US20220389806A1 - Downhole gas separator - Google Patents
Downhole gas separator Download PDFInfo
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- US20220389806A1 US20220389806A1 US17/805,769 US202217805769A US2022389806A1 US 20220389806 A1 US20220389806 A1 US 20220389806A1 US 202217805769 A US202217805769 A US 202217805769A US 2022389806 A1 US2022389806 A1 US 2022389806A1
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- United States
- Prior art keywords
- tubular member
- inner tubular
- outer tubular
- opening
- annulus
- Prior art date
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- Abandoned
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- 239000012530 fluid Substances 0.000 claims description 47
- 238000004891 communication Methods 0.000 claims description 13
- 239000007789 gas Substances 0.000 description 46
- 239000007788 liquid Substances 0.000 description 25
- 230000008878 coupling Effects 0.000 description 9
- 238000010168 coupling process Methods 0.000 description 9
- 238000005859 coupling reaction Methods 0.000 description 9
- 230000015572 biosynthetic process Effects 0.000 description 7
- 230000002706 hydrostatic effect Effects 0.000 description 4
- 238000004519 manufacturing process Methods 0.000 description 4
- 239000000463 material Substances 0.000 description 4
- 238000000034 method Methods 0.000 description 4
- 238000005086 pumping Methods 0.000 description 4
- 230000008859 change Effects 0.000 description 2
- 238000010276 construction Methods 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 238000000926 separation method Methods 0.000 description 2
- 230000035939 shock Effects 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 230000000712 assembly Effects 0.000 description 1
- 238000000429 assembly Methods 0.000 description 1
- 230000008901 benefit Effects 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 230000003028 elevating effect Effects 0.000 description 1
- 238000005259 measurement Methods 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 238000007789 sealing Methods 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
- E21B43/121—Lifting well fluids
- E21B43/126—Adaptations of down-hole pump systems powered by drives outside the borehole, e.g. by a rotary or oscillating drive
- E21B43/127—Adaptations of walking-beam pump systems
Abstract
A gas separator including a first separator section and a second separator section. The first separator section and the second separator section each including an outer tubular member having at least one opening extending therethrough adjacent an upper end and an inner tubular member positioned in the outer tubular member to define an annulus. The annulus of the first separator section is fluidically sealed from a tubing string. A lower end of the inner tubular member of the second separator section is open to define a lower open end having a flow area and the lower end of the outer tubular member is fluidically sealed. The inner tubular member of the first separator section has at least one opening extending therethrough adjacent the lower end thereof. The opening has a flow area less than the flow area of the lower open end.
Description
- This application claims benefit of U.S. Provisional Application No. 63/197,696, filed Jun. 7, 2021, which is hereby incorporated herein by reference in its entirety.
- Sucker rod pumps are often used when the natural pressure of an oil and gas formation is not sufficient to lift the oil to the surface of the earth. Sucker rod pumps operate by admitting fluid from the formation into a tubing and then lifting the fluid to the surface. To accomplish this, the sucker rod pump contains, among others, four elements: a pump or working barrel, a plunger which travels in an up and down motion inside the pump barrel, a standing valve positioned near the lower end of the pump barrel, and a traveling valve that is attached to and travels with the plunger. A chamber is formed inside the pump barrel between the standing valve and the traveling valve. The standing valve allows fluid to flow into the chamber but does not allow fluid to flow out of the chamber. The traveling valve allows fluid to flow out of the chamber, but not into the chamber.
- When the fluid that the sucker rod pump is pumping is substantially all liquids, the plunger is mechanically made to move up and down in a reciprocating motion. On the upstroke of a pumping cycle, where the plunger is moved upward, the hydrostatic pressure of the fluid above the traveling valve causes the traveling valve to close. The upward motion of the plunger also causes a negative fluid pressure to develop inside the chamber thereby causing the standing valve to open and to admit fluid from the formation into the chamber.
- At the end of the upstroke, the chamber is filled with liquid from the formation. When the plunger begins the downstroke, the pressure in the chamber becomes positive which causes the standing valve to close. Because liquids are substantially incompressible, the pressure in the chamber rapidly increases to a pressure greater than the fluid column pressure above the traveling valve. When the fluid pressure in the chamber becomes greater than the fluid column pressure above the traveling valve, the traveling valve opens and fluid passes by the traveling valve where it is able to be lifted by the sucker rod pump on the upstroke.
- When the fluid being pumped by the sucker rod pump is a mixture of gas and liquid, problems may be encountered. During the downstroke, the standing valve closes normally as the plunger compresses the gas and liquid in the chamber. However, the traveling valve does not open until the chamber pressure becomes greater than the hydrostatic pressure above the traveling valve. If the fluid contains a significant amount of gas, the traveling valve may not open at all, even as the plunger reaches the bottom of the downstroke. This condition results in a “gas lock.” When the plunger compresses the gas and collides with the liquid, the collision generates a shock wave and is referred to as “gas pound.” The shock wave causes the traveling valve to open quickly and this can cause damage to the traveling valve and to the tubing in the well.
- In oil and gas wells, both liquids and gases may be produced from the same well. In such wells, it is often desirable to separate gases and liquids so that the liquids may be more efficiently pumped or lifted to the surface. Gases that may be entrained or evolved from hydrocarbon liquids when such liquids are pumped to the surface may interfere or reduce the efficiency of the pumping operations, decreasing or slowing production.
- There have been a variety of different methods and devices used for such downhole separation of liquids and gases. One such separator device includes an inner tube with an open lower end positioned within and connected to the sucker rod pump so the inner tube is in fluid communication with the sucker rod pump. An outer tube is connected at an upper end to the sucker rod pump, but is not in direct fluid communication with the sucker rod pump. The outer tube may be provided with ports or slots at the upper end to allow liquids and gases in the annulus of the well to pass into the outer tube. The change in direction of the flow causes a portion of the gas to separate from the liquid. The liquid continues to pass down the outer tube, into the inner tube via the open lower end, and into the sucker rod pump. The gas travels upwardly through the outer tube and exits through the ports or slots.
- Simple devices like that described above can have limited effectiveness while more effective separators are more complicated and expensive to manufacture and thus susceptible to failure. To this end, a need exists for an improved gas separator, which effectively separates gas from liquid and which is simple to manufacture. It is to such an improved downhole gas separator that the inventive concepts disclosed herein are directed.
- The inventive concepts disclosed and claimed herein generally relate to a downhole gas separator. The downhole gas separator includes a first separator section and a second separator section. The first separator section including a first outer tubular member and a first inner tubular member. The first outer tubular member has an upper end, a lower end, and a sidewall extending between the upper end and the lower end. The sidewall has at least one opening extending therethrough adjacent the upper end, and the upper end of the first outer tubular member is connectable to a lower end of a tubing string positionable in a wellbore. The first inner tubular member has an upper end, a lower end, and a sidewall extending between the upper end and the lower end. The first inner tubular member is positioned in the first outer tubular member to define a first annulus between the first outer tubular member and the first inner tubular member. The upper end of the first inner tubular member is connected to the upper end of the first outer tubular member so the first annulus is fluidically sealed from the tubing string and the first inner tubular member is in fluid communication with the tubing string when the first inner tubular member is connected to the tubing string. The lower end of the first inner tubular member is connected to the lower end of the second outer tubular member.
- The second separator section includes a second outer tubular member and a second inner tubular member. The second outer tubular member has an upper end, a lower end, and a sidewall extending between the upper end and the lower end. The sidewall has at least one opening extending therethrough adjacent the upper end. The upper end of the second outer tubular member is connected to the lower end of the first outer tubular member, and the lower end of the second outer tubular member is being fluidically sealed. The second inner tubular member has an upper end, a lower end, and a sidewall extending between the upper end and the lower end, and the second inner tubular member is positioned in the second outer tubular member to define a second annulus between the second outer tubular member and the second inner tubular member. The upper end of the second inner tubular member is connected to the lower end of the first inner tubular member so the second annulus is fluidically sealed from the first annulus and the second inner tubular member is in fluid communication with the first inner tubular member. The lower end of the second inner tubular member is open to define a lower open end having a flow area,
- The sidewall of the first inner tubular member has at least one opening extending therethrough adjacent the lower end thereof. The opening has a flow area less than the flow area of the lower open end.
-
FIG. 1 is a schematic view of a sucker rod pump assembly with a downhole gas separator constructed in accordance with the inventive concepts disclosed herein incorporated with the sucker rod pump assembly. -
FIG. 2 is cross-sectional view of the downhole gas separator. -
FIG. 3 is a cross-sectional view of a first separator section of the downhole gas separator. -
FIG. 4 is cross-sectional view of a portion of the first separator section. - Before explaining at least one embodiment of the inventive concepts disclosed herein in detail, it is to be understood that the inventive concepts are not limited in their application to the details of construction and the arrangement of the components or steps or methodologies set forth in the following description or illustrated in the drawings. The inventive concepts disclosed herein are capable of other embodiments, or of being practiced or carried out in various ways. Also, it is to be understood that the phraseology and terminology employed herein is for the purpose of description and should not be regarded as limiting the inventive concepts disclosed and claimed herein in any way.
- In the following detailed description of embodiments of the inventive concepts, numerous specific details are set forth in order to provide a more thorough understanding of the inventive concepts. However, it will be apparent to one of ordinary skill in the art that the inventive concepts within the instant disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the instant disclosure.
- As used herein, the terms “comprises,” “comprising,” “includes,” “including,” “has,” “having,” and any variations thereof, are intended to cover a non-exclusive inclusion. For example, a process, method, article, or apparatus that comprises a list of elements is not necessarily limited to only those elements, and may include other elements not expressly listed or inherently present therein.
- Unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B is true (or present).
- In addition, use of the “a” or “an” are employed to describe elements and components of the embodiments disclosed herein. This is done merely for convenience and to give a general sense of the inventive concepts. This description should be read to include one or at least one and the singular also includes the plural unless it is obvious that it is meant otherwise.
- As used herein, qualifiers like “substantially,” “about,” “approximately,” and combinations and variations thereof, are intended to include not only the exact amount or value that they qualify, but also some slight deviations therefrom, which may be due to manufacturing tolerances, measurement error, wear and tear, stresses exerted on various parts, and combinations thereof, for example.
- Finally, as used herein any reference to “one embodiment” or “an embodiment” means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment. The appearances of the phrase “in one embodiment” in various places in the specification are not necessarily all referring to the same embodiment.
- Referring now to the drawings, and more particularly to
FIG. 1 , adownhole pump assembly 10 is shown in a wellbore 11 of a well. The wellbore 11 may be provided with acasing 13 that may be perforated at one or more positions along its length. The perforations allow fluids from the surrounding formation to enter thecasing 13. The fluids may include liquids and gases. - The
downhole pump assembly 10 is secured within in atubing string 12 and used with apump jack unit 15 and asucker rod string 14 for elevating fluids, such as hydrocarbons, to the earth's surface. Thedownhole pump assembly 10 may include apump barrel 20, a standingvalve 22, aplunger 24, and a travelingvalve 26. Thepump barrel 24 supports the standingvalve 22 in a lower end thereof. The standingvalve 22 is illustrated as being a conventional ball check valve. - The
plunger 24 is disposed in thepump barrel 20 and is adapted for reciprocating movement throughpump barrel 20. The travelingvalve 26 is located in a lower end of theplunger 24 to permit one way flow of fluid into theplunger 24. The travelingvalve 26 is shown to be a ball check valve and a seat. - As stated above, on the upstroke of a pumping cycle, the
plunger 24 is moved in an upward direction. The hydrostatic pressure of the fluid above the travelingvalve 26 causes the travelingvalve 26 to close. The upward motion of theplunger 24 further causes a negative pressure to develop inside achamber 28 below theplunger 24 thereby causing the standingvalve 22 to open and admit fluid from the formation into thechamber 28. - At the end of the upstroke, the portion of the
chamber 28, the travelingvalve 26, and the standingvalve 22 are filled with liquid from the formation. When theplunger 24 begins the downstroke, the pressure in thechamber 28 becomes positive which causes the standingvalve 22 to close. Because liquids are substantially incompressible, the pressure in thechamber 28 rapidly increases to a pressure greater than the pressure above the travelingvalve 26. When the fluid pressure in thechamber 28 becomes greater than the pressure above the travelingvalve 26, the travelingvalve 26 opens and fluid passes through the travelingvalve 26 where it is able to be lifted by theplunger 24 on the subsequent upstroke. - As further stated above, when the fluid being pumped by the
downhole pump assembly 10 is a mixture of gas and liquid, problems may be encountered. That is, because the travelingvalve 26 will not open until the pressure below the travelingvalve 26 becomes greater than the hydrostatic pressure above the travelingvalve 26, if the fluid contains a significant amount of gas, the travelingvalve 26 may not open at all, resulting in the condition known as “gas lock.” In another instance, theplunger 24 may compress the gas thereby resulting in theplunger 24 colliding with the liquid. The collision between theplunger 24 and the liquid generates a shockwave and is referred to as “gas pound.” The shockwave causes the travelingvalve 26 to open quickly which can result in damage to the travelingvalve 26 and to the other components of thedownhole pump assembly 10. - A
gas separator 50 constructed in accordance with inventive concepts disclosed herein is shown connected to a lower end of thedownhole pump assembly 10 to reduce the amount of gas entering thedownhole pump assembly 10. Thegas separator 50 is particularly suited for use in a downhole wellbore for separation of gas and liquids from a multi-phase fluid. - Referring now to
FIGS. 2-4 , thegas separator 50 includes afirst separator section 52 and a secondgas separator section 54. The secondgas separator section 54 is a conventional gas separator that may include anouter tubular member 56 and aninner tubular member 58. The outertubular member 56 has anupper end 60, alower end 62, and asidewall 64 extending between theupper end 60 and thelower end 62. Thesidewall 64 has at least oneinlet opening 66 extending therethrough adjacent theupper end 60 thereof. Conventionally, theupper end 60 of the outertubular member 56 is connected to the lower end of thepump assembly 10. Thelower end 62 of the outertubular member 56 is capped so fluid only enters thesecond separator section 52 via theinlet opening 66. - The
inner tubular member 58 has anupper end 68, alower end 70, and asidewall 72 extending between theupper end 68 and thelower end 70. Theinner tubular member 58 is positioned in the outertubular member 56 to define anannulus 74 between the outertubular member 56 and theinner tubular member 58. Conventionally, theupper end 68 of theinner tubular member 58 is connected to the lower end of thepump assembly 10 so theannulus 74 is fluidically sealed from thepump assembly 10 and theinner tubular member 58 is in fluid communication with thepump assembly 10. - In one embodiment, the second
gas separator section 54 may include aconnector 67. Conventionally, theconnector 67 connects theupper end 60 of the outertubular member 56 to thepump assembly 10 and theupper end 68 of theinner tubular member 58 is connected to the lower end of thepump assembly 10 so theannulus 74 is fluidically sealed from thepump assembly 10 and theinner tubular member 58 is in fluid communication with thepump assembly 10. Thelower connector 67 may be formed from a single, unitary piece of material, as shown, or it may be formed in two or more pieces. Theconnector 67 may have a tubular wall with an upper end provided with a female threadedportion 69 for coupling with thepump assembly 10 or the firstgas separator section 52 as discussed below. The lower end of theconnector 67 may be provided with a male threadedportion 71 for coupling to theupper end 60 of the outertubular member 56 and a female threadedportion 73 for coupling to theupper end 68 of theinner tubular member 58 of thesecond separator section 54. - The
lower end 70 of theinner tubular member 58 is open to define a loweropen end 76 having a flow area. In use, the reservoir fluids flow into the inlet opening 66 of the outertubular member 56 and pass down theannulus 74. The change of direction causes a portion of the gas in the reservoir fluid to separate from the liquid and travel up anannulus 77 between the outertubular member 56 and thecasing 13. Another portion of the gas separates from the fluid within theannulus 74. This gas travel upwards through theannulus 74 and exits through theinlet opening 66. The liquid passes into theinner tubular member 58 via the loweropen end 76 and up to thepump assembly 10. - The
first separator section 52 includes anouter tubular member 80 and aninner tubular member 82. The outertubular member 80 has anupper end 84, alower end 86, and asidewall 88 extending between theupper end 84 and thelower end 86. Thesidewall 88 has at least oneinlet opening 90 extending therethrough adjacent theupper end 84. Theupper end 84 of the outertubular member 80 is connectable to the lower end of thepump assembly 10. - The
inner tubular member 82 has anupper end 92, alower end 94, and asidewall 96 extending between theupper end 92 and thelower end 94. Theinner tubular member 82 is positioned in the outertubular member 80 to define anannulus 97 between the outer tubular 80 member and theinner tubular member 82. Theupper end 92 of theinner tubular member 82 is connected to theupper end 84 of the outertubular member 80 so theannulus 97 is fluidically sealed from thepump assembly 10 and theinner tubular member 82 is in fluid communication with thepump assembly 10 when theinner tubular member 82 is connected to thepump assembly 10. Thesidewall 88 of the firstinner tubular member 82 has at least oneopening 98 extending therethrough adjacent the lower end thereof. Theopening 98 has a flow area less than the flow area of the loweropen end 76 of theinner tubular member 58 of thesecond separator section 52. - The
opening 98 may be defined by a nozzle 99 (FIG. 4 ). Thenozzle 99 may be formed of a hardened material, such as carbide. Thenozzle 99 may have a diameter of approximately ¼ inch, by way of example. However, it will be appreciated that the diameter of theopening 98 may be varied. To reduce clogging, the firstgas separator section 52 may be provided with a screen 101 (FIG. 3 ) secured over theopening 98. - The
inlet opening 90 of the outertubular member 80 of thefirst separator section 52 is arranged to be less restrictive than theopening 98 such that fluid may readily enter through theinlet opening 90; however, gas can also escape from thefirst separator section 52 back into theannulus 97 through theinlet opening 90. In one embodiment, by way of example, theinlet opening 66 and theinlet opening 90 may be configured as slots with dimensions of approximately one to two inches in width and approximately eight inches in length. Theinlet opening 66 and theinlet opening 90 may be of similar dimension or different. - Referring to
FIG. 3 , thefirst separator section 52 may have anupper connector 100 and alower connector 102. Theupper connector 100 connects theupper end 84 of the outertubular member 80 toupper end 92 of theinner tubular member 82. Theupper connector 100 also enables thefirst separator section 52 to be connected to the lower end of thepump assembly 10. Similarly, thelower connector member 102 connects thelower end 86 of the outertubular member 80 to thelower end 94 of theinner tubular 82. Theupper connector 100 and thelower connector 102 connect theinner tubular member 82 to the outertubular member 80 so theannulus 97 is fluidically sealed from thepump assembly 10 and theannulus 74 of thesecond separator section 54 except via theopening 98. As such, fluid in theannulus 97 must pass through theopening 98. Thelower connector 102 also enables thefirst separator section 52 to be connected to thesecond separator section 54. - The
upper connector 100 may be formed from a single, unitary piece of material, as shown, or it may be formed in two or more pieces. Theupper connector 100 may have a tubular wall with an upper end portion configured with afemale thread portion 120 for coupling to thetubing string 12. The lower end of theupper connector 100 may be provided with a male threadedportion 122 for coupling to the outertubular member 80 and a female threadedportion 124 for coupling to the upper end of theinner tubular member 82. - Similarly, the
lower connector 102 may be formed from a single, unitary piece of material, as shown, or it may be formed in two or more pieces. Thelower connector 102 may have a tubular wall with an upper end provided with a male threadedportion 126 for coupling to thelower end 86 of the outertubular member 80 and a female portion 128 (including a sealing member, such as an O-ring) for coupling to thelower end 94 of theinner tubular member 82. The lower end of thelower connector 102 may be provided with a male threadedportion 130 for sealingly coupling to the female threadedportion 69 of theconnector 67 of the secondgas separator section 54 so theinner tubular member 58 is in fluid communication with theinner tubular member 82. - In another embodiment, the
gas separator 50 may be implemented with more than one of thefirst separator sections 52 connected to one another in series. - Although the presently disclosed inventive concepts has been described in conjunction with the specific language set forth herein above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, it is intended to embrace all such alternatives, modifications, and variations that fall within the spirit and broad scope of the presently disclosed inventive concepts. Changes may be made in the construction and the operation of the various components, elements, and assemblies described herein, without departing from the spirit and scope of the presently disclosed inventive concepts.
Claims (8)
1. A gas separator, comprising:
a first separator section, comprising:
a first outer tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the sidewall having at least one opening extending therethrough adjacent the upper end, the upper end of the first outer tubular member connectable to a lower end of a tubing string positionable in a wellbore; and
a first inner tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the first inner tubular member positioned in the first outer tubular member to define a first annulus between the first outer tubular member and the first inner tubular member, the upper end of the first inner tubular member connected to the upper end of the first outer tubular member so the first annulus is fluidically sealed from the tubing string and the first inner tubular member is in fluid communication with the tubing string when the first inner tubular member is connected to the tubing string, the lower end of the first inner tubular member connected to the lower end of the second outer tubular member; and
a second separator section, comprising:
a second outer tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the sidewall having at least one opening extending therethrough adjacent the upper end, the upper end of the second outer tubular member connected to the lower end of the first outer tubular member, the lower end of the second outer tubular member being fluidically sealed; and
a second inner tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the second inner tubular member positioned in the second outer tubular member to define a second annulus between the second outer tubular member and the second inner tubular member, the upper end of the second inner tubular member connected to the lower end of the first inner tubular member so the second annulus is fluidically sealed from the first annulus and the second inner tubular member is in fluid communication with the first inner tubular member, the lower end of the second inner tubular member being open to define a lower open end having a flow area,
wherein the sidewall of the first inner tubular member has at least one opening extending therethrough adjacent the lower end thereof, the opening having a flow area less than the flow area of the lower open end.
2. The gas separator of claim 1 , wherein the opening of the first outer tubular member has a flow area, and wherein the flow area of the opening of the first inner tubular member is less than the flow area of the opening of the first outer tubular member.
3. The gas separator of claim 1 , further comprising a screen positioned across the opening of the first inner tubular member.
4. A gas separator, comprising:
a tubing string positioned in a wellbore, the tubing string having an upper end and a lower end;
a first separator section, comprising:
a first outer tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the sidewall having at least one opening extending therethrough adjacent the upper end, the upper end of the first outer tubular member connected to the lower end of a tubing string; and
a first inner tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the first inner tubular member positioned in the first outer tubular member to define a first annulus between the first outer tubular member and the first inner tubular member, the upper end of the first inner tubular member connected to the upper end of the first outer tubular member so the first annulus is fluidically sealed from the tubing string and the first inner tubular member is in fluid communication with the tubing string when the first inner tubular member is connected to the tubing string, the lower end of the first inner tubular member connected to the lower end of the second outer tubular member; and
a second separator section, comprising:
a second outer tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the sidewall having at least one opening extending therethrough adjacent the upper end, the upper end of the second outer tubular member connected to the lower end of the first outer tubular member, the lower end of the second outer tubular member being fluidically sealed; and
a second inner tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the second inner tubular member positioned in the second outer tubular member to define a second annulus between the second outer tubular member and the second inner tubular member, the upper end of the second inner tubular member connected to the lower end of the first inner tubular member so the second annulus is fluidically sealed from the first annulus and the second inner tubular member is in fluid communication with the first inner tubular member, the lower end of the second inner tubular member being open to define a lower open end having a flow area,
wherein the sidewall of the first inner tubular member has at least one opening extending therethrough adjacent the lower end thereof, the opening having a flow area less than the flow area of the lower open end.
5. The gas separator of claim 4 , wherein the opening of the first outer tubular member has a flow area, and wherein the flow area of the opening of the first inner tubular member is less than the flow area of the opening of the first outer tubular member.
6. The gas separator of claim 4 , further comprising a screen positioned across the opening of the first inner tubular member.
7. The gas separator of claim 4 , wherein the tubing string includes a pump assembly positioned uphole of the first separator section.
8. The gas separator of claim 7 , wherein the pump assembly comprises:
a pump barrel having an upper end, a lower end, and a chamber extending through the pump barrel from the upper end to the lower end, the chamber being in fluid communication with the first separator section;
a standing valve located in the pump barrel to permit one way flow of fluid into the chamber of the pump barrel;
a plunger disposed in the chamber of the pump barrel above the standing valve and below the upper end of the pump barrel and adapted for reciprocating movement through at least a portion of the chamber of the pump barrel;
a traveling valve located in the plunger to permit one way flow of fluid into the plunger; and
a pull rod having one end connected to the plunger and an opposite end connected to a sucker rod string to affect reciprocating movement of the plunger.
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US17/805,769 US20220389806A1 (en) | 2021-06-07 | 2022-06-07 | Downhole gas separator |
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US202163197696P | 2021-06-07 | 2021-06-07 | |
US17/805,769 US20220389806A1 (en) | 2021-06-07 | 2022-06-07 | Downhole gas separator |
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US20190085677A1 (en) * | 2017-09-18 | 2019-03-21 | Gary V. Marshall | Down-hole gas separator |
US20200208506A1 (en) * | 2018-12-26 | 2020-07-02 | Odessa Separator, Inc. | Above packer gas separation |
US20200291762A1 (en) * | 2019-03-11 | 2020-09-17 | Blackjack Production Tools, Llc | Multi-Stage, Limited Entry Downhole Gas Separator |
US11028683B1 (en) * | 2020-12-03 | 2021-06-08 | Stoneview Solutions LLC | Downhole pump gas eliminating seating nipple system |
US20220251937A1 (en) * | 2021-02-11 | 2022-08-11 | Delwin E. Cobb | Downhole gas-liquid separator |
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US6945762B2 (en) * | 2002-05-28 | 2005-09-20 | Harbison-Fischer, Inc. | Mechanically actuated gas separator for downhole pump |
US10329886B2 (en) * | 2014-06-25 | 2019-06-25 | Raise Production Inc. | Rod pump system |
US11274541B2 (en) * | 2019-03-05 | 2022-03-15 | Well Worx Energy Solutions LLC | Gas bypass separator |
-
2022
- 2022-06-07 WO PCT/US2022/072795 patent/WO2022261629A1/en unknown
- 2022-06-07 US US17/805,769 patent/US20220389806A1/en not_active Abandoned
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US6182751B1 (en) * | 1996-12-25 | 2001-02-06 | Konstantin Ivanovich Koshkin | Borehole sucker-rod pumping plant for pumping out gas liquid mixtures |
US6039121A (en) * | 1997-02-20 | 2000-03-21 | Rangewest Technologies Ltd. | Enhanced lift method and apparatus for the production of hydrocarbons |
US7462225B1 (en) * | 2004-09-15 | 2008-12-09 | Wood Group Esp, Inc. | Gas separator agitator assembly |
US20130032341A1 (en) * | 2011-08-01 | 2013-02-07 | Raglin John M | Down-Hole Gas Separator |
US20180280834A1 (en) * | 2015-01-09 | 2018-10-04 | Modicum, Llc | Down-Hole Gas Separation System |
US20170151510A1 (en) * | 2015-12-01 | 2017-06-01 | Delwin E. Cobb | Downhole liquid / gas separator |
US20190085677A1 (en) * | 2017-09-18 | 2019-03-21 | Gary V. Marshall | Down-hole gas separator |
US20200208506A1 (en) * | 2018-12-26 | 2020-07-02 | Odessa Separator, Inc. | Above packer gas separation |
US20200291762A1 (en) * | 2019-03-11 | 2020-09-17 | Blackjack Production Tools, Llc | Multi-Stage, Limited Entry Downhole Gas Separator |
US11028683B1 (en) * | 2020-12-03 | 2021-06-08 | Stoneview Solutions LLC | Downhole pump gas eliminating seating nipple system |
US20220251937A1 (en) * | 2021-02-11 | 2022-08-11 | Delwin E. Cobb | Downhole gas-liquid separator |
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WO2022261629A1 (en) | 2022-12-15 |
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