Method for performing kickstart, lift and well logging operations using a cable deployed electrical submersible pump

Abstract

A method for pumping fluid from a well includes moving the pump to a selected depth in a conduit within the well. The moving is performed by spooling an electrical cable. The pump is connected to the electrical cable. The pump has a resettable annular seal disposed between a pump intake and a pump discharge. The annular seal is set in the conduit. The pump is operated. The resettable annular seal is released and the pump is moved within the conduit.

Description

METHOD FOR PERFORMING KICKSTART, LIFT AND WELL LOGGING OPERATIONS USING A CABLE DEPLOYED ELECTRICAL SUBMERSIBLE PUMPCross Reference to Related Applications

[0001] This application claims the benefit of U.S. Provisional Application No. 63 / 612,446, filed December 20, 2023.Statement Regarding Federally Sponsored Research or Development

[0002] Not ApplicableNames of the Parties to a Joint Research Agreement

[0003] Not Applicable.Background

[0004] This disclosure relates to the field of electric submersible well pumps (ESPs). More particularly, the disclosure relates to annular seal systems (packers) used to set ESPs in a well for fluid production, where the annular seal can be repeatedly set and released for ready removal of the ESP when deployed on an electrical cable.

[0005] U.S. Patent No. 10,032,610 issued to Maclean et al. discloses a method for deploying an electric submersible pump (ESP) into a subsurface well using an electrical cable. It is known in the art to deploy ESPs with or assembled to an annular seal, e.g., a packer, to close an annular space between the ESP and a conduit in the well, so that fluid lifted by the ESP is constrained to move within the conduit to surface.

[0006] Inflatable packers are known in the art to be used in circumstances where it may be expected to remove the packer for well intervention. Using an inflatable packer with an ESP, where pump discharge is used to inflate the packer, may be limited by the fact that ESPs are frequently centrifugal pumps. Centrifugal pumps flow in the same directionirrespective of the rotation direction of the ESP, thus requiring some form of valve arrangement to direct flow for inflating and deflating the packer. Further, inflatable seal type packers may have limited differential pressure capacity, which may become hazardous in the event fluid flow from a hydrostatically unloaded formation becomes excessive..

[0007] There is a need for improved resettable packer arrangements to be used with centrifugal type ESPs.

[0008] ESPs may be used in some cases to “kick start” a well by lifting liquid, e.g., water from the well to reduce hydrostatic pressure against hydrocarbon bearing formations adjacent to the well, thus enabling flow of hydrocarbons into the well.

[0009] In some cases, it may be desirable to measure flow rates and water / oil / gas fraction (“holdup”) at various depths within a well to obtain better understanding of which depth interval(s) are productive of hydrocarbons and which may be productive of water (which can be undesirable because of the resulting hydrostatic pressure). Measuring instruments known as production logging tools are used to make such measurements. It is desirable to be able to make such measurements while using an ESP, particularly where the ESP may be moved and operated at various depths in the well.Summary

[0010] A method for pumping fluid from a well according to one aspect of the present disclosure includes moving the pump to a selected depth in a conduit within the well. The moving is performed by spooling an electrical cable. The pump is connected to the electrical cable. The pump has a resettable annular seal disposed between a pump intake and a pump discharge. The annular seal is set in the conduit. The pump is operated. The resettable annular seal is released and the pump is moved within the conduit.

[0011] In some embodiments, the setting the resettable annular seal comprises operating a J-slot mechanism by extending and retracting the electrical cable.

[0012] Some embodiments further comprise actuating a seal element in the resettable annular seal by extending the electrical cable to apply weight of the pump to the resettable annular seal.

[0013] Some embodiments further comprise, during the operating the pump, operating at least one production logging sensor to obtain measurements of fluid flowing in the conduit.

[0014] In some embodiments, the at least one production logging sensor comprises a flow meter.

[0015] In some embodiments, the flow meter comprises one or more of an orifice flow meter, a spinner flow meter and a Coriolis effect flow meter.

[0016] In some embodiments, the at least one production logging sensor comprises a holdup meter.

[0017] In some embodiments, the holdup meter comprises one or more of a capacitance sensor and a density sensor.

[0018] In some embodiments, the at least one production logging sensor is disposed on a same side of the resettable annular seal as an intake of the pump.

[0019] In some embodiments, the at least one production logging sensor is disposed on a same side of the resettable annular seal as a discharge of the pump.

[0020] In some embodiments, the conduit comprises a production tubing nested within a casing disposed in the well.

[0021] Some embodiments further comprise stopping the pump at a different selected depth in the conduit, and repeating the setting the resettable annular seal, operating the pump, releasing the resettable annular seal and moving the pump.

[0022] In some embodiments, the pump comprises releasable gripping elements to restrain the pump from axial movement in the conduit.

[0023] A well pump and tool assembly according to another aspect of the present disclosure includes an electric submersible pump (ESP) coupled to a cable head. The cable head is configured to make electrical and mechanical connection between the ESP and an electrical cable. A resettable annular seal is disposed on the ESP between an inlet thereof and an outlet thereof. The resettable annular seal is operable to radially expand and radiallycontract other than by fluid pressure. At least one production logging sensor is coupled to the ESP.

[0024] In some embodiments, the at least one production logging sensor comprises a flow meter.

[0025] In some embodiments, the flow meter comprises one or more of an orifice flow meter, a spinner flow meter and a Coriolis effect flow meter.

[0026] In some embodiments, the at least one production logging sensor comprises a holdup meter.

[0027] In some embodiments, the holdup meter comprises one or more of a capacitance sensor and a density sensor.

[0028] Some embodiments further comprising resettable gripping elements disposed on the ESP and arranged to restrain axial movement of the ESP within a conduit in a well.

[0029] In some embodiments, the at least one production logging sensor is disposed on a pump discharge side of the resettable annular seal.

[0030] In some embodiments, the at least one production logging sensor is disposed on a pump intake side of the resettable annular seal.

[0031] Other aspects and possible advantages will be apparent from the description and claims that follow.Brief Description of the Drawings

[0032] FIG. 1 shows a well pump and tool assembly that may be used in accordance with the present disclosure by deployment on an electrical cable.

[0033] FIG. 2 shows an enlarged view of an example embodiment of a well pump and tool assembly.Detailed Description

[0034] FIG. 1 shows an example embodiment of a well pump and tool assembly (“assembly”) 10 in accordance with the present disclosure. The assembly 10 may be deployed in a subsurface well W drilled through various underground earthen formations (not shown). The well W may comprise a protective pipe or casing 32 extending from a valve assembly (“wellhead”) 34 coupled to a surface end of the casing 32. A string of smaller diameter conduit (“production tubing”) 30 may be nested within the casing 32 and provide a smaller cross section conduit to increase the velocity at which fluids move to the surface to facilitate fluid production, e.g., by entraining higher density fluids such as water within the flow of lower density fluids such as oil and / or gas.

[0035] The wellhead 34 may comprise one or more valves, e.g., at 38 to enable fluids moving up the production tubing 30 to leave the well W in a controlled manner. When well intervention devices such as the assembly 10 are moved into a well, safety considerations usually require that a pressure control device such as a blowout preventer (BOP) stack 40 are coupled above the wellhead 34 to provide positive closure of the well W in the event uncontrolled flow of fluid takes place. A conduit called a lubricator 42 may couple to the top of the BOP stack 40 to provide a sealed enclosure for the assembly 10 in order to introduce the assembly 10 into the well W so as to prevent the well W from being exposed at any time. A pack off or grease injection head 44 may be used to seal against an electrical cable 12 used to deploy the assembly 10 in the well W, while enabling movement of the electrical cable 12 and thereby the assembly 10 along the well W as may be needed.

[0036] The electrical cable 12 may transmit electrical power to operate the assembly 10 and may communicate signals from various measuring instruments associated with the assembly 10 as it is operated in the well W. The electrical cable 12 may be extended from and retracted onto a winch 48 of types well known in the art in order to move the assembly in the well W. A surface end of the electrical cable 12 may be electrically connected to a surface system 50 of types well known in the art used in connection with electric submersible pumps (ESPs). The surface system 50 may comprise pump speed control devices such as a variable frequency drive. The electrical cable 12 may pass through oneor more sheaves 46 between the winch 48 and the well W in order to direct the electrical cable 12 properly to move the assembly 10 freely along the interior of the well W.

[0037] The assembly 10 may be coupled to the electrical cable 12 by a cable head 14 of types well known in the art. The assembly 10 may comprise an electric motor 16 such as a permanent magnet motor rotationally coupled, through a protector assembly 20 and a sensor package 18 to a pump 22 such as a centrifugal pump. An inlet 22A to the pump 22 may be disposed proximate a lower end of the assembly 10, at least disposed below a resettable annular seal (“packer”) 26 disposed along the assembly 10. A discharge 22B of the pump 22 may be disposed on an opposed axial side of the resettable packer 26. Thus, flow from the pump 22 is constrained to move upwardly in the production tubing 30. A bypass valve 24 may be provided in the assembly 10 for circumstances wherein flow form parts of the well W below the resettable packer 26 exceeds the flow rate of the pump 22. Such flow may move through the bypass valve 24 upwardly through the production tubing 30.

[0038] The resettable packer 26 may comprise a J-slot mechanism (not shown) to set the packer 26 in a desired axial position in the production tubing 30. The J-slot mechanism may be operated by lifting and lowering the electrical cable 12. A seal element (not shown) in the resettable packer 26 may be energized using the weight of the assembly 10 alone, that is, to activate the seal element (not shown) the electrical cable 12 is unspooled from the winch 48 after the J-slot mechanism sets, such that weight of the assembly 10 will be applied to the resettable packer 26 to activate the seal element (not shown). When it is desired to release the resettable packer 26 to move the assembly 10, the electrical cable 12 may be spooled onto the winch 48 to lift the assembly and relieve weight from the resettable packer. The resettable packer 26 may be configured to resist forces bi-directionally, preventing differential pressure (blow-out) caused or other unwanted movement of the assembly 10 along the production tubing 30. The resettable packer 26 may be configured to resist blowout, e.g., by providing additional gripping elements (“slips”) to engage the interior of the production tubing 30 when the resettable packer 26 is released (unset) if naturally produced fluid causes sufficient upthrust on the assembly 10. The resettable packer 26 in some embodiments may comprise any mechanism to radially expand grippingelements (not shown separately) arranged to axially lock the assembly 10 into position within the production tubing 30, and to actuate the seal element, that is not operated by fluid pressure (i.e., an inflatable packer).

[0039] In some embodiments, production logging sensors 28 may be coupled to the assembly 10 at a selected axial position, such as below the resettable packer 26 as shown in FIG. 1, or as will be explained with reference to FIG. 2, above the resettable packer 26.

[0040] The production logging sensors 28 may comprise one or more types of flow meter, e.g., an orifice flow meter, a spinner flow meter, a hotwire anemometer or a Coriolis effect flow meter. The production logging sensors 28 may also comprise one or more types of fluid fraction sensors, known as “holdup” meters. Holdup meters may comprise, for example and without limitation, capacitance sensors to determine fractional volume of oil or water in liquid, density sensors to determine fractional volume of liquid or gas in a fluid. The production logging sensors 28 in the example embodiment of FIG. 1 may be battery operated and may internally record measurements made by the various sensors for interrogation when the assembly 20 is removed from the well W.

[0041] In some embodiments, and referring to FIG. 2, the production logging sensors 28 may be disposed within the assembly 10 above the resettable packer 26 such that power to operate the production logging sensors 28 and signals generated therefrom may be communicated along the electrical cable 12. In the example embodiment shown in FIG. 2, the production logging sensors 28 may comprise an orifice flowmeter 28A disposed in or proximate to the pump discharge (22B in FIG. 1). Various holdup meters 28B may be disposed in or proximate to the pump intake (22A in FIG. 1).

[0042] A sequence of actions in using an assembly as described above may include the following. The assembly 10, including the resettable packer 26 is run into the well W down to a first depth or zone of interest. The resettable packer 26 is set at the depth or zone of interest, securing the assembly 10 at the desired depth or zone. The pump 22 is switched on and is operated at the required rate (by suitable operation of the surface system 50) to obtain the desired production of well fluid to surface. Such pumping may be either with the goal of kickstarting the well, or to capture well fluid from the specific zone of interestfor later compositional analysis. The pump 22 may be run at any chosen number of different pumping rates at each zone of interest in order to better characterize the flow characteristics of the zone being investigated. Data from the production logging sensors 28 may be captured for either real-time or post-operation analysis. The pump 22 is shut down and the resettable packer 26 is released. The assembly 10 is raised or lowered as required to move the pump 22 to the next zone of interest. Setting the resettable packer 26, operating the pump 22 and making any necessary measurements may be repeated until the desired operation is completed at any or all zones of interest in the well W. The assembly 10 may then be removed from the well W.

[0043] A well pump and tool assembly according to the present disclosure may be used to kickstart a well into fluid production and may be used to characterize flow from various zones, depths or intervals within a subsurface well.

[0044] 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.

Claims

ClaimsWhat is claimed is:

1. A method for pumping fluid from a well, comprising: moving the pump to a selected depth in a conduit within the well by spooling an electrical cable, the pump connected to the electrical cable, the pump comprising a resettable annular seal disposed between a pump intake and a pump discharge; setting the annular seal in the conduit; operating the pump; releasing the resettable annular seal; and moving the pump within the conduit.

2. The method of claim 1 wherein the setting the resettable annular seal comprises operating a J-slot mechanism by extending and retracting the electrical cable.

3. The method of claim 2 further comprising actuating a seal element in the resettable annular seal by extending the electrical cable to apply weight of the pump to the resettable annular seal.

4. The method of claim 1 further comprising, during the operating the pump, operating at least one production logging sensor to obtain measurements of fluid flowing in the conduit.

5. The method of claim 4 wherein the at least one production logging sensor comprises a flow meter.

6. The method of claim 5 wherein the flow meter comprises one or more of an orifice flow meter, a spinner flow meter and a Coriolis effect flow meter.

7. The method of claim 4 wherein the at least one production logging sensor comprises a holdup meter.

8. The method of claim 7 wherein the holdup meter comprises one or more of a capacitance sensor and a density sensor.

9. The method of claim 4 wherein the at least one production logging sensor is disposed on a same side of the resettable annular seal as an intake of the pump.

10. The method of claim 4 wherein the at least one production logging sensor is disposed on a same side of the resettable annular seal as a discharge of the pump.

11. The method of claim 1 wherein the conduit comprises a production tubing nested within a casing disposed in the well.

12. The method of claim 1 further comprising stopping the pump at a different selected depth in the conduit, and repeating the setting the resettable annular seal, operating the pump, releasing the resettable annular seal and moving the pump.

13. The method of claim 1 wherein the pump comprises releasable gripping elements configured to constrain axial movement of the pump within the conduit.

14. A well pump and tool assembly, comprising: an electric submersible pump (ESP) coupled to a cable head, the cable head configured to make electrical and mechanical connection between the ESP and an electrical cable; a resettable annular seal disposed on the ESP between an inlet thereof and an outlet thereof, the resettable annular seal operable to radially expand and radially contract other than by fluid pressure; and at least one production logging sensor coupled to the ESP.

15. The assembly of claim 14 wherein the at least one production logging sensor comprises a flow meter.

16. The assembly of claim 15 wherein the flow meter comprises one or more of an orifice flow meter, a spinner flow meter and a Coriolis effect flow meter.

17. The assembly of claim 14 wherein the at least one production logging sensor comprises a holdup meter.

18. The assembly of claim 17 wherein the holdup meter comprises one or more of a capacitance sensor and a density sensor.

19. The assembly of claim 14 further comprising resettable gripping elements disposed on the ESP and arranged to restrain axial movement of the ESP within a conduit in a well.

20. The assembly of claim 14 wherein the at least one production logging sensor is disposed on a pump discharge side of the resettable annular seal.

21. The assembly of claim 14 wherein the at least one production logging sensor is disposed on a pump intake side of the resettable annular seal.

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