DOWNHOLE GAS SEPARATOR

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 63/678,831, filed Aug. 2, 2024, which is hereby incorporated herein by reference in its entirety.

BACKGROUND

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 string 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 that 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 prevents fluid from flowing 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 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 its downstroke, the pressure in the chamber becomes positive, causing 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 exceeds the fluid column pressure above the traveling valve, the traveling valve opens, allowing fluid to pass by it. The fluid can then be lifted by the sucker rod pump during 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 exceeds the hydrostatic pressure above the traveling valve. If the fluid contains a significant amount of gas, the traveling valve may not open, 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 known as a “gas pound.” The shock wave causes the traveling valve to open quickly, which can cause damage to the traveling valve and 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 can be pumped or lifted to the surface more efficiently. Gases that may be entrained or evolved from hydrocarbon liquids when such liquids are pumped to the surface may interfere with or reduce the efficiency of the pumping operations, decreasing or slowing production.

Various methods and devices have been 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 that 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 upward through the outer tube and exits through the ports or slots.

Simple devices like the ones 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 that effectively separates gas from liquid and is simple to manufacture. It is to such an improved downhole gas separator that the inventive concepts disclosed herein are directed.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagrammatic 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 a cross-sectional view of a downhole gas separator constructed in accordance with the inventive concepts disclosed herein.

FIG. 3 is a cross-sectional view of another embodiment of a downhole gas separator constructed in accordance with the inventive concepts disclosed herein.

FIG. 4 is a top plan view of a turbine constructed in accordance with the inventive concepts disclosed herein.

FIG. 5 is a cross-sectional view of another embodiment of a downhole gas separator constructed in accordance with the inventive concepts disclosed herein.

FIG. 6 is a cross-sectional view of the downhole gas separator shown in FIG. 5, illustrating the flow of fluids.

FIG. 7 is a cross-sectional view of another embodiment of a downhole gas separator constructed in accordance with the inventive concepts disclosed herein.

FIG. 8 is a cross-sectional view of the downhole gas separator shown in FIG. 7, illustrating the flow of fluids.

FIG. 9 is a cross-sectional view of another embodiment of a downhole separator constructed in accordance with the inventive concepts disclosed herein.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

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 are 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, the use of the “a” or “an” is 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 should also include 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 do not necessarily refer to the same embodiment.

Referring now to the drawings, and more particularly to FIG. 1, a downhole pump assembly 10 is shown in a wellbore 11 of a well. The wellbore 11 may be provided with a casing 13 perforated at one or more positions along its length. The perforations allow fluids from the surrounding formation to enter the casing 13. The fluids may include liquids and gases.

The downhole pump assembly 10 is secured within a tubing string 12 and used in conjunction with a pump jack unit 15 and a sucker rod string 14 to elevate fluids, such as hydrocarbons, to the earth's surface. The downhole pump assembly 10 may include a pump barrel 20, a standing valve 22, a plunger 24, and a traveling valve 26. The pump barrel 24 supports the standing valve 22 in a lower end thereof. The standing valve 22 is illustrated as being a conventional ball check valve.

The plunger 24 is disposed in the pump barrel 20 and is adapted for reciprocating movement through the pump barrel 20. The traveling valve 26 is located at a lower end of the plunger 24 to permit a one-way flow of fluid into the plunger 24. The traveling valve 26 is illustrated as a ball check valve with a seat.

As stated above, on the upstroke of a pumping cycle, the plunger 24 is moved upward. The hydrostatic pressure of the fluid above the traveling valve 26 causes the traveling valve 26 to close. The upward motion of the plunger 24 further causes a negative pressure to develop inside a chamber 28 below the plunger 24, thereby causing the standing valve 22 to open and admit fluid from the formation into the chamber 28.

At the end of the upstroke, the portion of the chamber 28, the traveling valve 26, and the standing valve 22 are filled with liquid from the formation. When the plunger 24 begins its downstroke, the pressure in the chamber 28 becomes positive, causing the standing valve 22 to close. Because liquids are substantially incompressible, the pressure in the chamber 28 rapidly increases to a pressure greater than the pressure above the traveling valve 26. When the fluid pressure in the chamber 28 exceeds the pressure above the traveling valve 26, the traveling valve 26 opens, allowing fluid to pass through the traveling valve 26, which can be lifted by the plunger 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. The traveling valve 26 will not open until the pressure below it becomes greater than the hydrostatic pressure above it. If the fluid contains a significant amount of gas, the traveling valve 26 may not open at all, resulting in the condition known as “gas lock.” In another instance, the plunger 24 may compress the gas, causing it to collide with the liquid. The collision between the plunger 24 and the liquid generates a shockwave called “gas pound.” The shockwave causes the traveling valve 26 to open quickly, which can damage the traveling valve 26 and the other components of the downhole pump assembly 10.

A gas separator 50 constructed in accordance with inventive concepts disclosed herein is connected to a lower end of the downhole pump assembly 10 to reduce the amount of gas entering the downhole pump assembly 10. The gas separator 50 is particularly suited for use in a downhole wellbore to separate gas and liquids from a multi-phase fluid.

Referring to FIG. 2, the gas separator 50 includes an outer tubular member 56, an inner tubular member 58, and a turbine 59. The outer tubular member 56 has an upper end 60, a lower end 62, and a sidewall 64 extending between the upper end 60 and the lower end 62. The sidewall 64 has at least one opening 66 extending through adjacent to the upper end 60 thereof. The upper end 60 of the outer tubular member 56 is connected to the lower end of the pump assembly 10. The lower end 62 of the outer tubular member 56 may be capped.

The inner tubular member 58 has an upper end 68, a lower end 70, and a sidewall 72 extending between the upper end 68 and the lower end 70. The inner tubular member 58 is positioned in the outer tubular member 56 to define an annulus 74 between the outer tubular member 56 and the inner tubular member 58. The upper end 68 of the inner tubular member 58 is connected to the lower end of the pump assembly 10, so the annulus 74 is fluidically sealed from the pump assembly 10, and the inner tubular member 58 is in fluid communication with the pump assembly 10. The lower end 70 of the inner tubular member 58 is open to define a lower open end 76.

The gas separator 50 may include a connector 67. The connector 67 connects the upper end 60 of the outer tubular member 56 to the pump assembly 10. The upper end 68 of the inner tubular member 58 is connected to the lower end of the pump assembly 10, so the annulus 74 is fluidically sealed from the pump assembly 10. The inner tubular member 58 is in fluid communication with the pump assembly 10. The lower connector 67 may be formed from a single, unitary piece of material, as shown, or it may be formed in two or more pieces. The connector 67 may have a tubular wall with an upper end provided with a female threaded portion 69 for coupling with the pump assembly 10. The lower end of the connector 67 may be provided with a male threaded portion 71 for coupling to the upper end 60 of the outer tubular member 56 and a female threaded portion 73 for coupling to the upper end 68 of the inner tubular member 58.

The turbine 59 is rotatably connected to the inner tubular member 56. The turbine 59 has a mounting hub 80 sized to be rotatably positioned about the inner tubular member 56 and at least one blade or fin 82 extending from the hub 80. The hub 80 is rotatably connected to the inner tubular member 56 below the opening 66 of the outer tubular member 56. The blade 82 extends outward from the hub 80, so the blade 82 is positioned in the annulus 74 below the opening 66 of the outer tubular member 56. The blade 82 has a leading end 84 and a trailing end 86. The leading end 84 is positioned uphole of the trailing end 86, so the leading end 84 is positioned between the opening 66 of the outer tubular member 56 and the trailing end 86 of the blade 82.

As shown in FIG. 2, the blade 82 may be a single blade in the form of a spiral or helix. The blade 82 may be wound clockwise from the leading end 84 toward the trailing end 86. In other embodiments, the blade 82 may be wound in a counterclockwise direction. The blade 82 may complete a full revolution between the leading end 84 and the trailing end 86. It is to be appreciated that in other embodiments, the blade 82 may complete more or less than a full revolution between the leading end 84 and the trailing end 86. The blade 82 may have a diameter so that the outer tubular member 56 does not interfere with the rotation of the turbine 59. The pitch of the blade 82 may be varied.

The blade 82 may have an opening 88 formed near the hub 80 to facilitate the passage of the gas separated from the liquid by the rotation of the blade 82. The blade 82 may have one or more openings 88.

The turbine 59 may be affixed to the inner tubular member 58 in any suitable manner. The mounting hub 80 may be tubular and secured to the inner tubular member 58 using any suitable connectors, allowing the hub 80 to float on the inner tubular member 58. The mounting hub 80 and the blade 82 may be die-cast or machined using a suitable metal, such as steel. It will be appreciated that the hub 80 and the blade 82 may be fabricated as integral parts or as separate parts joined together. It is contemplated that one or more turbines 59 could be used in the gas separator 50.

In use, the reservoir fluids flow into the opening 66 of the outer tubular member 56 and pass down the annulus 74. The change of direction, in part, causes a portion of the gas in the reservoir fluid to separate from the liquid and travel up an annulus 77 (FIG. 1) between the outer tubular member 56 and the casing 13. Another portion of the gas separates from the fluid within the annulus 74. This gas travels upward through the annulus 74 and exits through the opening 66.

The liquid is pulled down the annulus 74 by the pump assembly 10 and into contact with the blade 82 of the turbine 59, which causes the turbine 59 to rotate. The rotation of the blade 82 causes additional gas to separate from the liquid, creating a centrifugal force that causes the liquid to spin outward toward the outer side of the annulus 74 and the separated gas to accumulate toward the inner side of the annulus 74. This gas then travels upwards through the opening 88 of the blade 82, through the annulus 74, and exits to the annulus 77 through the opening 66. The liquid passes into the inner tubular member 58 via the lower open end 76 and up to the pump assembly 10.

FIG. 3 illustrates another embodiment of a downhole gas separator 50a. The gas separator 50a is similar to the gas separator 50, except as described below. The gas separator 50a has a turbine 59a rotatably connected to the inner tubular member 58. The turbine 59a has a mounting hub 90 sized to be rotatably positioned about the inner tubular member 56 and a plurality of blades 92 extending from the hub 90. The hub 90 is rotatably connected to the inner tubular member 56 below the opening 66 of the outer tubular member 56. The blades 92 extend outward from the hub 90, so the blades 92 are positioned in the annulus 74 below the opening 66 of the outer tubular member 56. Each of the blades 92 has a leading end 94 and a trailing end 96. The leading end 94 is positioned uphole of the trailing end 96 so the leading end 94 is positioned between the opening 66 of the outer tubular member 56 and the trailing end 96 of the blades 92.

The blades 92 may be oriented to cause the turbine to rotate clockwise or counterclockwise. The blades 92 may have various shapes, from straight to curved. The blades 92 may have a diameter so that the outer tubular member 56 does not interfere with the rotation of the turbine 59a. The pitch of the blades 92 may be varied. Although four blades 92 are shown on the turbine 59a, it will be understood that fewer or greater numbers of blades 92 could also be used.

The turbine 59a may be affixed to the inner tubular member 58 in any suitable manner. The mounting hub 90 may be tubular and secured to the inner tubular member 58 using any suitable connectors, allowing the hub 90 to float on the inner tubular member 58. The mounting hub 90 and the blade 92 may be die-cast or machined using a suitable metal, such as steel. It will be appreciated that the hub 90 and the blades 92 may be fabricated as integral parts or as separate parts joined together. It is contemplated that one or more turbines 59a could be used in the gas separator 50a.

In use, the reservoir fluids flow into the opening 66 of the outer tubular member 56 and pass down the annulus 74. The change of direction, in part, causes a portion of the gas in the reservoir fluid to separate from the liquid and travel up the annulus 77 (FIG. 1) between the outer tubular member 56 and the casing 13. Another portion of the gas separates from the fluid within the annulus 74. This gas travels upward through annulus 74 and exits through opening 66.

The liquid is pulled down the annulus 74 and into contact with the blades 92 of the turbine 59a, which causes the turbine 59a to rotate. The rotation of the blades 92 causes additional gas to separate from the liquid, creating a centrifugal force that causes the liquid to spin outward toward the outer side of the annulus 74 and the separated gas to accumulate toward the inner side of the annulus 74. This gas then travels upward past the blades 92, through the annulus 74, and exits through the annulus 77 via the opening 66. The liquid passes into the inner tubular member 58 via the lower open end 76 and up to the pump assembly 10.

FIG. 4 shows another embodiment of a turbine 59b. The turbine 59b has a mounting hub 90a sized to be rotatably positioned about the inner tubular member 56 and a plurality of blades 92a extending from the hub 90a. The mounting hub 90 may have one or more openings 98 formed therethrough to facilitate the passage of the gas separated from the liquid by the rotation of the blades 92a.

Problems can arise when the pump assembly 10 is exposed to sand and other solid particles. With reference to FIGS. 5 and 6, the downhole gas separator 50a is shown to include a funnel section 100 and a collector section 102.

The inner tubular member 58 has at least one spiral protrusion 104 extending outwardly from a sidewall to cooperate with an interior side of the outer tubular member 56 to form a spiral channel 106. The spiral protrusion 104 may be formed in various shapes and angles. Additionally, more than one spiral protrusion may be employed.

The funnel section 100 is a tubular member with an upper end, a lower end, and a sidewall defining a funnel-shaped bore 116 extending between the upper end and the lower end. The funnel section 100 is configured to be inserted into a lower portion of the outer tubular member 56 or incorporated as a part of the outer tubular member 56.

The liquid is guided downward into the spiral channel 106 formed by the spiral protrusion 104 and the interior side of the outer tubular member 56. The spiral channel 106 induces a cyclonic flow to the liquid, which causes heavier particles, such as sand and other solids, to be forced outward and fall to the lower end 62 of the outer tubular member 56. The separated fluid flows into the lower open end 76 of the inner tubular member 58. The funnel-shaped bore 116 of the funnel section 100 promotes continued cyclonic flow of the solids.

The sand and solids from the funnel section 100 may pass into the collector section 102.

FIGS. 7 and 8 illustrate a tubing anchor catcher 120 incorporated with the downhole gas separator 50a between the outer tubing member 56 and the connector 67.

Tubing anchor catchers (TACs) are used to anchor the tubing string downhole, preventing movement during the production phase. TACs are mechanically operated tools-manipulation of the tubing string typically involves rotating or up/down movements to set and release. TACs have a safety release mechanism in case rotation does not work after they've been downhole-they are pinned to release the anchor when a certain tension is reached.

The TAC 120 is installed below the seat nipple or connector 67 as part of the gas separator 50a. The TAC 120 features heavy-walled slotted subs 122 and 124 positioned above and below the TAC 120. The inner tubular member 58 is run through the subs 122 and 124 and the TAC 120, and is connected to a connector, such as the connector 67, below a seat nipple.

Referring to FIG. 9, another embodiment of a downhole gas separator 50b is illustrated. The gas separator 50b is similar to the gas separator 50 and 50a, except as described below. The gas separator 50b has an inner tubular member 152 and an outer tubular member 154. The inner tubular member 152 serves as a conduit to deliver fluid to the pump assembly 10. The outer tubular member 154 cooperates with the inner tubular member 152 to form a dead chamber that will act as a fluid-holding chamber for entry into the inner tubular member 152.

The inner tubular member 152 has an upper end 156, a lower end 158, and a sidewall 160 extending between the upper end and the lower end. The lower end of the inner tubular member 152 has an opening 162 in the form of an open lower end. The inner tubular member 152 is often referred to as a “dip tube.” The inner tubular member 152 may be formed as a single section of tubing or as multiple sections of tubing. By way of example, the inner diameter of the inner tubular member 152 may be in a range from about one inch to about two inches, and the length of the inner tubular member 152 may be in a range from about ten feet to about thirty feet.

The outer tubular 154 member has an upper end 164, a lower end 166, and a sidewall 168, extending between the upper end of the outer tubular member 154 and the lower end of the outer tubular member 154. The outer tubular member 154 is positioned about at least a portion of the inner tubular member 152. The outer tubular member 154 is connected to the inner tubular member 154 to define an annulus 170 between the inner tubular member 152 and the outer tubular member 154. The upper end 164 of the outer tubular 154 is free from the inner tubular member 152 to define an open-ended, circumferential inlet 172 between the upper end of the outer tubular member 154 and the inner tubular member 152. The circumferential inlet 172 is in fluid communication with the opening 162 at the lower end of the inner tubular member 152. By way of example, the inner diameter of the outer tubular member 154 may be in a range from about two inches to about five inches, and the length of the outer tubular member 154 may be in a range from about fifteen feet to about forty feet.

The separator 50b may have a connector member (not shown) to support the outer tubular member 154 relative to the inner tubular member 152 in a way that maintains the upper end of the outer tubular member 154 free from the inner tubular member 152 and permits fluid communication between the circumferential inlet 172 and the opening 162 at the lower end of the inner tubular member 152. The connector member may be positioned between the upper end of the outer tubular member 154 and the opening 162 at the lower end of the inner tubular member 152. The connector member may have a plurality of flow ports extending therethrough, permitting the reservoir fluid to pass from the circumferential inlet 172 to the opening 162 at the lower end of the inner tubular member 152. In one embodiment, the flow area of the flow ports may be at least equal to the flow area of the inner tubular member 152.

The gas separator 50b has a turbine, such as the turbine 59a described above. The turbine 59a is rotatably connected to the inner tubular member 152, as described above.

The turbine 59a may be affixed to the inner tubular member 158 so the turbine 59a is positioned uphole of the circumferential inlet 172 as illustrated in FIG. 9. Alternatively, the turbine 59a may be affixed to the inner tubular member 158 so that the turbine 59a is positioned downhole of the circumferential inlet 172. It is contemplated that one or more turbines 59a could be used in the gas separator 50b.

In use, the reservoir fluids come into contact with the blades 92 of the turbine 59a, causing the turbine 59a to rotate. The rotation of the blades 92 causes gas to separate from the liquid, creating a centrifugal force that causes the liquid to spin outwards and downward, facilitating its movement down the annulus 170 to the lower open end 162 of the inner tubular member 152. The liquid passes into the inner tubular member 158 via the lower open end 162 and up to the pump assembly 10. The separated gas accumulates towards the inner tubular member 152, travels upwards past the blades 92, and continues upward through the annulus 77 (FIG. 1).

Although the presently disclosed inventive concepts have 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.