Separators in the Oil and Gas Industry

Separators in the Oil and Gas Industry
ELPT 1301_ Chapter 0x_W Source: 1

Separators for the Oil and Gas Industry
Description 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 - oil, - gas - water x x 2 Source: Wikipedia

Various Names for Separators or Similar Vessels An oil and gas separator vessel may be referred to in the following ways: - 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). x x 3 Source: Wikipedia

Use at Oilfield Well Sites 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 x x 4 Source: Wikipedia

General Components and Features of a Separator An oil and gas separator generally includes a vessel that includes - a primary separation device and/or section - a secondary “gravity” settling (separating) section - mist extractor to remove small liquid particles from the gas - a gas outlet - a liquid settling (separating) section to remove gas or vapor from oil (on a three-phase unit, this section also separates water from oil) - an oil outlet - a water outlet (three-phase unit) x x 5 Source: Wikipedia

General Components and Features of a Separator Separators must incorporate - 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 x x 6 Source: Wikipedia

Principle of Separator Operation Separators for oilfield operations 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 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 x x 7 Source: Wikipedia

Classification of Oilfield Separators Oil and gas separators can have three general configurations - vertical - horizontal - spherical x x 8 Source: Wikipedia

Vertical Separator Vertical separators can vary in size from 10 or 12 in. in diameter and 4 to 5 ft seam to seam (S to S) up to 10 or 12 ft in diameter and 15 to 25 ft S to S 9 Source: Wikipedia

Vertical Separators x 10 Source: Wikipedia

Horizontal Separator Horizontal separators may vary in size from 10 or 12 in. in diameter and 4 to 5 ft S to S up to 15 to 16 ft in diameter and 60 to 70 ft S to S 11 Source: Wikipedia

Spherical Separator Spherical separators are usually available in 24 or 30 in. up to 66 to 72 in. in diameter. 12 Source: Wikipedia

Classification of Oilfield Separators Vertical separators can vary in size from 10 or 12 in. in diameter and 4 to 5 ft seam to seam (S to S) up to 10 or ft in diameter and 15 to 25 ft S to S Horizontal separators may vary in size from 10 or 12 in in diameter and 4 to 5 ft S to S up to 15 to 16 ft in diameter and 60 to 70 ft S to S Spherical separators are usually available in 24 or 30 in up to 66 to 72 in. in diameter x x 13 Source: Wikipedia

Classification of Oilfield Separators Horizontal oil and gas separators are manufactured with monotube and dual-tube shells - monotube units have one cylindrical shell - 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 x x 14 Source: Wikipedia

Monotube vs. Dual Tube Oilfield Separators 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 x x 15 Source: Wikipedia

Monotube vs. Dual Tube Oilfield Separators 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 x x 16 Source: Wikipedia

Monotube vs. Dual Tube Oilfield Separators 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 see Powers et al (1990) x x 17 Source: Wikipedia

Functional Classification of Oilfield Separators 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) x x 18 Source: Wikipedia

Functional Classification of Oilfield Separators 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 engineering analysis (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 x x 19 Source: Wikipedia

Functional Classification of Oilfield Separators 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 separator sizes. According to Song et al (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. x 20 Source: Wikipedia

Operating Pressure Classification of Separators Separators in oilfield operations can operate for vacuum pressures to 5,000 psi Generally oilfield separators are classified as - low pressure – from 10 to 225 psig - medium pressure – from 230 to 750 psig - high pressure – from 750 to 1500 psig and higher x x 21 Source: Wikipedia

Application Classification of Oilfield Separators Another classification of oilfield separators is by application such as - test separators - production separators - low temperature separators - metering separators - elevated separators - stage separators (first, second, etc.) x x 22 Source: Wikipedia

Test Separators A test separator is used to separate and to meter the well fluids and is specifically used as a well tester or well checker Test separators can be vertical, horizontal, or spherical, and they can be two-phase or three-phase They can be permanently installed or portable (skid or trailer mounted) Test separators are generally equipped with various types of meters for measuring the oil, gas, and/or water for potential tests, periodic production tests, marginal well tests, etc. x x 23 Source: Wikipedia

Low Temperature Separator A low-temperature separator is a special separator 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 x 24 Source: Wikipedia

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. x x 25 Source: Wikipedia

Separating the Oil from the Gas Difference in density of the liquid and gaseous hydrocarbons will generally accomplish acceptable separation in an oil and gas separator In some instances, it will be 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 It may be desirable or necessary to use some means to remove nonsolution gas from the oil before the oil is discharged from the separator. x x 26 Source: Wikipedia

x x x 27 Source: Wikipedia

Removing the Gas From the 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 - physical and chemical characteristics of the crude - operating pressure - operating temperature - rate of throughput - size and configuration of the separator - other factors. x x 28 Source: Wikipedia

Removing the Gas From the Oil 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 interfaced 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. x x 29 Source: Wikipedia

Removing the Gas From the Oil 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. x x 30 Source: Wikipedia

Removing the Gas From the Oil A combination of 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 x 31 Source: Wikipedia

Removing the Gas From the Oil 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 interfaced 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. 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 x 32 Source: Wikipedia

Removing the Gas From the Oil – Coalescer Coalescer 33 Source:

Separating the Oil from the Water The production of water with oil continues to be a problem for engineers and the oil producers. Since 1865 when water was coproduced with hydrocarbons, it has challenged and frustrated the industry on how to separate the valuable from the disposable According to Rehm et al (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 coalescer and most recently to the Performax Matrix Plate Coalescer, an enhanced gravity settling separator. x x 34 Source: Wikipedia

Separating the Oil from the Water 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 disposal 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 the reservoir x x 35 Source: Wikipedia

Separating the Oil from the Water In some instances it is preferable to separate and to remove water from the well fluid before it flows through pressure reductions, such as those caused by chokes and valves Early water removal may prevent difficulties that could be caused downstream by the water, such as corrosion 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. x x 36 Source: Wikipedia

Separating the Oil from the Water 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 oil 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 upstream or downstream of the separators. x x 37 Source: Wikipedia

Oil and Gas Separators Maintaining the Optimum Separator Pressure
For an oil and gas separator to accomplish its primary functions, pressure must be maintained in the separator so that the liquid and gas can be discharged into their respective processing or gathering systems Pressure is maintained on the separator by use of a gas backpressure valve 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 hydrocarbons. x x 38 Source: Wikipedia

Oil and Gas Separators Maintaining the Liquid Seal in the Separator
To maintain pressure on a separator, a liquid seal must be effected in the lower portion of the vessel This liquid seal prevents loss of gas with the oil and requires the use of a liquid-level controller and a valve. x x 39 Source: Wikipedia

Oil and Gas Separators Methods to remove Oil and Gas Using Separators
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 separated from by a demisting device x x 40 Source: Wikipedia

Until recently the main technologies used for this application were - reverse-flow cyclones - mesh pads - vane packs More recently new devices with higher gas-handling have been developed which have enabled potential reduction in the scrubber vessel size. x x 41 Source: Wikipedia

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 floating production facilities. Below are some of the ways in which oil is separated from gas in separators x x 42 Source: Wikipedia

Density Differences – Gravity Separation Natural gas is lighter than liquid hydrocarbon. 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 gas 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. x x 43 Source: Wikipedia

Density Differences – Gravity Separation At standard conditions of pressure and temperature, the droplets of liquid hydrocarbon may have a density 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. x x 44 Source: Wikipedia

Density Differences – Gravity Separation Liquid droplets may have a density 6 to 10 times that of the gas This density difference would 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. x x 45 Source: Wikipedia

Density Differences – Gravity Separation 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. x x 46 Source: Wikipedia

Oil and Gas Separators Impingement Methods
If a flowing stream of gas containing liquid, 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 impingement surfaces may be required to effect satisfactory removal of the mist. x x 47 Source: Wikipedia

Oil and Gas Separators Flow Direction Change
When the direction of flow of a gas stream containing liquid 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 removed may coalesce on a surface or fall to the liquid section below x x 48 Source: Wikipedia

Use of Centrifugal Force 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 x x 49 Source: Wikipedia

Use of Centrifugal Force 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 x x 50 Source: Wikipedia

Use of Centrifugal Force If a gas stream carrying liquid 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 effective methods of separating liquid mist from gas x x 51 Source: Wikipedia

Methods to Remove Gas from Oil in Separators Because of higher prices for natural gas, the widespread reliance on metering of liquid hydrocarbons, 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: x x slide is dated x 52 Source: Wikipedia

Agitation Process to Separate Nonsolution Gas Moderate, controlled agitation which can be defined as movement of the crude oil with sudden force is usually helpful in removing nonsolution gas 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. x x 53 Source: Wikipedia

Heat Effect in the Separator Process Heat as a form of energy that is transferred from one body to another is frequently manifested as a difference in temperature Heat reduces surface tension and viscosity of the oil and thus assists in releasing gas 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 water bath affords slight agitation, which is helpful in coalescing and separating entrained gas from the oil x 54 Source: Wikipedia

Heat Effect in the Separator Process A heated-water bath is a very 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 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 x x 55 Source: Wikipedia

Centrifugal Force for Separators 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. Cenrtrifugal force and its balanced but opposing centripetal force are effective in separating gas 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 liquid flows downward to the bottom of the unit x x 56 Source: Wikipedia

Measurement of Flow in Oil and Gas Separators The direction of flow in and around a separator along with other flow instruments are usually illustrated on the Piping and instrumentation diagram, (P&ID) Flow instruments include the - flow Indicator (FI) - flow transmitter (FT) - flow controller (FC) Flow and its measurement is of paramount importance in the oil and gas industry Understanding flow helps engineers come up with better designs for separators x x 57 Source: Wikipedia

Measurement of Flow in Oil and Gas Separators Mohan et al (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 hydrodynamic flow behavior in a three-phase oil and gas separator. A mechanistic model was developed alongside a computational fluid dynamics (CFD) simulator. These were then used to carry out a detailed experimentation on the three-phase separator. x x 58 Source: Wikipedia

Measurement of Flow in Oil and Gas Separators 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-in 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 x x 59 Source: Wikipedia

Calibration of Flow Instruments in Separators 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 time x x 60 Source: Wikipedia

Calibration of Flow Instruments in Separators 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 x x 61 Source: Wikipedia

Calibration of Flow Instruments in Separators 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. Another type of meter used is the transfer meter However, according to Ting et al (1989), transfer meters have been proven to be less accurate if the operating conditions are different from its original calibrated points x x 62 Source: Wikipedia

Calibration of Flow Instruments in Separators 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 National Institute of Standards and Technology, (NIST) NIST certification of a flowmeter lab means that its methods have been approved by NIST x x 63 Source: Wikipedia

Calibration of Flow Instruments in Separators NIST traceability normally means that the standards used in the flowmeter calibration 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 into or out of a container during the calibration procedure is the most ideal method for measuring the actual amount of flow x x 64 Source: Wikipedia

Calibration of Flow Instruments in Separators Normally, this includes NIST traceability, meaning that the standards used in the flowmeter calibration 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 into or out of a container during the calibration procedure is the most ideal method for measuring the actual amount of flow x x 65 Source: Wikipedia

Calibration of Flow Instruments in Separators Apparently, the weighing scale used for this method also has to be traceable to the National Institute of Standards and Technology (NIST) as well 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 flowrate as determined by the standardized National Institute of Standards and Technology master meter or weigh scale. x x 66 Source: Wikipedia

Oil and Gas Separators Controls and Features for Oil and Gas Separators The controls required for oil and gas separators are liquid level controllers for oil and oil/water interface (three phase operation) and gas back-pressure control valve 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).[17] x x 67 Source: Wikipedia

Oil and Gas Separators Controls and Features for Oil and Gas Separators The Big Piney wells with separators were located above ,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 Distributed Control System All in all, this improved the efficiency of personnel and the operation of the field, with a corresponding increase in production from the area x x 68 Source: Wikipedia

Valves The valves required for oil and gas separators include - oil discharge control valves - water-discharge control valve (three-phase operation - drain valves, block valves - pressure relief valves - emergency shutdown valves (ESD) x x 69 Source: Wikipedia

Emergency Shutdown (ESD) Valves 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[18] x x 70 Source: Wikipedia

Accessories for Oil and Gas Separators Some separator accessories include - pressure gauges - thermal sensors - pressure reducing regulators - sight glass levels - safety head with rupture disk - piping - tubing x x 71 Source: Wikipedia

Oil and Gas Separators High and Low Level Controls for Separators
High- and low liquid-level controls normally are float- operated pilots that - actuate a valve on the inlet to the separator - open a bypass around the separator - sound a warning alarm - perform some other pertinent function to prevent damage that might result from high or low liquid levels in the separator x x 72 Source: Wikipedia

High and Low Pressure Controls for Separators 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 - electric The control process can - sound a warning - actuate a shut-in valve - open a bypass - perform other pertinent functions to protect personnel, the separator, and surrounding equipment x x 73 Source: Wikipedia

High and Low Temperature Controls for Separators Temperature 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 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 "vapor-phase" reservoirs. x x 74 Source: Wikipedia

High and Low Temperature Controls for Separators Low temperatures obtainable from the expansion of these high-pressure gas streams are utilized to a profitable advantage Low temperature control can result in - more efficient recovery of the hydrocarbon condensate - a greater degree of dehydration of the gas as compared to the conventional heater and separator installation A major advantage of low-temperature controls in oil and gas separators.[ x x 75 Source: Wikipedia

Safety Relief Valve on Oil and Gas Separators A spring-loaded safety relief valve is usually installed on all oil and gas 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 fluid 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 x x 76 Source: Wikipedia

Safety Heads and Rupture Disks on Separators A safety head or rupture disk is a device containing a thin metal membrane that is designed to rupture when the pressure 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 valve has opened and is incapable of preventing excessive pressure buildup in the separator x x 77 Source: Wikipedia

Operations and Maintenance (O&M) of Separators 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 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 et al (1990).[20] x 78 Source: Wikipedia

Periodic Inspection for Corrosion and Erosion In refineries and processing plants, it is normal practice to inspect all pressure vessels and piping periodically for corrosion 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 equipment It is recommended that periodic inspection schedules for all pressure equipment be established and followed to protect against undue failures. x x 79 Source: Wikipedia

Installing Safety Devices All safety relief devices should be installed as close to the vessel as possible and in such manner that the reaction force from exhausting fluids will not break off, unscrew, or otherwise dislodge the safety device The discharge from safety devices should not endanger personnel or other equipment x x 80 Source: Wikipedia

Low Temperature Precautions Separators should be operated above hydrate-formation temperature 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 liquid or gas outlet is plugged or restricted, this causes the safety valve 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 x x 81 Source: Wikipedia

Corrosive Fluid Precautions A separator handling corrosive fluid should be checked periodically to determine whether remedial work is required Extreme cases of corrosion may require a reduction in the rated working pressure of the vessel Periodic hydrostatic testing is recommended, especially if the fluids being handled are corrosive. x x 82 Source: Wikipedia

Corrosive Fluid Precautions Expendable anode can be used in separators to protect them against electrolytic corrosion 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 x x 83 Source: Wikipedia

Oil and Gas Separators x x x 91 Source: Wikipedia

Description of Oil and Gas Separators An oil/gas separator is a pressure vessel used for separating a well stream into gaseous and liquid components They are installed either in an onshore processing station or on an offshore platform Based on the vessel configurations, the oil/gas separators can be divided into - horizontal separators - vertical separators - spherical separators x x 98 Source: Wikipedia

Description of Oil and Gas Separators In terms of fluids to be separated, the oil/gas separators can be grouped into - gas/liquid two-phase separator - oil/gas/water three-phase separator Based on separation function, the oil/gas separators can also be classified into - primary phase separator - test separator - high-pressure separator - low-pressure separator - deliquilizer - degasser - more x x 99 Source: Wikipedia

Description of Oil and Gas Separators To meet process requirements, the oil/gas separators are normally designed in stages The first stage separator is used for preliminary phase separation The second and third stage separator are applied for further treatment of each individual phase (gas, oil and water). x x 100 Source: Wikipedia

Description of Oil and Gas Separators Depending on a specific application, oil/gas separators are also called - deliquilizers - degasser The deliquilizers are used to remove dispersed droplets from a bulk gas stream The degassers are designed to remove contaimined gas bubbles from the bulk liquid stream. x x 101 Source: Wikipedia

Other Names for Separators The terminology for separators varies depending on region and field. Some names are: - oil/gas separator - gas/liquid separator - degasser - deliqulizer - scrubber - trap x x 102 Source:

Principal Components of the Separator Principal components for an oil and gas separator include (monotube or vertical) - inlet device located in the pre-separation zone - baffles downstream of the inlet to improve flow distribution - separation enhancement device located in the primary separation or gravity settling section for major separation - mist extraction device located in the gas space to reduce liquid in the gas stream - various weirs to control the liquid level or interface level - vortex breaker to prevent gas carry-under at the outlet of the liquid phase - liquid level / interface detection and control features - gas, water and oil outlets - pressure relief devices x x 103 Source:

Oil and Gas Separators Positioning of the Oil and Gas Separator
In most oil/gas processing systems, the oil/gas separator is the first vessel the well stream flows through after it leaves the producing well Other equipment such as heaters may be installed upstream of the separator x x 104 Source:

x x x 105 Source:

Separator Requirements Separators are designed to meet the requirements of oil and gas streams that met saleable pipeline specifications as well as disposal Oil must have less than 1% (by volume) water and less than 5 lbm water/MMscf gas Water stream must have less than 20 ppm oil for overboard discharge in the Gulf of Mexico (GOM). x x 106 Source:

Requirements of Separators Fig. 1—Typical GOM production separation train consisting of HP, IP, FWKO, degasser, and BOT (courtesy of CDS Separation Technologies Inc.). Source:

Bulk Water Removal Bulk water is removed in the third stage, FWKO, and final dewatering is accomplished in the BOT In the North Sea and other locations, water may be removed in the HP and/or IP vessels The BOT is typically an electrostatic treater Sometimes, the BOT will include a degassing section, eliminating the need for a separate degasser vessel. x x 108 Source:

Bulk Water Removal Typical deepwater GOM platform pressures for degasser stages are psig for HP - 700 psig for IP - 250 psig for IP - 50 psig for FWKO x x 109 Source:

x x x 110 Source: petrowikii

in the Oil and Gas Industry
Separators in the Oil and Gas Industry Separators in the Oil and Gas Industry PTRT xxxx Chapter xx Source: xx 111

Functional Descriptions of Separators for O&G An oil/gas separator is a pressure vessel used for separating a well stream into gaseous and liquid components and applicable on shore and offshore Based on the vessel configurations, the oil/gas separators can be divided into horizontal, vertical, or spherical separators In terms of fluids to be separated, the oil/gas separators can be grouped into gas/liquid two-phase separator or oil/gas/water three-phase separator Based on separation function, the oil/gas separators can also classified into primary phase separator, test separator, high-pressure separator, low-pressure separator, deliquilizer, degasser, etc. x 112 Source: Petrowiki

Functional Descriptions of Separators for O&G To meet process requirements, the oil/gas separators are normally designed in stages, in which the first stage separator is used for preliminary phase separation, while the second and third stage separator are applied for further treatment of each individual phase (gas, oil and water) Depending on a specific application, oil/gas separators are also called deliquilizer or degasser The deliquilizers are used to remove dispersed droplets from a bulk gas stream Degassers are designed to remove contamined gas bubbles from the bulk liquid stream x 113 Source: Petrowiki

Separator Components An oil/gas separator generally consists of following components - inlet device located in pre-separation zone/section for preliminary phase separation - baffles downstream the inlet component to improve flow - separation enhancement device in the primary separation (gravity settling) section for major phase separation - mist extraction device located in gas space to further reduce liquid content in the bulk gas stream - various weirs to control the liquid level or interface level - vortex breaker to prevent gas carryunder at outlet of liquid phase - liquid level/interface detection and control, etc. - gas, oil, water outlet - pressure relief devices x 114 Source: Petrowiki

Separator Components In most oil/gas processing systems, the oil/gas separator is the first vessel the well stream flows through after it leaves the producing well However, other equipment such as heaters may be installed upstream of the separator. x x 115 Source: Petrowiki

Functions of a Separator The primary functions of an oil/gas separator, along with separation methods, are summarized in table x x 116 Source: Petrowiki

Requirements of Separators Separators are required to provide oil/gas streams that meet saleable pipeline specification as well as disposal Oil must have less than 1% (by volume) water and less than 5 lbm water/MMscf gas Water stream must have less than 20 ppm oil for overboard discharge in the Gulf of Mexico (GOM). x x 117 Source: Petrowiki

Separator Depressurization Stage recovery of liquid hydrocarbons - Staged separation (depressurization) - to maximize the liquid hydrocarbon volumes from the figure on the next slide shows a typical deepwater GOM (Gulf of Mexico) process train There are four stages of depressurization - high pressure (HP) - intermediate pressure (IP) - free water knockout (FWKO) - the degasser/bulk oil treater (BOT) combination Terms/acronyms to remember - GOM Gulf of Mexico - BOT bulk oil treater - FWKO free water knock out - FGC - VRU x 118 Source: Petrowiki

GOM Process Train Typical GOM production separation train consisting of HP, IP, FWKO, degasser, and BOT (courtesy of CDS Separation Technologies Inc.) 119 Source: Petrowiki

Bulk Water Removal Bulk water is removed in the third stage, FWKO, and final dewatering is accomplished in the BOT In the North Sea and other locations, water may be removed in the HP and/or IP vessels The BOT is typically an electrostatic treater. Sometimes, the BOT will include a degassing section, eliminating the need for a separate degasser vessel Typical deepwater GOM platform pressures for degasser stages are: - 1,500 psig for HP - 700 psig for IP - 250 psig for IP - 50 psig for FWKO x x 120 Source: Petrowiki

Metering Metering is performed for - protection of pumps and compressors - booster compressor unit x x 121 Source: Petrowiki

Three-stage Compressor Train Typical three-stage compressor train (courtesy of CDS Separation Technologies Inc.). 122 Source: Petrowiki

Glycol Dehydration The glycol dehydration unit. Both systems make use of separators as a major component in their design. x F 123

Glycol Dehydration System Figure showing typical glycol dehydration system (Courtesy of CDS Separation Technologies Inc.) 124

Vertical vs. Horizontal Separators x 125

Design Considerations The oil/gas separators are typically sized by the settling theory or retention time for the liquid phase To handle the liquid surges or production fluctuation frequently encountered during oil/gas production, it is a common practice to size the oil/gas separators with a sufficient margin. x x 126

Design Considerations The separator is generally divided into the following functional zones - inlet zone - flow distribution zone - gravity separation/coalescing zone - outlet zone Each zone has to be carefully designed to achieve the designated overall separation performance. x x 127

Separator Inlet Zone Appropriate inlet device is needed to obtain an initial bulk separation of liquid/gas In most cases, gas will have already come out of solution in the pipeline, leading to the separator (because of pressure drop across an upstream choke or a control valve) Hence, the majority of the gas is separated from the liquid in the inlet zone x x 128

Separator Inlet Zone Because of foaming issues and the need for higher capacities, cyclonic inlets are now becoming increasingly popular For applications with inlet momentum saying less than kPa, a vane inlet can be used Typical inlets include: - flat impact plates - dished-head plates - half-open pipes - vane-type inlet - cyclone-cluster inlet x x 129

Separator Inlet Zone These inlets, although inexpensive, may negatively affecting separation performance especially for higher- momentum fluids The flat or dished-head plates can result in small drops and foam. The open-pipe designs can lead to fluid short-circuiting or channeling Although inlet momentum is a good starting guideline for selection, the process conditions, as well as the demister choice, should also be considered For example, if the liquid loading is low enough that a demister can handle all the liquid, then inlet devices can be applied beyond their typical momentum ranges x 130

Flow Distribution Zone Regardless of the size of the vessel, short-circuiting can result in poor separation efficiency Integral to any inlet device is a flow straightener such as a single perforated baffle plate A full-diameter plate allows the gas/liquid to flow more uniformly after leaving the vane-type inlet, inlet cyclones, or even the impact plates The plate also acts as an impingement demister and foam breaker as well. x x 131

Flow Distribution Zone Typical net-free area (NFA) ranges in the 10-50% range As the NFA lowers, the shear of the fluids gets higher, so the NFA should be matched to the particular application One concern of these plates is solids buildup on the upstream side Generally, the velocities are high enough in the inlet zone to carry the solids through the perforations In any case, a flush nozzle should be installed in the inlet zone Other designs include flow straightening vanes However, the open area is generally too high to be effective x 132

Gravity / Coalescing Zone Mechanisms to assist in separation (and foam breaking) are sometimes introduced in the gas/liquid separator These include: - mesh pad - vane pack - and/or plate/matrix packs These devices provide more impingement or shearing surfaces to enhance coalescing effect of the dispersed phase For the gas phase, matrix/plate packs and vanes have been used to aid in liquid drop coalescence or foam breaking. x x 133

Gravity / Coalescing Zone The theory behind installing the high surface internals such as plate packs for foam breaking is that the bubbles will stretch and break as they are dragged along the surfaces However, if most of the gas flows through the top portion of the pack, the foamy layer will not be sufficiently sheared, and the bubbles will meander through to the other end x x 134

Outlet Zone Mist capture can occur by three mechanisms; it should be kept in mind that there are no sharply defined limits between mechanisms - inertial impaction - direct impaction - Browninan capture x x 135

Outlet Zone As the momentum of a droplet varies directly with liquid density and the cube of the diameter, heavier or larger particles tend to resist following the streamline of a flowing gas and will strike objects placed in their line of travel This is inertial impaction, the mechanism responsible for removing most particles of diameter > 10 μm x x 136

Outlet Zone Smaller particles that follow the streamlines may collide with the solid objects, if their distance of approach is less than their radius. This is direct impaction. It is often the governing mechanism for droplets in the 1- to 10-μm range x x 137

Outlet Zone With submicron mists, Brownian capture becomes the dominant collection mechanism. This depends on Brownian motion—the continuous random motion of droplets in elastic collision with gas molecules As the particles become smaller and the velocity gets lower, the Brownian capture becomes more efficient. x x 138

Outlet Zone Almost all mist elimination equipment falls into four categories: - mesh - vanes - cyclones - fiber-beds x x 139

Separator Performance Separation performance can be evaluated by liquid carrying over and gas carrying down rates, which are affected by many factors, that include: - flow rates - fluid properties - vessel configuration - internals - control system - more x x 140

Separator Performance The gas capacity of most gas/liquid separation vessel is sized on the basis of removing a certain size of liquid droplets The main unknown is the incoming drop-size distribution Without this, the effluent quality cannot realistically be estimated For example, a specification that the gas outlet should have less than 0.1 gal/MMscf liquid is somewhat difficult to guarantee because of the unknown drop-size distribution. x x 141

Separator Performance Pressure drops across upstream piping components and equipment can create very small drops (1 to 10 μm) while coalescence in piping and inlet devices can create larger drops A removal drop size of 10 μm for scrubbers is more realistic to specify. The same discussion applies to water-in-oil and oil-in-water specifications To the author’s knowledge, a correlation is not available to predict water-in-oil or oil-in-water concentrations For example, prediction of whether a separator can produce an oil stream with less than 20%v water is generally based on experience or analogous separators x x 142

Separator Performance The liquid capacity of most separators is sized to provide enough retention time to allow gas bubbles to form and separate out More retention time is needed for separators that are designed to separate oil from water, as well as gas from liquid (three-phase compared to two-phase separators) x x 143

Interior Vessel Impact on Separator Performance It is evidenced that vessel internals could significantly affect the operating performance of an oil/gas separator through the following ways: - flow distribution - drop/bubble shearing and coalescence - foam creation - mixing - level control x x 144

Foaming in Oil and Gas Separators – Bad News When pressure is reduced on crude oil, an amount of dissolved gas will be released During this process , on certain types of crude oil, some of the gas evolves as tiny bubbles that are encased in a thin film of oil This may result in foam, or froth, being dispersed in the oil and creates what is known as “foaming” oil In other types of crude oil, the viscosity and surface tension of the oil may mechanically lock gas in the oil and can cause an effect similar to foam Oil foam is not stable or long-lasting unless a foaming agent is present in the oil x x 145

Foaming in Oil and Gas Separators – Bad News Whether crude oil is foamy is not well known The presence of a surface active agent and process conditions play a part The literature indicates organic acids as being a foaming agent High-gravity oils and condensates typically do not result in foaming situations, as described by Callaghan et al.[1] x x 146

Foaming in Oil and Gas Separators – Bad News Foaming greatly reduces the capacity of oil/gas separators because a much longer retention time is required to adequately separate a given quantity of foaming crude oil Foaming crude oil cannot be measured accurately with positive-displacement meters or with conventional volumetric metering vessels These problems, combined with the potential loss of oil/gas because of improper separation, emphasize the need for special equipment and procedures in handling foaming crude oil. x x 147

Foaming in Oil and Gas Separators – Bad News Principal factors that assist in “breaking” foaming oil are: - settling - agitation (baffling) - heat - chemicals - centrifugal force These factors or methods of “reducing” or “breaking” foaming oil are also used to remove entrained gas from oil x x 148

Foaming in Oil and Gas Separators – Bad News Many different designs of separators have evolved for handling foaming crude oil They are available from various manufacturers—some as standard foam handling units and some designed especially for a specific application Silicone- and fluorosilicone-based chemical defoamers are typically used in conjunction with cyclonic inlets to break foam The chemical defoamer concentration is generally in the range of 5 to 10 ppm, but for many GOM crudes, 50 to ppm is common x x 149

Foaming in Oil and Gas Separators – Bad News Fig. 4 is a gamma ray scan of a 48-in.-diameter horizontal gas separator showing the problems resulting from foam. The horizontal axis is signal strength, and the vertical axis is height within the separator. High signal strength indicates less mass or more gas. Less signal strength indicates more mass or liquid. As the chemical rate is decreased, the interface between gas/liquid becomes less defined. The bottom of the vessel becomes gassy (more signal), while the upper portion becomes foamy (less signal). Liquid carryover occurs as the foam is swept through the demister. Gas carry-under occurs as the bubbles cannot be separated. Fig. 4—Example of gamma scan results (courtesy of CDS Separation Technologies Inc.). x x 150

x x x 151

Processing Foamy Crudes through Separators Fig. 5 shows a horizontal separator used to process foamy crudes. The fluids flow through inlet cyclones, where the centrifugal action helps break the large bubbles. A perforated plate downstream of the inlet cyclones aids in promoting uniform flow as well as demisting and defoaming. Demisting cyclones in the gas outlet remove large amounts of the liquid that results from a foamy oil layer. The foamy oil pad results from the small bubbles that cannot be removed in the inlet cyclones. Fig. 5—Two-phase separator designed for foam breaking (courtesy of CDS Separation Technologies Inc.). x x 152

x x xFig. 5—Two-phase separator designed for foam breaking (courtesy of CDS Separation Technologies Inc.). 153

Processing Foamy Crudes through Separators In between the perforated plate and the demister, high- surface internals such as plate or matrix packs are sometimes installed to break the large bubbles. As previously discussed, the theory behind the high- surface internals is that the bubbles will stretch and break as they are dragged along the surfaces However, if most of the gas flows through the top portion of the pack, the foamy layer will not be sufficiently sheared, and the bubbles will meander through to the other end. x x 154

Paraffin in Oil and Gas Separators – Bad News Paraffin deposition in oil/gas separators reduces their efficiency and may cause them to be inoperable by partially filling the vessel and/or blocking the mist extractor and fluid passages Paraffin can be removed by steam or solvents, however, the best solution is to prevent initial deposition in the vessel by heat or chemical treatment of the fluid upstream of the separator Another generally successful method involves the coating of all internal surfaces of the separator with a plastic for which paraffin has little or no affinity The weight of the paraffin causes it to slough off the coated surface before it builds to a harmful thickness. x 155

Paraffin in Oil and Gas Separators – Bad News In general, paraffinic oils are not a problem when the operating temperature is above the cloud point (temperature at which paraffin crystals begin to form) The problems arise, however, during a shutdown, when the oil has a chance to cool. paraffin comes out of solution and plates surfaces. When production is restored, the incoming fluid may not be able to flow to the plated areas to dissolve the paraffin In addition, temperatures higher than the cloud point are required to dissolve the paraffin x x 156

Solids and Salt Handling If sand and other solids are continuously produced in appreciable quantities with well fluids, they should be removed before the fluids enter the pipelines. Salt may be removed by mixing water with the oil, and after the salt is dissolved, the water can be separated from the oil and drained from the system. x x 157

Solids and Salt Handling Vertical vessels are well suited for solids removal because of the small collection area. The vessel bottom can also be cone-shaped, with water jets to assist in the solids removal. In horizontal vessels, sand jets and suction nozzles are placed along the bottom of the vessel, typically every 5 to 8 ft. Inverted troughs may be placed on top of the suction nozzles as well to keep the nozzles from plugging. A sand-jet system is shown in Fig. 6. x x 158

Solids and Salt Handling This type of system is sometimes difficult to use while the vessel is in operation because of the effect of the jetting and suction on separation and level control. For vessels that must be designed to enable sand jetting while in service, see the discussion on Emulsion Treating x x 159

x x xFig. 6—Sand-jet system (courtesy of CDS Separation Technologies Inc.). 160

Corrosion in Oil and Gas Separators Produced well fluids can be very corrosive and cause early failure of equipment. The two most corrosive elements are hydrogen sulfide and carbon dioxide. These two gases may be present in the well fluids in quantities from a trace up to 40 to 50% of the gas by volume. A discussion of corrosion in pressure vessels is included in the page of water treating. x x 161

Sloshing Because of the action of waves or ocean current on a floating structure, liquid contents in an oil/gas separator would be excited, which results in internal fluid sloshing motions It is particularly a problem in long horizontal separators Sloshing degrades the separation efficiency through additional mixing, resulting in liquid carry-over in the gas line, gas carry-under in the liquid line, and loss of level control In three-phase separators, oil/water and gas/liquid separation efficiency is degraded. x x 162

Sloshing It is necessary to design internal baffle systems to limit sloshing Emphasis is generally placed on internals for wave dampening in gas-capped separators because of the larger fluid motions The liquid level changes from end to end must be considered in the design of the inlet and outlet devices Too low a liquid level can result in gas blow-by of inlet cyclones, whereas too high a liquid level can cause siphoning of liquid through the mist extractor. x x 163

x Table 3 gives some estimates of the natural period of the liquid for vessels undergoing lengthwise motions (sway). The periods are in the order of 10s, which is similar to the period found for floating platforms such as tension leg platforms (TLP) and floating production, storage and offloading (FPSO) vessels under a 10-year storm condition. x x 164

x x x 165

x The alignment of the separators with the structure motion should be considered when designing the layout. For example, on TLP, the vessels are recommended to be aligned with their long dimension, perpendicular to the TLP prevailing motion. On ships, the magnitude and period of the pitch and roll should be considered when aligning the vessels. Normally, it is recommended to align the separators with their long dimension along the length of the ship. - the available literature, as described by Roberts et al.[2], highlights two main features of wave-damping internals: - elimination of the gas/liquid interface - shifting of the natural sloshing frequency of the separator away from the platform frequency - on some ships, fuel tanks fill with sea water, as the fuel is spent, to prevent problems associated with sloshing x 166

x Shifting the natural frequency is usually accomplished by segmenting the vessel with transverse baffles. The baffles are perforated, can be placed throughout the liquid phase, or can be placed in the region of the oil/water interface. However the following are major concerns: - vessel access - solids collection - mixing are major concerns - horizontal perimeter baffles can be used, but they have disadvantages as well. Other baffle shapes include angled wings along the length of the vessel to mitigate waves because of roll as well as vertical perforated baffles down the length of the vessel. Table 4 highlights the differences between horizontal and vertical baffles. x 167

x x x 168

Level Controls for Oil and Gas Separators Stable control of the oil/water and gas/oil interfaces is important for good separation. The typical two-phase separator level settings are shown in Table 5 For three-phase operation, level settings are placed on both the oil/water interface and oil/gas interface levels x x 169

x x x 170

Spacing of the Levels in Oil and Gas Separators Typically, the spacing between the different levels is at least 4 to 6 in. or a minimum of 10 to 20 seconds of retention time. The location of the lowest levels must also consider sand/solids settling. These levels are typically 6 to 12 in. from the vessel bottom. Minimum water/oil pad thicknesses are approximately 12 in. Note that these minimum settings may dominate the vessel sizing as opposed to the specified retention times. x x 171

Spacing of the Levels in Oil and Gas Separators In a two- or three-phase horizontal separator with very little liquid/water, a boot or “double-barrel” separator configuration is used. All the interface controls are then located within the boot or lower barrel. Examples of these types of separators can be seen at Separator types. x x 172

Spacing of the Levels in Oil and Gas Separators To coerce the liquid to exit through the tube-wall gap, a slipstream of gas is also withdrawn. The slipstream is induced to exit through the gap by maintaining a lower pressure in the outer annular space than that which is inside the tubes. This is done by constructing ducts between the annular space and the hollow core pieces of all the spin generators. The tails of these hollow cores are, in turn, open to the low pressure of the newly generated gas vortices. A gas slipstream of about 5% is recycled out of the tubes to pull liquid out, then back to the spin generator and out its tail end, where it joins the main gas stream. x x 173

x ρc = continuous phase density, kg/m3; μc continuous phase dynamic viscosity, kg/(m∙s) or N∙s/m2; Vc continuous phase velocity, m/s; dh hydraulic diameter. Vr drop/rise velocity, m/s; Vh horizontal water velocity, m/s; L plate-pack length, m; dpp plate-pack perpendicular gap spacing, m. ρw water density, kg/m3; ρo oil density, kg/m3; μw water dynamic viscosity, kg/(m∙s) or N∙s/m2; g gravitational acceleration, 9.81 m/s2; Do drop diameter, m. Vm design velocity, m/s; ρg gas-phase density, kg/m3; ρl liquid-phase density, kg/m3; K mesh capacity factor, m/s x Nomenclature x 174

References Callaghan, I.C., McKechnie, A.L., Ray, J.E. et al Identification of Crude Oil Components Responsible for Foaming. SPE J. 25 (2): 171–175. SPE PA. ↑ Roberts, J.R., Basurto, E.R., and Chen, P.Y Slosh Design Handbook I, NASA-CR-406, Contract No. NAS Huntsville, Alabama: Northrop Space Laboratories. x x 175

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