WO2025259993A2 - Multistage electro-hydraulic connector for completions - Google Patents

Abstract

A method for disconnecting an upper completion from a lower completion includes positioning a cutter at a first position, actuating the cutter to initiate a cut in a mandrel, wherein the mandrel is disposed within the downhole tubing assembly, and wherein the mandrel is separated into an upper portion of the mandrel and a lower portion of the mandrel by the cut, lifting the cutter out of the downhole tubing assembly, lifting the upper portion of the mandrel as a part of a pull out of hole (POOH) operation, wherein the upper portion of the mandrel is configured to pull a support sleeve during the POOH operation, disengaging a locking mechanism between a cut-to-release (CTR) collet from the lower completion, and lifting the upper completion up from the downhole tubing assembly, wherein the upper completion comprises the upper portion of the mandrel, the support sleeve, and the CTR collet.

Description

MULTISTAGE ELECTRO-HYDRAULIC CONNECTOR FOR COMPLETIONS

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 63/659,933 titled “CUT-TO-RELEASE (CTR) CONNECTOR,” filed June 14, 2024, U.S. Provisional Application No. 63/661,322 titled “MULTISTAGE ELECTRO- HYDRAULIC CONNECTOR FOR COMPLETIONS,” filed June 18, 2024, and U.S. Provisional Application No. 63/671981 titled “ELECTRIC CUT-TO-RELEASE (CTR) CONNECTOR,” filed July 16, 2024, each of which is hereby incorporated by reference in its entirety for all purposes.

BACKGROUND

[0002] The present disclosure generally relates to systems and methods for connecting and disconnecting wellbore elements for various downhole operations. In particular, the present disclosure relates to various mechanical, electro-mechanical, and electrical methods for connecting and disconnecting wellbore elements of a downhole tube assembly for maintenance and operational uses.

[0003] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the presently described embodiments, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.

[0004] To meet consumer and industrial demand for natural resources, companies often invest significant amounts of time and money in searching for and extracting oil, natural gas, hydrocarbons, and other subterranean resources from the earth. Particularly, once a desired subterranean resource such as oil or natural gas is discovered, drilling and production systems may be employed to access and extract the resource. Further, such systems may include downhole tooling and pipe completions, such as wellbore elements, an upper completion, a lower completion, connectors, couplers, and the like, that contribute to drilling and extraction operations.

[0005] In some cases, the wellbore elements may be removed for maintenance, recovery operations, or other similar borehole operations. In one non-limiting example, the upper completion from the drilling system may undergo periodic maintenance, leading to the surface equipment engaging in a removal procedure to pull the upper completion from the borehole. Efforts to improve the effectiveness and efficiency of this removal procedure may be advantageous.

SUMMARY

[0006] A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.

[0007] In certain embodiments, a method for disconnecting an upper completion from a lower completion within a downhole tubing assembly includes positioning a cutter at a first position, actuating the cutter to initiate a cut in a mandrel, such that the mandrel is disposed within the downhole tubing assembly, and such that the mandrel is separated into an upper portion of the mandrel and a lower portion of the mandrel by the cut, lifting the cutter out of the downhole tubing assembly, lifting the upper portion of the mandrel as a part of a pull out of hole (POOH) operation, wherein the upper portion of the mandrel is configured to pull a support sleeve during the POOH operation, disengaging a locking mechanism between a cut- to-release (CTR) collet from the lower completion, and lifting the upper completion up from the downhole tubing assembly, wherein the upper completion comprises the upper portion of the mandrel, the support sleeve, and the CTR collet.

[0008] In another embodiment, a system includes an electro-actuated disconnection latch system that includes an electric cut-to-release (CTR) connector, an electro-mechanical actuator (EMA) configured to convert electrical energy into mechanical energy, such that the EMA is disposed on the electric CTR connector, and a support sleeve configured to couple to the EMA, such that the support sleeve is configured to translate axially in response to receiving the mechanical energy from the EMA.

[0009] In one embodiment, a system includes a controller that includes a memory and processing circuitry, wherein the memory stores instructions, that when executed by the processing circuitry, cause the processing circuitry to perform operations including outputting an electrical signal to an inductive coupler, such that the inductive coupler includes a male inductive coupler and a female inductive coupler of a downhole assembly, and such that the electrical signal causes the male inductive coupler to couple with the female inductive coupler, and outputting an additional electrical signal to the inductive coupler to disengage the male inductive coupler from the female inductive coupler.

[0010] The brief summary presented above is intended only to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

[0011] The subject disclosure is further described in the following detailed description, and the accompanying drawings and schematics of non-limiting embodiments of the subject disclosure. The features depicted in the figures are not necessarily shown to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form, and some details of elements may not be shown in the interest of clarity and conciseness. These and other features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

[0012] FIG. 1 is a cross-sectional side view of an embodiment of a cut-to-release connector as a portion of a downhole tubing assembly, in accordance with aspects of the present disclosure; [0013] FIG. 2 is a cross-sectional side view of an embodiment of a cut-to-release connector during a cut-to-release procedure, in accordance with aspects of the present disclosure;

[0014] FIG. 3 is a cross-sectional side view of an embodiment of a cut-to-release connector during a cut-to-release procedure, in accordance with aspects of the present disclosure;

[0015] FIG. 4 is a cross-sectional side view of an embodiment of a cut-to-release connector during a cut-to-release procedure, in accordance with aspects of the present disclosure;

[0016] FIG. 5 is a cross-sectional side view of an embodiment of a cut-to-release connector during a cut-to-release procedure, in accordance with aspects of the present disclosure;

[0017] FIG. 6 is a flowchart of an embodiment of a method for performing a cut-to- release procedure for a downhole tubing assembly, in accordance with aspects of the present disclosure;

[0018] FIG. 7A is a perspective view of an assembled connector in a single trip configuration, in accordance with aspects of the present disclosure;

[0019] FIG. 7B is a cross-sectional side view of various parts and components that may be removed during a conversion from the single trip configuration, in accordance with aspects of the present disclosure;

[0020] FIG. 8 is a perspective view of an assembled connector in a dual trip configuration, in accordance with aspects of the present disclosure;

[0021] FIG. 9 is a cross-sectional side view of an embodiment of an electric cut-to-release connector that may be utilized in an electro-actuated disconnection latch system, in accordance with aspects of the present disclosure;

[0022] FIG. 10 is a cross-sectional side view of an embodiment of the electric cut-to- release connector that may be utilized in the electro-actuated disconnection latch system, in accordance with aspects of the present disclosure; [0023] FIG. 11 is a perspective view of an embodiment of a combination of a hydraulic stinger assembly that assembles into a hydraulic receptacle assembly, in accordance with aspects of the present disclosure;

[0024] FIG. 12 is a cross-sectional side view of a portion of the downhole tubing assembly, and in particular the portion of the downhole tubing assembly where the hydraulic stinger overlaps with the hydraulic receptacle, in accordance with aspects of the present disclosure;

[0025] FIG. 13 A is a schematic view of a hydraulic connector positioned in the hydraulic receptacle, in accordance with aspects of the present disclosure;

[0026] FIG. 13B is a perspective view of the hydraulic connector, in accordance with aspects of the present disclosure; and

[0027] FIG. 14 is a cross-sectional side view of the inductive coupler utilized in the downhole tubing assembly, in accordance with aspects of the present disclosure.

DETAILED DESCRIPTION

[0028] Certain embodiments commensurate in scope with the present disclosure are summarized below. These embodiments are not intended to limit the scope of the disclosure, but rather these embodiments are intended only to provide a brief summary of certain disclosed embodiments. Indeed, the present disclosure may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

[0029] As used herein, the term “coupled” or “coupled to” may indicate establishing either a direct or indirect connection (e.g., where the connection may not include or include intermediate or intervening components between those coupled), and is not limited to either unless expressly referenced as such. The term “set” may refer to one or more items. Wherever possible, like or identical reference numerals are used in the figures to identify common or the same elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale for purposes of clarification. [0030] As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”

[0031] Furthermore, when introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment,” “an embodiment,” or “some embodiments” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, the phrase A “based on” B is intended to mean that A is at least partially based on B. Moreover, unless expressly stated otherwise, the term “or” is intended to be inclusive (e.g., logical OR) and not exclusive (e.g., logical XOR). In other words, the phrase A “or” B is intended to mean A, B, or both A and B.

[0032] Certain terms are used throughout the description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name, but not function.

[0033] For decades, humans have relied on resources found below the earth’s surface to meet increasing energy demands. These resources include but are not limited to natural gas, coal, hydrocarbons, petroleum, and other materials suitable to generate energy for consumption by humans. In some cases, these resources may be harvested as part of a deep- sea mining operation to recover resources from below a sea floor. As energy demands increase, significant efforts are expended by drilling and production systems to extract an appropriate supply of energy to meet the increasing demand. Included in these efforts are systems and methods that enable expanded extraction of these subterranean resources at increased levels of efficiency. In some cases, some drilling and production systems may operate at elevated operational temperatures, elevated operational pressures, and other elevated operational parameters to meet the increasing demand. In this way, these elevated operational characteristics may lead to cases where improved maintenance is beneficial to the operations of these drilling and production systems. Additionally, various components within the drilling and production systems may be improved to handle the elevated operational parameters of these improved systems and methods.

[0034] In some cases, as a portion of these improved maintenance procedures, or due to specific situations, wellbore elements are sometimes required to be retrieved from wells. For example, a production packer may be retrievable from a well for operations such as secondary recoveries, re-completions, or to change out the production tubing. In other situations, an electric submersible pump (ESP) may be retrieved from the well due to a failure in the ESP, performance issues, maintenance and replacement, or other appropriate reasons. In situations like this, specialized connectors for connecting wellbore elements that are easily disconnectable may be used. In another example, an upper completion portion of a borehole tubing assembly may require periodic maintenance and may be removed from a lower completion portion of the borehole tubing assembly. Also, to facilitate the functionality of these expanded drilling operations at elevated temperatures and elevated pressures, improved sealing and connectors may be introduced to various components within the borehole tubing assembly. Connectors are commonly used to connect wellbore elements for run in hole. These connectors secure the connection between two wellbore elements by preventing potential movements between the wellbore elements during various wellbore operations. An example of such a connector can be found in U.S. Patent Application No. US 7,757,773 B2 in the form of a snap latch. The disconnection process of the connector requires a force applied to the tubing or the annulus. The disconnection process is complex and convoluted. Therefore, there is a need to provide an improved connector which simplifies the disconnection process. In this way, improved systems and/or methods for disconnecting and re-connecting these various wellbore elements may be advantageous. [0035] Present embodiments include specialized connectors, coupling methods, and hydraulic and sealing solutions that enable successful operation of the specialized connectors and coupling methods. In one embodiment, a cut-to-release (CTR) connector may improve methods for disengaging upper completions from lower completions in the borehole. In some embodiments, the CTR connector may utilize a support sleeve to enable the CTR connector to enter the borehole in a run-in-hole (RIH) operation, couple with an upper collector assembly, disengage teeth from a snap latch portion of the support sleeve from a lower completion, thus enabling the entire upper completion to be removed from the borehole in a pull out of hole (POOH) operation. Further, the CTR connector may be assembled in multiple configurations. That is, a first configuration of the CTR connector may be organized such that multiple borehole operations may be completed efficiently in a single trip downhole, thereby receiving a designation as a “Single Trip” configuration. Additionally, a second configuration of the CTR connector may be organized with fewer components in a simplified set-up, while also providing for two or more trips downhole to complete a maintenance operation, thereby receiving a designation as a “Multiple Trip” configuration. While various advantages and tradeoffs exist for each configuration, present embodiments enable an operator the flexibility to modify the CTR connector to swap between both configurations based on the operational inputs of a particular downhole operation.

[0036] In some cases, an electric motor may be coupled to a locking latch assembly of the upper completion. In this embodiment, the electric motor may be configured to receive an electrical signal and output a mechanical actuation to a connection arm that further couples to the locking latch assembly. By virtue of this electrical signal, actuatable protrusions disposed about an outer circumferential surface of the locking latch assembly may be mechanically actuated, such that the locking latch assembly may disengage from the lower completion. For example, these actuatable protrusions may be biased such that in a default configuration, the actuatable protrusions may be in an extended position, enabling the locking latch assembly to secure the upper completion with the lower completion. That is, the electric motor may cause the actuatable protrusions to mechanically actuate to a retracted position, providing for the removal of the upper completion via an electro-mechanical operation. [0037] In other embodiments, an electro-actuated disconnection latch system may provide for methods for disconnecting the upper completion from the lower completion via electrical inputs. This electro-activated solution may utilize at least some of the mechanical parts of various mechanical systems (e.g., cut-to-release mechanisms), while providing a solution that may be operated via a permanent downhole cable (PDC) that is configured to actuate the support sleeve. As part of the electro-activated solution, an inductive male coupler electrically couples to an inductive female coupler to secure the connection between the upper and lower completions. In this way, an electrical signal may be provided from a surface unit to the electro-actuated disconnection latch system via the PDC, causing the latch system to de-couple, enabling the upper completion to be removed from the lower completion.

[0038] With the introduction of the inductive type couplers, additional inductive and electro-magnetic fields may be introduced downhole during operation. In some cases, hydraulic systems utilized to operate downhole tubing may affect or be affected by the various fields generated by the couplers. To avoid this potential situation, present embodiments may provide for a modified hydraulic system in a downhole application to properly function in conjunction with the electro actuated disconnection latch system. In such embodiments, a system may utilize hydraulic lines circumferentially disposed about a stinger assembly that enables fluid connectivity between the upper completion and the lower completion, and to further components located further downhole. Present embodiments provide for improved hydraulic connectors that resist these fields generated by the inductive couplers as well as improved sealing solutions to properly operate and withstand the elevated pressures and elevated temperatures experienced during various drilling operations. Taken together, present embodiments enable improved operational capabilities of drilling and production systems, including expanded operational capacities and characteristics to increase productivity and improve efficiency of associated operations.

[0039] Turning to the drawings, FIG. 1 illustrates a cross-sectional side view of an embodiment of a cut-to-release (CTR) connector 12 as a portion of a downhole tubing assembly 10, in accordance with aspects of the present disclosure. As illustrated, the CTR connector 12 includes an anti-rotation housing 14, a mandrel 16, a support sleeve 18, a CTR collet 20, a collet receptacle 22, an upper collector 24, and an upper nut 26, each having a generally annular shape. The anti-rotation housing 14 may include an annular outer circumferential surface 42 and an annular inner circumferential surface 44 with a planar interior surface 46 (e.g., disc-shaped shoulder) at a first end 48 of the anti-rotation housing 14. The annular inner circumferential surface 44 may receive the upper nut 26 such that the upper nut 26 may slidably translate along the annular inner circumferential surface 44 of the anti-rotation housing 14. In some embodiments, as an upper completion 50 of the downhole tubing assembly is removed from the borehole, the upper nut 26 may interface with the planar interior surface 46 of the anti-rotation housing 14. As discussed in more detail below, the anti-rotation housing 14 may removably couple (e.g., via a threaded connection 34) to the CTR collet 20 and be configured to lift the CTR collet 20 out of the borehole via the threaded connection 34.

[0040] In one or more embodiments, the CTR connector 12 may include a mandrel 16 for connecting an upper completion 50 and a lower completion 60, a support sleeve 18 enveloping an outer surface 52 of the mandrel 16, and a CTR collet 20, with the “teeth” of the CTR collet 20 supported by the support sleeve 18, each having a generally annular shape. The mandrel 16 may be a bar, shaft, spindle, or otherwise tubular component that runs along an axial length of the downhole tubing assembly 10. As illustrated, the mandrel 16 may include an annular outer surface 52 configured to interface with various components within the upper completion 50. For example, the annular outer surface 52 of the mandrel 16 may include a first outer thread profile 32 configured to interface with an inner threaded surface of the support sleeve 18 and a second outer thread profile 36 configured to interface with an inner threaded surface of the upper nut 26. In one embodiment, as the mandrel 16 is removed from the borehole as a portion of the upper completion 50, the first outer thread profile 32 couples to the support sleeve 18 and thereby causes the support sleeve 18 to slide with the mandrel 16 up and out of the borehole.

[0041] As the support sleeve 18 slides out of the borehole removably coupled to the mandrel 16, the support sleeve 18 may slide along an interior annular surface of the CTR collet 20. In certain embodiments, prior to the mandrel 16 and support sleeve 18 being removed from the borehole, the support sleeve 18 may provide a radial force to lock the CTR collet 20 into place within the collet receptacle 22. In the illustrated embodiment, the CTR collet 20 includes multiple biasing members 38 (e.g., teeth) that are disposed around an outer annular surface of the CTR collet 20. In some embodiments, multiple cutouts and/or slots are circumferentially disposed around the outer annular surface among the multiple biasing members 38, thereby enabling the multiple biasing members to flex and plastically deform into a retracted or extended position. The multiple biasing members 38 may normally (e.g., when not interacting with the support sleeve 18) be in a retracted position (e.g., radially retracted position), such that the CTR collet 20 may slide into the collet receptacle 22 without interference between the components. As the support sleeve 18 slides along an interior surface of the CTR collet 20, the multiple biasing members 38 are pushed radially outward into an extended position (e g., radially extended position), thereby causing the multiple biasing members to interface with the collet receptacle 22 to create a locking mechanism and axially locking the CTR collet 20 in place within the collet receptacle 22. Additionally or alternatively, as the support sleeve 18 is removed with the mandrel 16 out of the borehole, and the support sleeve 18 is no longer interfacing with the interior surface of the CTR collet 20 and pushing the multiple biasing members 38 into the extended position, the multiple biasing members 38 may return to the retracted position, thereby enabling the CTR collet 20 to be removed from the collet receptacle 22.

[0042] As mentioned above, the CTR collet 20 also includes a threaded connection 34 that may be configured to removably couple the CTR collet 20 with the anti-rotation housing 14. As the mandrel 16 and support sleeve 18 are pulled out of hole (POOH), the mandrel 16 may slide through a cylindrical opening in the anti-rotation housing 14. In some embodiments, the support sleeve 18 may slide with the mandrel 16 until it axially abuts with the planar interior surface 46 of the anti -rotation housing 14. At this point, the support sleeve 18 may have completely translated away from the CTR collet 20, such that the support sleeve 18 no longer provides the radial force to engage the multiple biasing members 38 with the collet receptacle 22. As the support sleeve 18 abuts the planar interior surface 46 of the antirotation housing 14 and the mandrel 16 continues to be POOH, the anti-rotation housing 14 may be lifted and begin to translate with the support sleeve 18 and the mandrel 16 via the interface between the support sleeve 18 and the planar interior surface 46. In other embodiments, the upper nut 26 may provide the interface between the planar interior surface 46 and the components translating with the mandrel 16 up and out of the borehole.

[0043] In this way, in some embodiments, as the support sleeve 18 enacts a lifting force on the planar interior surface 46, thereby lifting the anti-rotation housing 14, the anti-rotation housing lifts the CTR collet via the threaded interface 34. As discussed previously, as the support sleeve 18 abuts the planar interior surface 46, the multiple actuatable members 38 may have returned to their normal retracted position, thereby enabling the CTR collet 20 to slidably disengage from the collet receptacle 22. Taken together, the anti-rotation housing 14, the mandrel 16, the support sleeve 18, and the CTR collet 20 make up a portion of the upper completion 50 that may be removed from the borehole during a maintenance operation, or other various drilling and borehole operations. As the upper completion 50 is removed, the lower completion 60, including the collet receptacle 22 may remain in the borehole.

[0044] FIGS. 2-5 illustrate various steps in a process 600 for utilizing a cut-to-release (CTR) connector 12 to separate an upper completion 50 from a lower completion 60 of a downhole tubing assembly 10, as further depicted in a flowchart illustrated in FIG. 6, in accordance with aspects of the present disclosure. To facilitate discussion and illustrate various steps in the process 600, FIGS. 2-6 will be described in the context of carrying out the process 600. In particular, the process 600 operates a cutter 200 to make a cut at a determined position on the CTR connector 12 of FIGS. 1-5 to separate the upper completion 50 from the lower completion 60 of the downhole tubing assembly 10, enabling the upper completion 50 to be removed from the borehole for maintenance, drilling procedures, or other appropriate operational purposes.

[0045] Any suitable device (e.g., a controller 230) that controls components of the downhole tubing assembly 10, such as a processor 234 (e.g., processing circuitry), may perform the process 600. In some embodiments, the process 600 may be implemented by executing instructions 236 stored in a tangible, non-transitory, computer-readable medium, such as a memory 232 or storage, using the processing circuitry 234. For example, the process 600 may be performed at least in part by one or more software components, such as an operating system of an electronic device, one or more software applications of the electronic device, and the like. The controller 230 may receive a communication signal from a surface component (e.g., surface computer) via communication circuitry 238 disposed within the controller 230. In other embodiments, the controller 230 may automatically execute the instructions 236 independent of any electrical and/or communication signal received from the surface computer. While the process 600 is described using steps in a specific sequence, it should be understood that the present disclosure contemplates that the described steps may be performed in different sequences than the sequence illustrated, the described steps may be performed simultaneously, and certain described steps may be skipped or not performed altogether.

[0046] At block 610, and as illustrated in FIG. 2, the controller 230 may output an electronic or communication signal to a running and retrieval drive system of the cutter 200 to position the cutter 200 at a first position 210 within the CTR connector 12. That is, the cutter 200 is first sent downhole through the upper completion 50 to a specified target within the mandrel 16. In some embodiments, the first position 210 may be along an axial direction 220 parallel to a length of the downhole tubing assembly 10, and in other embodiments, the first position 210 may fall within the upper completion 50. The cutter 200 may travel in the axial direction 220 along and within an inner circumferential surface of the mandrel 16 to arrive at the first position 210.

[0047] At block 620, and as illustrated by FIG. 3, the controller 230 may output an electronic signal to a cutting drive system of the cutter 200 to actuate the cutter 200 to initiate a cut 300 in the mandrel 16. In some embodiments, the cutter 200 may cut through the inner circumferential surface of the mandrel 16 through to the outer circumferential surface of the mandrel 16, thereby separating the mandrel 16 into an upper portion of the mandrel 320 and a lower portion of the mandrel 330. The cut 300 may span for a first length 310, and in some embodiments, the first length 310 may extend over various lengths (e.g., 5 cm, 15 cm, 50 cm, 1 meter, etc.). In some embodiments, the first length 310 may correspond with a thickness of the cutter 200.

[0048] At block 630, as illustrated by FIG. 3, the controller 230 may output an electronic and/or communication signal to the running and retrieval drive system of the cutter 200 to lift the cutter 200 out of the borehole in a pull out of hole (POOH) operation. That is, the cutter 200 may retract back through the interior circumferential surface of the upper portion of the mandrel 320 and the CTR connector 12 back up the borehole. By virtue of the cutter 200 actuating and milling a cut 300 with the first length 310, the upper completion 50 may be removed from the borehole and thereby removed from the downhole tubing assembly 10. As discussed in more detail below, as the upper completion 50 is lifted out of the borehole, various parts and components may translate relative to one another within the downhole tubing assembly 10 to enable removal of the upper completion 50.

[0049] At block 640, as illustrated by FIG. 4, the mandrel 16 (e.g., upper portion of the mandrel 320) may be lifted up the borehole to initiate removal of the upper completion 50 from the borehole. In some embodiments, the operation may be referred to as the POOH operation. Due to the threaded connection at the first outer threaded profile 32 between the mandrel 16 and the support sleeve 18, as the upper portion of the mandrel 320 starts to lift out of the borehole, the support sleeve 18 also starts to translate with the upper portion of the mandrel 320.

[0050] At block 650, as illustrated by FIG. 4, as the support sleeve 18 translates with the upper portion of the mandrel 320, the support sleeve 18 may translate until a planar surface of the support sleeve 18 may abut a planar interior surface 46 of an upper collector assembly 340. That is, as the support sleeve 18 engages with the planar interior surface 46, the lifting force experienced by the upper portion of the mandrel 320 and the support sleeve 18 may be translated to the upper collector assembly 340. Additionally or alternatively, the upper collector assembly 340 may be coupled to a cut-to-release (CTR) collet 20 via the threaded connection 34 between the upper collector assembly 340 and the CTR collet 20. So, by extension, the lifting force experienced by the collector assembly 340 may be translated to the CTR collet 20 to facilitate lifting the CTR collet 20 out of the borehole as a portion of the upper completion 50.

[0051] At block 660, as illustrated by FIG.4, lifting the support sleeve 18 away from an engagement within the CTR collet 20, the multiple biasing members 38 (e.g., teeth) of the CTR collet 20 may return to a retracted position and disengage from the collet receptacle 22. As discussed previously, the multiple biasing members 38 may be actuated into an extended protruded position due to the support sleeve 18 assembling into the CTR collet 20, but as the support sleeve 18 translates up the borehole and away from engagement with the CTR collet 20, the multiple biasing members 38 may return to their normal, retracted positions. At this point in time, the teeth of the CTR collet 20 are free to collapse inwards, as the contact between the support sleeve 18 and the CTR collet 20 is removed. By virtue of this normal configuration, the CTR collet 20 may be removed from the collet receptacle 22, such that the CTR collet 20 may be removed with the upper completion 50.

[0052] At block 670, and as illustrated in FIG. 5, as the CTR collet 20 is now disengaged from the collet receptacle 22, the upper completion 50 may be lifted out of the borehole as part of the POOH operation. In some embodiments, the upper completion 50 may then receive various maintenance operations, quality checks, and other appropriate inspections once removed from the borehole.

[0053] In one or more embodiments, the CTR connector 12 may be converted to run multi-stage completions in a dual trip configuration before a run-in-hole (RIH) operation. FIG. 7A is a perspective view of an assembled connector in a single trip configuration 700 and FIG. 7B is a cross-sectional side view of the parts and components that may be removed during the conversion from the single trip configuration 700. In some embodiments, a single trip configuration 700 enables the operator to run in hole (RIH) multiple stage completions in a single trip, thereby reducing an operating time associated with installing the completions (e.g., the upper completion 50, the lower completion 60, etc.) in the borehole. By utilizing the single trip configuration 700, operators may efficiently install the completions, leading to substantial (1 day, 2 days, 5 days, 10 days, etc.) time savings on the installation operations. Additionally, FIG 8 is a perspective view of an assembled connector in a dual trip configuration 750. For example, as shown in the illustrated embodiments, the anti-rotation housing 14, the upper nut 26, the upper collector 24, the support sleeve 18, and the CTR collet 20 may be removed from the single trip configuration 700 and removed up while slidingly translating up over an upper bore tubing 702. To complete the changeover to the dual trip configuration 750, a snap latch 752 may slide over the upper bore tubing 702 to assemble onto the mandrel 16. In this embodiment, the snap latch 752 replaces the CTR mechanism of the connector. In certain embodiments, the operator may utilize a dual trip configuration 750 to redress an upper completion 50 for maintenance purposes and/or to provide enhances control of characteristics within the borehole. For example, in situations where the drilling and production systems experience losses or fluctuations in well pressure, the operator may prefer to utilize a dual trip configuration 750.

[0054] FIG. 9 is a cross-sectional side view of an embodiment of an electric cut-to-release (CTR) connector 900 that may be utilized in an electro-actuated disconnection latch system, in accordance with aspects of the present disclosure. In the illustrated embodiment, the electric CTR connector 900 includes an electro mechanical actuator (EMA) 902 that may couple with an embodiment of a support sleeve 908 via a threaded connecting rod 906. For example, the EMA 902 may include an electric drive or motor coupled to a mechanical element, such as a shaft, a gear, a transmission, or the like. In the illustrated embodiment, the EMA 902 couples to and/or includes a shuttle connector 903, which may represent the mechanical element driven by the electric drive or motor. As illustrated, the EMA 902 (e.g., via the shuttle connector 903) may couple to the threaded connecting rod 906 via a threaded interface 904. In some embodiments, the shuttle connector 903 and the threaded connecting rod 906 may be part of the EMA 902. In some embodiments, the threaded interface 904 may be disposed within the shuttle connector 903, wherein the EMA 902 is configured to rotate the shuttle connector 903 about the threaded connecting rod 906 to convert a rotational motion into an axial motion of the threaded connecting rod 906 in an axial direction 920 parallel to the length of the mandrel 916. That is, the electrical energy input received at the EMA 902 enables the EMA 902 to drive the rotational motion of the shuttle connector 903 about the threaded connecting rod 906 to provide an axial, mechanical force. As illustrated, the threaded connecting rod 906 threads in and out of the shuttle connector 903 depending on the rotational direction. For example, rotation of the shuttle connector 903 in a first rotational direction (e.g., clockwise rotation) causes axial motion of the threaded connecting rod 906 in a first axial direction, whereas rotation of the shuttle connector 903 in a second rotational direction (e.g., counter clockwise rotation) causes axial motion of the threaded connecting rod 906 in a second axial direction opposite from the first axial direction. In other embodiments, the EMA 902 may electrically couple to a permanent downhole cable 918 (PDC) that is configured to transmit electrical signals from the surface to the downhole components. In this way, a power source at the surface may send an electrical signal downhole via the PDC 918 configured to disconnect the electric CTR connector 900. In one embodiment, the controller 230 may be communicatively coupled to the PDC 918, such that the controller 230 may automatically output the electric signal to the EMA 902 via the PDC 918.

[0055] As discussed above, the EMA 902 and the shuttle connector 903 may be configured to convert the electrical energy from the PDC 918 into mechanical energy. In the illustrated embodiment, the shuttle connector 903 may removably couple to the threaded connecting rod 906 via the threaded interface 904. Further, the threaded connecting rod 906 may couple to the support sleeve 908 via a fixedjoint or fixed coupling 910 (e.g., anti-rotation joint), which prevents rotation of the threaded connecting rod 906 relative to the support sleeve 908 while imparting an axial force in response to axial motion of the threaded connecting rod 906 relative to the shuttle connector 903. In this way, as the shuttle connector 903 outputs the converted mechanical energy in the axial direction 920, the support sleeve 908 may be pulled by the shuttle connector 903 via the threaded connection 904, the fixed joint 910, and the threaded connecting rod 906. That is, the support sleeve 908 may translate up the borehole and away from engagement with the cut-to-release collet 20 or snap latch 752 - depending on the configuration of the electric CTR connector 900. That is, the electric CTR connector 900 may be compatible with a single trip configuration as illustrated by element 700 in FIG.7 or in a dual trip configuration as illustrated by element 750 in FIG. 8.

[0056] FIG. 10 is a cross-sectional side view of an embodiment of the electric cut-to- release (CTR) connector 900 that may be utilized in the electro-actuated disconnection latch system, in accordance with aspects of the present disclosure. As illustrated, the EMA 902 may have successfully received an electrical signal via the PDC 918, and the EMA 902 may have begun to pull the support sleeve 908 away from the CTR collet 20, thereby disengaging the teeth of the CTR collet 20 from the collet receptacle 22. By virtue of the electric CTR connector 900 and the electro-actuated disconnection latch system, the upper completion 50 may be removed from the lower completion 60 without relying on a cutter 200 being RIH to mechanically make a cut 300 in the mandrel 16, 916. [0057] In some cases, the downhole tubing assembly 10 may utilize an inductive coupler as a means for disconnecting an upper completion 50 from a lower completion 60. In this way, an operator at the surface may output an electrical signal downhole causing the inductive coupler 1100 to enable the connection to disengage, thereby permitting the upper completion 50 to be removed in a POOH operation. In other embodiments, the controller 230 from FIGS. 2-6 may automatically output the electrical signal downhole to cause the inductive couple to engage or disengage the connection. That is, the controller 230 may store instructions 236 configured to, when executed, cause the processing circuitry 234 to execute operations including enabling or disabling the inductive coupler 1100. For example, FIG. 1 1 is a perspective view of an embodiment of a combination of a hydraulic stinger assembly 1000 that assembles into a hydraulic receptacle assembly 1050, in accordance with aspects of the present disclosure. Additionally, the aforementioned inductive coupler 1100 may provide for a mechanism to secure the hydraulic stinger assembly 1000 within the hydraulic receptacle assembly 1050. Additionally or alternatively, present embodiments further include improved metallurgical qualities of the various components within the hydraulic stinger assembly 1000 and the hydraulic receptacle assembly 1050 that enable the components to function as intended (e.g., enable hydraulic fluid communication between the surface and other various downhole tools) without interference from the inductive coupler 1100. As discussed in more detail below, the hydraulic stinger assembly 1000 may include an improved sealing design for the hydraulic connectors disposed within the hydraulic stinger assembly 1000 and the downhole tubing assembly 10 to ensure successful operation in elevated operating temperatures and operating pressures.

[0058] In FIG. 11, the hydraulic stinger assembly 1000 includes a latch 1002 and a hydraulic stinger 1004 and the hydraulic receptacle assembly 1050 includes a hydraulic receptacle 1052 and a collet housing 1054. In some embodiments, the latch 1002 may be configured to mechanically secure with the collet housing 1054 to secure a mechanical connection between the hydraulic stinger assembly 1000 and the hydraulic receptacle assembly 1050. As they assemble into one another, the hydraulic stinger 1004 may align with the hydraulic receptacle 1052, as discussed further in FIG. 12 below. However, in other embodiments, a hydro-electric wet mate (HEWM) connector 1200 utilizes the inductive coupler 1100 to ensure the connection between the hydraulic stinger assembly 1000 and the hydraulic receptacle assembly 1050.

[0059] FIG. 12 is a cross-sectional side view of a portion of the downhole tubing assembly 10, and in particular the portion of the downhole tubing assembly where the hydraulic stinger 1004 overlaps with the hydraulic receptacle 1052, in accordance with aspects of the present disclosure. In the illustrated embodiment, the hydraulic stinger 1004 includes multiple downhole hydraulic lines 1350 configured to fluidly connect the surface with multiple downhole tooling. In some embodiments, the hydraulic lines 1350 may be utilized for actuation of downhole tooling, chemical injection, or other various downhole operations. In other embodiments, the hydraulic stinger 1004 may include multiple hydraulic lines 1350 circumferentially disposed (e.g., spaced at different circumferential positions) around an outer circumferential surface of the hydraulic stinger 1004. In some cases, the hydraulic stinger may include seven (7) hydraulic lines, but embodiments that include greater or fewer hydraulic lines 1350 (e.g., 1, 2, 3, 4, 5, 6, 8, 9, 10, etc.) may be considered within the scope of the present disclosure.

[0060] In the illustrated embodiment, the hydraulic line 1350 is shown to intersect with a hydraulic connector 1300. As shown, the hydraulic connector 1300 is configured to fluidly couple the hydraulic line 1350 with a lower downhole hydraulic line 1360 that runs along an outer circumferential surface of the downhole tubing assembly 10. As discussed previously, the downhole tubing assembly 10 may be configured to operate in harsher conditions (e.g., elevated pressures, elevated temperatures, more stab-in and/or stab-out couplings, harsh debris, etc.). As such, the hydraulic connector 1300 may enable the hydraulic fluid to flow as intended without interruptions or interferences from the environment.

[0061] FIG. 13A is a schematic view of a hydraulic connector 1300 positioned in the hydraulic receptacle assembly 1050 and FIG. 13B is a perspective view of the hydraulic connector 1300, in accordance with aspects of the present disclosure. In the illustrated embodiment, the hydraulic connector 1300 includes a tube 1302, an outer nut 1304, an inner lock collet 1306, straight connector 1308, and a tapered seal 1310. In some embodiments, the tube 1302 runs along a length of the hydraulic connector 1300 with the straight connector 1308 enveloping the outer annular surface of the tube 1302. The inner lock collet 1306 may abut with a first end of the straight connector 1308, and as the outer nut 1304 threadably couples to the first end of the straight connector 1308, the inner lock collet 1306 may be compacted to match a profile of the tube 1302. Additionally, the straight connector 1308 may include a second end that interfaces with the tapered seal 1310, such that the tapered seal 1310 may be configured to block out any and all harsh debris from entering the hydraulic lines 1350, 1360, while keeping the pressurized hydraulic fluid within the hydraulic lines 1350, 1360. In some embodiments, the tapered seal 1310 may be a metal end cap seal having a geometry capable of bonding a large volume of elastomer to metal end caps. The elastomer may be of various types, including hydrogenated nitrile butadiene rubber (HNBR), fluorocarbon rubber (FKM), perfluoroelastomer (FFKM), or otherwise appropriate sealing materials. In other embodiments, the tapered seal 1310 may be a dual mesh seal that utilizes Inconel mesh bonded with FFKM. In any case, this improved tapered seal 1310 may provide for enhanced resistance to shearing forces, chemical deterioration, and/or extrusion when the tapered seal 1310 is exposed to harsh environments.

[0062] In certain embodiments, the hydraulic connector 1300 and associated components may be made from materials configured to not interfere with the inductive coupling 1100. For example, the hydraulic connector 1300 may be made from stainless steel, a nickel alloy, non-ferrous stainless steel, or otherwise appropriate materials. By utilizing this improved sealing design, operators may fluidly connect the upper completion 50 with the lower completion 60 and operate the system at elevated pressures and temperatures.

[0063] FIG. 14 is a cross-sectional side view of the inductive coupler 1100 utilized in the downhole tubing assembly 10, in accordance with aspects of the present disclosure. The inductive coupler 1100 includes a power section 1102, a telepathy section 1104, a female inductive coupler 1106, and a male inductive coupler 1108. In the illustrated embodiment, the telepathy section 1104 of the inductive coupler 1100 may be configured to receive a communication signal from the surface that provides an indication of whether the inductive coupler should power on to engage the female inductive coupler 1106 with the male inductive coupler 1108, or cycle off to enable separation of the inductive coupler 1100. Based on this received communication signal, the telepathy section 1104 may communicate with the power section 1102 of the inductive coupler 1100 to keep the engagement between the male inductive coupler 1108 and the female inductive coupler 1106, or power off the connection, thereby enabling the male inductive coupler 1108 to separate and disconnect from the female inductive coupler 1106.

[0064] The technical effect of the disclosed embodiments includes improved operational capabilities of drilling and production systems, including expanded operational capacities and characteristics to increase productivity and improve efficiency of associated operations. For example, present embodiments provide improved methods for disconnecting wellbore elements while the elements are disposed downhole in a wellbore, while providing for improved connection and sealing capabilities to enable the downhole tubing assembly and associated components to function at elevated pressures and temperatures. Additionally, present embodiments enable an operator the flexibility to modify the CTR connector to swap between a single trip configuration and a dual trip configuration based on the operational inputs of a particular downhole operation. In addition to mechanical solutions, present embodiments include electro-mechanical solutions for efficiently disconnecting wellbore elements via electrical signals communicated via a permanent downhole cable.

[0065] The subject matter described in detail above may be defined by one or more clauses, as set forth below.

[0066] In an embodiment, a method for disconnecting an upper completion from a lower completion within a downhole tubing assembly includes positioning a cutter at a first position, actuating the cutter to initiate a cut in a mandrel, such that the mandrel is disposed within the downhole tubing assembly, and such that the mandrel is separated into an upper portion of the mandrel and a lower portion of the mandrel by the cut, lifting the cutter out of the downhole tubing assembly, lifting the upper portion of the mandrel as a part of a pull out of hole (POOH) operation, wherein the upper portion of the mandrel is configured to pull a support sleeve during the POOH operation, disengaging a locking mechanism between a cut- to-release (CTR) collet from the lower completion, and lifting the upper completion up from the downhole tubing assembly, wherein the upper completion comprises the upper portion of the mandrel, the support sleeve, and the CTR collet. [0067] The method of the preceding embodiment, wherein the upper completion is configured to run in hole (RIH) in a single trip configuration.

[0068] The method of any preceding embodiment, wherein the cutter includes a running and retrieval drive system communicatively coupled to a controller.

[0069] The method of any preceding embodiment, wherein the controller is configured to automatically output a communication signal to the running and retrieval drive system to initiate the lifting of the cutter out of the downhole tubing assembly.

[0070] The method of any preceding embodiment, wherein the locking mechanism comprises multiple biasing members disposed on an outer annular surface of the CTR collet.

[0071] The method of any preceding embodiment, wherein the multiple biasing members include a plurality of cutouts, slots, or a combination thereof, and wherein each biasing member of the multiple biasing members is configured to actuate from a radially retracted position to a radially extended position.

[0072] The method of any preceding embodiment, wherein the multiple biasing members, when actuated to the radially extended position, are configured to axially lock the CTR collet to a collet receptacle.

[0073] The method of any preceding embodiment, wherein the mandrel is configured to removably couple to the support sleeve via a threaded connection.

[0074] In an embodiment, a system includes an electro-actuated disconnection latch system that includes an electric cut-to-release (CTR) connector, an electro-mechanical actuator (EMA) configured to convert electrical energy into mechanical energy, such that the EMA is disposed on the electric CTR connector, and a support sleeve configured to couple to the EMA, such that the support sleeve is configured to translate axially in response to receiving the mechanical energy from the EMA.

[0075] The system of the preceding embodiment, wherein the EMA includes an electric motor, a shuttle connector coupled to the electric motor, wherein the electric motor is configured to cause rotation of the shuttle connector in response to the electrical energy, and the shuttle connector includes a threaded interface, and a threaded connecting rod coupled to the threaded interface, wherein the threaded connecting rod is configured to translate axially in response to the rotation of the shuttle connector.

[0076] The system of any preceding embodiment, wherein the shuttle connector is configured to rotate in a first rotational direction to cause an axial motion of the threaded connecting rod in a first axial direction, wherein the shuttle connector is configured to rotate in a second rotational direction to cause an additional axial motion of the threaded connecting rod in a second axial direction, and the second axial direction is opposite from the first axial direction.

[0077] The system of any preceding embodiment, wherein the threaded connecting rod is configured to couple to the support sleeve via a fixed joint, a fixed coupling, or a combination thereof.

[0078] The system of any preceding embodiment, wherein the electric CTR connector is configured to be compatible with an upper completion in a single trip configuration or the upper completion in a dual trip configuration.

[0079] The system of any preceding embodiment, wherein the EMA is electrically coupled to a permanent downhole cable (PDC), and the PDC is configured to supply an electric signal to the EMA.

[0080] The system of any preceding embodiment, wherein the PDC is communicatively coupled to a controller, wherein the controller is configured to automatically output the electric signal to the EMA via the PDC.

[0081] In one embodiment, a system includes a controller that includes a memory and processing circuitry, wherein the memory stores instructions, that when executed by the processing circuitry, cause the processing circuitry to perform operations including outputting an electrical signal to an inductive coupler, such that the inductive coupler includes a male inductive coupler and a female inductive coupler of a downhole assembly, and such that the electrical signal causes the male inductive coupler to couple with the female inductive coupler, and outputting an additional electrical signal to the inductive coupler to disengage the male inductive coupler from the female inductive coupler. [0082] The system of the preceding embodiment, wherein the inductive coupler is configured to couple an upper completion of the downhole assembly with a lower completion of the downhole assembly.

[0083] The system of any preceding embodiment, wherein the upper completion includes a hydraulic stinger assembly.

[0084] The system of any preceding embodiment, wherein the lower completion includes a hydraulic receptacle, and the hydraulic receptacle is configured to receive the hydraulic stinger assembly.

[0085] The system of any preceding embodiment, wherein the hydraulic receptacle receives the hydraulic stinger assembly via a hydro-electric wet mate (HEWM) connector.

[0086] The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the disclosure to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrated and described may be re-arranged, and/or two or more elements may occur simultaneously. The embodiments were chosen and described in order to best explain the principles of the disclosure and its practical applications, to thereby enable others skilled in the art to best utilize the disclosure and various embodiments with various modifications as are suited to the particular use contemplated.

[0087] Finally, the techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for (perform]ing (a function]...” or “step for (perform]ing (a function], . it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

Claims

1. A method for disconnecting an upper completion from a lower completion within a downhole tubing assembly, comprising: positioning a cutter at a first position; actuating the cutter to initiate a cut in a mandrel, wherein the mandrel is disposed within the downhole tubing assembly, and wherein the mandrel is separated into an upper portion of the mandrel and a lower portion of the mandrel by the cut; lifting the cutter out of the downhole tubing assembly; lifting the upper portion of the mandrel as a part of a pull out of hole (POOH) operation, wherein the upper portion of the mandrel is configured to pull a support sleeve during the POOH operation; disengaging a locking mechanism between a cut-to-release (CTR) collet from the lower completion; and lifting the upper completion up from the downhole tubing assembly, wherein the upper completion comprises the upper portion of the mandrel, the support sleeve, and the CTR collet.

2. The method of claim 1, wherein the upper completion is configured to run in hole (RIH) in a single trip configuration.

3. The method of claim 1, wherein the cutter comprises a running and retrieval drive system communicatively coupled to a controller.

4. The method of claim 3, wherein the controller is configured to automatically output a communication signal to the running and retrieval drive system to initiate the lifting of the cutter out of the downhole tubing assembly.

5. The method of claim 1, wherein the locking mechanism comprises multiple biasing members disposed on an outer annular surface of the CTR collet.

6. The method of claim 5, wherein the multiple biasing members comprise a plurality of cutouts, slots, or a combination thereof, and wherein each biasing member of the multiple biasing members is configured to actuate from a radially retracted position to a radially extended position.

7. The method of claim 6, wherein the multiple biasing members, when actuated to the radially extended position, are configured to axially lock the CTR collet to a collet receptacle.

8. The method of claim 1 , wherein the mandrel is configured to removably couple to the support sleeve via a threaded connection.

9. A system, comprising: an electro-actuated disconnection latch system, comprising: an electric cut-to-release (CTR) connector; an electro-mechanical actuator (EMA) configured to convert electrical energy into mechanical energy, wherein the EMA is disposed on the electric CTR connector; and a support sleeve configured to couple to the EMA, wherein the support sleeve is configured to translate axially in response to receiving the mechanical energy from the EMA.

10. The system of claim 9, wherein the EMA comprises: an electric motor; a shuttle connector coupled to the electric motor, wherein the electric motor is configured to cause rotation of the shuttle connector in response to the electrical energy, and the shuttle connector comprises a threaded interface; and a threaded connecting rod coupled to the threaded interface, wherein the threaded connecting rod is configured to translate axially in response to the rotation of the shuttle connector.

11. The system of claim 10, wherein the shuttle connector is configured to rotate in a first rotational direction to cause an axial motion of the threaded connecting rod in a first axial direction, wherein the shuttle connector is configured to rotate in a second rotational direction to cause an additional axial motion of the threaded connecting rod in a second axial direction, and the second axial direction is opposite from the first axial direction.

12. The system of claim 10, wherein the threaded connecting rod is configured to couple to the support sleeve via a fixed joint, a fixed coupling, or a combination thereof.

13. The system of claim 9, wherein the electric CTR connector is configured to be compatible with an upper completion in a single trip configuration or the upper completion in a dual trip configuration.

14. The system of claim 9, wherein the EMA is electrically coupled to a permanent downhole cable (PDC), and the PDC is configured to supply an electric signal to the EMA.

15. The system of claim 14, wherein the PDC is communicatively coupled to a controller, wherein the controller is configured to automatically output the electric signal to the EMA via the PDC.

16. A system, comprising: a controller comprising a memory and processing circuitry, wherein the memory stores instructions, that when executed by the processing circuitry, cause the processing circuitry to perform operations comprising: outputting an electrical signal to an inductive coupler, wherein the inductive coupler comprises a male inductive coupler and a female inductive coupler of a downhole assembly, and wherein the electrical signal causes the male inductive coupler to couple with the female inductive coupler; and outputting an additional electrical signal to the inductive coupler to disengage the male inductive coupler from the female inductive coupler.

17. The system of claim 16, wherein the inductive coupler is configured to couple an upper completion of the downhole assembly with a lower completion of the downhole assembly.

18. The system of claim 17, wherein the upper completion comprises a hydraulic stinger assembly.

19. The system of claim 18, wherein the lower completion comprises a hydraulic receptacle, and the hydraulic receptacle is configured to receive the hydraulic stinger assembly.

20. The system of claim 19, wherein the hydraulic receptacle receives the hydraulic stinger assembly via a hydro-electric wet mate (HEWM) connector.