BACKGROUND OF THE INVENTION
One type of well pump, known as a progressing cavity pump, has a stator that comprises a tubular housing with an elastomeric liner in its interior. The liner has a central passage through it with helical cavities. A rotor extends through the stator, the rotor being of rigid material such as metal and having a helical exterior. When the rotor is rotated, fluid is forced through the passage in the stator and up the well.
In one type of system, the rotor is driven by a string of rods that extends upward to a drive head at the surface that rotates the rods. The string of rods extends within a production tubing that is coupled to the stator for conveying the produced fluid up the well. Normally, the stator is secured to the lower end of the tubing and installed when running the tubing. The rotor is then secured to the lower end of the string of rods and lowered into engagement with the stator.
While these systems work well, the flow area up the tubing is reduced by the rods. The diameter of the tubing is limited by the size of the casing. In some wells, the casing size results in tubing that has a smaller flow area than desired because of the restriction created by the rods.
Further, the installation of a rod-driven progressing cavity pump system requires two trips. First the operator runs the string of tubing with the stator on the lower end, then runs the string of rods with the rotor on the lower end. Reducing the amount of time to install a progressing cavity well pump would save on the installation cost.
SUMMARY OF THE INVENTION
In the pumping system of this invention, drive rods are not required and the progressing cavity pump can be installed in a single trip. Instead of drive rods, the string of tubing is rotatably driven. The stator of the progressing cavity pump is in operative engagement with the tubing for rotation therewith and relative to the rotor for pumping well fluid up the tubing.
An anchor mechanism is in operative engagement with the rotor and the casing for preventing rotation of the rotor as the stator rotates. Preferably the stator communicates with the interior of the tubing for pumping the well fluid through the tubing to the surface. A flexible joint extends between the lower end of the rotor and the anchor. Preferably the tubing, stator, rotor, flexible joint, and anchor are made up in an assembly that is installed and retrieved from the well simultaneously.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic sectional view illustrating a well pumping system in accordance with this invention.
FIGS. 2A-2C comprise a sectional view of a portion of the system of FIG. 1, and showing the stator in a lower position relative to the rotor.
FIGS. 3A-3C comprise a sectional view of the system as shown in FIGS. 2A-2C, but showing the pump assembly in an operational position.
FIGS. 4A-4C comprise a sectional view similar to FIGS. 2A-2C, and showing the pump assembly with the stator in an upper position relative to the rotor.
DETAILED DESCRIPTION OF THE INVENTION
Referring to FIG. 1, a well has a casing 11 cemented in place. A string of tubing 13 is shown suspended within casing 11. Tubing 13 may comprise conventional well production tubing made up of separate joints of pipe secured together by threads. Alternately, tubing 13 may comprise a single section of continuous coiled tubing. The term “tubing” as used herein means any type of conduit, including rods that are hollow.
A stator 15 of a conventional progressing cavity pump 17 is secured to the lower end of tubing 13. Stator 15 has a tubular housing, normally of metal, with an elastomeric liner 19 within the interior. Liner 19 has a helical inner passage 21. A rotor 23 is located within passage 21 of stator 15. Rotor 23 is normally metal and has a helical exterior 25. When relative rotation occurs between rotor 23 and stator 15, fluid will be pumped up tubing 13.
Tubing 13 extends to a wellhead assembly 27 and is rotated during operation of progressing cavity pump 17. A set of bearings and seals 29 seals between wellhead 27 and the exterior of tubing 13. A drive source 31, which comprises an electrical motor and a bearing box, is coupled to tubing 13 to rotate tubing 13. Drive source 31 may be generally of the same type as used in the prior art to rotate drive rods. A manifold 33 is located at the upper end of tubing 13 for receiving well fluid flowing upward from pump 17. Manifold 33 is stationary and has bearings and seals 35 that enable relative rotation between manifold 33 and tubing 13. Manifold 33 has an outlet conduit 37 that leads to a facility for further processing of the well fluid.
Stator 15 rotates in unison with tubing 13. An anchor 39 is secured to the lower end of rotor 23 to prevent rotation of rotor 23 while stator 15 rotates. Anchor 39 may comprise various devices that can be set to grip casing 11 to prevent rotation and vertical movement of anchor 39. Preferably, a flexible shaft 41 extends between anchor 39 and the lower end of rotor 23. Even though rotor 23 does not rotate, the rotation of stator 15 will cause lateral oscillations of rotor 23. Flex shaft 41 is typically metal, but has sufficient length and flexibility to accommodate those oscillations. The lower end of flex shaft 41 will be stationary while the upper end will oscillate laterally with rotor 23. As shown by the arrows in FIG. 1, well fluid flows into the lower end of stator 15 and is discharged into tubing 13.
FIGS. 2A-2C shows stator 15 in a lower position relative to anchor 39, which is a position that may be utilized during the installation process to determine the proper vertical alignment of rotor 23 within stator 15. The upper end 45 of rotor 23 is protruding a substantial distance above the upper end of liner 19 in this lower position. Preferably, stator 15 is secured by threads to an upper adapter 43, which in turn is secured to the lower end of tubing 13. In this lower position, the upper end 45 of rotor 23 may extend through upper adapter 43 into tubing 13.
Referring to FIG. 2B, a lower adapter 47 is secured by threads to the lower end of the housing of stator 15. Lower adapter 47 has a coupling for connecting stator 15 to a flex shaft housing 49. Flex shaft housing 49 is a cylindrical member extending downward from lower adapter 47. A collar 51 is secured to the lower end of flex shaft housing 49. Collar 51 has an internal diameter that is smaller than the internal diameter of flex shaft housing 49, defining a reduced diameter section with an upward facing internal shoulder 53. Lower adapter 47, flex shaft housing 49 and collar 51 rotate in unison with stator 15.
Flex shaft 41 is secured by a coupling 57 to the lower end of rotor 23. Flex shaft 41 has an annular stop 59 formed on it against which coupling 57 makes up. Coupling 57 is a sleeve having an outer diameter greater than stop 59 and greater than the inner diameter of collar 51, defining an upper external shoulder that will land on internal shoulder 53 when stator 15 is in the upper or retrieval position relative to rotor 23, as shown in FIG. 4B. The outer diameter of stop 59 is slightly less than the inner diameter of collar 51 to enable flex shaft 41 to be inserted into and assembled within flex shaft housing 49.
Referring still to FIG. 2B, an adapter 61 secures the lower end of flex shaft 41 to anchor 39. Another stop similar to stop 59 is contacted by adapter 61 when adapter 61 is made up to the lower end of flex shaft 41. Adapter 61 has an outer diameter larger than the inner diameter of collar 51, defining a lower external shoulder that will abut the lower end of collar 51 when stator 15 is in the lower position shown in FIG. 2B. Adapter 61 is preferably hollow, having a plurality of ports 63 leading from the interior to the exterior. The lower portion of adapter 65 is of larger diameter than the upper portion, being approximately the same diameter as the outer diameter of stator 15. The lower portion of adapter 61 is secured by threads to a tubular mandrel 65.
Referring to FIG. 2C, mandrel 65 is part of anchor 39 and has a passage 66 extending through it for transmitting well fluid to ports 63 in adapter 65. Slips 67 are carried by mandrel 65 for movement between a retracted position and an engaged position with casing 11. Slips 67 have and teeth or grooves on the exterior and tapered interior surfaces that engage a tapered cam surface on mandrel 65. When slips 67 are pushed upward and outward on the cam surface of mandrel 65, they will frictionally grip the inner diameter of casing 11. A coil spring 69 urges slips 67 to the upper position. Anchor 39 has a retaining mechanism, such as one or more shear pins (not shown) operatively engaged between slips 67 and mandrel 65, that will allow anchor 39 to be run into the well with slips 67 in a retracted position (not shown). In one embodiment, dropping tubing 13, then rapidly stopping downward movement of tubing 13 creates a jarring movement that shears the shear pins. Spring 69 then forces slips 67 to the engaged position. Also, a key or spline (not shown) prevents relative rotation between mandrel 65 and slips 67.
In operation, the operator will assemble anchoring device 39 to the lower end of flex shaft 41. Rotor 23 will be located within passage 21 of stator 15. The operator secures stator 15 to the lower end of tubing 13, then lowers the entire assembly into the well simultaneously. When at the desired depth, the operator will actuate anchor 39 to cause slips 67 to move to the engaged position shown in FIG. 2C.
After setting, the operator moves rotor 23 to desired axial position in stator 15 for operation, which is shown in FIG. 3A-3C. This procedure can be done by lowering tubing 13 after setting anchor 39. Tubing 13 will move downward relative to anchor 39 until collar 51 lands on the upper end of adapter 61, as shown in FIGS. 2A-2C. The weight indicator at the surface will indicate that stator 15 is in the lower position. Stator 15 will move downward with tubing 13, but rotor 23 will remain stationary because of the engagement of anchor 39 with casing 11. The operator may then pick up tubing 13 a known distance so as to place stator 15 in the intermediate or operational position relative to rotor 23, shown in FIGS. 3A-3C. In the operational position, stop 59 is spaced above internal shoulder 53, and adapter 61 is spaced below collar 59 (FIG. 3C). The upper end 45 of rotor 23 will be substantially flush with the upper end of elastomeric liner 19. When moving to the operational position, the operator could pick up tubing 13 until collar 51 engages coupling 57, as shown in FIG. 4B, at which time the weight indicator should begin to increase due to the frictional engagement of slips 67 with mandrel 65. The operator would then lower tubing 13 a short distance to place stator 15 in the operational position.
The operator assembles drive head 31 and manifold 33 (FIG. 1). The operator begins rotating tubing 13, which will cause stator 15 and flex shaft housing 49 to rotate in unison. Anchor 39, flex shaft 41, and rotor 23 will not rotate because of the frictional engagement of anchor 39 with casing 11. The relative rotation causes well fluid to flow up mandrel passage 66, through adapter ports 63, collar 51, flex shaft housing 49 and into the lower end of stator 15. The well fluid flows up stator passage 21 into tubing 13. The well fluid flows up tubing 13 (FIG. 1) through manifold 33 and out conduit 37. During the rotational movement, the upper end of flex shaft 41 will oscillate laterally with the lower end of rotor 23. The lower end of flex shaft 41 will remain stationary.
To retrieve pump 17 for maintenance or replacement, the operator will disconnect drive source 31 and manifold 33, then pull upward on tubing 13. The upward pull will cause stator 15 to move to the upper position shown in FIGS. 4A-4C. In this position, upper end 45 of rotor 23 is below the upper end of elastomeric liner 19. Internal shoulder 53 on collar 51 will be in engagement with the lower end of coupling 57. Continued upward pull on tubing 13 transmits through flex shaft 41 to anchor mandrel 65. As mandrel 65 moves upward, slips 67 retract and release the grip on casing 11. The entire assembly, including tubing 13, stator 15, rotor 23 and anchor 39 are pulled out simultaneously as a single assembly.
The invention has significant advantages. By rotating the tubing, a string of drive rods is not required. Omitting the drive rods allows a smaller diameter tubing to be deployed with the same or larger flow area than a larger diameter tubing. In addition to weighing less and generally costing less, a smaller diameter tubing can be useful for wells with smaller diameter casing. Additionally, coupling the anchor, rotor and stator together in the manner shown allows the assembly to be run along with the tubing in a single trip. This installation saves on rig time that is normally required for rod-driven progressing cavity pump installations.
While the invention has been shown in only one of its forms, it should be apparent to those skilled in the art that it is not so limited but is susceptible to various changes without departing from the scope of the invention.
Patent Application
20070209800
