DOWNHOLE SEPARATOR

Abstract

A downhole separator includes an inner tubular member and an outer tubular member. The outer tubular member is positioned about at least a portion of the inner tubular member and connected to the inner tubular member to define an annulus between the inner tubular member and the outer tubular member. The upper end of the outer tubular is free from the inner tubular member to define a circumferential inlet between the upper end of the outer tubular member and the inner tubular member. The circumferential inlet is in fluid communication with the lower open end of the inner tubular member. Reservoir fluid passes into the annulus formed between the inner tubular member and the outer tubular member via the circumferential inlet. The reservoir fluid is guided downwardly to the opening of the inner tubular member so the fluid continues to travel up through the inner tubular member.

Description

BACKGROUND

Sucker rod pumps are often used when the natural pressure of an oil and gas formation is insufficient to lift the oil to the earth's surface. 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 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 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, which can 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 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 called “gas pound.” The shock wave causes the traveling valve to open quickly, and this 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 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 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 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 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.

SUMMARY OF INVENTIVE CONCEPTS

The inventive concepts disclosed and claimed herein generally relate to a downhole separator, including an inner tubular member and an outer tubular member. The outer tubular member is positioned about at least a portion of the inner tubular member and connected to the inner tubular member to define an annulus between the inner tubular member and the outer tubular member. The upper end of the outer tubular is free from the inner tubular member to define a circumferential inlet between the upper end of the outer tubular member and the inner tubular member. The circumferential inlet is in fluid communication with the lower open end of the inner tubular member. Reservoir fluid passes into the annulus formed between the inner tubular member and the outer tubular member via the circumferential inlet. The reservoir fluid is guided downwardly to the opening of the inner tubular member so the fluid continues to travel up through the inner tubular member.

The fluid can flow through a connector member, which supports the outer tubular member relative to the inner tubular member, to a desander housing to remove solids. The connector member may have a sand separator below the opening of the inner tubular member to assist with removing solids before entering the inner tubular member and the pump assembly.

By forming a circumferential inlet, more fluid will “stall” below the critical lifting velocity at the circumferential inlet and be allowed to accumulate in the annulus, thereby causing the gas to separate and travel upward.

In one version, the dip tube is used as a structural member to support the desander and the shroud to remove gas and solids. The dip tube is placed on a connector member capable of holding the weight of the tubing string below it. The lower end of the dip tube is connected into a cross-over connection where the shroud is held. The shroud diverts fluid and gas around the outer diameter of the dip tube and allows fluid to fall downward while gas continues upward. The fluid then passes through the cross-over connection, and solids are spun outwardly through the hydro-cyclonic sand separator. The fluid travels upward through the dip tube, and the solids fall downward.

In another embodiment, the lower end of the dip tube is threaded into a bypass sub that holds the shroud and allows fluid to enter the dip tube.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view of a sucker rod pump assembly with a downhole separator constructed in accordance with the inventive concepts disclosed herein incorporated with the sucker rod pump assembly.

FIG. 2 is an elevational view of the downhole separator.

FIG. 3 is a partial cross-sectional view of the downhole separator.

FIG. 4 is a cross-sectional view of a portion of another embodiment of a downhole separator.

FIG. 5 is a perspective, cross-sectional view of the portion of the downhole separator shown in FIG. 4.

FIG. 6 is a partial cross-sectional view of the downhole separator shown with a solids collector section.

FIG. 7 is a partial 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” 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 have 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 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 at a lower end of the plunger 24 to permit a one-way fluid flow 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 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 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 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, 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. 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 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 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 separator 50 is particularly suited for use in a downhole wellbore to separate gas, liquids, and solids from a multi-phase fluid.

Referring now to FIGS. 2-6, the separator 50 includes an inner tubular member 52 and an outer tubular member 54. The inner tubular member 52 is a conduit to bring fluid to the pump assembly 10. The outer tubular member 54 cooperates with the inner tubular member 52 to form a dead chamber that will act as a fluid-holding chamber for entry into the inner tubular member 52.

The inner tubular member 52 has an upper end 56, a lower end 58, and a sidewall 60 extending between the upper end 56 and the lower end 58. The lower end 58 of the inner tubular member 52 has an opening 62 (FIGS. 4-6) in the form of an open lower end. The inner tubular member 52 is often called a “dip tube.” The inner tubular member 52 may be formed as one section of tubing or may be formed as multiple sections of tubing (as shown herein). By way of example, the inner diameter of the inner tubular member 52 may be in a range from about one inch to about two inches, and the length of the inner tubular member 52 may be in a range from about ten feet to about thirty feet.

The outer tubular 54 member has an upper end 64, a lower end 66, and a sidewall 68, extending between the upper end 64 of the outer tubular member 54 and the lower end 66 of the outer tubular member 54. The outer tubular member 54 is positioned about at least a portion of the inner tubular member 52. The outer tubular member 54 is connected to the inner tubular member 54 to define an annulus 70 between the inner tubular member 52 and the outer tubular member 54. The upper end 64 of outer tubular 54 is free from the inner tubular member 52 to define an open-ended, circumferential inlet 72 between the upper end of the outer tubular member 54 and the inner tubular member 52. The circumferential inlet 72 is in fluid communication with the opening 62 at the lower end 58 of the inner tubular member 52. By way of example, the inner diameter of the outer tubular member 54 may be in a range from about two inches to about five inches, and the length of the outer tubular member 54 may be in a range from about fifteen feet to about forty feet.

The separator 50 has a connector member 80 to support the outer tubular member 54 relative to the inner tubular member 52 in a way that maintains the upper end 64 of the outer tubular member 54 free from the inner tubular member 52 and permits fluid communication between the circumferential inlet 72 and the opening 62 at the lower end 58 of the inner tubular member 52.

The connector member 80 is positioned between the upper end 64 of the outer tubular member 54 and the opening 62 at the lower end 58 of the inner tubular member 52. In one embodiment, the connector 80 is connected to a lower end of one segment of the outer tubular member 54 and to an upper end of another segment of the outer tubular member 54. The connector 80 may also be connected to a lower end of one segment of the inner tubular member 52 and to an upper end of another segment of the inner tubular member 52 in a way that fluid flows through the connector member 80 from the lower end of the inner tubular member 52 to the pump assembly 10. The connector member 80 may have a central passage 81.

The connector member 80 may have a plurality of flow ports 82 extending therethrough to permit the reservoir fluid to pass from the circumferential inlet 72 to the opening 62 at the lower end 58 of the inner tubular member 52. In one embodiment, the flow area of the plurality of flow ports 82 may be at least equal to the flow area of the inner tubular member 52.

Reservoir fluid passes into the annulus 70 formed between the inner tubular member 52 and the outer tubular member 54 via the circumferential inlet 72. The reservoir fluid is guided downwardly to the opening 62 at the lower end of the inner tubular member 62 so the fluid continues to travel up through the inner tubular member 52 and to the pump assembly 10. The connections with the connector member 80 may be made in any suitable manner, such as by threads.

The outer tubular member 54 may also include a desander housing 92. The desander housing 92 may have an upper end connected to a lower end of a section of the outer tubular member 54 (FIG. 3). Alternatively, as shown in FIGS. 4 and 5, the desander housing 92 may be connected directly to the connector member 80 in a suitable way, such as by threads.

The inner tubular member 52 may include a desander spiral 94 with a spiral protrusion 96 extending outwardly from a sidewall to cooperate with an interior side of the outer tubular member 54 (e.g., the desander housing 92) to form a spiral channel 98. The spiral protrusion 92 may be formed in various shapes and angles. Additionally, more than one spiral protrusion may be employed.

The outer tubular member 54 may also include a funnel section 100, which is a tubular member with a funnel-shaped bore. The funnel section 100 is configured to be inserted into a lower portion of the outer tubular member 54 or incorporated as a part of the outer tubular member 54.

In the illustrated embodiment, the opening 62 of the inner tubular member 52 is located at a lower end of the desander spiral 94. Reservoir fluid passes into the annulus 70 formed between the inner tubular member 52 and the outer tubular member 54 via the circumferential inlet 72. The reservoir fluid is guided downwardly into the spiral channel 98, so the spiral channel 98 induces a cyclonic flow that causes heavier particles, such as sand and other solids, to be forced outwardly and fall to the lower end of the outer tubular member 54. The separated fluid flows into the inner tubular member 52 via the opening 62. The fluid continues to travel up through the inner tubular member 52 to the pump assembly 10. The funnel-shaped bore 108 of the funnel section 100 promotes continued cyclonic flow of the solids.

The sand and solids from the funnel section 100 may pass into a collector section 110 (FIG. 6). The collector section 110 may have an upper end connected to the lower end of the outer tubular member 54. The collector section 110 may be a tubular member having an upper end 112, a closed lower end 114, and a sidewall 116 defining a chamber 118 extending between the upper end 112 and the closed lower end 114. The upper end 112 of the collector section 110 is connected to the lower end 122 of the outer tubular member 54. In one version, the collector section 110 may have a length of approximately 32 feet or more. However, it will be appreciated that the length of the collector section 110 may be varied.

In another version, the collector section may be in the form of a dump valve or check valve (not shown) connected to the lower end of the outer tubular member 54. Flow from below the check valve prevents fluid flow up the tubing string and directs fluid flow to the circumferential inlet. When the flow of fluid stops, the check drops to allow the passage of solids through the desander housing. This cycle will continue with the check valve preventing flow directly up the tubing while preventing sand from entering the tubing string.

Referring now to FIG. 7, another embodiment of a separator 50a is illustrated. The separator 50a includes an inner tubular member 52a and an outer tubular member 54a. The inner tubular member 52a is a conduit to bring fluid to the pump assembly 10. The outer tubular member 54a cooperates with the inner tubular 52a to form a dead chamber that will act as a fluid holding chamber and entry into the inner tubular member 52a.

The inner tubular member 52a has an upper end 56a, a lower end 58a, and a sidewall 60a extending between the upper end 56a and the lower end 58a. The lower end 58a of the inner tubular member 52a has at least one opening 62a formed in the sidewall 60a near the lower end 58a. The inner tubular member 52a is often called a “dip tube.” The inner tubular member 52a may be formed as one section of tubing or may be formed as multiple sections of tubing. By way of example, the inner diameter of the inner tubular member 52a may be in a range from about one inch to about two inches, and the length of the inner tubular member 52a may be in a range from about ten feet to about thirty feet.

The outer tubular 54a member has an upper end 64a, a lower end 66a, and a sidewall 68a extending between the upper end 64a of the outer tubular member 54a and the lower end 66a of the outer tubular member 54a. The outer tubular member 54a is positioned about at least a portion of the inner tubular member 52a. The outer tubular member 54a is connected to the inner tubular member 54a to define an annulus 70a between the inner tubular member 52a and the outer tubular member 54a. The upper end 64a of outer tubular 54a is free from the inner tubular member 52a to define an open-ended, circumferential inlet 72a between the upper end of the outer tubular member 54a and the inner tubular member 52a. The circumferential inlet 72a is in fluid communication with the opening 62a at the lower end of the inner tubular member 52a. By way of example, the inner diameter of the outer tubular member 54a may be in a range from about two inches to about five inches, and the length of the outer tubular member 54a may be in a range from about fifteen feet to about forty feet.

The separator 50a has a connector member 80a to support the outer tubular member 54a relative to the inner tubular member 52a in a way that maintains the upper end of the outer tubular member 54a free from the inner tubular member 52a and permits fluid communication between the circumferential inlet 72a and the opening 62a at the lower end 66a of the inner tubular member 52a. The connector member 80a is connected to the lower end 58a of the inner tubular member 52a and the lower end 66a of the outer tubular member 54a. In one embodiment, the connector member 80a forms a seal at the lower end of the annulus 70a.

Reservoir fluid passes into the annulus 70a formed between the inner tubular member 52a and the outer tubular member 54a via the circumferential inlet 72a. The reservoir fluid is guided downwardly to the opening 62a at the lower end 58a of the inner tubular member 52a, so the fluid continues to travel up through the inner tubular member 52a and to the pump assembly 10.

Although the presently disclosed inventive concepts have been described in conjunction with the specific language set forth herein, 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 separator, comprising: an inner tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the lower end of the inner tubular member having an opening, the upper end of the inner tubular member connectable to a lower end of a tubing string positionable in a wellbore; andan outer tubular member having an upper end, a lower end, and a sidewall extending between the upper end of the outer tubular member and the lower end of the outer tubular member, the outer tubular member positioned about at least a portion of the inner tubular member and connected to the inner tubular member to define an annulus between the inner tubular member and the outer tubular member, the upper end of outer tubular being free from the inner tubular member to define a circumferential inlet between the upper end of the outer tubular member and the inner tubular member, the circumferential inlet being in fluid communication with the lower open end of the inner tubular member,wherein reservoir fluid passes into the annulus formed between the inner tubular member and the outer tubular member via the circumferential inlet, the reservoir fluid guided downwardly to the opening of the inner tubular member so the fluid continues to travel up through the inner tubular member.

2. The separator of claim 1, further comprising a connector member supporting the outer tubular member relative to the inner tubular member in a way that permits fluid communication between the circumferential inlet and the opening at the lower end of the inner tubular member.

3. The separator of claim 2, wherein the connector member is positioned between the upper end of the outer tubular member and the opening at the lower end of the inner tubular member, the connector member having a plurality of flow ports extending therethrough.

4. The separator of claim 3, wherein the inner tubular member has at least one spiral protrusion extending outwardly from the sidewall to cooperate with an interior side of the outer tubular member to form a spiral channel, wherein reservoir fluid passes into the annulus formed between the inner tubular member and the outer tubular member via the circumferential inlet, the reservoir fluid guided downwardly into the spiral channel so the spiral channel induces a cyclonic flow that causes heavier particles to be forced outwardly and to fall to the lower end of the outer tubular member, the separated fluid flows into the lower open end of the inner tubular member so the fluid continues to travel up through the inner tubular member.

5. The separator of claim 4, wherein a lower portion of the outer tubular member includes a funnel-shaped bore.

6. The separator of claim 5, further comprising a collector section having an upper end connected to the lower end of the outer tubular member.

7. The separator of claim 6, wherein the collector section comprises a tubular member having an upper end, a closed lower end, and a sidewall defining a chamber extending between the upper end and the lower end, the upper end of the collector section connected to the lower end of the outer tubular member.

8. A separator, comprising: a tubing string positioned in a wellbore, the tubing string having an upper end and a lower end;an inner tubular member having an upper end, a lower end, and a sidewall extending between the upper end and the lower end, the lower end of the inner tubular member having an opening, the upper end of the inner tubular member connected to the lower end of the tubing string; andan outer tubular member having an upper end, a lower end, and a sidewall extending between the upper end of the outer tubular member and the lower end of the outer tubular member, the outer tubular member positioned about at least a portion of the inner tubular member and connected to the inner tubular member to define an annulus between the inner tubular member and the outer tubular member, the upper end of outer tubular being free from the inner tubular member to define a circumferential inlet between the upper end of the outer tubular member and the inner tubular member, the circumferential inlet being in fluid communication with the lower open end of the inner tubular member,wherein reservoir fluid passes into the annulus formed between the inner tubular member and the outer tubular member via the circumferential inlet, the reservoir fluid guided downwardly to the opening of the inner tubular member so the fluid continues to travel up through the inner tubular member to the tubing string.

9. The separator of claim 8, further comprising a connector member supporting the outer tubular member relative to the inner tubular member in a way that permits fluid communication between the circumferential inlet and the opening at the lower end of the inner tubular member.

10. The separator of claim 9, wherein the connector member is positioned between the upper end of the outer tubular member and the opening at the lower end of the inner tubular member, the connector member having a plurality of flow ports extending therethrough.

11. The separator of claim 10, wherein the inner tubular member has at least one spiral protrusion extending outwardly from the sidewall to cooperate with an interior side of the outer tubular member to form a spiral channel, wherein reservoir fluid passes into the annulus formed between the inner tubular member and the outer tubular member via the circumferential inlet, the reservoir fluid guided downwardly into the spiral channel so the spiral channel induces a cyclonic flow that causes heavier particles to be forced outwardly and to fall to the lower end of the outer tubular member, the separated fluid flows into the lower open end of the inner tubular member so the fluid continues to travel up through the inner tubular member.

12. The separator of claim 11, wherein a lower portion of the outer tubular member includes a funnel-shaped bore.

13. The separator of claim 12, further comprising a collector section having an upper end connected to the lower end of the outer tubular member.

14. The separator of claim 13, wherein the collector section comprises a tubular member having an upper end, a closed lower end, and a sidewall defining a chamber extending between the upper end and the lower end, the upper end of the collector section connected to the lower end of the outer tubular member.

15. The separator of claim 8, wherein the tubing string includes a pump assembly positioned uphole of the inner tubular member.

16. The separator of claim 15, 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 inner tubular member;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; anda 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.