droplets of hydrocarbon will quickly settle out of the gas, but the smaller ones will take longer. At standard conditions of
984:
on the inlet to the separator, open a bypass around the separator, sound a warning alarm, or perform some other pertinent function to prevent damage that might result from high or low
511:
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
245:
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
678:. Minute particles of liquid hydrocarbon that are temporarily suspended in a stream of natural gas will, by density difference or force of gravity, settle out of the stream of
849:(1999) carried out a research into the design and development of separators for a three-phase flow system. The purpose of the study was to investigate the complex multiphase
231:
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
811:
added to the oil by direct or indirect fired heaters and/or heat exchangers, or heated free-water knockouts or emulsion treaters can be used to obtain a heated-water bath.
1507:
A. W. Francis, 1951. Low-Temperature
Separation as Applied to Gas-Condensate Production. Drilling and Production Practice, 1951. Houston: American Petroleum Institute.
1027:
capacity of the separator. Full-capacity safety relief valves can be used and are particularly recommended when no safety head (rupture disk) is used on the separator.
283:
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
139:
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:
1484:
R. A. Fair, 1968. Gas-field
Telemetering and Remote Control, Big Piney, Wyoming. Drilling and Production Practice, 1968. Houston: American Petroleum Institute.
542:(1983), innovation over the years has led from the skim pit to installation of the stock tank, to the gunbarrel, to the freewater knockout, to the hay-packed
579:
Other factors that affect the removal of water from oil include hydrate formation and the formation of tight emulsion that may be difficult to resolve into
1097:. Otherwise hydrates may form in the vessel and partially or completely plug it thereby reducing the capacity of the separator. In some instances when the
936:
separators are oil discharge control valve, water-discharge control valve (three-phase operation), drain valves, block valves, pressure relief valves, and
1085:
will not break off, unscrew, or otherwise dislodge the safety device. The discharge from safety devices should not endanger personnel or other equipment.
1073:
equipment. It is recommended that periodic inspection schedules for all pressure equipment be established and followed to protect against undue failures.
617:
and gas can be discharged into their respective processing or gathering systems. Pressure is maintained on the separator by use of a gas backpressure
920:. All in all, this improved the efficiency of personnel and the operation of the field, with a corresponding increase in production from the area.
325:
135:(gas filter). These separating vessels are normally used on a producing lease or platform near the wellhead, manifold, or tank battery to separate
1150:
hand. Or water sparge pipes in the base of the separator used to fluidize the sand which can be drained from the drain valves in the base.
157:
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.
883:
874:
788:
Moderate, controlled agitation which can be defined as movement of the crude oil with sudden force is usually helpful in removing nonsolution
1259:
300:
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
1081:
All safety relief devices should be installed as close to the vessel as possible and in such manner that the reaction force from exhausting
1292:
Arnold, Steward, 2008. Surface
Production Operations. Design of Oil handling Sysytems and Facilities. Oxford: Gulf Professional Publishing.
660:
1426:
Ram S. Mohan, Ovadia Shoham, 1999. Design and
Development of Gas-Liquid Cylindrical Cyclone Compact Separators for Three-Phase Flow.
262:
The three configurations of separators are available for two-phase operation and three-phase operation. In the two-phase units,
288:
separator in API 12J is used. The sizing methods by K factor and retention time give proper separator sizes. According to Song
1130:
of the vessel. Periodic hydrostatic testing is recommended, especially if the fluids being handled are corrosive. Expendable
160:
A means of controlling an oil level in the separator, which usually includes a liquid-level controller and a diaphragm motor
1243:
1475:
Jesse Yoder, 2000. Flowmeter
Calibration: How, Why, and Where. Control for the Process Industries. Houston: Putman Media.
1466:
Jesse Yoder, 2000. Flowmeter
Calibration: How, Why, and Where. Control for the Process Industries. Houston: Putman Media.
1359:
1247:
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flowrate as determined by the standardized National Institute of Standards and Technology master meter or weigh scale.
842:
32:
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Agitation, heat, special baffling, coalescing packs, and filtering materials can assist in the removal of nonsolution
999:, open a bypass, or perform other pertinent functions to protect personnel, the separator, and surrounding equipment.
1301:
Joon H. Song, B. E. Jeong, H.J. Kim, S. S. Gil, 2010. Three-Phases Separator Sizing Using Drop Size Distribution.
1541:
841:
The direction of flow in and around a separator along with other flow instruments are usually illustrated on the
568:
1237:
1033:
A safety head or rupture disk is a device containing a thin metal membrane that is designed to rupture when the
381:
of expanding well fluid as it flows through the pressure-reducing choke or valve into the separator. The lower
313:
Oil and gas separators may be classified according to application as test separator, production separator, low
1546:
1536:
1414:"Centrifugal Force on Encyclopædia Britannica 2011 – Encyclopædia Britannica Online. Accessed: 04 April 2011"
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1314:
Rehm, S.J., Shaughnessy, R.J., III, C-E Natco, 1983. Enhanced Oil-Water Separation-The Performax Coalescer.
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854:
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separator, metering separator, elevated separator, and stage separators (first stage, second stage, etc.).
1318:
Oklahoma City, Oklahoma 27 February – 1 March 1983. Oklahoma City: Society of Petroleum Engineers of AIME.
194:
in the middle. Any solids such as sand will also settle in the bottom of the separator. The functions of
911:
level controllers for oil and oil/water interface (three-phase operation) and gas back-pressure control
1441:"Calibration on Encyclopædia Britannica 2011 – Encyclopædia Britannica Online. Accessed: 04 April 2011"
1234:– Parameters and influencing factors for the best possible separation results including Separator video
1184:
1174:
917:
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956:, pressure-reducing regulators (for control gas), level sight glasses, safety head with rupture disk,
377:
is reduced appreciably below the well-fluid temperature. The temperature reduction is obtained by the
1413:
1329:"Corrosion on Encyclopædia Britannica 2011 – Encyclopædia Britannica Online. Accessed: 04 April 2011"
1254:
Computational fluid dynamics (CFD) simulation illustrating a three-phase oil, gas and water separator
853:
flow behaviour in a three-phase oil and gas separator. A mechanistic model was developed alongside a
202:
separators can be divided into the primary and secondary functions which will be discussed later on.
973:
or accessories fail. The following safety features are recommended for most oil and gas separators.
39:
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378:
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psi. High-pressure separators generally operate in the wide pressure range from 750 to 1,500 psi.
1453:
Ting, V.C., Halpine, J.C., 1989. Portable Piston Gas Prover for Field Calibration of Flowmeters.
1400:"Heat on Encyclopædia Britannica 2011 – Encyclopædia Britannica Online. Accessed: 04 April 2011"
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should be checked periodically to determine whether remedial work is required. Extreme cases of
1516:
Powers, Choi, M.S., 1990. Prediction of Separator Performance Under Changing Field Conditions.
1189:
1440:
1262:– Based on settling time required for liquid droplets of a given minimum size to be separated.
1341:
Stewart, A.C., Chamberlain, N.P., Irshad, M., 1998. A New Approach to Gas–Liquid Separation.
1328:
382:
1238:
Pictorial illustration of what the internal structure of an Oil and Gas Separator looks like
642:
seal must be effected in the lower portion of the vessel. This liquid seal prevents loss of
1194:
8:
1204:
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components. A separator for petroleum production is a large vessel designed to separate
707:
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is liberated from a given oil is a function of change in pressure and temperature. The
1360:
https://www.youtube.com/watch?v=vhkcGCUN_Uo&playnext=1&list=PLD23100F9395C2BB0
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has opened and is incapable of preventing excessive pressure buildup in the separator.
980:
High- and low liquid-level controls normally are float-operated pilots that actuate a
821:
1231:
356:
143:
A vessel that includes (a) primary separation device and/or section, (b) secondary
80:
937:
64:
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Powers, Maston L., 1990. Analysis of Gravity Separation in Freewater Knockouts.
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liquid capacity to handle liquid surges (slugs) from the wells and/or flowlines.
1253:
1214:
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850:
663:. Below are some of the ways in which oil is separated from gas in separators.
1530:
1056:(1990). Some operational maintenance and considerations are discussed below:
869:
Another type of meter used is the transfer meter. However, according to Ting
551:
the reservoir. In some instances it is preferable to separate and to remove
1385:
1345:
The Hague, Netherlands 20–22 October 1998. The Hague: Kvaerner Paladon Ltd.
953:
1386:"Agitation on The Free Dictionary by Farlex 2011. Accessed: 10 April 2011"
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In refineries and processing plants, it is normal practice to inspect all
178:
Separators work on the principle that the three components have different
1135:
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can be removed from the top of the drum by virtue of being gas. Oil and
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A low-temperature separator is a special one in which high-pressure well
340:
for potential tests, periodic production tests, marginal well tests, etc.
314:
183:
88:
1428:
In: Oil and Gas Conference – Technology Options for Producers' Survival,
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removed may coalesce on a surface or fall to the liquid section below.
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New Orleans, Louisiana 23–26 September 1990. New Orleans: Conoco Inc.
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Keplinger, 1931. Physical Problems in the Separation of Oil and Gas.
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with the oil and requires the use of a liquid-level controller and a
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115:(Knockout drum, knockout trap, water knockout, or liquid knockout),
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567:. Such water removal may prevent difficulties that could be caused
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824:) but points in the opposite direction is effective in separating
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95:. A separating vessel may be referred to in the following ways:
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is jetted into the vessel through a choke or pressure reducing
267:
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227:. Vertical separators can vary in size from 10 or 12 inches in
151:
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1305:
Houston: Dawoo Shipbuilding & Marine Engineering Co., LTD.
1244:
Typical P&ID arrangement for three-phase separator vessels
408:
215:
Oil and gas separators can have three general configurations:
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A production separator is used to separate the produced well
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A back pressure valve on the gas outlet to maintain a steady
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may be required to effect satisfactory removal of the mist.
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Doha, Qatar 13–16 February 2011. Doha: Kuwait Oil Company.
1199:
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1256:– This illustrates the direction of flow in the separator.
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because of the viscosity and surface tension of the oil.
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outlet is plugged or restricted, this causes the safety
182:, which allows them to stratify when moving slowly with
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Separators should be operated above hydrate-formation
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653:
1260:
Quick calculator for horizontal knock out drum sizing
1496:
In: SPE Project and Facilities Challenges Conference
1518:
In: SPE Annual Technical Conference and Exhibition,
1430:
Dallas, Texas 28–30 June 1999. Dallas: DOE and PTTC
479:it will contain in solution. The rate at which the
1134:can be used in separators to protect them against
1303:In: Offshore Technology Conference, 3–6 May 2010.
1076:
463:The physical and chemical characteristics of the
455:before the oil is discharged from the separator.
1528:
1373:Proceedings of the Oklahoma, University of Tulsa
613:must be maintained in the separator so that the
609:separator to accomplish its primary functions,
563:reductions, such as those caused by chokes and
528:
884:National Institute of Standards and Technology
875:National Institute of Standards and Technology
1126:may require a reduction in the rated working
210:
1283:, 5(1). Available through OnePetro database
597:Maintenance of optimum pressure on separator
713:
446:may accomplish acceptable separation in an
409:Primary functions of oil and gas separators
833:flows downward to the bottom of the unit.
730:
458:
433:
328:is used to separate and to meter the well
773:, the widespread reliance on metering of
1356:Production Separator Principles – sample
1316:In: SPE Production Operations Symposium.
1047:Operation and maintenance considerations
893:
295:
275:(2008). In three-phase separators, well
206:Classification of oil and gas separators
667:Density difference (gravity separation)
630:Maintenance of liquid seal in separator
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1059:
814:
591:
495:that otherwise may be retained in the
948:The accessories required for oil and
769:Because of higher prices for natural
525:to further reduce the water content.
83:into their constituent components of
63:in oilfield terminology designates a
1144:
1068:vessels and piping periodically for
1019:is usually installed on all oil and
836:
747:
15:
1113:
977:High- and low-liquid-level controls
860:
765:Methods used to remove gas from oil
654:Methods used to remove oil from gas
13:
1343:In: European Petroleum Conference.
1248:Piping and instrumentation diagram
1160:Piping and instrumentation diagram
1088:
1002:High- and low-temperature controls
963:
903:The controls required for oil and
843:Piping and instrumentation diagram
14:
1558:
1225:
588:or downstream of the separators.
308:
42:and remove advice or instruction.
952:separators are pressure gauges,
718:When the direction of flow of a
391:The function of separating well
279:is separated into gas, oil, and
20:
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1118:A separator handling corrosive
991:High- and low-pressure controls
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1077:Installation of safety devices
1015:A spring-loaded safety relief
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693:
661:floating production facilities
257:
119:(flash vessel or flash trap),
1:
1266:
1030:Safety heads or rupture disks
438:Difference in density of the
1170:Computational fluid dynamics
855:computational fluid dynamics
783:
671:Natural gas is lighter than
529:Separation of water from oil
7:
1153:
898:
10:
1563:
1455:SPE Production Engineering
1281:SPE Production Engineering
918:Distributed Control System
211:By operating configuration
938:emergency shutdown valves
923:
521:separator is routed to a
362:Low-temperature separator
67:used for separating well
988:levels in the separator.
714:Change of flow direction
559:before it flows through
475:determine the amount of
174:Pressure relief devices.
1375:, Volume VI, pp. 74–75.
1232:The Flottweg Separator
796:
731:Change of flow velocity
698:If a flowing stream of
459:Removal of gas from oil
434:Removal of oil from gas
1542:Natural gas technology
1190:Natural gas condensate
1185:Vapor–liquid separator
1175:Souders–Brown equation
571:by the water, such as
467:and its conditions of
373:so that the separator
285:Souders–Brown equation
266:is separated from the
71:produced from oil and
932:required for oil and
894:Controls and features
383:operating temperature
296:By operating pressure
97:Oil and gas separator
1547:Industrial equipment
1537:Petroleum technology
1457:, 6(4), pp. 454–458.
1195:Oil production plant
1180:Joule–Thomson effect
1012:Safety relief valves
708:impingement surfaces
379:Joule–Thomson effect
343:Production separator
40:rewrite this article
1060:Periodic inspection
592:Secondary functions
507:are separated by a
121:Expansion separator
722:stream containing
638:on a separator, a
533:The production of
388:Metering separator
190:on the bottom and
164:on the oil outlet.
145:"gravity" settling
1358:Available at:<
1205:Cyclone separator
1145:Solids separation
837:Flow measurements
822:centripetal force
815:Centrifugal force
748:Centrifugal force
421:may begin as the
81:production fluids
75:into gaseous and
57:
56:
33:a manual or guide
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1114:Corrosive fluids
886:(NIST) as well.
861:Flow calibration
756:stream carrying
357:vapor-tight tank
131:(gas scrubber),
125:expansion vessel
52:
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43:
31:is written like
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1089:Low temperature
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964:Safety features
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907:separators are
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113:Knockout vessel
105:Stage separator
65:pressure vessel
53:
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1226:External links
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1165:Fluid dynamics
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735:Separation of
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555:from the well
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413:Separation of
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321:Test separator
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309:By application
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171:in the vessel.
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117:Flash chamber
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29:This article
27:
18:
17:
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1148:
1136:electrolytic
1117:
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1080:
1063:
1053:
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967:
954:thermometers
947:
927:
902:
888:
870:
868:
864:
851:hydrodynamic
846:
840:
818:
800:
787:
778:hydrocarbons
768:
751:
734:
717:
697:
670:
657:
634:To maintain
633:
624:hydrocarbons
600:
578:
549:
539:
532:
490:
462:
444:hydrocarbons
442:and gaseous
437:
412:
312:
299:
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177:
132:
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120:
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112:
108:
104:
100:
96:
60:
58:
45:
38:Please help
30:
1215:Stokes' law
1095:temperature
1006:Temperature
944:Accessories
879:calibration
702:containing
694:Impingement
688:temperature
676:hydrocarbon
473:temperature
375:temperature
315:temperature
258:By function
238:cylindrical
1531:Categories
1267:References
569:downstream
547:disposal.
395:into oil,
221:horizontal
152:volumetric
1139:corrosion
1124:corrosion
1070:corrosion
784:Agitation
573:corrosion
544:coalescer
523:coalescer
516:vessel.
336:, and/or
225:spherical
180:densities
150:Adequate
101:Separator
73:gas wells
61:separator
59:The term
1154:See also
1128:pressure
1066:pressure
1035:pressure
968:Oil and
899:Controls
684:pressure
636:pressure
611:pressure
586:upstream
561:pressure
469:pressure
359:package.
353:diameter
302:pressure
233:diameter
229:diameter
217:vertical
186:on top,
169:pressure
129:Scrubber
48:May 2022
601:For an
1220:Safety
1099:liquid
1083:fluids
986:liquid
958:piping
930:valves
924:Valves
909:liquid
831:liquid
775:liquid
758:liquid
737:liquid
724:liquid
704:liquid
673:liquid
640:liquid
615:liquid
565:valves
518:Valves
513:fluids
509:baffle
485:volume
440:liquid
428:liquid
399:, and
393:fluids
330:fluids
268:liquid
247:liquid
243:volume
223:, and
137:fluids
133:Filter
77:liquid
69:fluids
1362:>
1210:Valve
1132:anode
1120:fluid
1107:valve
1054:et al
1040:valve
1025:fluid
1017:valve
997:valve
982:valve
913:valve
871:et al
847:et al
808:water
752:If a
648:valve
619:valve
557:fluid
553:water
540:et al
535:water
505:water
423:fluid
417:from
401:water
371:valve
367:fluid
348:fluid
338:water
290:et al
281:water
277:fluid
273:et al
252:et al
188:water
162:valve
93:water
1200:Heat
928:The
797:Heat
739:and
686:and
605:and
471:and
450:and
404:oil.
198:and
109:Trap
91:and
1103:gas
1101:or
1021:gas
970:gas
950:gas
934:gas
905:gas
826:gas
803:gas
790:gas
771:gas
754:gas
741:gas
720:gas
700:gas
680:gas
644:gas
607:gas
603:oil
581:oil
501:Gas
497:oil
493:gas
481:gas
477:gas
465:oil
452:gas
448:oil
419:gas
415:oil
397:gas
334:gas
264:gas
200:gas
196:oil
192:oil
184:gas
123:or
89:gas
85:oil
1533::
1246:–
650:.
626:.
324:A
219:,
127:,
111:,
107:,
103:,
99:,
87:,
1443:.
1416:.
1402:.
1388:.
1331:.
50:)
46:(
35:.
Text is available under the Creative Commons Attribution-ShareAlike License. Additional terms may apply.