CENTRIFUGAL WELL PUMP WITH THREADEDLY COUPLED DIFFUSERS

Abstract

A well pump includes a plurality of diffusers, wherein each diffuser comprises a first threaded coupling on one longitudinal end and a second threaded coupling on an opposed longitudinal end. An impeller is disposed in each diffuser. The plurality of diffusers are coupled end to end to form a pump housing, in which the first threaded coupling on one diffuser is threadedly engaged to the second threaded coupling on adjacent diffuser.

Claims

1. A well pump, comprising: a plurality of diffusers, each diffuser comprising a first threaded coupling on one longitudinal end and a second threaded coupling on an opposed longitudinal end; an impeller disposed in each diffuser; and wherein the plurality of diffusers are coupled end to end to form a pump housing, wherein the first threaded coupling on one diffuser is threadedly engaged to the second threaded coupling on adjacent diffuser.

2. The well pump of claim 1 wherein the first threaded coupling on one diffuser and the second threaded coupling on another diffuser form a metal to metal seal when threadedly engaged to each other.

3. The well pump of claim 1 wherein the first threaded coupling on one diffuser is sealed to the second threaded coupling on another diffuser using an elastomer seal.

4. The well pump of claim 1, further comprising a drive shaft inserted into the impeller in each diffuser.

5. The well pump of claim 1, further comprising a protector coupled to one end of the plurality of diffusers.

6. The well pump of claim 5 further comprising a monitoring and star point sub and at least one motor coupled to an end of the protector opposed to the end of the protector coupled to the one end of the plurality of diffusers.

7. The well pump of claim 6 wherein the at least one motor comprises an electric motor.

8. The well pump of claim 1, wherein each diffuser comprises a separate diffuser body and diffuser vanes, wherein the diffuser vanes are fit into each diffuser body.

9. The well pump of claim 1, wherein each impeller is axially movably attached to a drive shaft, and wherein each impeller and each diffuser comprise a respective axial thrust face, wherein axial force generated by the impellers is transferred to the diffusers.

10. The well pump of claim 1, wherein the first threaded coupling is a male threaded connector and the second threaded coupling is a female threaded connector.

11. A method for assembling a well pump, comprising: disposing an impeller in each of a plurality of diffusers, each diffuser comprising a threaded first coupling on one longitudinal end and a second threaded coupling on an opposed longitudinal end; threadedly coupling the plurality of diffusers end to end; and deploying the threadedly coupled diffusers in a well.

12. The method of claim 11 wherein the first threaded coupling on one diffuser and the second threaded coupling on another diffuser form a metal to metal seal when threadedly engaged to each other.

13. The method of claim 11 wherein the first threaded coupling on one diffuser is sealed to the second threaded coupling on another diffuser using an elastomer seal.

14. The method of claim 11, further comprising inserting a drive shaft into the impeller in the plurality of diffusers.

15. The method of claim 11, further comprising assembling a protector to one end of the plurality of diffusers.

16. The method of claim 15 further comprising assembling a monitoring and star point sub and at least one motor to an end of the protector opposed to the end of the protector coupled to the one end of the plurality of diffusers.

17. The method of claim 16 wherein the at least one motor comprises an electric motor.

18. The method of claim 11, wherein each diffuser comprises a separate diffuser body and diffuser vanes, wherein the diffuser vanes are fit into each diffuser body.

19. The method of claim 11, further comprising assembling each impeller axially movably to a drive shaft, and wherein each impeller and each diffuser comprise a respective axial thrust face, wherein axial force generated by the impellers is transferred to the diffusers.

20. The method of claim 11, wherein the first threaded coupling is a male threaded connector and the second threaded coupling is a female threaded connector.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0029] FIG. 1 shows and example centrifugal pump system that may be deployed in a subsurface well.

[0030] FIG. 2 shows a cross sectional view of a multiple stage centrifugal well pump known in the art prior to the present disclosure.

[0031] FIG. 3 shows a cross sectional view of an example embodiment of a multiple stage centrifugal well pump according to the present disclosure.

[0032] FIG. 4 shows a cross sectional view of an example embodiment of a multiple stage centrifugal well pump where each diffuser comprises a separate diffuser body and diffuser vanes, wherein the diffuser vanes are fit into each diffuser body this embodiment also shows a drive shaft installed.

[0033] FIG. 5 is an enlarged view corresponding to FIG. 4.

[0034] FIG. 6 shows an example embodiment of deploying a pump system in a well.

DETAILED DESCRIPTION

[0035] FIG. 1 shows an example embodiment of a well pump system, such as an electric submersible pump (ESP) system 10, that may be conveyed into a well (see FIG. 6) using, for example and without limitation, jointed tubing, wireline, slickline or coiled tubing. The ESP system 10 may include an upper or “top” sub 12 that comprises features to make connection to an end of one of the foregoing conveyance devices for movement into and out of the well. A lower end of the ESP system 10 may include an “intake” sub 28. The intake sub 28 may be added below a pump 26, such as a rotary pump, to provide protection while running into the well during deployment, and to provide a mounting location for a pump (e.g., ESP) intake memory gauge or sensors. In addition, the intake sub 28 may provide a suitable location for inner bore sealing as part of a well barrier control mechanism. Both a single shot sealing option and a pressure responsive valve with multiple stable positions may be considered as suitable, but not limiting example options for well sealing below the intake sub 28. For purposes of this disclosure, the term “up” is intended to mean in a direction toward the outlet of a wellbore when the ESP system 10 is installed therein, while “down” is intended to mean in the opposite direction. Corresponding terms may include “upper end” and “lower end” with reference to various modules or sections that make up the ESP system 10. Accordingly, the use of such terms is for ease of understanding and is not intended to limit the scope of the present disclosure. The example embodiment shown in FIG. 1 is an “inverted” ESP system wherein one or more motors, e.g., electric motors, are disposed proximate the top end of the system for deployment on an electrical cable. It should be clearly understood that the respective longitudinal positions of the components shown in FIG. 1 is not intended to limit the scope of the present disclosure. Although the present example embodiment is described as having one or more electric motors, for purposes of defining the scope of the present disclosure, any other form of motor may be used, for example and without limitation, hydraulic motors, pneumatic motors, and rod driven motors.

[0036] The top sub 12 may be followed successively by one or more motor(s) 13, which in the present example may be electric motor(s) and a “monitoring and star point sub” 14. The “monitoring and star point sub” 14 may include one or more sensors and control devices (not shown separately) related to operation of the ESP system 10 and the motor(s) 13. The monitoring and star point sub 14 may also be positioned above the motor(s) 13 and used to make electrical connection between a cable (not shown) and the motor(s) 13. The motor(s) 13 may be coupled at the lower end thereof to a solid enclosed driveshaft, a flexible shaft, magnetic gearing or any other rotational motion transmission. In the present example, the rotational motion transmission may be a solid driveshaft disposed inside the “monitoring and star point sub” 14 which accepts rotational input from the motor(s) 13, and transmits such rotational motion to the pump 26, which may be a rotary pump. A protector 18, may be similar in operating principle to the protector ordinarily used in ESP systems, and may be configured to exclude well fluids at existing well pressure and temperature from entering the motor(s) 13. Not shown in FIG. 1 for clarity is a flow shroud that diverts well fluid flow from the pump discharge 20 so that it can travel in an annular space outside the ESP system 10 and be sealingly diverted into a tubing or coiled tubing and thence flow upwardly in the well (not shown).

[0037] The present example of ESP system 10 may be of modular design and deployed in the well as separate subassemblies, or the entire ESP system 10 may be lowered into the well as an assembled unit, e.g., as shown in FIG. 1. The pump 26, the protector 18, the monitoring and star point sub 14 and the motor(s) 13 may each be enclosed in a respective pressure resistant housing, and such housings may be coupled by threads, locking rings or any other device known in the art for joining housings or housing segments together end to end. Various sections of a pump system constructed as disclosed herein in the form of modules can be (quick) coupled to other pump modules, thrust and discharge modules and intake pressure modules, for example. The specific coupled components as disclosed herein are not intended to limit the scope of other components that may be similarly coupled to a pump system according to this disclosure.

[0038] In order to better understand the structure of a well pump according to the present disclosure, FIG. 2 shows, for comparison purposes, a cross-sectional view of a multiple stage centrifugal well pump 26 known in the art prior to the present disclosure. A plurality of diffusers 40 and associated impellers 42 are disposed longitudinally adjacently end to end in a housing 44. The housing 44 may be a generally cylindrical, solid tube into which successive impeller 42/diffuser 40 combinations are inserted. Typically, the plurality of impellers/diffusers, known as a “stack” is inserted into the housing 44, then is compressed axially to provide rotational locking, sealing and room for thermal expansion. Disassembly of the pump 26 may be performed by reversing the foregoing assembly operation.

[0039] FIG. 3 shows a corresponding cross-sectional view of an example embodiment of a well pump according to the present disclosure. The pump 26A may comprise a plurality of diffusers 46 coupled together end to end. Each diffuser 46 may have disposed therein a corresponding impeller 42A. Each diffuser 46 comprises at one longitudinal end a first threaded coupling, which may be an internally threaded female connector 47, and on the opposite longitudinal end, a second threaded coupling, which may be an externally threaded male connector 49. The male connector 49 has diameter and thread configuration to threadedly engage the female connector 47 of an adjacent diffuser 46. The threads, thread reliefs and/or thread shoulders, seal diameters, as applicable, of the male connector 49 and the female connector 47 may comprise features to enable provision of an elastomeric seal such as an O-ring, a metal to metal seal, or both a metal to metal and elastomeric seal on engagement of a female connector 47 to a male connector 49 between adjacent diffusers 46. In this way, assembling a plurality of diffusers 46 may provide the functional equivalent of the housing (44 in FIG. 2) of a centrifugal well pump known in the art prior to the present disclosure as explained with reference to FIG. 2. That is, fluid may be constrained to flow longitudinally within the interior of the space defined by the assembled diffusers 46. In the example embodiment shown, the exterior surface (47A in FIG. 4) of the female connector 47 may be the same as the external diameter of a correspondingly sized (i.e., outer or external diameter) conventional well pump, such as shown in FIG. 2. An internal diameter of the male connector 49 may be larger diameter than the internal diameter of a diffuser in a correspondingly sized conventional well pump (see FIG. 2). Such increased internal diameter may provide that the impellers 42A in the present example embodiment may be larger diameter than those in a correspondingly sized conventional well pump. Increased internal diameter and increased impeller diameter may provide increased flow area, and such increased diffuser and impeller diameters may provide a well pump according to the present disclosure with greater head and/or flow rate than correspondingly sized conventional well pumps in accordance with pump affinity laws.

[0040] While in the present example embodiment, the first threaded coupling is described as a female threaded connector, and the second threaded coupling is described as a male threaded connector. It will be appreciated that it is fully within the scope of the present disclosure for the first threaded coupling to be either male or female thread, and the same applies to the second threaded coupling. If the first and second threaded couplings are both male threaded connectors or are both female threaded connectors, a respective double female or double male connector may be used to connect adjacent diffusers.

[0041] In the embodiment of FIG. 3, the impellers 42A may comprise an internal opening that is shaped to accept a keyed drive shaft (50 in FIG. 4). The size of the internal opening on each impeller 42A may be made such that the impellers 42A may move axially along the drive shaft (50 in FIG. 4). Axial thrust forces produced by the impellers 42A may be respectively transferred to each impeller's corresponding diffuser 46 by having opposed thrust faces 42B, 46A, respectively on the impellers 42A and diffusers 46.

[0042] Such thrust surfaces 42B, 46A may comprise bearing material suitable for transfer of such axial thrust forces. In this way, thrust applied to a thrust bearing (not shown) will be reduced as contrasted with conventional pumps having axially fixed impellers. The example embodiment shown in FIG. 3 provides that the impellers 42A are not axially locked to a driveshaft (see below with reference to FIG. 4). Such feature is not intended to limit the scope of the present disclosure; other embodiments may have some or all of the impellers 42A axially locked to the drive shaft.

[0043] FIG. 4 shows the cross sectional view of FIG. 3 wherein a main drive shaft 50 is inserted through the impellers 42A. The pump 26 shown in and explained with reference to FIGS. 3 and 4 may be assembled to an ESP system as explained with reference to FIG. 1. An additional feature of the example embodiment shown in FIG. 4 as contrasted with that of FIG. 3 is that the diffusers 46 may comprise two separate components for ease of manufacture, assembly and quality control. A diffuser body 46B may comprise the female and male connectors (47, 49, respectively in FIG. 3).

[0044] Diffuser vanes 46C may be formed as a separate component. The diffuser vanes 46C may be shrink fit or press fit into the diffuser body 46B to assemble a complete diffuser 46, which may be assembled as explained above.

[0045] FIG. 5 shows a view similar to that of FIG. 4 in enlarged scale for better understanding of the separate diffuser vanes 46C, diffuser bodies 46B and respective thrust surfaces 42B, 46A.

[0046] FIG. 6 shows an example embodiment of deploying a pump system in a well or wellbore. The wellbore 60 is drilled through subsurface formations including a fluid producing formation 64. The producing formation 64 may have hydrocarbons and water therein, and when the formation 64 is exposed to a pressure in the wellbore 60 lower than the fluid pressure in the producing formation 64, such pressure may urge the hydrocarbons and water in various amounts into the wellbore 60. The wellbore 60 may have cemented in place therein a protective pipe or casing 62 that extends from a wellhead 66 at the surface 81. A length of smaller diameter pipe or “tubing” 68 nested in the casing 62 may extend from the wellhead 66 to a selected depth in the wellbore 60, typically, although not necessarily above the depth of the producing formation 64. The tubing 68 may be provided to increase the velocity of fluid moved from the producing formation 64 to the wellhead 66. An annular space between the tubing 68 and the casing 62 may be closed to fluid communication by an annular seal or packer 72. The casing 62 may include perforations 74 therein at a depth corresponding to the depth of the producing formation 64 to enable fluid flow from the producing formation 61 to move into the wellbore 50.

[0047] A wellbore pump system 10, substantially as explained with reference to FIGS. 1 through 5, may be connected to one end of a deployment cable, pipe “string” or conduit. In some embodiments, the deployment string, cable or conduit may be a tubing encapsulated cable (TEC) 70. As explained above with reference to FIG. 1, however, it should be clearly understood that any other known device for deploying an ESP system in a well may be used in accordance with this disclosure. The wellbore pump system 10 may include a high speed, permanent magnet AC electric motor 49 rotationally coupled to a pump 92 as explained above. In some embodiments, the wellbore pump system 10 may include a remotely controllable, inflatable annular seal 98 to close off fluid communication between an inlet of the pump 92 and a pump fluid discharge 96 disposed in the tubing 68. In other embodiments the annular seal 98 may already be in place in the tubing 68 or in the casing 62. In other embodiments, the tubing 68 may not be used; the wellbore 60 may be completed using only a casing.

[0048] The TEC 70 may be stored on and deployed from a drum, reel or spool forming part of a winch such as a wireline winch 80. The wireline winch 38 may be mounted on a vehicle 78 for on road transportation. In other embodiment the winch 80 may be a “skid” mounted unit for use on offshore well service units. The TEC 70 may be extended into the wellbore 60 through suitably positioned sheave wheels 76 positioned as would ordinarily be used in deployment of wireline wellbore measuring instruments or intervention instruments.

[0049] A wireline pressure control head 82 may be coupled to the top of the wellhead 66. The wireline pressure control head 82 may include an hydraulically compressible seal element 84 disposed in a bladder 86. The bladder 86 may be inflated by hydraulic pressure using equipment (not shown) known in the art for such purpose. The seal element 84 may have an internal opening sized to seal on an exterior surface of the TEC 27 to substantially prevent escape of fluid under pressure as the ESP system 10 and the TEC 70 are extended into the wellbore 60 or withdrawn from the wellbore 60. The seal element 84 may also substantially prevent fluid from escaping around the exterior of the TEC 70 during operation of the ESP system 10.

[0050] A centrifugal pump made according to the present disclosure herein does not require a separate housing and multiple diffusers, and instead combines the diffusers longitudinally to form an equivalent structure to the housing. The diffusers thread together end to end and seal between each other, isolating the pump discharge from the pump inlet. The pump can be re-staged much quicker as the thrust assembly and discharge does not need to be dismantled. Possible advantages of this design may include one or more of the following.

[0051] Improved pump performance (head and/or flow) may result from increased flow/design area with respect to a conventional multiple stage centrifugal pump with the same external diameter. The same length of pump can be used for higher flow rate applications and/or higher head applications.

[0052] A well pump made according to the present disclosure may be easier to re-stage for different well applications. The space needed and tooling required to change the number of stages in the pump is greatly reduced, providing possible faster turnaround between each job or between applications. Such feature may be particularly useful for short term well intervention which requires frequent restaging of the centrifugal pump, preferably in the field.

[0053] The pump thrust assembly, discharge and connections between subassemblies do not need to be disassembled in order to re-stage a pump, saving time, cost, consumable components and motor oil. This is because the pump can be split and dismantled at any diffuser without having to remove the entire pump stage stack from a housing.

[0054] Such a well pump can provide reduced pump weight for the same head and/or flow as a correspondingly sized (outer diameter) pump. A lighter pump aids assembly and handling as well as increasing maximum running depth.

[0055] Diffuser casting or 3D-print may be shortened in length considerably, thereby reducing material used, casting/printing complexity, casting/printing cost and time, and final machining cost and time.

[0056] The threaded diffuser bodies may be machined from billet or coupling stock to ensure material properties for strength, hardness and chemical resistance etc. The diffuser vanes may be printed/cast and press fit or shrink fit into the diffuser bodies. The machined diffuser bodies are then threaded together end to end to create the required length of assembly and numbers of stages to match application requirements. By avoiding the diffusers being stacked, inserted then compressed inside a separate housing, the pump can be stripped from the inlet end, meaning the thrust and discharge section at the top of the pump can stay in place or be attached to the rest of the assembly during re-stage for quick turnaround well intervention applications. As long, specialized tooling for pump assembly and disassembly of conventional well pumps is not required, re-staging operation can take place in a smaller area and with simple, readily available hand tools such as may be available at a well location. Such make possible re-stage of a well pump at a well location.

[0057] In light of the principles and example embodiments described and illustrated herein, it will be recognized that the example embodiments can be modified in arrangement and detail without departing from such principles. The foregoing discussion has focused on specific embodiments, but other configurations are also contemplated. In particular, even though expressions such as in “an embodiment,” or the like are used herein, these phrases are meant to generally reference embodiment possibilities, and are not intended to limit the disclosure to particular embodiment configurations. As used herein, these terms may reference the same or different embodiments that are combinable into other embodiments. As a rule, any embodiment referenced herein is freely combinable with any one or more of the other embodiments referenced herein, and any number of features of different embodiments are combinable with one another, unless indicated otherwise. Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible within the scope of the described examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.