DOWNHOLE GAS SEPARATOR

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

CROSS REFERENCE TO RELATED APPLICATIONS

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.

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 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.

SUMMARY OF INVENTIVE CONCEPTS

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.

BRIEF DESCRIPTION OF THE DRAWINGS

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.

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 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, a downhole pump assembly 10 is shown in a wellbore 11 of a well. The wellbore 11 may be provided with a casing 13 that may be 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 in a tubing string 12 and used with a pump jack unit 15 and a sucker rod string 14 for elevating 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 pump barrel 20. The traveling valve 26 is located in a lower end of the plunger 24 to permit one way flow of fluid into the plunger 24. The traveling valve 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 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 the downstroke, the pressure in the chamber 28 becomes positive which causes 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 becomes greater than the pressure above the traveling valve 26, the traveling valve 26 opens and fluid passes through the traveling valve 26 where it is able to 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. That is, because the traveling valve 26 will not open until the pressure below the traveling valve 26 becomes greater than the hydrostatic pressure above the traveling valve 26, 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 thereby resulting in the plunger 24 colliding with the liquid. The collision between the plunger 24 and the liquid generates a shockwave and is referred to as “gas pound.” The shockwave causes the traveling valve 26 to open quickly which can result in damage to the traveling valve 26 and to the other components of the downhole pump assembly 10.

A gas separator 50 constructed in accordance with inventive concepts disclosed herein is shown 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 for separation of gas and liquids from a multi-phase fluid.

Referring now to FIGS. 2-4, the gas separator 50 includes a first separator section 52 and a second gas separator section 54. The second gas separator section 54 is a conventional gas separator that may include an outer tubular member 56 and an inner tubular member 58. 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 inlet opening 66 extending therethrough adjacent the upper end 60 thereof. Conventionally, 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 is capped so fluid only enters the second separator section 52 via the inlet opening 66.

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. Conventionally, 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.

In one embodiment, the second gas separator section 54 may include a connector 67. Conventionally, the connector 67 connects the upper end 60 of the outer tubular member 56 to the pump assembly 10 and 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 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 or the first gas separator section 52 as discussed below. 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 of the second separator section 54.

The lower end 70 of the inner tubular member 58 is open to define a lower open end 76 having a flow area. In use, the reservoir fluids flow into the inlet opening 66 of the outer tubular member 56 and pass down the annulus 74. The change of direction causes a portion of the gas in the reservoir fluid to separate from the liquid and travel up an annulus 77 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 travel upwards through the annulus 74 and exits through the inlet opening 66. The liquid passes into the inner tubular member 58 via the lower open end 76 and up to the pump assembly 10.

The first separator section 52 includes an outer tubular member 80 and an inner tubular member 82. The outer tubular member 80 has an upper end 84, a lower end 86, and a sidewall 88 extending between the upper end 84 and the lower end 86. The sidewall 88 has at least one inlet opening 90 extending therethrough adjacent the upper end 84. The upper end 84 of the outer tubular member 80 is connectable to the lower end of the pump assembly 10.

The inner tubular member 82 has an upper end 92, a lower end 94, and a sidewall 96 extending between the upper end 92 and the lower end 94. The inner tubular member 82 is positioned in the outer tubular member 80 to define an annulus 97 between the outer tubular 80 member and the inner tubular member 82. The upper end 92 of the inner tubular member 82 is connected to the upper end 84 of the outer tubular member 80 so the annulus 97 is fluidically sealed from the pump assembly 10 and the inner tubular member 82 is in fluid communication with the pump assembly 10 when the inner tubular member 82 is connected to the pump assembly 10. The sidewall 88 of the first inner tubular member 82 has at least one opening 98 extending therethrough adjacent the lower end thereof. The opening 98 has a flow area less than the flow area of the lower open end 76 of the inner tubular member 58 of the second separator section 52.

The opening 98 may be defined by a nozzle 99 (FIG. 4). The nozzle 99 may be formed of a hardened material, such as carbide. The nozzle 99 may have a diameter of approximately ¼ inch, by way of example. However, it will be appreciated that the diameter of the opening 98 may be varied. To reduce clogging, the first gas separator section 52 may be provided with a screen 101 (FIG. 3) secured over the opening 98.

The inlet opening 90 of the outer tubular member 80 of the first separator section 52 is arranged to be less restrictive than the opening 98 such that fluid may readily enter through the inlet opening 90; however, gas can also escape from the first separator section 52 back into the annulus 97 through the inlet opening 90. In one embodiment, by way of example, the inlet opening 66 and the inlet opening 90 may be configured as slots with dimensions of approximately one to two inches in width and approximately eight inches in length. The inlet opening 66 and the inlet opening 90 may be of similar dimension or different.

Referring to FIG. 3, the first separator section 52 may have an upper connector 100 and a lower connector 102. The upper connector 100 connects the upper end 84 of the outer tubular member 80 to upper end 92 of the inner tubular member 82. The upper connector 100 also enables the first separator section 52 to be connected to the lower end of the pump assembly 10. Similarly, the lower connector member 102 connects the lower end 86 of the outer tubular member 80 to the lower end 94 of the inner tubular 82. The upper connector 100 and the lower connector 102 connect the inner tubular member 82 to the outer tubular member 80 so the annulus 97 is fluidically sealed from the pump assembly 10 and the annulus 74 of the second separator section 54 except via the opening 98. As such, fluid in the annulus 97 must pass through the opening 98. The lower connector 102 also enables the first separator section 52 to be connected to the second 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. The upper connector 100 may have a tubular wall with an upper end portion configured with a female thread portion 120 for coupling to the tubing string 12. The lower end of the upper connector 100 may be provided with a male threaded portion 122 for coupling to the outer tubular member 80 and a female threaded portion 124 for coupling to the upper end of the inner 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. The lower connector 102 may have a tubular wall with an upper end provided with a male threaded portion 126 for coupling to the lower end 86 of the outer tubular member 80 and a female portion 128 (including a sealing member, such as an O-ring) for coupling to the lower end 94 of the inner tubular member 82. The lower end of the lower connector 102 may be provided with a male threaded portion 130 for sealingly coupling to the female threaded portion 69 of the connector 67 of the second gas separator section 54 so the inner tubular member 58 is in fluid communication with the inner tubular member 82.

In another embodiment, the gas separator 50 may be implemented with more than one of the first 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

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.