WO2011037864A1 - Séparation gaz-liquide en fond de puits - Google Patents

Séparation gaz-liquide en fond de puits Download PDF

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Publication number
WO2011037864A1
WO2011037864A1 PCT/US2010/049503 US2010049503W WO2011037864A1 WO 2011037864 A1 WO2011037864 A1 WO 2011037864A1 US 2010049503 W US2010049503 W US 2010049503W WO 2011037864 A1 WO2011037864 A1 WO 2011037864A1
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WO
WIPO (PCT)
Prior art keywords
gas
liquid
separation chamber
passing
separator
Prior art date
Application number
PCT/US2010/049503
Other languages
English (en)
Inventor
Guy Morrison
Original Assignee
Guy Morrison
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US12/567,933 external-priority patent/US20110073304A1/en
Application filed by Guy Morrison filed Critical Guy Morrison
Priority to MX2012003722A priority Critical patent/MX2012003722A/es
Priority to CA2775841A priority patent/CA2775841C/fr
Priority to AU2010298524A priority patent/AU2010298524B2/en
Publication of WO2011037864A1 publication Critical patent/WO2011037864A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/38—Arrangements for separating materials produced by the well in the well

Definitions

  • the present invention relates to the separation of gas from liquids in oil and gas wells, and particularly to a method of downhole separation of gas and liquid from a producing reservoir.
  • Production fluid the fluid obtained from oil and gas wells, is generally a combination of substantially incompressible liquids and compressible gases.
  • production fluid for methane production from coal formations includes such gases and water.
  • pumping of such production fluid has presented difficulties due to the compressibility of the gases, which leads in the best of circumstances to reduction in pumping efficiency, and more detrimental, to pump lockage or cavitation.
  • Cavitation happens as cavities or bubbles form in pumped fluid, occurring at the low pressure or suction side of a pump.
  • the bubbles collapse when passing to higher pressure regions, causing noise and vibration, leading to material erosion of the pump components. This can be expected to cause loss of pumping capacity and reduction in head pressure, reducing pump efficiency to the point of, over time, pump stoppage.
  • waste components of the production fluid are reinjected above or below the production formation instead of bringing such waste components to the surface.
  • Various embodiments of the present invention are generally directed to the production of gas and liquid from a subterranean formation.
  • a method for separating gas from liquid in a gas and liquid producing oil well having a bore extending from ground surface to a reservoir level and having a tubing string extending from the surface.
  • the method includes separating gas from liquid by a downhole gas separator having a separation chamber; and pumping liquid from the separation chamber by a downhole submersible pump to the tubing at a rate to at least partially vacate the separation chamber whereby sufficient space is provided in the separation chamber for the gas to separate from the liquid, the liquid passing to the tubing and the gas passing to the well bore.
  • a method for use in a gas and liquid producing well in which tubing extends in a well bore from ground surface to a reservoir fluid level.
  • the method includes separating gas from liquid in a downhole gas separation chamber, and pumping liquid from the separation chamber at a rate to maintain a less than full liquid level in the separation chamber to provide sufficient space in the separation chamber for gas to have sufficient residence time to substantially separate from the liquid, the liquid passing to the tubing and the gas passing to the well bore.
  • FIG. 1 is a partially detailed, side elevational representation of a downhole gas separator capable of practicing the present invention.
  • FIG. 2 is a partially detailed, side cut away, elevational view of one section of the downhole gas separator of FIG. 1.
  • FIG. 3 is a full cutaway elevational view of a separator section of the downhole gas separator of FIG. 1.
  • FIG. 4 is a partially cut away view of a back pressure diffuser of a pumping stage of the separator section of FIG. 3.
  • FIG. 5 is a partially cut away view of an impeller of a pumping stage of FIG. 3.
  • FIG. 6 is a partially cut away view of the back pressure device of the separator section of FIG. 3.
  • FIG. 7 is a side cut away view of a separator section of the separator of FIG. 1 with an alternative internal pump and vortex generator.
  • FIG. 8 is a functional block representation of a gas and liquid producing well configured and operated in accordance with various embodiments.
  • FIG. 9 shows a graphical representation of an exemplary pump curve that can be used to configure the well of FIG. 8.
  • FIG. 10 is a schematic representation of a two-stage separator of the equipment configuration depicted in FIG. 8.
  • FIG. 1 1 is a plan view of a back pressure device in the form of a plate having a plurality of calibrated fluid passing bores.
  • the present disclosure is generally directed to production fluids from a subterranean formation, such as gas, water (fresh or brine), oil or any other matter that are generally collectively referred to herein as production fluid.
  • a method is generally disclosed for separating gas from liquid in a gas and liquid producing oil well having a bore extending from ground surface to a reservoir level and having an oil well tubing extending from the surface. Gas is separated from liquid by a downhole gas separator having a gas and liquid separation chamber, and liquid is pumped from the separation chamber by a variable speed downhole submersible pump to the oil well tubing at a rate to at least partially vacate the separation chamber, thereby providing sufficient space in the separation chamber for the gas to have adequate residence time in the chamber to separate from the liquid.
  • Both the liquid stream, which passes to the tubing, and the separated gas stream, which passes external to the tubing to the well bore flow as separated steams to the surface.
  • the downhole gas separator receives gas and liquid fluid from the reservoir through the well bore, restricting the amount of gas and liquid entering the separation chamber to a predetermined flow rate that is less than the set pumping rate of the upstream submersible pump.
  • a vortex of the gas and liquid is generated in the separation chamber so liquid is moved to the periphery of the separation chamber and the gas remains near the axial center of the separation chamber; the gas is separated from the liquid to pass through a gas outlet port into the well bore and transported to the surface by the buoyancy, and the separated liquid passes to a liquid inlet port of the submersible pump.
  • the rate of fluid flow to the separation chamber is selectively determined in relation to the liquid pumping rate of the downhole submersible pump so as to admit less liquid to the separation chamber than the liquid pumping rate of the downhole submersible pump. That is, the capacity size of the downhole submersible pump will be considered in sizing the inlet flow rate to the separation chamber, and the pumping rate will be set, so as to cause the submersible pump to run "lean", thereby inducing a drop in pressure in the separation chamber.
  • the gas and liquid fluid received by the downhole gas separator is passed through a flow restrictor having one or more calibrated bores, the sum of the cross sectional flow areas of the calibrated bores being a predetermined value that permits passage of the gas and liquid fluid at a predetermined flow rate that is less, by a predetermined amount, than the pumping rate of the submersible pump.
  • the downhole separation will be described as being conducted by a downhole separator 10 shown in FIG. 1.
  • the downhole separator 10 in its operational application, will be supported from a submersible pump (not shown in FIG. 1) that in turn is supported from the lower end of a tubing string (also not shown) that is positioned in the well bore of an oil well that provides fluid communication with a gas and oil producing geological, underground reservoir so the gas and oil fluid can be pumped to surface located facilities.
  • the term oil well shall have its usual meaning of an oil producing well, a gas producing well or a gas and oil producing well.
  • the downhole separator 10 preferably embodies a lower first separation section 12 and an upper second separation section 14.
  • Each of the separation sections 12, 14 has a housing defining an interior cavity in which, as described below, is located a flow restricting means, an internal pump and a separation chamber. Except as described herein, the construction of the first and second separation sections 12, 14 is essentially the same, so it will be necessary only to describe the construction details with regard to one of the sections. Of course, it will be appreciated that the quantity of production fluid passing through the lower, first separation section 12 will be reduced by the amount of gas removed therefrom, so that the quantity of fluid passed to the upper, second separation section will be less than that through the first separation section. Thus, the sizing of the internal components will be different for the two separation sections.
  • the number of separator sections, and the flow capacity of the sections is predetermined to be less than the pumping capacity of the submersible pump, which in turn is engineered to service the withdrawal capacity of the well. This is also a function of the gas content of the production fluid.
  • the entering flow rate from the reservoir through the separator being determined to be lower than the submersible pump flow rate, assures vacating the upper separation chamber.
  • the downstream separator sections are designed to handle lower fluid flow rates, because the gas removed from upstream sections diminish the amount of fluid passed to the downstream separator sections and thereafter to the submersible pump.
  • the first separation section 12 has a housing 16, a base 18, and a head member 20, and the second separation section 14 also has a housing 16, a base 18 and a head member 20.
  • Each housing 16 is a hollow, elongated, cylinder.
  • the base 1 8 of the lower section 12 has a plurality of circumferentially arranged inlet ports 22 that communicate production fluid received from the underground reservoir to the interior cavities of the housings 16 of the first and second separator sections 12, 14.
  • the head member 20 has a body portion 24 that is generally cylindrically shaped and has a plurality of upwardly extending threaded studs 26.
  • An external, circumferential channel 28 extends around the body portion 24, and the body portion is externally threaded to engage with internal threads at the upper end of the housing 16.
  • An upwardly opening, tapered cavity 30 extends through the body portion 24.
  • An upper bearing 32 is mounted in the cavity 30, and a plurality of
  • circumferentially arranged liquid outlet ports 34 extend upwardly and inwardly through the body portion 24.
  • a plurality of circumferentially arranged gas outlet ports 36 extend upwardly and outwardly to the channel 28.
  • An elongated cylindrical drive shaft 38 with opposing splined ends extends through the interior cavity 40 of the housing 16 and is supported by appropriately spaced apart bearings to extend the length of the housing 16.
  • a downhole electric motor (not shown in these figures) is connected to, and supported by, the base 18 on the lower end of the first separator section; the drive shaft 38 connects to, and is rotated by the downhole electric motor, which is powered by electrical conductor lines (not shown) that extend upwardly through the well bore to a power source at the ground surface.
  • the upper end of the drive shaft 38 is connected to, and serves to power, the submersible pump.
  • a pair of vortex generators 42 are provided in the interior cavity 40, with each vortex generator having a plurality of spaced vertical paddles 44 extending radially from a hub member 46 that is supported by the drive shaft 38.
  • Each of the vortex generators 42 is disposed within a separation chamber portion 48.
  • the paddles 44 stir the passing fluid in the separation chamber 46 into a vortex, with the liquid forced against the inner surface of the housing 16, separating the gas to pass along the axial center thereof.
  • the dimensional length of the separation chamber 48 is determined so as to provide sufficient fluid dwell time (the time for fluid to travel the length of the chamber) to effect separation of gas from the production fluid.
  • the length of the separation section 14 in which components below the separation chamber 48 is designated as LI and the length of the separation chamber portion 48 of the separation chamber is designated as L2.
  • the length L2 will be about twice the length LI , or greater. While not limiting, a typical length LI will be about 2 feet, and a typical length of L2 will be about 2 1 ⁇ 2 to 5 feet. While the length of the separation chamber is not critical, it is important to establish sufficient length such that gas separation occurs as the fluid passes there through.
  • the length of the separation chamber for a downhole separator requires approximately 1 to 10 inches per 100,000 cubic feet of gas (or 0.1 MCF), and depending on the production pressure, usually requires a minimum of about 12 inches.
  • Gas is separated from liquid by the downhole gas separator 10 in the separation chamber 48, and liquid is drawn from the separation chamber 48 by the submersible pump (not shown) and to the tubing string at a rate to partially vacate the separation chamber; as used herein, the term partially vacate is meant to convey that the separation chamber 48 will have a dynamic low liquid level maintained therein during proper operation, and space is thereby provided for gas and liquid separation.
  • the length L2 of the separation chamber 48 can vary, but this length is established as necessary to provide sufficient space and time for the gas to effectively separate from the liquid.
  • the gas is passed to the casing through the gas outlet ports 36 while the liquid is passed to an inlet port of the submersible pump via the liquid outlet ports 34 to be pumped through the tubing string.
  • the downhole gas separator 10 receives gas and liquid fluid from the underground geological reservoir through the well bore, and restricts the amount of gas and liquid entering the separation chamber 46 to a flow rate less than the pumping rate of the submersible pump.
  • a vortex of the gas and liquid is generated in the separation chamber by rotation of the vortex generator 48 so liquid is moved to the periphery of the housing 16 and the gas remains passing near the axial center thereof, the gas being separated from the liquid to pass through gas outlet ports 36 into the well bore and the separated liquid passes out liquid outlet ports 34 to the inlet port of the submersible pump.
  • the first separation section 12 includes an internal pump 50 with first and second pumping stages 52 and 54, a first sleeve 56, a means for restricting flow 58, and a second sleeve 60, with each having a cylindrical exterior sized and shaped to fit into the interior cavity 40 of the housing 16, and with each being assembled into the interior cavity 40 in the above listed order from the base 18 to the head member 20.
  • the means for restricting fluid flow 58 is a back pressure device 62, also sometimes referred to herein as the fluid flow restrictor 62; and it will be understood that other means for restricting fluid flow are suitable for the present invention.
  • the first and second pumping stages 54 and 54 each include an impeller housing 64 and a back pressure back pressure diffuser 66, sized and shaped to fit into the interior cavity 40 of the housing 16, and an impeller member 68.
  • Internally disposed cylinder spacers serve to support and separate the components disposed in the internal cavity of the housing 14.
  • the back pressure diffuser 66 includes a bore 70 extending upwardly through the center of back pressure diffuser 66, a cylindrical outer wall 72, and a plurality of spaced, radially arranged, upwardly, inwardly and helically extending passages 74 between the bore 70 and the outer wall 72, with the passages 74 being separated by radial fins 76.
  • FIG. 5 shows the impeller 68 having a hub 80 and a plurality of spaced, radially arranged, upwardly, outwardly and helically extending passages 82 around the hub 80.
  • the back pressure device 62 is generally cylindrical with an intermediate bearing aperture 84 and a plurality of spaced, radially arranged passages 85 extending through the back pressure device 62.
  • An intermediate bearing 86 is mounted in the intermediate bearing aperture 84.
  • Passages 85 are configured to restrict fluid flow so that back pressure device 62 divides the interior cavity 40 into an upstream, first chamber 88 and a downstream, second chamber 90, the second chamber 90 sometimes herein referred to as the separation chamber 90.
  • the passages 85 extend upwardly, inwardly and helically, so that the passages 85 initiate vortex generation in the production fluid as the production fluid flows into the separation chamber 90.
  • the elongated drive shaft 38 extends through the interior cavity 40 of both the first and second separator sections 12 and 14 for rotation by an electrical pump (not shown) supported by the base 18 of the lower or first separation section 12. Bearing journals are spaced along both first and second separator sections 1 , 14 to support the shaft 38 for rotary motion; and the impellers 68 are mounted on the shaft 38 and keyed for rotation therewith.
  • the vortex generator 48 is depicted as a paddle assembly positioned in the separation chamber 46 with the hub member 44 supported by the drive shaft 38 and having the plurality paddles 42 extending radially from the hub member 44. Other styles of vortex generator, such as spiral or propeller, are also suitable.
  • the separator chamber 46 is elongated, having sufficient length to allow sufficient time for gas to separate from the liquid in the production fluid. In practice, the length of the separator chamber can be up to three feet or longer.
  • the back pressure device 62 can be a bearing housing of the type normally used to stabilize a long shaft in a well pump. Such bearing housings are available in different capacities to compliment the capacity of the well pump.
  • the back pressure device 62 has a selected capacity that is selected such that the flow rate of liquid passing to the inlet port of the submersible pump is less than the capacity of the submersible pump. That is, the object is to operate the submersible pump, coupled to the downhole separator 10, is somewhat starved, that is, running lean of its full fluid pumping capacity at the operating rotation as powered by the drive shaft 38.
  • the selected capacity of the back pressure device 62 is limits fluid flow.
  • each of the first and second third sleeves 56 and 60 is a relatively thin walled hollow cylinder.
  • the first sleeve 56 spaces the back pressure device 62 from the pump 50.
  • the second sleeve 60 spaces the back pressure device 62 from the head member 20.
  • the gas and liquid received by the downhole gas separator is passed through a flow restrictor with calibrated holes or bores the size of which permit passage of production fluids at a predetermined flow rate.
  • the predetermined flow rate serves to determine the rate of separated liquid that is passed to the submersible pump. That is, the calibrated bores are sized to permit fluid flow of well and gas, that will be of a different size in a well making 1000 BPD (barrels of liquid per day) and 80% gas than in a well making 1000 BPD and 40% gas.
  • the calibrated bores are predetermined to permit passage of the correct amount of fluid to pump the well down with whatever percentage of gas that enters the separator to supply the correct amount of fluid flow for the well.
  • Each of the first and second separator sections has a drive shaft 38 extending therethrough to drive the components, and these drive shafts can be connected by means of a coupler (now shown) so an electric motor (not shown) connected to the lower end of the drive shaft in the first separator section will drive both of the drive shafts.
  • the upper end of the drive shaft extending from the upper or second separation section 14 can be connected by a similar coupler (not shown) to the drive shaft of a submersible pump.
  • the studs 26 on the head member 20 of the first separation section 12 connect to a flange on the base 18 of the second separation section 14 to interconnect the first and second separator sections.
  • a typical installation of the separator 10 mounts between a motor on the base 18 of the first separation section 12 and a well pump secured to the head member 20 of the second separation section 14.
  • the impeller 68 of the second pumping stage 54 of the first separation section 12 receives the pressurized production fluid from the first pumping stage 54 and further increases the pressure of the production fluid.
  • the back pressure diffuser 66 of the second pumping stage 54 of the first separation section 12 builds further fluid pressure, forcing the production fluid into the first chamber 88 of the first separation section 12.
  • the first impeller starts fluid going up and the size of the bores in the back pressure diffusers is what determines the fluid flow produced and pressure required to produce the desired flow rate through the calibrated bores.
  • the back pressure diffuser also maintains the pressure till the next impeller can pick up the fluid flow and maintain the flow while increasing the pressure on the fluid. This is what a back pressure diffuser and bearing housing do inside a submersible pump and which is what is occurring in the separator, selected limitation of fluid flow and the build up of fluid pressure.
  • the process is repeated in the second separation section 14.
  • the impeller 68 of the second pumping stage 54 of the second separation section 14 pulls the remainder production fluid (the amount of production fluid to the first separation section 12 and lessened by separation and exhaustion of gas from the first separation section 12) and increases the velocity of the fluid.
  • the back pressure diffuser 66 of the second pumping stage 54 of the second separation section 14 converts the increased velocity of the pressurized remainder production fluid into additional pressure, forcing the remainder production fluid into the first chamber 88 of the second separator section 12. As gas is separated from the remainder production fluid in the upper or second separation section
  • the gas is exhausted from the gas outlet port 36 of the head member 20 into the well bore casing external to the tubing string.
  • the liquid of the remainder production fluid is passed from the separation chamber 90 of the second separator section through the upper cavity 30 of the head member 20 to the inlet port of the submersible pump.
  • the passages 85 limit the flow of production fluid through the back pressure device 62 between the first and second chambers 88 and 90.
  • the liquid and gas travel upward to the separation chamber 46 and contact with the vortex generator 48.
  • the paddles 42 whirl the liquid and gas in a circular vortex, thereby centrifugally separating the liquid at radially outward and the gas nearest to the axial center of the separation chamber 46.
  • the liquid passes upwardly to the liquid outlet ports 34.
  • Gas passes upwardly to the gas outlet ports 36 and out the downhole separator 10 into the well annulus external to the tubing string.
  • the second separation section 14 separates gas remaining in the production fluid by the same process, and the production fluid flows from the second separation section 14 into the well pump.
  • the capacity of the separator 10 is selected based on the required pumping rate and the gas content of the production fluid.
  • the capacity of the separator 10 is determined by the capacity of the first and second separation stages 12 and 14.
  • the capacity of each of the first and second separation stages 12 and 14 is determined by the size and number of pumping stages and the restriction of the back pressure device.
  • the number of stages is determined as that which is necessary to effect more pressure increase of the passing production fluid. For example, the pressure increase might be 13 psig for one stage and an accumulative 65 psig for five stages.
  • each of the first and second separation stages 12 and 14 will be predetermined selected separately, as a portion of the gas in the production fluid is removed and exhausted to the well annulus, the liquid passing to the second separation section 14 will be the same as that entering the first separation section 14 will be less by the amount of gas separated and removed from the first separation section 12.
  • the capacity of each of the separator sections will generally be determined by selecting an appropriately sized fluid restrictor, or back pressure device. The number and capacity of the pumping stages in each separator section is selected to build up pressure in its separation chamber.
  • the capacity of the back pressure devices in each separator section is selected to limit the fluid flow to the separation chambers to assure that the separation chambers will not fill as fluid is withdrawn.
  • the fluid flow out of the separation chamber is the gas exiting through the gas outlet ports, and the fluid is pulled from the separation chambers through the liquid outlet ports by the next downstream pump, whether that pump is in the next separator section or that pump is the submersible well pump.
  • the first and second separator sections 12 and 14 can each include five pumping stages with a capacity of 6000 BPD each, the back pressure device 62 for the first separation section 12 could have a capacity of 3000 BPD and the back pressure device 62 for the second separation section 14 could have a capacity of 1500 BPD.
  • a method of separating gas and liquid from production fluid in a well includes providing connected first and second separator sections each having a first chamber and a separation chamber, pumping production fluid into the first chamber of the first separator section, limiting flow of production fluid into the separation chamber of the first separator section, increasing the pressure of the production fluid as the fluid passes between the first and second chamber of the first separator section, generating a vortex in the separation chamber of the first separator section, pumping production fluid from the separation chamber of the first separator section into the first chamber of the second separator section, limiting flow of production fluid into the separation chamber of the second separator section, and generating a vortex in the separation chamber of the second separator section.
  • the gas is passed from each separation chamber through gas outlet ports to the well bore annulus external to the tubing string.
  • the liquid passes from the separation chamber through liquid outlet ports to the second separator section.
  • the steps of the first separator section are repeated in the second separator section wherein the liquid separated in the separation chamber passes to the inlet port of a submersible pump.
  • the fluid flow capacity of the last separator section is coordinated with the capacity of the submersible pump to be less than the capacity of the submersible pump so that the last separation chamber is dynamically vacated by the submersible pump to provide sufficient space for the separation of gas and liquid.
  • FIG. 7 shows the first separation section 12 with an alternative internal pump 100 and an alternative vortex generator 102.
  • the internal pump 100 is an inducer 104 having an elongated, cylindrical hub member 106 and a pair of opposed blades 108 that project radially from hub member 106 in an augur shape.
  • the hub member 106 is mounted on drive shaft 38 and secured on drive shaft 38 by key 85, so that the inducer 104 rotates with shaft 38.
  • the length of inducer 104, the number of blades 108 and the angle of the blades 108 can vary.
  • the vortex generator 102 includes a pair of spaced paddle assemblies 1 10, each having a hub member 1 12 mounted on drive shaft 38, and a plurality of spaced vertical paddles 1 14 that extend radially from the hub member 1 12.
  • the second or upper separator section 1 14 is preferably constructed identically to that described for the first separator section 1 12 with the exception of the inlet ports 22 for entry of the production fluid to the first separator section 1 12, as discussed above.
  • the inducer 104 in first separation section 12 pumps production fluid through the first chamber 88 to the back pressure device 62, restricting the fluid flow to the separation chamber 90.
  • the paddles 1 14 stir the liquid and gas into a circular vortex, thereby centrifugally separating the liquid to the radial outside and the gas to the axial center of the separation chamber 46.
  • the remainder production fluid passes upwardly to the liquid outlet ports 34 and to the second separation section 14. Gas passes upwardly to the gas outlet ports 36 to the well annulus external to the tubing string.
  • the second separation section 14 separates the gas of the remainder production fluid by the same process, and the liquid of the remainder production fluid flows from the second separation section 14 to the submersible pump.
  • known prior art systems seek to employ a liquid-gas separator to prevent gas lock, or cavitation, of the submersible pump, which can lead its damage or stalling, so that ultimately the need to remove and reinsert the submersible pump to restart the process.
  • the prior art systems seek to maintain sufficient volume and pressure of the inlet liquid to the pump so that, to the extent that any gas is present in the liquid as the liquid passes into the submersible pump, the gas remains under compression as relatively small bubbles that do not interfere with the ability of the submersible pump to force the liquid component of the subterranean fluid to the surface.
  • Prior art systems thus accept the fact that the pumped fluid will maintain a substantial amount of compressed gas therein.
  • FIG. 8 is a functional block representation of an exemplary well system 200 configured and operated in accordance with various embodiments.
  • the system 200 includes a well bore 202 that extends downwardly to a subterranean formation 204 having a mixture of liquid and gas.
  • the liquid may comprise an admixture of water (fresh or brine) and oil or other liquid hydrocarbons, and the gas may comprise methane or other pressurized gases.
  • the purpose of the well system 200 is to ultimately extract commercially useful components from the subterranean formation, such as natural gas and oil.
  • the well bore 202 will be of the depth suitable to reach the subterranean formation 204; such can be several hundreds or thousands of feet, and may be encased in a cylindrical casing (not separately illustrated).
  • a liquid level within the bore is generally represented at 206, with area 208 representing a pressurized vapor space above this level.
  • a tubing or pump string 210 extends down the center of the well bore into and below the liquid level 206 useful in urging the upward production of the desired subterranean components.
  • the exemplary pump string 210 includes the aforementioned motor (M), liquid-gas separator (S), and submersible pump (P), respectively numerically denoted as 212, 214 and 216.
  • the pump string 210 further includes a liquid conduit or tubing 218 along which the pumped liquid passes upwardly through the vapor space 208 to a water-oil separator (WOS) 220, which extracts the water to produce a flow of oil for a downstream piping or storage network.
  • WOS water-oil separator
  • a well cap mechanism 222 retains the pressure on the pressurized vapor space 208 and directs the gaseous components to a water-gas separator (WGS) to similarly direct a flow stream of pressurized natural gas for downstream processing.
  • WOS water-oil separator
  • the desired liquid production rate of the well is identified in terms of the amount of liquid to be pumped from the well. This may be expressed in any convenient form, such as the conventionally well utilized production rate of barrels per day (BPD), with each barrel constituting a volume of liquid equal to 42 gallons and a day constituting 24 hours. For purposes of the present example, a liquid production rate value of 4,000 BPD will be selected.
  • BPD barrels per day
  • a number such as 4,000 BPD does not usually mean that 4,000 barrels of oil will be produced each day. Rather, the amount of oil will tend to be significantly less than this amount, because in most exemplary environments the liquid will largely be water (or other non-oil liquids) and a lesser component of the extracted liquid will be oil.
  • the amount of oil within the liquid as a percentage can be from as low of around 1% to upwards of 10% or more. Oil and water do not mix, and oil generally tends to have a lower specific gravity than water. A measure of the specific gravity of the subterranean fluid can give some indication of this ratio.
  • salt water has a specific gravity (Sg) of around 1.05, so a Sg near this value will generally tend to indicate a relatively low oil content.
  • a lower Sg such as a value of around 0.8, can indicate a relatively larger oil content.
  • Sg specific gravity
  • Another initial value that may be obtained during the configuration of the system 200 is the ratio of gas to liquid to be produced by the well. It is known in the art that these ratios can vary widely from formation to formation, and can vary widely over the production age of a formation.
  • liquid-gas separator system is effectual for environments where there is a substantial amount of gas within the well bore; clearly, if the well is substantially depleted of gaseous pressure, a pump jack or other mechanical lifting means may be required to lift the liquid to the surface and there is no need for liquid-gas separation.
  • the amount of gas to be produced can be estimated using various well known means and instrumentation, and is usually expressed in terms of thousands of cubic feet (MCF). This can conveniently converted to equivalent BPD volumetric rate using known conversion factors. For a present example, it will be conveniently estimated that the well system 200 of FIG. 8 will produce the equivalent of 2000 BPD of natural gas. Thus, the entire fluidic production rate (on average) will be about 6,000 BPD, of which 4,000 (or roughly 67%) will be liquid. Assuming 10% oil, the well will thus produce about 400 barrels of crude oil per day.
  • the sequence in designing the system 200 generally involves steps of (1 ) sizing the submersible pump 216 to accommodate the desired liquid extraction rate of 4,000 BPD; and (2) sizing the liquid-gas separator 218 to accommodate the gas flow rate of 2,000 BPD while ensuring the pump is enabled to meet the desired flow rate of 4,000 BPD.
  • the next piece of information that may be required is the depth of the liquid level line 206 relative to the surface. As before, this can be determined using suitable instrumentation. For purposes of the present example, a depth of about 2,000 feet will be used. This means that the submersible pump 216 will need to be sized to pump the liquid a vertical height of about 2,000 feet.
  • FIG. 9 shows an exemplary pump curve 230 for a pumping stage such as described previously herein. Since different pump styles and pump manufacturers will have different pump curve characteristics, curve 230 is exemplary and not limiting. It is contemplated that the curve 230 describes the characteristics for a stage having two floating impellers that rotate responsive to a keyed shaft passing there through. The curve 230 is plotted against an x-axis 232 in terms of BPD and a y-axis 234 in terms of vertical height.
  • FIG. 10 a schematic representation of the two-stage separator 214 is shown in FIG. 10, with upper and lower sections 240, 242.
  • the liquid-gas separator 214 is sized for this pump configuration. This is carried out as discussed above to facilitate sufficient flow into the pump so that the submersible pump continuously empties the amount of liquid that is presented thereto from the uppermost separation chamber.
  • the separator includes two stages, a lower stage and an upper stage.
  • the lower section 240 includes impellers 244, 246, back pressure plate 248 and impeller 250.
  • the upper section 242 includes impellers 254, 256, back pressure plate 258 and impeller 260.
  • the back pressure plates 248, 258 may take the form of a back pressure diffuser or a bearing housing support as discussed above, or a plate 262 with apertures or bores 264 extending there through as shown in FIG. 1 1.
  • the plate 248 is accordingly sized to accommodate the flow of 6,000 BPD at this pressure.
  • the plate may be provisioned with a plurality of annular apertures having a combined cross-sectional area sufficient to allow this much volume to pass there through.
  • the total cross-sectional area may be empirically determined; it has been found, for example, that a cross sectional area of 5 square millimeters (mm 2 ) will permit passage of about 500 BPD under certain operational conditions.
  • a suitable combined equivalent area to allow 6,000 BPD to pass through the lower plate 248 may be about 60 mm 2 . This is merely exemplary, however; empirical analysis may be required to arrive at the particular value for a particular application.
  • the next determination to be made is an evaluation of what percentage of gas will be removed by the lower stage 240. Again, this may require some empirical analysis. Generally, it has been found that the amount of gas in the liquid that passes from the lower stage 240 to the upper stage 242 will depend on a variety of factors including the specific gravity of the fluid. For a higher Sg, less fluid may be removed whereas for a lower Sg, more fluid may be removed. An exemplary value may be 50% of the gas in the fluid passing into the lower stage 240 is removed by the lower stage. Using this value, it can be seen that there will now only be the equivalent of 1000 BPD (2,000 BPD x 0.50) of gas passing into the upper stage 242. This means that, generally, the upper stage 242 will be receiving the equivalent of about 5,000 BPD of fluid.
  • a BPD rate of 5,000 BPD will provide a vertical height value of about 18 feet, as indicated by point 268 on the curve. This converts to a back pressure of about 7.8 psig.
  • the upper back plate 258 is sized to permit the flow of the equivalent of about 5,000 BPD there through at this pressure. Empirical analysis will allow determination of this value.
  • An exemplary value may be on the order of about 50 mm 2 of total surface area of the apertures passing through the upper plate 242.
  • the upper plate can be sized as a derated value of the lower plate, rather than by making reference to the pump curve.
  • the upper plate will generally tend to have a smaller cross-sectional area because of the removal of gas from the inlet fluid. Accordingly, the upper plate is sized to ensure that the upper chamber is supplied with just this amount so that the submersible pump empties the separation chamber and runs lean. This promotes the efficacy of the separator so that substantially no component of gas remains in the liquid stream passing through the pump.
  • the system can be adaptively adjusted to attain an optimum level of performance through the adjustment of various parameters. This allows the system to be tuned to ensure that the upper chamber of the liquid-gas separator is being fully vacated by the pump operation; that is, the pump is operated to empty the upper chamber at the same rate at which the liquid is being introduced into the upper chamber.
  • Some systems utilize a variable frequency drive mechanism at the surface of the well that allows adjustments in the rotational rate of the motor that drives the central shaft to which the submersible pump, impellers and inducers are coupled. While the system may be designed to operate at a selected alternating current (AC) frequency, such as 60 Hz, an operative range may be available so that the motor can be rotated at any desired frequency from a lower rate of from around 50 Hz or less to an upper rate of around 70 Hz or more.
  • AC alternating current
  • the system can be initially operated at a baseline frequency, such as 60 Hz.
  • the pump efficiency can be evaluated at this level through various
  • a user can slowly increase the frequency of the motor operation, such as from 60 Hz to 65 Hz. This may result in an increase in the volume of liquid reaching the surface since the pump will generally be able to pump more liquid at a higher rotational rate, whereas the maximum amount of liquid that can flow into the upper chamber remains fixed due to the orifice size of the back pressure plate.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Structures Of Non-Positive Displacement Pumps (AREA)

Abstract

Lorsque l'on sépare un gaz d'un liquide en fond de puits par un séparateur (10) de gaz en fond de puits, le gaz est séparé et envoyé dans l'anneau (202) du puits et le liquide est transféré vers une pompe immergée (216) à un débit étalonné auquel le liquide est déchargé d'une chambre de séparation (48), la longueur de la chambre de séparation (48) assurant un espace suffisant pour la séparation du gaz lorsque le liquide est pompé hors du séparateur (10). Le séparateur de gaz (10) qui limite la quantité de fluide qui est envoyé dans la chambre de séparation (48) à un débit inférieur au débit de pompage de la pompe immergée (216) crée un vortex de fluide qui amène le liquide séparé à se déplacer vers la périphérie et le gaz séparé à passer près du centre axial de la chambre de séparation (48). Le gaz séparé passe dans l'anneau (202) du puits et le liquide passe dans l'entrée de la pompe immergée (216).
PCT/US2010/049503 2009-09-28 2010-09-20 Séparation gaz-liquide en fond de puits WO2011037864A1 (fr)

Priority Applications (3)

Application Number Priority Date Filing Date Title
MX2012003722A MX2012003722A (es) 2009-09-28 2010-09-20 Separacion de gas y liquido en el fondo del pozo.
CA2775841A CA2775841C (fr) 2009-09-28 2010-09-20 Separation gaz-liquide en fond de puits
AU2010298524A AU2010298524B2 (en) 2009-09-28 2010-09-20 Downhole gas and liquid separation

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US12/567,933 US20110073304A1 (en) 2009-09-28 2009-09-28 Multistage downhole separator and method
US12/567,933 2009-09-28
US12/612,065 US20110073305A1 (en) 2009-09-28 2009-11-04 Multisection Downhole Separator and Method
US12/612,065 2009-11-04

Publications (1)

Publication Number Publication Date
WO2011037864A1 true WO2011037864A1 (fr) 2011-03-31

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PCT/US2010/049503 WO2011037864A1 (fr) 2009-09-28 2010-09-20 Séparation gaz-liquide en fond de puits

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US (1) US20110073305A1 (fr)
AU (1) AU2010298524B2 (fr)
CA (1) CA2775841C (fr)
MX (1) MX2012003722A (fr)
WO (1) WO2011037864A1 (fr)

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7794199B2 (en) * 2005-05-24 2010-09-14 Franklin Electric Co., Inc. Bypass system for purging air from a submersible pump
CN110159247A (zh) * 2019-06-24 2019-08-23 西安石油大学 水龙卷涡旋排水采气装置及方法
WO2023158811A2 (fr) * 2022-02-17 2023-08-24 Extract Management Company, Llc Conditionneur de fluide multiphase de pompe de fond de trou

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US3304006A (en) * 1965-08-13 1967-02-14 Nash Engineering Co System for handling fluids in both liquid and gaseous phases
US4231767A (en) * 1978-10-23 1980-11-04 Trw Inc. Liquid-gas separator apparatus
US5902378A (en) * 1997-07-16 1999-05-11 Obrejanu; Marcel Continuous flow downhole gas separator for processing cavity pumps
US6066193A (en) * 1998-08-21 2000-05-23 Camco International, Inc. Tapered flow gas separation system
US20040045708A1 (en) * 2002-09-06 2004-03-11 Morrison James Eric Downhole separator and method
US7461692B1 (en) * 2005-12-15 2008-12-09 Wood Group Esp, Inc. Multi-stage gas separator

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US5673752A (en) * 1995-12-22 1997-10-07 Scudder; Pat Method and apparatus for producing gas from a formation containing both gas and water
BR9704499A (pt) * 1997-08-26 1999-12-07 Petroleo Brasileiro Sa Separador helicoidal aperfeiçoado
US6155345A (en) * 1999-01-14 2000-12-05 Camco International, Inc. Downhole gas separator having multiple separation chambers
US6382317B1 (en) * 2000-05-08 2002-05-07 Delwin E. Cobb Apparatus and method for separating gas and solids from well fluids

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3304006A (en) * 1965-08-13 1967-02-14 Nash Engineering Co System for handling fluids in both liquid and gaseous phases
US4231767A (en) * 1978-10-23 1980-11-04 Trw Inc. Liquid-gas separator apparatus
US5902378A (en) * 1997-07-16 1999-05-11 Obrejanu; Marcel Continuous flow downhole gas separator for processing cavity pumps
US6066193A (en) * 1998-08-21 2000-05-23 Camco International, Inc. Tapered flow gas separation system
US20040045708A1 (en) * 2002-09-06 2004-03-11 Morrison James Eric Downhole separator and method
US7461692B1 (en) * 2005-12-15 2008-12-09 Wood Group Esp, Inc. Multi-stage gas separator

Also Published As

Publication number Publication date
AU2010298524B2 (en) 2015-07-30
AU2010298524A1 (en) 2012-04-19
CA2775841C (fr) 2017-07-04
US20110073305A1 (en) 2011-03-31
MX2012003722A (es) 2012-07-25
CA2775841A1 (fr) 2011-03-31

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