Gas separator with inlet tail pipe

Abstract

An oil and gas well gas separator that operates in conjunction with an isolation means and a tail pipe to reduce the pressure gradient of the well fluids flowing up the tailpipe, to thereby reduce the well's producing bottom hole pressure.

Claims

1. An apparatus for production of well fluids, including well liquids and well gases, in an oil and gas well having a casing extending down to an oil and gas formation, wherein the casing has an interior and has perforations formed therethough for receiving oil and gas from the formation, and the well having a pump supported from a tubing string with a pump inlet located above the perforations, the apparatus comprising: a gas separator coupled to the pump inlet to deliver well liquids thereto, and having a well fluid inlet, said separator having an exterior defining a separation annulus with the casing interior within which well gases rise and are separated from well liquids; a tailpipe having a fluid inlet for receiving the formation well fluids that enter the casing through the perforations, and having a fluid outlet located above said tailpipe fluid inlet and coupled to said gas separator well fluid inlet; an isolation means disposed to sealably engage the casing at a location below said separator well fluid inlet to thereby provide a pressure seal which isolates the well fluids in the casing above and below said isolation means, and wherein said tailpipe has an internal diameter less than that of said tubing string to thereby reduce a pressure gradient of the well fluids flowing in said tailpipe as compared to a pressure gradient that would exist without use of said tailpipe, and thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase well fluid production in the oil and gas well.

2. The apparatus of claim 1, and further comprising: a tubing anchor connected proximate said gas separator to fixedly locate said gas separator and said well fluid outlet of said tail pipe with respect to the casing.

3. The apparatus of claim 1, and wherein: said isolation means is a pack-off assembly.

4. The apparatus of claim 1 wherein said isolation means is a packer.

5. The apparatus of claim 1, and wherein: said isolation means is plural diverter cups.

6. The apparatus of claim 1, and wherein: said isolation means is a flow diverter consisting of plural elastomeric discs.

7. The apparatus of claim 1, and wherein: said isolation means is slidably mounted along a vertical axis of the casing.

8. The apparatus of claim 1, and wherein: said separation annulus is formed between said gas separator and the casing.

9. The apparatus of claim 1, and wherein: said isolation means is configured as at least a first disc having an outer diameter selected to fit within an interior diameter of the casing, and having a mounting hole formed there through and sized to engage an exterior surface of said tail pipe.

10. The apparatus of claim 1, and wherein: said oil and gas well has a horizontal portion.

11. A method of producing well fluids, including well liquids and well gases, in an oil and gas well having a casing extending down to an oil and gas formation, wherein the casing and interior and has perforations formed therethrough for receiving oil and gas from the formation, and having a pump located above the perforations and supported from a tubing string, having a tubing string diameter, with a pump inlet, the method comprising the steps of: operating the pump, thereby enabling well liquids to flow into the pump inlet, and inducing flow of the well fluids below the pump, including enabling well fluids to flow from the oil and gas formation, through the perforations, and into the casing; inducing the well fluids to flow up a tailpipe from a fluid inlet located proximate the oil and gas formation and an outlet located above said fluid inlet, the tailpipe having an internal diameter that is less than the tubing string diameter to thereby reduce a pressure gradient of the well fluids therein, as compared to a pressure gradient that would exist without use of the tailpipe, as a result of the smaller diameter thereof, and thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase well fluid production from the oil and gas well, and discharging the well fluids from a fluid outlet of a gas separator, which is coupled to an upper end of the tailpipe, into a separation annulus defined by an exterior of the gas separator and the casing interior, wherein the well gases rise and are separated from the well liquids that fall, entering a liquid inlet of the gas separator, and delivering the separated well liquids from the gas separator into the pump inlet, and isolating the flow of well fluids up the casing from the oil and gas formation by an isolation means disposed to sealably engage the casing interior at a location below the gas separator liquid inlet.

12. Apparatus for the production of well fluid, which includes liquids and gas, from a well having therein a casing, having an interior, that extends from the surface down to a formation that is the source of well fluids and a downhole pump, having an inlet, located above the formation for driving the liquids upward through tubing, having a diameter, to the surface, comprising: a gas separator having a fluid inlet, a liquid outlet and which defines a separation annulus between an exterior of said gas separator and the casing interior, and wherein gas in the fluid rises and separates from the liquid, said gas separator liquid outlet coupled to the inlet of said pump; a tailpipe having a fluid inlet located below said gas separator for receiving said well fluids that have flowed into said casing from said formation and a fluid outlet coupled to said gas separator fluid inlet; an isolator disposed within the casing below said separator to provide a pressure seal to isolate a casing interior region above the isolator from a casing interior region below the isolator, and said tailpipe having an internal diameter less than the diameter of said tubing to provide a lower pressure gradient of said well fluid passing upward through said tailpipe in comparison to a tailpipe having the same internal diameter as that of said tubing, to thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase fluid production from the well.

13. Apparatus as recited in claim 12 wherein said isolator is a packer.

14. Apparatus as recited in claim 12 wherein said isolator is mounted to said tailpipe.

15. The apparatus as recited in claim 12 wherein said isolator is a packer mounted to said tailpipe.

16. The apparatus as recited in claim 12 wherein said isolator primarily comprises polymeric material.

17. The apparatus as recited in claim 12 wherein said isolator includes a metal sleeve and a plurality of polymeric cups.

18. The apparatus as recited in claim 12 wherein said well has a horizontal portion.

19. The apparatus as recited in claim 12 including a tubing anchor installed in said well within said casing to limit the vertical movement of said isolator with respect to said casing.

20. The apparatus as recited in claim 12 wherein said gas separator comprises an inner barrel and an outer barrel coaxial with said inner barrel, said fluid inlet located at an lower region of said separator, said outer barrel having a liquid inlet at a lower region thereof, said liquid inlet coupled to said gas separator liquid outlet, and said separation annulus defined at least partially by the exterior wall of said outer barrel and the adjacent interior wall of said casing.

21. The apparatus as recited in claim 12 including a tubing anchor connected to said tubing to restrict vertical movement of said pump with respect to said casing.

22. A method for producing fluid, which includes liquid and gas, from a well having therein a casing that has an interior, and which extends from the surface down to a formation that is the source of the fluid and a downhole pump located above the formation within the casing for pushing liquids upward through tubing to the surface, comprising the steps of: receiving said fluid from said formation through perforations in said casing into a bottom hole casing annulus region, driving fluid in said bottom hole casing annulus region upward through a tailpipe which has an inlet in said casing annulus region, said tailpipe having an internal diameter less than the diameter of said tubing such that the pressure gradient of said fluid in said tailpipe is less than the pressure gradient of a tailpipe similarly located and having the same diameter as that of said tubing, to thereby reduce correspondingly a minimum required producing bottom hole pressure and correspondingly increase fluid production from the well, receiving said fluid from said tailpipe at a fluid inlet of a gas separator, which has an exterior, directing said fluid received at the fluid inlet of said gas separator to a gas separation zone that is contiguous with said separator, said separation zone defined by the separator exterior and the casing interior, and wherein gas rising in said gas separation zone at least partially separates from said liquid in said fluid, said gas separation zone formed by an isolation member positioned in said casing below said gas separator, said isolation member providing a pressure seal between the gas separation zone and the casing annulus region below said isolation member, transferring said liquid, which remains after said gas has been at least partially separated from said liquid, from said gas separation zone into an inlet of said pump, and flowing said gas, which has separated from said fluid in said gas separation zone, upward through the casing to the surface.

23. The method recited in claim 22 wherein the step of directing said fluid received at the fluid inlet of the separator includes the steps of driving said fluid from the lower end of said gas separator upward through the interior of said separator to a fluid outlet located at the upper region of said separator and from this fluid outlet into said gas separation zone, and transferring said liquid from said gas separation zone through a liquid inlet at the lower end of said separator and transferring said liquid to the inlet of said pump.

24. An apparatus for the production of well fluids, including liquids and gases, from a horizontal oil well having a casing, with an interior, that has perforations formed therethrough for ingress of the well fluids from an oil bearing formation and a pump, located above the perforations, coupled to tubing within the casing for extracting liquids from the oil well, the apparatus comprising: a gas separator, having an exterior, coupled to receive well fluids from a tailpipe located below said gas separator, wherein said gas separator exterior defines a separation annulus with the casing interior in which the well gases rise and are separated from the well liquids that fall within said separation annulus that is coupled to deliver well liquids to said pump; a packer having pressure seal between said separation annulus above and a casing annulus below, said packer being coupled at a top end to said gas separator and a bottom end being coupled to a tail pipe, and wherein said tail pipe is coupled at an upper end thereof to said packer and extending downward in the oil well, said tail pipe transfers well fluid to said packer, wherein said tail pipe reduces a well fluid pressure gradient, to thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase well fluid production from the horizontal oil well.

25. The apparatus of claim 24, and wherein: said packer further comprises plural locking lugs to engage the casing wall.

26. The apparatus of claim 24, and wherein: said packer is a polymeric pressure isolating member.

27. The apparatus as recited in claim 24 including a tubing anchor installed in said well within said casing to limit the vertical movement of said isolator with respect to said casing.

28. An apparatus for the production of well fluids, including liquids and gases, from an oil well having a casing that has perforations formed threrethrough for ingress of the well fluids from an oil bearing formation and a pump located above the perforations, and coupled to tubing within the casing for extracting liquids from the well, the apparatus comprising: a gas separator, having an exterior, coupled to deliver well liquids to an inlet of the pump, said gas separator defining a separation annulus zone between the exterior of said gas separator and an interior wall of the casing adjacent to said gas separator, said gas separator having a fluid inlet at a lower portion thereof and a fluid outlet at an upper portion thereof for transferring well fluid from said gas separator into said separation annulus zone; a tail pipe coupled at an upper end thereof to said gas separator fluid inlet and extending downward in the oil well to receive well fluids in the casing below said gas separator, said tail pipe having a lesser interior diameter than that of said tubing to thereby reduce a pressure gradient for well fluids flow upward through said tail pipe to said gas separator, to thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase fluid production from the well, and a polymeric isolating member mounted to an exterior surface of said tail pipe below said gas separator to provide a pressure seal in a casing annulus.

29. The apparatus of claim 28, and wherein: said polymeric pressure isolating member includes a plurality of coaxial cupped type discs.

30. The apparatus of claim 28, and wherein: said polymeric pressure isolating member includes a steel sleeve, which is in contact with the outer surface of said tail pipe.

31. The apparatus as recited in claim 28 wherein said well has a horizontal portion.

32. The apparatus of claim 28, and wherein: said gas separator includes a inner cylindrical barrel and an outer cylindrical barrel which has a greater diameter than said inner cylindrical barrel and defines an upward fluid flow zone therebetween and said gas separator inlet connected to transfer well fluid from said tail pipe into said upward fluid flow zone, said outer barrel having a fluid outlet at an upper region thereof for transferring well fluid from said upward fluid flow zone into said separation annulus zone.

33. The apparatus of claim 28, and further comprising: a tubing anchor connected to said tubing.

34. The apparatus recited in claim 28 wherein said pressure isolating member is in sliding relation with the interior wall of said casing.

35. An apparatus for the production of well fluids, including liquids and gases, from an oil well having a casing with perforations formed therethrough for ingress of the well fluids from an oil bearing formation and a pump located above the perforations, and coupled to tubing within the casing for extracting liquids from the oil well, the apparatus comprising: a gas separator coupled to deliver well liquids to an inlet of the pump, said gas separator defining a separation annulus zone between an exterior of said gas separator and an interior wall of the casing adjacent to said gas separator, said gas separator having a fluid inlet at a lower portion thereof and a fluid outlet at an upper portion thereof for transferring well fluids from said gas separator into said separation annulus zone; a tail pipe coupled at an upper end thereof to said gas separator fluid inlet and extending downward in the oil well to receive well fluids in the casing below said gas separator, said tail pipe for transferring well fluids to said gas separator at a reduced pressure gradient and thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase fluid production from the oil well, and a polymeric pressure isolating member having a center opening with a cylindrical surface wall and an outer periphery edge, said center opening having said tail pipe therein and having said cylindrical surface wall joined to an exterior wall of said tail pipe, said outer periphery edge of said isolating member in sliding relation with the interior wall of the casing , and said isolating member providing a pressure seal between said separation annulus zone and a casing annulus below said isolating member.

36. The apparatus of claim 35, and wherein: said polymeric pressure isolating member includes a plurality of coaxial cupped type discs.

37. The apparatus of claim 35, and wherein: said isolating member cylindrical surface wall is a metal sleeve.

38. The apparatus of claim 35, and wherein: said gas separator includes a inner cylindrical barrel and an outer cylindrical barrel which has a greater diameter than said inner cylindrical barrel and defines an upward fluid flow zone therebetween and said gas separator inlet connected to transfer well fluid from said tail pipe into said upward fluid flow zone, said outer barrel having a fluid outlet at an upper region thereof for transferring well fluid from said upward fluid flow zone into said separation annulus zone.

39. The apparatus of claim 35, and further comprising: a tubing anchor connected to said tubing.

40. The apparatus as recited in claim 35 wherein said well has a horizontal portion.

41. An apparatus for the production of well fluids, including liquids and gases, from an oil well having a casing with perforations formed therethrough for ingress of the well fluids from an oil bearing formation and a pump located above the perforations and coupled to tubing within the casing for extracting liquids from the oil well, the apparatus comprising: a gas separator having a fluid inlet for receiving said well fluids to an upper region of said separator for discharge into a separation annulus zone defined between an exterior of said separator and an interior wall of the casing adjacent to said gas separator and a liquid inlet at a lower region of said separator for receiving liquid from said separation annulus zone for transfer upward to an inlet of said pump; a tail pipe coupled at an upper end thereof to said gas separator fluid inlet and extending downward in the oil well to intake well fluids from within the casing below said gas separator, said tail pipe for transferring well fluids to said gas separator at a reduced pressure gradient compared to a larger diameter conduit, and thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase well fluids production from the oil well, and a polymeric pressure isolating member mounted to an exterior surface of said tail pipe below said gas separator to provide a pressure seal in a casing annulus.

42. The apparatus of claim 41 wherein said gas separator having an inner cylindrical barrel and outer cylindrical barrel which has a greater diameter than said inner cylindrical barrel and is positioned coaxial with said inner cylindrical barrel to define an upward well fluid flow zone therebetween, said gas separator having a fluid inlet at a lower end thereof for receiving well fluid into said upward well fluid flow zone, said gas separator having a fluid outlet at an upper region of said outer cylindrical barrel for transferring well fluid from said upward well fluid flow zone into said separation annulus zone defined between the exterior of said outer cylindrical barrel and an interior wall of the casing adjacent to said gas separator, a passage at the lower region of said gas separator from said separation annulus zone through said outer and inner cylindrical barrels to transfer liquid from said separation annulus zone into said inner cylindrical barrel, said inner cylindrical barrel connected at the upper end thereof to the inlet of the pump.

43. The apparatus of claim 41, and wherein: said polymeric pressure isolating member includes a plurality of coaxial cupped type discs.

44. The apparatus of claim 41, and wherein: said polymeric pressure isolating member includes a steel sleeve, which is in contact with the outer surface of said tail pipe.

45. The apparatus of claim 41, and further comprising: a tubing anchor connected to said tubing.

46. A method of producing well fluids, including well liquids and well gases, in an oil and gas well having a casing, with an interior, extending down to an oil and gas formation, wherein the casing has perforations formed therethrough for receiving oil and gas from the formation, and having a pump with a pump inlet supported from a tubing string above the oil and gas formation, the method comprising the steps of: operating the pump, thereby enabling well liquids to flow into the pump inlet, and inducing flow of the well fluids below the pump, including enabling well fluids to flow from the oil and gas formation, through the perforations, and into the casing; inducing the well fluids to flow up a tailpipe from a fluid inlet located proximate the oil and gas formation, the tailpipe having an internal diameter that is less than the diameter of the adjacent casing to thereby reduce a pressure gradient, as compared to a pressure gradient that would exist without use of said tailpipe, of the well fluids therein as a result of the smaller diameter thereof, to thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase well fluid production from the oil and gas well, and separating the well liquids from the well gases by discharging the well fluids from a fluid outlet of a gas separator coupled to an upper end of the tailpipe, and into a separation annulus defined by an exterior of the gas separator and the casing interior, wherein the well gases rise and are separated from the well liquids that fall, entering a liquid inlet of the gas separator, and delivering the separated well liquids from the gas separator into the pump inlet, and isolating the flow of well fluids up the casing from the oil and gas formation by an isolation means disposed to sealably engage the casing at a location below the gas separator liquid inlet.

47. The method of claim 46, and further comprising the step of: sliding the isolating member along the tail pipe, thereby accommodating movement of the tailpipe with respect to the casing.

48. A method of producing well fluids, including well liquids and well gases, in an oil and gas well having a casing, with a casing interior, extending down to an oil and gas formation, and having a pump with a pump inlet supported from a tubing string, wherein the casing has perforations formed therethrough for receiving oil and gas from the formation, the perforations located below the pump inlet, the method comprising the steps of: operating the pump, thereby enabling well liquids to flow into the pump inlet, and inducing flow of the well fluids below the pump, including enabling well fluids to flow from the oil and gas formation, through the perforations, and into the casing; inducing the well fluids to flow up a tailpipe from a fluid inlet located proximate the oil and gas formation, the tailpipe having an internal diameter that is less than a tubing string internal diameter to thereby reduce a pressure gradient, as compared to a pressure gradient that would exist without use of the tailpipe, of the well fluids therein and thereby correspondingly reduce a minimum required producing bottom hole pressure and correspondingly increase well fluid production from the oil and gas formation, as a result of the smaller diameter thereof, and separating the well liquids from the well gases by discharging the well fluids from a fluid outlet of a gas separator coupled to an upper end of the tailpipe, and into a separation annulus defined by the gas separator exterior and the casing interior, wherein the well gases rise and are separated from the well liquids that fall, entering a liquid inlet of the gas separator, and delivering the separated well liquids from the gas separator into the pump inlet, and isolating a flow of well fluids up the casing from the oil and gas formation by an isolation means disposed to sealably engage the casing at a location below the gas separator liquid inlet.

49. The method of claim 48, and further comprising the step of: sliding the isolating member along the tail pipe, thereby accommodating movement of the tailpipe with respect to the casing.

50. The method of claim 48 wherein the step of isolating the flow of well liquids up the casing further comprises isolating the flow of well liquids up the casing by means of a packer connected to said tubing.

51. The method of claim 48 further including the step of restricting movement of said pump by a tubing anchor connected to said tubing and contacting said casing and located proximate said pump.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 is a section view of an oil well with rod pump, gas separator and isolation means according to an illustrative embodiment of the present invention.

(2) FIG. 2 is a partial section of an oil well with a gas separator, check valve, pack-off assembly, and tubing anchor according to an illustrative embodiment of the present invention.

(3) FIGS. 3A and 3B are section view drawings of a gas separator according to an illustrative embodiment of the present invention.

(4) FIGS. 4A and 4B are side view drawings of a gas separator according to an illustrative embodiment of the present invention.

(5) FIGS. 5A and 5B are section views of a gas separator showing fluid flow paths according to an illustrative embodiment of the present invention.

(6) FIG. 6 is a schematic diagram of a downhole pump with a bottom hold down in a well according to an illustrative embodiment of the present invention.

(7) FIG. 7 is a schematic diagram of a downhole pump with a top hold down in a well according to an illustrative embodiment of the present invention.

(8) FIGS. 8A, 8B, and 8C are side view, end view, and section view drawings, respectively, of a seating nipple portion of a gas separator according to an illustrative embodiment of the present invention.

(9) FIGS. 9A and 9B are side view and end view drawings, respectively, of a top collar portion of a gas separator according to an illustrative embodiment of the present invention.

(10) FIGS. 10A, 10B, and 10C are side view, end view, and section view drawings, respectively, of an inlet fitting portion of a gas separator according to an illustrative embodiment of the present invention.

(11) FIGS. 11A, 11B, and 11C are side view, end view, and section view drawings, respectively of a lower outer barrel portion of a gas separator according to an illustrative embodiment of the present invention.

(12) FIG. 12 is a section view drawing along the upper barrel portion of a gas separator according to an illustrative embodiment of the present invention.

(13) FIG. 13 is a section view drawing along the seating nipple portion of a gas separator according to an illustrative embodiment of the present invention.

(14) FIG. 14 is a section view drawing along a flow diverter according to an illustrative embodiment of the present invention.

(15) FIG. 15 is a section view drawing of a flow diverter according to an illustrative embodiment of the present invention.

(16) FIGS. 16A, 16B, and 16C are top view, side view, and section view drawing, respectively, of a flow diverter cup according to an illustrative embodiment of the present invention.

DESCRIPTION OF THE INVENTION

(17) Illustrative embodiments and exemplary applications will now be described with reference to the accompanying drawings to disclose the advantageous teachings of the present invention.

(18) While the present invention is described herein with reference to illustrative embodiments for particular applications, it should be understood that the invention is not limited thereto. Those having ordinary skill in the art and access to the teachings provided herein will recognize additional modifications, applications, and embodiments within the scope hereof and additional fields in which the present invention would be of significant utility.

(19) In considering the detailed embodiments of the present invention, it will be observed that the present invention resides primarily in combinations of steps to accomplish various methods or components to form various apparatus and systems. Accordingly, the apparatus and system components and method steps have been represented where appropriate by conventional symbols in the drawings, showing only those specific details that are pertinent to understanding the present invention so as not to obscure the disclosure with details that will be readily apparent to those of ordinary skill in the art having the benefit of the disclosures contained herein.

(20) In this disclosure, relational terms such as first and second, top and bottom, upper and lower, and the like may be used solely to distinguish one entity or action from another entity or action without necessarily requiring or implying any actual such relationship or order between such entities or actions. The terms “comprises,” “comprising,” or any other variation thereof, are intended to cover a non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements does not include only those elements but may include other elements not expressly listed or inherent to such process, method, article, or apparatus. An element proceeded by “comprises a” does not, without more constraints, preclude the existence of additional identical elements in the process, method, article, or apparatus that comprises the element.

(21) Most downhole liquid and gas separators, also referred to as “gas anchors”, in use in the oil and gas industry employ gravity separation. The flow of well fluids, comprising crude oil, water, and gases, is routed into a vertical orientation where the gas bubbles are allowed to rise upwardly and out of the well liquids. The well liquids are drawn away and then pumped to the surface. In most oil wells, the gas flows out of the well through the well-bore casing, while the liquid is pumped to the surface through a tubing string that is disposed within the casing. As an aid to clarity, in this disclosure, “fluid” is used to describe a blend of both gas and liquids, which may contain crude oil and water, such as the raw well fluids that enter the well casing from the adjacent geologic formation. “Gas” is used to describe that portion of the fluids that comprises little or no liquids, which may include natural gas, carbon dioxide, hydrogen sulfide, and other gases in the case of an oil or gas well. And, “liquid” is used to describe fluids after the removal of a substantial portion of the gas therefrom. It will be appreciated by those skilled in the art that even the most efficient downhole gas separators often times do not remove 100% of the gas from the well liquids. This is due, in part, to the fact that some of the gases are soluble in the liquids such that changes in temperature, pressure, and mechanical agitation, can cause additional gas to escape from solution. The goal of any gas separator is to separate as much free gas from the fluids as possible, which enables the pumping efficient and production rate of the well to increase. Free gas is gas that is not in solution with the liquids. Dissolved gases are actually part of the liquids, and it is generally preferable to avoid dissolution of the dissolved gases.

(22) Gas bubbles rise upwardly in oil or water under the force of gravity, and at a rate of approximately six inches per second. Thus, gas bubbles will be released from a fluid column if the downward liquid velocity is less than six inches per second. Therefore, in order to achieve gas separation by force of gravity, it is necessary to control the flow of well fluids in a separation region such that they move downwardly at a velocity of less than six inches per second. However, the solution to effective gas separation is not simply to move the fluids as slowly as possible because it is also desirable to move as high a volume of liquids out of the well as possible. A liquid column having an area of one square inch travelling at six inches per second is a flow rate of approximately fifty barrels per day. Thus, it is significant to consider the cross sectional area of the separation chamber in a gas separator and pumping volume in determination an optimum gas separator design. In a well bore having a four to six inch internal diameter, the allocation of cross section area for gas separation, liquid pumping, and other fluid routing functions is critical to efficient separator design.

(23) In any gas separator design that employs gravity separation, there is a point in the flow processes where the liquid is drawn out of a separation chamber so that it can be fed to the inlet of the downhole pump, and then be pumped to the surface. The critical location in which it is most desirable to minimize the percentage of gas in the well liquids is in the downhole pump chamber. This is because the requirement to compress the gas portion to the high pump outlet pressure prior to the discharge of liquids from the pump outlet reduces the effective displacement of the pump, and thus directly affects the pump efficiency and maximum well production rate. In prior art gas separator designs, the gas separator is typically located below the downhole pump, and fluids are drawn upwardly through the gas separator to the pump inlet. Considering that the separation chamber portion of the gas separator must be oriented vertically for gravity to act, and that the gas rises while the liquids fall, it is necessary for the liquid portion to be drawn upward through most of the length of the gas separator to the pump inlet. This requires a negative pressure differential, which will naturally draw more gas out of solution, thus exacerbating the separation challenge.

(24) Another aspect of gas separation in an oil and gas well is the location from which the raw well fluids are drawn into the pumping system. Considering a typical oil and gas well casing, there is a depth at which raw fluids from the adjacent formation flow into the well casing. In many wells, the casing is perforated to allow the formation fluids to drain into the casing. In other wells, the fluids may flow into the casing through an opening at the bottom of the casing. These raw well fluids contain liquids and gases. The gases naturally rise in a static well, and the liquids naturally fall. Once a well stabilizes, during times when there is no fluid removal by production operations, then a static formation pressure will stabilizes, and a static liquid level within the casing will also stabilize. The static liquid level is referred to as the gas-liquid interface. In fact, the height of the liquid column from the gas-liquid interface to the formation perforations is determined by the static pressure at the formation. It will be readily appreciated that the pumping system must draw the well fluids in at a location below the static liquid level. However, it should be further noted that once pumping commences, the static liquid level will fall, depending on the rate liquids are pumped out of the well and the rate at which the formation can naturally drain well fluids into the casing. Also, once pumping commences, the movement of fluids out of the perforations and up to the pumping system suction inlet presents a dynamic fluid environment with turbulence and pressure gradients that generally become lower as fluids move upward. These are contributing factors in the dissolution of soluble gases from the well fluids.

(25) With respect to the present invention, the pumping system comprises at least a pump and a gas separator that is located ahead of the pump inlet in the fluid flow path. Therefore, the inlet to the pumping and separation system may be the fluid inlet to the gas separator. However, the separator may employ either a drawtube or a tail pipe that reaches further downward into the well, and which establishes the location of the pumping system suction inlet. This is significant because it enables engineers and operators to decide about the location of the system inlet with respect to the formation, the static and dynamic gas-liquid interface, and other well production parameters.

(26) In the case where the pumping system inlet is located below the point at which raw well fluids enter the case, and there is adequate flow area, gas can rise upwardly through the annulus between the casing and the tubing, and almost none of the gas will enter the pumping system as long as the downward liquid velocity in the annulus doesn't exceed six inches per second. Thus, the primary concerns about gases are the dissolution by pressure changes and agitation within the pumping system. In the case where the pumping system inlet must be set at a high location due to operating constraints or in the case of horizontal wells where the pump generally is set shallower than the horizontal section, then gas separator installed ahead of the pump is preferred in order to eliminate the majority of the gas in the fluid before it reaches the pump intake. The disadvantage of using a gas separator is that it can only handle limited gas and liquid rates since all of the flow paths and channels have to fit inside the wellbore and consequently their dimensions and corresponding flow areas have to be smaller than those provided by the full casing annulus.

(27) The present invention advantageously utilizes an annulus between the inside surface of the well casing and an outer barrel of the gas separator apparatus, referred to as the separation annulus, to yield the largest practicable sectional area as a separation chamber while still providing other fluid conduit requirements within the gas separator structure. In order to control the flow of fluids, liquids, and gas within the separation annulus, there must be an isolation means disposed within the well bore casing so that the separation annulus is not continuous with the casing that located below the gas separator. This device is referred to herein as an isolation means, which can be implement in several embodiments, including, but not limited to, a pack-off assembly and a flow diverter. Were there no isolation means, the gases from the raw well fluids would rise into the separation annulus and make it impractical to draw the liquid portion into the pumping system.

(28) With respect to oil and gas well pumps, there are a wide variety known to those skilled in the art. The primary pumping mechanisms in use today are the reciprocating chamber pump, the progressive cavity pump, the electrical-submersible pump, and the jet-fluid pump. The reciprocating pump is used in the majority of wells that employ artificial lift. A typical reciprocating pump includes a stationary assembly and a traveling assembly. There is a pump inlet at the lower end of the stationary assembly, which is coupled to a standing valve located at the lower end of a pumping chamber. The traveling assembly reciprocates within a pump barrel portion of the stationary assembly, which has a travelling valve hear its upper end. The two valves are check valves, which cooperate to draw well liquids into the pumping chamber and discharge them through the top of the pump assembly on successive strokes of the reciprocating drive. The top of the pump assembly discharges into a tubing string that connects to a surface well head. Thus the pump draws in fluids at the bottom and pumps them to the surface.

(29) An important consideration in the process of drilling, operating, and maintaining an oil and gas well, is how the equipment is inserted into the well casing, how it is operated, and how it is serviced from time to time. Assuming the well has been drilled and a steel casing has been cemented in place and that the casing has been perforated in the region of the oil producing geologic formation, the remaining system components can be install and operated. A tubing string is run down the casing, and connects to the pump, which is coupled to a gas separator, and any other flow devices associated with the pumping system. A sucker rod is run down the inside of the tubing string, and connects to the travelling assembly of the pump. Since the perforations in many wells are located several thousand feet below the surface level, it can be appreciated that running the tubing string and sucker rod down the well and removing them are considerably expensive service tasks. The tubing string task is a substantially larger task than the sucker rod task. Thus, engineers and suppliers, as well as the API (American Petroleum Institute), have designed pump configurations to address these service issues. For example, there are tubing pumps that are run down with the tubing string and rod insert pumps that are run down with the sucker rod. In the case of a rod insert pump, a seating nipple is run down with the tubing string, and the pump has a seating assembly, which engages the seating nipple when the pump is run down with the sucker rod string. Regardless of which type pump is used, the stationary assembly must be anchored to the tubing string and the travelling assembly reciprocated with the sucker rod. Since it is easier and less expensive to service the sucker rod, as compared to the tubing string, it isn't surprising that rod insert pumps are in common use.

(30) In the case of the tubing pump, the pump's stationary assembly is run down with the tubing string and the pump's travelling assembly is run down with the sucker rod. In the case of a rod insert pump, both the stationary assembly and the travelling assembly are run down with the sucker rod. However, since the stationary assembly must be anchored to the tubing string, designers have incorporated an anchoring assembly with two components. These are referred to as a seating assembly, which is fixed to the pump's stationary assembly, and a seating nipple, which is fixed to the tubing string. Thus, the seating nipple is run down with the tubing string. The API has promulgated standards for the seating assemblies and seating nipples. There are two dominant types, mechanical and cup-type, which may be located at either the top of the pump or the bottom of the pump. The rod insert pumps are therefore referred to as top anchored and bottom anchored, respectively. In operation, a drive mechanism at the surface level drives the traveling portion of the downhole pump through the sucker rod. The surface drive unit is referred to as a pump jack, as are well known in the art. While there are a range of manufacturer and standardized designs for downhole pumps, the American Petroleum Institute (API), does promulgate certain pump standards, which conform to physical sizes and capacities, and to materials, interfaces and connections. A number of pump manufacturers adhere to the API pump specifications. In fact, alphanumerical pump designations include specifications for the tubing size, the pump barrel bore diameter, whether it is a rod or tubing pump, the seating assembly location, the seating assembly type, as well as the barrel length, plunger travel, and overall pump length.

(31) In the case where an engineer selects a rod insert pump for a given well, the operator specifies the pump and seating nipple. The seating nipple is run down with the tubing string, and then the pump is run down with the sucker rod to engage the seating assembly with the seating nipple. In the case of a bottom seated pump, the pump inlet is generally at the lowest end of the seating assembly, with the standing valve of the pump directly above. In the case of the top seated pump, the lower end of the pump barrel has the pump inlet, with the standing valve immediately above. The illustrative embodiment highlighted in this disclosure is a bottom anchor design with a cup type seating assembly and seating nipple, which adhere to on of the API promulgated standards. Of course, all of the top and bottom seated pumps with both cup type and mechanical hold downs are applicable under the teachings of the present invention.

(32) Reference is now directed to FIG. 1, which is a section view of an oil well 2 with rod insert pump 8, gas separator 12 and isolation means 16 according to an illustrative embodiment of the present invention. The well 2 is a conventional subterranean bore hole well with a steel casing 4 extending down to an oil and gas bearing geologic formation 18. A gas separator 12 is coupled to a conventional tubing string 6, which is used as the conduit through which oil is pumped out of the well. The gas separator 12 includes a specific seating nipple 14, which receives a seating assembly on the pump 8. In this embodiment, a rod insert pump 8 is employed. The pump 8 is coupled to and driven by a conventional sucker rod 10. The isolation means 16, which is a disc type flow diverter in this embodiment, is coupled to the lower end of the gas separator. The isolation means 16 serves to isolate the casing below the gas separator 12 from the annulus formed between the gas separator 12 and the interior of the casing 4, which is referred to as the separation annulus. This arrangement enables that annulus to serve as the separation chamber of the gas separation process. The design is advantageous in that the full annular area between the casing 4 and the gas separator barrel 12 is utilized to provide a relatively large cross sectional area of the separation chamber, thereby minimizing the downward velocity of the liquid. In addition, the separated liquid is very directly routed to the inlet of the pump 8 so as to minimize pressure losses due to flow through longer and more restricted passages in prior art separator designs. The separated gases rise upwardly in the casing 4 to the well head 22, where they are removed. Section lines A, B, and C will be more fully described with reference to FIGS. 12, 13, and 14, respectively.

(33) The illustrative embodiment of FIG. 1 provides a number of design and operation features and benefits. The integral pump seating nipple 14 is located at the bottom of the gas separator 12 so that the pump inlet is adjacent to the liquid accumulated in the casing to separator annulus. The gas separator 12 is built using inner and outer barrels which are concentric, and the outside diameter the separator 12 is nearly identical to the outside diameter of the of the couplers used with the tubing string 6. The isolation means 16, which may be a pack-off assembly or diverter cups, is located at the bottom of the gas separator, and may further employ a tubing anchor or tubing catcher, as are known to those skilled in the art. The gas separator design can be used with a conventional pack-off assembly or a flow diverter consisting of elastomeric discs on a draw tube positioned below the well fluid inlet of the gas separator. The pressure drop across the separator is generally less than 10 psi so flexible elastomeric rings can be used instead of a high pressure pack-off assembly where otherwise appropriate. The gas separator includes a single fluid outlet (not shown in this drawing) at the top of the gas separator so that fluid flow impinges on the casing wall, thereby spreading the liquid into a film with circular downwards motion to facilitate gas-liquid separation. The gas separator includes a means for attaching a tail pipe to the bottom of the assembly of adequate length and diameter to minimize any multi-phase flow gradient between the separator and the producing formation.

(34) With respect to the isolation means 16 in FIG. 1, all of the formation fluids must be directed into the bottom of the gas separator 12 to pass through the gas separator and be discharged out of the top of the gas separator. Then the discharged liquid in the casing annulus falls to the pump inlet and the gas flows upward in the casing 4. The flow can be directed into the gas separator using a conventional pack-off assembly, a set of flow diverter cups (shown in FIG. 1), or may include a pack-off assembly with a tail pipe. The pack-off assembly can withstands very high differential pressures, into the thousands of PSI. The diverter cup assembly is appropriate where differential pressures are much lower. The use of a tail pipe allows the formation fluids to be drawn from locations much deeper than the location of the gas separator. In some applications, that may be thousands of feet deeper. It is also useful to add check valve below the inlet of the gas separator. This is useful where a tail pipe is employed to prevent the fluids in the tail pipe from falling back down the well. The check valve is also useful in the case where a well produces slugs of fluids and gas, so that the check valve holds the fluids in the separator for subsequent pumping out of the well. The check valve is also useful to hold liquids above the check valve. For example, at the time a flow diverter is run down the well casing, water may be added to lubricated the diverter cups as the travel down the casing, thereby minimizing friction heat build up and possible damage to the diverter cups.

(35) Reference is directed to FIG. 2, which is a partial section view of an oil well with a gas separator 30, check valve 33, pack-off assembly 35, tubing anchor 38, and tail pipe 40 according to an illustrative embodiment of the present invention. This embodiment is suitable for deeper wells where the formation fluids are drawn from a deeper depth and where a high pressure differential exist above and below the isolation means. The well casing 24 is illustrated with a tubing string 28 having a sucker rod 26 disposed therein. The gas separator 30 exterior is illustrated, and it is to be understood that a sucker rod pump is disposed within the gas separator 30. A tubing connector 32 connects the fluid inlet of the separator 30 to a check valve 33, which is oriented to allow upward flow fluid flow only. Another tubing connector 34 connects the check valve 33 to a conventional pack-off assembly 35, as are known to those skilled in the art. The pack-off assembly 35 is run down with the tubing string, and is then expanded to sealably engage the interior wall of the well casing, thereby isolating the casing fluids above and below the pack-off assembly 35, which can withstand several thousand PSI pressure differentials. Thus, formation fluids can only pass upward through the central passage of the pack-off assembly 55, and into the check valve 33. In this embodiment, a tubing anchor with centralizer arms 38 is also attached to the pack-off assembly 35 using a tubing connector 36. The tubing anchor 38 is also run down with the tubing string, and once located, is expanded to mechanically engage the interior of the casing 24. The tubing anchor is load bearing, and fixedly locates the equipment at the position where it is engaged. This prevents vertical movement of the assembly during operation. The bore centralizer arms position the tubing anchor 38 near the geometric center of the casing 24, as is understood by those skilled in the art. Finally, a tail pipe 40 is connected to the tubing anchor 38, and extends downward to a depth where the designer wants the raw well fluids to enter the pumping system. This is one example of the anchor and tail pipe assembly, and it will be appreciated by those skilled that the art that other configurations are known, and would be selected based on well performance requirements.

(36) With regards to embodiments similar to that illustrated in FIG. 2, the objective of a pack-off assembly type isolation means is to reproduce as closely as possible the flow characteristics that could be achieved if the pump intake were located below the bottom of the perforations, which enables the system to draw in fluids that contain a lesser percentage of gas. It is know in the art of oil and gas wells to employ a pack-off assembly (commonly referred to as a “packer”) with a tubing anchor, which is used to rigidly fix the well's tubing string to the well casing at the location of the packer, and which may be deep in the well, and even at the location of a downhole pump. There are a number of technical reasons why it may be desirable to install a packer, but they are beyond the scope of this disclosure. While a packer may isolate the fluids below it from the fluids above it, the essential problems with using a packer as a casing flow isolation means is that the packer constricts movement of the tubing string along the vertical axis of the well. In fact, some tubing anchors incorporate a pack-off assembly. At any rate, the constriction must be addressed elsewhere in the well design, such as allowing the tubing string at the surface to move, or by adding tension to the tubing string at some point on its length. Otherwise, the expansion and contraction, and the forces of pump operation and fluid movement would cause undue stresses and buckling to occur. In addition, the installation and removal of a packer from a well requires a specialized process of inserting the packer unit, and then expanding it to engage the interior wall of the case, and the converse to remove it. There are many wells in operation, and many more that will be built in the future, where the use of a packer is simply not desirable. The use of a slidable flow diverter as taught in the present disclosure enables such wells to utilize the efficient gas separator of the present invention. Flow diverter type isolation means will be more fully discussed hereinafter.

(37) Packer type separators have been in use for many years. Conventional wisdom considered that their application should be limited to wells where production of solids is minimal in order to reduce the potential of mechanical problems when the tubing needs to be retrieved. This concern was taken into account in the design of the present disclosure through use of an optimized separator design by minimizing the distance between the top of the packing element and the pump inlet so that the volume of solids that may settle in this part of the annulus is relatively small. In addition by locating the pump seating nipple in the immediate vicinity of the top of the packing element, it reduces the volume of solids that may accumulate inside the separator cavity.

(38) With respect to the tail pipe 40 in FIG. 2, and its applicability, the tail pipe can reduce the gradient of fluids below a pump, where the pump is set above the formation. The tail pipe can increase the production rate of a well in most situations where the pump is set above the formation. Also, the tail pipe is can be used with a packer-type isolation means. It has been determined that tail pipes with a smaller tube size reduces the pressure gradients of the gas/oil/water mixtures. In general, when the pump is set above the formation a considerable distance, the pressure drop will be less between the formation and the pump if tail pipe is used. Thus for any pump inlet pressure, such as 100 psi, which is common, the pressures at various depths below the pump are less and allow the operator to determine the PBHP (Producing Bottom Hole Pressure) and thus the producing rate efficiency of the well when the SBHP (Static Bottom Hole Pressure) is known. The tail pipe with packer configuration is very effective and will increase production in a well when the pump is set a considerable distance above the formation. The tail pipe reduces the pressure required to push the formation fluids to the pump so a lower PBHP exists. Field tests of separator performance indicate that better performance is obtained from downhole separators if the tubing anchor is located below the separator instead of above the separator.

(39) Reference is directed to FIGS. 3A and 3A, which are section view drawings of a gas separator 12 according to an illustrative embodiment of the present invention. These Figures correspond to the gas separator 12 in FIG. 1, and these FIGS. 3A and 3B show section views that are oriented ninety degrees apart to more clearly show the internal structure. The upper end of the separator 12 is a top collar 44, which is threaded to engage the standard pipe thread size for the tubing string that is applicable. Generally, the separator 12 is approximately the same diameter as the tubing string. There is an inner barrel 58 and an outer barrel 46 that are both sealably connected to the top collar 44. In the illustrative embodiment, they are welded together. The annulus between the inner barrel 58 and the outer barrel 46 is referred to as the well fluid annulus 47 because it is used as a passage through which the well fluids travel to exit the well fluid outlet 48. A single well fluid outlet 48 is illustrated, however, plural outlets can be used. The outlet 48 is adjacent the upper end of the outer barrel 46, which naturally provides a long path on the exterior of the outer barrel 46 for the separation annulus with the well casing (not shown).

(40) The inner barrel 58 is sealably connected to the top of a seating nipple 14, which is compliant with a predetermined API specification. In this embodiment, it is a type RHB bottom anchored cup type seating pump. The pump is not shown in FIGS. 3A and 3B. The inner barrel 58 is welded to the seating nipple 14 in the illustrative embodiment. At the bottom end of the separator 12, there is an inlet fitting 52, which is threaded to suit the tubing string fitting sizes, in a similar fashion to the top collar 44. The well fluids enter the separator 12 through the inlet fitting 52, and enter the aforementioned well fluid annulus 47, then travel upwardly to eventually exit through the well fluid outlet 48. To complete the well fluid annulus, the outer barrel 46 must extend down to the inlet fitting 52. However, in this embodiment a slightly larger diameter lower outer barrel 50 is employed, which also improves manufacturability. These two outer barrel components are sealably coupled at both ends to perfect the sealed well fluid annulus 47. The purpose of the larger diameter lower outer barrel 50 is to provide adequate cross sectional area of the well fluid annulus in the area of the seating nipple 14, particularly where the well liquid passage 54 is located.

(41) The well liquid passage 54 is a pare of holes formed through the lower outer barrel 50, and through the inlet fitting 52, and through the sides of the seating nipple 14, which provides a pathway for the well liquids that have separated in the separation annulus (not shown) to flow into the interior passage at the bottom of the seating nipple 14, and thereby enter the inlet of the pump (not shown). Note that the diameters of the lower outer barrel 50, the inlet fitting 52, and the seating nipple 14 are selected for a sealed fit, which isolates the well fluid annulus 47 from the well liquid passage 54. The lower end of the seating nipple 14 is closed with a tapered plug 60, which serves to direct well fluid flow from the inlet fitting 52 into the well fluid annulus 47. These flow arrangements will be more fully discussed hereinafter.

(42) Reference is directed to FIGS. 4A and 4B, which are side view drawings of a gas separator 12 according to an illustrative embodiment of the present invention. These figures are consistent with the embodiment shown in FIGS. 1, 3A, and 3B. FIGS. 4A and 4B are exterior views, looking at ninety degree views from one another. At the lower end of the separator 12 is the inlet fitting 52, which is joined to the top collar 44 by the lower outer barrel 50 and the upper outer barrel 46. The well liquid passage 54 is located on the exterior of the lower outer barrel 50. The well fluid outlet 48 is located at the upper end of the upper outer barrel 46. The distance between the well fluid outlet 48 and the well liquid inlet defines the length of the separation annulus with the well casing (not shown). In the illustrative embodiment, the upper outer barrel is ninety-four inches, the top collar is four inches, the lower outer barrel is six inches, and the inlet fitting is four inches, totaling approximately one hundred eight inches.

(43) Reference is directed to FIGS. 5A and 5B, which are section views of a gas separator showing fluid flow paths according to an illustrative embodiment of the present invention. Again, the section views are taken at ninety degrees from one another to more clearly show the internal details. FIGS. 5A and 5B also comport with the illustrative embodiment of the FIGS. 1, 3A, 3B, 4A, and 4B. However, FIGS. 5A and 5B also incorporate a well casing 4, a tubing string 4, a pump 8 with seating assembly 66, a draw tube 72, and an isolation means 16. In these figures well liquid is illustrated with directional arrows and well gas with small bubbles. Note that the isolation means 16 isolates the separation annulus 57 from the open casing below the isolation means 16. Therefore, all of the well fluids that enter the pumping system must enter through the draw tube 72 and enter the inlet fitting 52 of the gas separator 12. As the well fluids enter the inlet fitting 52, they are routed into the well fluid annulus 47 and travel upwardly to exit the well fluid outlet 48. Also note that the motive force for the fluid movement is created by the suction pressure at the inlet of the pump 8, which is located at the bottom of the seating assembly 66. The seating assembly 66 is engaged with the seating nipple 14 portion of the gas separator 12.

(44) As the well fluids exit the well fluid outlet 48 and enter the separation annulus 57, the cross sectional area increases and the fluid movement slows to a velocity of less than six inches per second. Gravity acts on the well fluid so that the gas bubble rise upwardly within the casing annulus while the liquid portion settles downwardly through the separation annulus 57 toward the well liquid inlet 54. The well liquids enter the well liquid passage and move into the pump inlet within a matter of a few inches of travel. This short distance and relatively minimal pressure differential are beneficial in preventing additional gases from being released from the liquid, and thereby diminishing the pump 8 efficiency. This is possible due to the design feature of incorporating the seating nipple 14 as a part of the gas separator 12, and also by accommodating a substantial portion of the pump 8 body and barrel within the gas separator 12. If the pump seating nipple were positioned above the gas separator well fluid outlet ports, a pressure drop in the liquids entering the pump would occur and gas would be released into the pump chamber. Additionally, if the well liquid passages were restrictive to flow, an excessive pressure drop occurs because of the high velocities associated with the pump plunger upward movement, which often approaches 80-100 inches per second on high pump capacity wells. Additionally, the standing valve of the pump 8 is located directly above the seating assembly portion 66. This results in a well liquid travel distance of approximately twelve to thirteen inches, at most, which is substantially less then in prior art systems where the entire gas separator was located below the pump inlet. Thus it can be appreciated that the features of the illustrative embodiment substantially improve pumping efficiency.

(45) Reference is directed to FIG. 6, which is a schematic diagram of a downhole pump 94 with a bottom hold down in a well according to an illustrative embodiment of the present invention. This figure is generally consistent with an API type RHB pump operating in an oil and gas well. The well casing 90 has a tubing string 92 disposed therein. The gas separator comprises an outer barrel 100 that is sealably coupled to the tubing string 92 it its upper end. The lower end of the outer barrel 100 extends downwardly to a point below an isolation means 108, and this presents the well fluid inlet 109 for the pumping system. An inner barrel 98 is disposed within the outer barrel 100. The inner barrel is also sealably coupled to the tubing string 92 at its upper end. Alternatively, it may be sealably coupled to the outer barrel 100. The lower end of the inner barrel 98 is sealably coupled to a seating nipple 104, which is also compliant with an API type RHB pump. The seating nipple 104 has a well liquid inlet passage 106 that couples to the exterior of the outer barrel 100, and this provides a conduit for well liquids to flow into the seating nipple 104, and into the inlet of a pump 94 though its seating assembly 96. The seating assembly 96 of the pump 94 engages the seating nipple 104, thereby locating and retaining the pump 94. The arrangement of these components defines a well fluid annulus 103 between the inner barrel 98 and the outer barrel 100, and also defines a separation annulus 99 between the outer barrel 100 and the casing 90.

(46) FIG. 6 illustrates the well fluid and well liquid movement using solid lines with arrowheads, and illustrates separated gases using dashed lines with arrowheads. Well fluids enter the well fluid inlet 109 at the bottom of the outer barrel 100, and flow upwardly through the well fluid annulus 103. The well fluids exit a well fluid outlet 102 formed through the outer barrel 100 at it upper end, and into the separation annulus 99. Gravity then acts upon the well fluids such that the gases rise into the casing annulus 91 and exit the well therethrough. The well liquids fall through the separation annulus 99 and enter the well liquid passage 106 to enter the seating nipple 104 to the inlet of the downhole pump 94 through the lower end of the seating assembly 96. The pump 94 pumps the well liquids up through the tubing string 92.

(47) Reference is directed to FIG. 7, which is a downhole pump 114 with a top hold down in a well according to an illustrative embodiment of the present invention. This figure is generally consistent with an API type RHA pump operating in an oil and gas well. The well casing 110 has a tubing string 112 disposed therein. The gas separator comprises an outer barrel 124 that is sealably coupled to a seating nipple 120 at its upper end. The seating nipple 102 is, in turn, sealably coupled to the tubing string 112. The lower end of the outer barrel 124 extends downwardly to a point below an isolation means 130, and thus presents the well fluid inlet 132 for the pumping system. An inner barrel 122 is disposed within the outer barrel 124. The inner barrel is also sealably coupled to the seating nipple 120 at its upper end. The lower end of the inner barrel 122 sealably encloses the lower end of pump 114, which presents the pump inlet 108 within the inner barrel 124. The seating nipple 120 is also compliant with an API type RHA pump. The lower end of the inner barrel 122 has a well liquid inlet passage 128 that couples to the exterior of the outer barrel 124, and this provides a conduit for well liquids to flow into the inner barrel 124, and into the inlet 108 of a pump 114. A seating assembly 116 at the upper end of the pump 114 engages the seating nipple 120, thereby locating and retaining the pump 114. The arrangement of these components defines a well fluid annulus 125 between the inner barrel 122 and the outer barrel 124, and also defines a separation annulus 127 between the outer barrel 124 and the casing 110.

(48) The length of the inner barrel 122 and outer barrel 124 can be adapted to the specific length of the pump 114 by employing a coupling along their length so that two sections are used, and the length of the additional section is selected specific to the length of the pump. FIG. 7 further illustrates the well fluid and well liquid movement using solid lines with arrowheads, and illustrates separated gases using dashed lines with arrowheads. Well fluids enter the well fluid inlet 132 at the bottom of the outer barrel 124, and flow upwardly through the well fluid annulus 125. The well fluids exit a well fluid outlet 126 formed through the outer barrel 124 at it upper end, and into the separation annulus 127. Gravity then acts upon the well fluids such that the gases rise into the casing annulus 113 and exit the well therethrough. The will liquids fall through the separation annulus 127 and enter the well liquid passage 128 to enter the pump inlet 108 of the downhole pump 114. The pump 114 pumps the well liquids up through the tubing string 112.

(49) Reference is directed to FIGS. 8A, 8B, and 8C, which are side view, end view, and section view drawings, respectively of a seating nipple portion 14 of a gas separator according to an illustrative embodiment of the present invention. These figures are consistent with the illustrative embodiments of FIGS. 1, 3, 4, and 5. In the illustrative embodiment, the seating nipple 14 is fabricated from carbon steel, however many other alloys could be used, as will be appreciated by those skilled in the art. The seating nipple body 140 is generally cylindrical with a central bore 142 formed therethrough. A receiving portion 146 of the central bore is further formed at the upper end. The specific dimensions of the central bore 142 and receiving portion 146 follow the API seating nipple specification for the pump seating assembly intended for coupling thereto. These specifications are known to those skilled in the art. A pair of well liquid passage ports 54 are formed through the side walls of the seating nipple 14 at its lower end. The lower end of the seating nipple 14 central bore 142 is closed with a suitable plug 60, which is welded in place. Two flats 144 are formed on the outer surface of the seating nipple body 14 at is lower end, and are located at ninety degrees with respect to the well liquid passages 54. The flats 144 are provided to increase the flow area of the well fluid annulus in the area of the well fluid passages 54. The requirement for and size of the flats is determined by the flow rates and dimensions of the components in the gas separator, as will be appreciated by those skilled in the art. The flats also cooperate with upper extensions on the inlet fitting, as will be more fully discussed with respect to FIGS. 10A, 10B, and 10C.

(50) Reference is directed to FIGS. 9A and 9B, which are side view and end view drawings, respectively, of a top collar portion 44 of a gas separator according to an illustrative embodiment of the present invention. These figures are consistent with the illustrative embodiments of FIGS. 1, 3, 4, and 5. In the illustrative embodiment, the top collar is fabricated from type 316 stainless steel. The top collar 44 is threaded 152 according to the standard pipe thread requirement for the size of tubing string employed in the well. The lower end of the top collar is recessed 154 to receive the outer barrel (not shown), so as to provide a smooth exterior surface of the assembled gas separator. The inner barrel (not shown) slides into the interior of the top collar 44, and is welded in place.

(51) Reference is directed to FIGS. 10A, 10B, and 10C, which are side view, end view, and section view drawings, respectively, of an inlet fitting portion 52 of a gas separator according to an illustrative embodiment of the present invention. These figures are consistent with the illustrative embodiments of FIGS. 1, 3, 4, and 5. In the illustrative embodiment, the inlet fitting 52 is fabricated from type 316 stainless steel. The lower end 156 of the inlet fitting 52 is threaded 158 according to the thread specification of the target well tubing string size. The upper end of the inlet fitting 54 comprises two extensions 160, which each have a well liquid passage 54 formed therethrough. When the gas separator is assembled, the extensions fill the annular space between the seating nipple and the lower outer barrel to enable the well liquid passage 54 to sealably connect the separation annulus through to the interior of the seating nipple. The area between the extensions 166 provides the passageway from the inlet to the well fluid annulus.

(52) Reference is directed to FIGS. 11A, 11B, and 11C, which are side view, end view, and section view drawings, respectively of a lower outer barrel portion 50 of a gas separator according to an illustrative embodiment of the present invention. These figures are consistent with the illustrative embodiments of FIGS. 1, 3, 4, and 5. The lower outer barrel 50 is also fabricated from type 316 stainless steel. The inside diameter of the lower outer barrel 50 is the same dimension as the outside diameter of the upper outer barrel. When assembled, the lower outer barrel 50 slips over the upper outer barrel and is welded in place. A pair of well liquid passages 54 are formed through the lower outer barrel 50, and when assembled align with the passages formed in the inlet fitting and seating nipple.

(53) Reference is directed to FIG. 12, which is a section view drawing along the upper barrel portion of a gas separator according to an illustrative embodiment of the present invention. This figure is consistent with the illustrative embodiments of FIGS. 1, 3, 4, and 5, and is referenced as “Section A” in FIG. 1. FIG. 12 shows the well casing 4, the upper outer barrel 96, the inner barrel 58, and the pump 8. The well fluid annulus 47 is located between the inner barrel 58 and the upper outer barrel 96. The separation annulus 57 is located between the upper outer barrel 96 and the casing 4.

(54) Reference is directed to FIG. 13, which is a section view drawing along the seating nipple portion of a gas separator according to an illustrative embodiment of the present invention. This figure is consistent with the illustrative embodiments of FIGS. 1, 3, 4, and 5, and is referenced as “Section B” if FIG. 1. FIG. 13 shows the well casing 4, the lower outer barrel 50, the seating nipple 56, and the pump seating assembly 66. Note that the seating nipple 56 includes the two machined flats 144, which provide extra flow clearance in the well fluid annulus 47. In addition, the separation annulus is located between the casing 4 and the lower outer barrel 50.

(55) Reference is directed to FIG. 14, which is a section view drawing along a flow diverter according to an illustrative embodiment of the present invention. This figure is consistent with the illustrative embodiments of FIGS. 1, 3, 4, and 5, and is referenced as “Section C” in FIG. 1. In FIG. 14, the casing 4 is illustrated as well as the inlet draw tube 72. A diverter disc 78 is visible. The diverter disc assembly will be more fully described hereinafter.

(56) Reference is directed to FIG. 15, which is a section view drawing of a flow diverter assembly 16 according to an illustrative embodiment of the present invention. This figure is consistent with FIG. 1. The flow diverter 16 in FIG. 15 is one embodiment of an isolation means of the present invention. The assembly consists of a draw tube 72 which has a first threaded coupler 74 at its upper end and second threaded coupler 76 at its lower end. The thread size is selected to match the thread standard for the tubing string employed in the target well. Along the length of the draw tube 72 are plural diverter discs 78, which slidably engage the draw tube 72. The discs' 78 outer portion is an elastomeric disc that may be cupped in shape, and which is sized to slidably engage the well casing of the target well. The diverter assembly 16 is run down the well with the gas separator and tubing string, and thus the discs 78 slide along the inner surface of the well casing. Wear and heat build-up are addressed by pouring water down the casing, and above the flow diverter assembly 16 as it is run down the well.

(57) Reference is directed to FIGS. 16A, 16B, and 16C, which are top view, side view, and section view drawing, respectively, of a cupped type flow diverter disc 78 according to an illustrative embodiment of the present invention. The diverter disc 78 is molded from a polymeric material that is suitable for use with crude oil and well gases and has strength, flexibility, and abrasion resistance, such as polyethylene, acetal, fluoropolymers or fluoroethelenes. The outer rim 82 of the disc is rounded to facilitate sliding movement along the interior surface of the well casing (not shown). The disc is cupped and tapers along its upper and lower surfaces, and increases in thickness towards it interior so there is adequate area to support an embedded stainless steel sleeve 80. The sleeve 80 engages and supports the disc 60 to the draw tube (not shown).

(58) Thus, the present invention has been described herein with reference to a particular embodiment for a particular application. Those having ordinary skill in the art and access to the present teachings will recognize additional modifications, applications and embodiments within the scope thereof.

(59) It is therefore intended by the appended claims to cover any and all such applications, modifications and embodiments within the scope of the present invention.