US20190316432A1

US20190316432A1 - Downhole Torqueing

Info

Publication number: US20190316432A1
Application number: US15/952,315
Authority: US
Inventors: Christophe Michaud
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2018-04-13
Filing date: 2018-04-13
Publication date: 2019-10-17

Abstract

Apparatus and methods for performing downhole torqueing. The apparatus may be a downhole tool for rotating a first downhole equipment disposed within a wellbore. The downhole tool may include first and second rotative members operable to rotate relative to each other along an axis of the downhole tool. The downhole tool may further include a first gripping member connected with the first rotative member and operable to engage the first downhole equipment, and a second gripping member connected with the second rotative member and operable to engage a second downhole equipment. An actuator may be operable to impart a force to cause the relative rotation between the first and second rotative members thereby causing rotation of the first downhole equipment when the first gripping member is connected with the first downhole equipment and the second gripping member is connected with the second downhole equipment.

Description

BACKGROUND OF THE DISCLOSURE

Intervention operations in completed wells may entail installation, removal, or replacement of various production equipment within the wellbore as part of well repair or maintenance operations or permanent abandonment. Production equipment, such as production tubing, packers, and valves, may be disconnected downhole via release systems to permit removal of such production equipment to a wellsite surface. However, if a release system fails, the production equipment may be cut and removed to the wellsite surface and disassembled. Cutting operations may be performed by conveying a cutting tool within the wellbore and positioning it at a lower end of the production equipment designated for removal. The cutting tool may then cut the production equipment and the separated piece may be retrieved to the wellsite surface. However, cutting tools, such as chemical cutters, jet cutters, power cutters, split shot cutters, or mechanical milling cutters are destructive and often damage the wellbore casing located near the production equipment that is being cut. Such cutting tools also damage the production equipment along the cut, preventing new equipment from being reconnected with the equipment remaining in the wellbore.
Intervention operations in completed wells may also entail shifting or actuating various fluid valves, sliding doors, or other downhole equipment installed within the wellbore. For example, fluid valves may be installed during completion operations and then generally remain closed to prevent fluid transfer between the wellbore and the formation while still permitting passage, through the valves, of tubing, tools, and/or other equipment. The valves may be opened remotely by applying a sequence of pressure pulses. However, valve opening mechanisms often become stuck, such as due to sand or other contaminants, and the applied pressure pulses are often insufficient to actuate the valves to the open position.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.
The present disclosure introduces an apparatus including a downhole tool for moving downhole equipment disposed within a wellbore. The downhole tool includes a first member, a second member, and a third member. The first member includes a first engagement feature and a second engagement feature each extending along an outer surface of the first member. The second member includes a third engagement feature extending along a surface of the second member. The third member includes a fourth engagement feature extending along a surface of the third member. The first and third engagement features are engaged, and the second and fourth engagement features are engaged, such that axial movement of the first member with respect to the second and third members causes relative movement between the second and third members.
The present disclosure also introduces an apparatus including a downhole tool for rotating a first downhole equipment disposed within a wellbore. The downhole tool includes a first rotative member, a second rotative member, a first gripping member connected with the first rotative member, a second gripping member connected with the second rotative member, and an actuator. The first and second rotative members are operable to rotate relative to each other along an axis of the downhole tool. The first gripping member is operable to engage the first downhole equipment. The second gripping member is operable to engage a second downhole equipment. The actuator is operable to impart a force to cause the relative rotation between the first and second rotative members, thereby causing rotation of the first downhole equipment when the first gripping member is connected with the first downhole equipment and the second gripping member is connected with the second downhole equipment.
The present disclosure also introduces a method including conveying a downhole tool within a wellbore. The downhole tool includes a first rotative member, a second rotative member, a first gripping member connected with the first rotative member, and a second gripping member connected with the second rotative member. The method also includes engaging the first gripping member with a first downhole equipment within the wellbore, engaging the second gripping member with a second downhole equipment within the wellbore, and operating the downhole tool to rotatably move the first and second downhole equipment relative to each other by rotatably moving the first and second rotative members relative to each other.
The downhole tools within the scope of the present disclosure may permit removal, replacement, or installation of various downhole equipment within the wellbore as part of well repair or maintenance operations or permanent abandonment, without using downhole cutters or other cutting means. For example, the downhole tools may be utilized to threadedly disconnect (i.e., unscrew) downhole equipment for removal to the wellsite surface without damaging the downhole equipment. Such non-destructive means may permit reconnection or installation of new downhole equipment. For example, the downhole tools may be utilized to threadedly connect (i.e., screw) new downhole equipment with other downhole equipment located within the wellbore. The downhole tools within the scope of the present disclosure may be further operable to shift, actuate, or loosen downhole fluid valves, sliding doors, or other downhole equipment installed within the wellbore that has become stuck or jammed in a position. For example, the downhole tools may be utilized to slightly rotate or wiggle back and forth at least a portion of the stuck downhole equipment to free the downhole equipment.
These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 3 is a sectional axial view of a portion of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.

FIG. 4 is a side view of the apparatus shown in FIGS. 2 and 3 at a different stage of operation according to one or more aspects of the present disclosure.

FIG. 5 is a sectional axial view of a portion of the apparatus shown in FIG. 4 according to one or more aspects of the present disclosure.

FIG. 6 is an exploded perspective view of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 7 is a perspective view of the apparatus shown in FIG. 6 according to one or more aspects of the present disclosure.

FIG. 8 is a perspective view of the apparatus shown in FIG. 7 at a different stage of operation according to one or more aspects of the present disclosure.

FIG. 9 is a perspective view of a portion of another example implementation of the apparatus shown in FIGS. 6-8 according to one or more aspects of the present disclosure.

FIG. 10 is a perspective view of a portion of still another example implementation of the apparatus shown in FIGS. 6-8 according to one or more aspects of the present disclosure.

FIG. 11 is a schematic side view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 12 is a side view of the apparatus shown in FIG. 11 at a different stage of operation according to one or more aspects of the present disclosure.

FIG. 13 is a side view of the apparatus shown in FIGS. 11 and 12 at a different stage of operation according to one or more aspects of the present disclosure.

FIG. 14 is a sectional axial view of a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 15 is a sectional axial view of another portion of the apparatus shown in FIG. 14 according to one or more aspects of the present disclosure.

FIG. 16 is a sectional axial view of the portion of the apparatus shown in FIG. 14 at a different stage of operation according to one or more aspects of the present disclosure.

FIG. 17 is a sectional axial view of the portion of the apparatus shown in FIG. 15 at a different stage of operation according to one or more aspects of the present disclosure.

FIG. 18 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
FIG. 1 is a schematic view of at least a portion of an example implementation of a wellsite system 100 to which one or more aspects of the present disclosure may be applicable. The wellsite system 100, which may be situated onshore or offshore, comprises a downhole tool string 110 suspended within a wellbore 102 that extends from a wellsite surface 106 into one or more subterranean formations 104. The tool string 110 may be suspended within the wellbore 102 via a conveyance means 112 operably coupled with a tensioning device 114 and/or other surface equipment 116 disposed at the wellsite surface 106. The wellbore 102 may be lined with a casing 108 secured by cement 109. However, one or more aspects of the present disclosure may be applicable to and/or readily adaptable for utilizing in an open-hole wellbore lacking the casing 108 and cement 109.
The tensioning device 114 may be operable to apply an adjustable tensile force to the tool string 110 via the conveyance means 112 to convey the tool string 110 within the wellbore 102. The tensioning device 114 may be, comprise, or form at least a portion of a crane, a winch, a drawworks, an injector, a top drive, and/or other lifting device coupled to the tool string 110 via the conveyance means 112. The conveyance means 112 may be or comprise a cable, a wireline, a slickline, a digital slickline, an e-line, coiled tubing, production tubing, and/or other conveyance means spooled at the wellsite surface 106, such as by or in conjunction with the tensioning device 114.
The conveyance means 112 may comprise and/or be operable in conjunction with means for communication between the tool string 110, the tensioning device 114, and/or one or more other portions of the surface equipment 116, including a surface control system 118. For example, a multi-conductor cable (generally called a wireline cable), hereinafter referred to as a conductor 120, may extend through the conveyance means 112 and at least partially within the tool string 110 and surface equipment 116. The conductor 120 may permit electrical power transfer between the surface equipment 116 and the tool string 110. The conductor 120 may also facilitate electrical and/or optical signal communication between one or more components of the surface equipment 116, including the surface control system 118, and one or more portions of the tool string 110, including a downhole control system 122. However, the conveyance means 112 may instead be a single wire cable or slickline. The wire may be covered by an insulation, with no additional conductors. The slickline may then be utilized as an electrical conductor between the tool string 110 and surface equipment 116, and electrically coupled with the casing 108 utilized as the ground. There may be contact between the tool string 110 and the casing 108 and/or surface equipment 116, such as described in U.S. Pat. No. 7,652,592. The coupling may also or instead be a capacitive coupling. In the following, such cable will be designated as a digital slickline. The digital slickline may thus facilitate electrical signal communication between the tool string 110 and the surface equipment 116 without utilizing multiple electric or other conductors, such as the conductor 120, extending between the tool string 110 and the surface equipment 116.
The tool string 110 may comprise one or more downhole tools, subs, modules, and/or other apparatuses operable in wireline, coiled tubing, completion, production, and/or other operations. For example, the tool string 110 may comprise a cable head 126, a telemetry/control tool 128, and a torqueing tool 130. The tool string 110 may also comprise additional one or more subs, modules, or tools 132, 134, 136 at various locations along the tool string 110. For example, the additional tools 132, 134, 136 may be or comprise one or more of an acoustic tool, a density tool, a directional tool, an electrical power module, an electromagnetic (EM) tool, a formation testing tool, a fluid sampling tool, a gravity tool, a formation logging tool, a hydraulic power module, a magnetic resonance tool, a formation measurement tool, a jarring tool, a mechanical interface tool, a monitoring tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a power module, a ram, a release tool, a reservoir characterization tool, a resistivity tool, a seismic tool, a stroker tool, and/or a surveying tool, among other examples also within the scope of the present disclosure.
One or more of the additional tools 132, 134, 136 may be or comprise an inclination sensor and/or another position sensor, such as an accelerometer, a magnetometer, a gyroscopic sensor (e.g., a micro-electro-mechanical system (MEMS) gyro), and/or another sensor for utilization in determining the orientation of the tool string 110 relative to the wellbore 102. One or more of the additional tools 132, 134, 136 may be or comprise a depth correlation tool, such as a casing collar locator (CCL) operable to detect ends of casing collars or other tubular (e.g., prodictin tubing) by sensing a magnetic irregularity caused by the relatively high mass of an end of a collar of the casing 108 or another tubular installed within the wellbore 102. The correlation tool may also or instead be or comprise a gamma ray (GR) tool that may be utilized for depth correlation. The CCL and/or GR tools may transmit signals in real-time to the wellsite surface equipment 116, such as the surface control system 118, via the conveyance means 112 and/or the conductor 120. The CCL and/or GR signals may be utilized to determine the position of the tool string 110 or portions thereof, such as with respect to known casing collar or tubular numbers and/or positions within the wellbore 102. Therefore, the CCL and/or GR tools may be utilized to detect and/or log the location of the tool string 110 within the wellbore 102, such as to facilitate intended positioning of the torqueing tool 130 with respect to the downhole equipment 140 (e.g., dowhole tubulars) as part of methods and operations described herein.
One or more of the cable head 126, the telemetry/control tool 128, the torqueing tool 130, and the additional tools 132, 134, 136 may be electrically connected to the conductor 120, for instance, via the cable head 126. The conductor 120 may include various electrical and/or optical connectors or interfaces (not shown), such as may facilitate connection between the conductor 120 and the tool string 110 to permit communication between one or more of the tools 126, 128, 130, 132, 134, 136 and one or more components of the surface equipment 116. Accordingly, the conductor 120 may be operable to transfer electrical power, electrical signals, and/or optical signals between the surface equipment 116, including the surface control system 118, and one or more of the tools 126, 128, 130, 132, 134, 136, including the downhole control system 122. Fluid power may be transferred from the surface equipment 116 to the tool string 110 via the conveyance means 112, such as when implemented as coiled tubing.
The cable head 126 may be operable to connect the conveyance means 112 with the tool string 110. The telemetry/control tool 128 may facilitate communication between the tool string 110 and the surface equipment 116 and/or control of one or more portions of the tool string 110. The telemetry/control tool 128 may comprise the downhole control system 122 communicatively coupled to the surface control system 118 via the conductor 120. However, when the conveyance means 112 is implemented as a digital slickline, the telemetry/control tool 128 may instead utilize digital slickline telemetry to facilitate communication between the tool string 110 and the surface equipment 116.
The surface and downhole control systems 118, 122 may each comprise a processing device (e.g., a computer) and a memory operable to store programs or instructions that, when executed by the processing device, may cause the tool string 110 and/or the surface equipment 116 to perform methods, processes, and/or routines described herein. The surface and/or the downhole control systems 118, 122 may also include various electronic components, such as an interface for receiving commands from a human wellsite operator. The downhole control system 122 may be operable to receive control commands from the surface control system 118 for controlling the tools 126, 128, 130, 132, 134, 136 and other components of the tool string 110 from the wellsite surface 106. The surface and downhole control systems 118, 122 may operate independently or cooperatively to control one or more portions of the tool string 110. The surface and/or downhole control systems 118, 122 may also receive, store, and/or process measurements and other data obtained from various sensors of the tool string 110, and store and/or communicate the processed measurements and other data to the surface equipment 116 for subsequent analysis.
The torqueing tool 130 may be operable to engage and apply a torque to target downhole components or equipment 140 installed, stuck, or otherwise disposed within the wellbore 102 to operate, actuate, rotate, connect, disconnect, or otherwise impart movement to such downhole equipment 140. The downhole equipment 140 may be or comprise, for example, downhole tools, downhole tubulars (e.g., flow tubes, completion piping, etc.), completion equipment, and production equipment (e.g., packers, sliding sleeve doors (SSD), downhole safety valves (DHSV), etc.), among other examples. Accordingly, the torqueing tool 130 may be operable to, for example, threadedly engage or disengage a tubular member or tool to or from another threaded tubular member or tool. The torqueing tool 130 may also be operable to apply torque to a stuck or jammed SSD or a control sleeve of a DHSV to unstick or otherwise help loosen such downhole equipment so that it can be actuated to the open position. For clarity and ease of understanding, the downhole equipment 140 shown in FIG. 1 is a schematic representation of at least a portion of the actual downhole equipment, described above, that may be operated by the torqueing tool 130. The downhole equipment 140 is shown having a generic shape without specific features integral to the actual downhole equipment. It is to be understood that the actual downhole equipment operated by the torqueing tool 130 may comprise a substantially different configuration (e.g., size, shape, length, thickness, etc.) than shown.
The torqueing tool 130 may comprise upper (i.e., uphole) and lower (i.e., downhole) portions 142, 144 operable to rotate with respect to each other, as indicated by arrows 131, 133. Each portion 142, 144 may comprise a corresponding body 146, 148 (e.g., a housing, a chassis, a ring, a sleeve, or another rotative component or member, etc.) and a set of arms 152, 154 (e.g., gripping members) operable to selectively engage with elements of or defining the wellbore 102, such as a sidewall 103 (e.g., the casing 108, the rock formation 104) of the wellbore 102, and/or elements disposed within the wellbore 102, such as the downhole equipment 140. The gripping arms 152, 154 facilitate a temporary connection between each portion 142, 144 of the torqueing tool 130 with a respective element of or within the wellbore 102. The arms 152, 154 may thus permit transfer of torque from the torqueing tool 130 to the downhole equipment 140 to rotatably move one or more portions of the downhole equipment 140, as indicated by the arrow 133, relative to another portion of the downhole equipment 140 or relative to the sidewall 103 of the wellbore 102, such as the casing 108, another tubular containing the downhole equipment 140, and/or other downhole equipment containing the downhole equipment 140 that is not intended to be loosened or unstuck. Each one of the arms 152, 154 may be selectively operable to move radially (i.e., laterally) with respect to the corresponding bodies 146, 148 and/or a central axis 111 of the tool string 110 to engage the downhole equipment 140, the sidewall 103, and/or another element of or within the wellbore 102. Although each set of arms 152, 154 is shown comprising two arms, it is to be understood that each set of arms 152, 154 may include three, four, or more arms, each selectively operable to engage the downhole equipment 140.
For example, before commencing torqueing operations, the upper set of arms 152 may engage the casing 108 and the lower set of arms 154 may be engage the downhole equipment 140. During torqueing operations, the torqueing tool 130 may impart torque to the downhole equipment 140, as indicated by the arrow 133, to cause relative rotation between the downhole equipment 140 and the casing 108. The relative rotation of the downhole equipment 140 and the casing 108 may be determined based on resistance to rotation of the downhole equipment 140 within the casing 108, such as due to friction between the downhole equipment 140 and the casing 108.
The torqueing tool 130 may further comprise one or more torque sensors 162 (e.g., a load cell, a strain gauge) each operable to generate a signal or information indicative of the torque imparted to the downhole equipment 140 or otherwise generated by the torqueing tool 130. The torque sensors 162 may be mounted within or otherwise disposed in association with one or more of the arms 152, 154, the bodies 146, 148, or another internal or external portion of the torqueing tool 130, such as may permit the torque sensors 162 to monitor torque generated by the torqueing tool 130. The torqueing tool 130 may further comprise one or more position sensors 164 each operable to generate a signal or information indicative of relative rotational position (i.e., angular displacement) between the upper and lower bodies 146, 148, such as to monitor relative rotational position (i.e., movement) of the downhole equipment 140 with respect to the casing 108. The position sensors 164 may be mounted within or otherwise disposed in association with one or more of the arms 152, 154, the bodies 146, 148, or another internal or external portion of the torqueing tool 130, such as may permit the position sensors 164 to monitor relative position between the upper and lower bodies 146, 148. Each of the sensors 164 may be or comprise an encoder, a rotary potentiometer, a synchro, a resolver, a gyroscope, a proximity sensor, a Hall effect sensor, and/or a rotary variable-differential transformer (RVDT), among other examples. The sensors 162, 164 may be communicatively connected with the downhole and/or surface control systems 122, 118 via the conductor 120 or the conveyance means 112, such as may permit the downhole and/or surface control systems 122, 118 to receive, process, store, and/or transmit the signals generated by each sensor 162, 164.
One or more of the subs, modules, or tools 132, 134, 136, such as the tool 134, may be or comprise an actuator, such as a linear actuator, operable to power (i.e., drive, actuate, operate) the torqueing tool 130. For example, the linear actuator 134 may be operable to impart a force to one or more internal portions (e.g., an actuating member 202 shown in FIGS. 2-5, a shaft 302 shown in FIGS. 6-8) of the torqueing tool 130 and, in turn, cause the upper and lower portions 142, 144 of the torqueing tool 130 to rotate with respect to each other. The linear actuator 134 may be implemented, for example, as a mechanical actuator, as a hydraulic actuator, such as a ram or stroker tool, or as an electrical actuator. The force may also or instead be imparted from the wellsite surface 106 by the tensioning device 114 via the conveyance means 112 connected with the internal portions of the torqueing tool 130. The force may thus be imparted to the internal portions of the torqueing tool 130 and, in turn, cause the upper and lower portions 142, 144 of the torqueing tool 130 to rotate with respect to each other. During example torqueing operations, the upper arms 152 may anchor the torqueing tool 130 against the casing 108 and provide counter-torque while the lower arms 154 engage the downhole equipment 140 to transfer torque generated by the torqueing tool 130 to the downhole equipment 140. The torqueing tool 130 may thus be operable to receive and convert a linear force, such as the linear force imparted by the linear actuator 134 or the tensioning device 114, into a torque, and impart such torque to the downhole equipment 140, as described herein.
One or more of the subs, modules, or tools 132, 134, 136, such as the tool 132, may be or comprise a power module operable to provide power to operate the torqueing tool 130, the linear actuator 134, and/or other portions of the tool string 110. For example, the power module 132 may be or comprise a hydraulic power module, which may be operable to supply hydraulic power directly to the torqueing tool 130 or indirectly via the linear actuator 134 to drive the torqueing tool 130. For example, the hydraulic power module may provide a pressurized hydraulic fluid to actuate the torqueing tool 130, the hydraulic linear actuator 134, and/or other portions of the tool string 110. The power module 132 may also or instead be or comprise an electrical power module, such as a battery or a supercapacitor. In such implementations, the battery may provide electrical power to the electrical linear actuator 134. The power module 132 may also be omitted from the tool string 110, such as in implementations in which the hydraulic and/or electrical power is provided from the wellsite surface 106 via the conveyance means 112.
FIGS. 2 and 3 are schematic side and sectional axial views, respectively, of a portion of an example implementation of a torqueing tool 200 according to one or more aspects of the present disclosure. The torqueing tool 200 may comprise one or more features of the torqueing tool 130 shown in FIG. 1, except as described below.
The torqueing tool 200 may comprise an actuating member 202 (e.g., a shaft, a bar, a mandrel, a cylinder, etc.) having engagement features 204, 206 extending along an outer surface 208 of the actuating member 202. The engagement features 204, 206 may extend at an angle 214 with respect to each other, such that the engagement features 204, 206 may converge and diverge from each other in opposing directions along a longitudinal axis 210 of the actuating member 202. One or both of the engagement features 204, 206 may extend at an angle with respect to the longitudinal axis 210. For example, the engagement feature 204 may extend substantially parallel with respect to the longitudinal axis 210, and the engagement feature 206 may extend at an angle 216 with respect to the longitudinal axis 210. The engagement features 204, 206 may each be or comprise a protrusion, a lug, a ridge, a male spline, a female spline, a channel, or a groove, among other examples, extending along an outer surface 208 of the actuating member 202.
The torqueing tool 200 may further comprise actuated members 220, 222 (e.g., rotative members) operatively connected with the actuating member 202 such that axial movement of the actuating member 202 with respect to the actuated members 220, 222 causes relative movement between the actuated members 220, 222. The actuated members 220, 222 may each be or comprise a ring or sleeve having an inner surface 224, 226 defining a corresponding opening configured to slidably receive the actuating member 202 therethrough. Each actuated member 220, 222 may comprise a corresponding engagement feature 230, 232 extending along the inner surface 224, 226 of each actuated member 220, 222. The engagement features 230, 232 may each be or comprise a protrusion, a lug, a ridge, a male spline, a female spline, a channel, or a groove, among other examples, extending along the corresponding inner surface 224, 226 of the actuated members 220, 222 and operable to respectively engage the engagement features 204, 206 of the actuating member 202. The actuating member 202 may be slidably disposed within the actuated members 220, 222 such that the engagement feature 230 of the actuated member 220 slidably engages the engagement feature 204 of the actuating member 202 and the engagement feature 232 of the actuated member 222 slidably engages the engagement feature 206 of the actuating member 202. When the engagement features 204, 206 and the engagement features 230, 232 are engaged, relative rotational position of each actuated member 220, 222 is controlled by or otherwise depends on an axial position of the actuating member 202 with respect to the actuated members 220, 222. In the example implementation of the torqueing tool 200 shown in FIGS. 2-5, the engagement features 230, 232 comprise male engagement features (e.g., lugs, male splines, protrusions, ridges) and the engagement features 204, 206 comprise female engagement features (e.g., female splines, channels, grooves) configured to slidably receive the engagement features 230, 232.
FIGS. 2 and 3 show the torqueing tool 200 in a first position, in which a bottom end 236 of the actuating member 202 is inserted into or otherwise adjacent to the actuated member 222 and an upper end 238 is located externally or otherwise at a distance from the actuated member 220. In such position, the engagement feature 232 is located adjacent the bottom end 236 of the actuating member 202, and the engagement feature 230 is located at a distance from the upper end 238 of the actuating member 202. Furthermore, the engagement features 230, 232 are separated by an angle 240 with respect to the axis 210.
FIGS. 4 and 5 are schematic side and sectional axial views, respectively, of the torqueing tool 200 shown in FIGS. 2 and 3 at a different stage of operation according to one or more aspects of the present disclosure. The following description refers to FIGS. 1-5, collectively.
During torqueing operations, the actuating member 202 may be moved axially (e.g., downwards) through or otherwise with respect to the actuated members 220, 222, as indicated by arrow 242, until the torqueing tool 200 reaches a second position, in which the bottom end 236 of the actuating member 202 is located externally or otherwise at a distance from the actuated member 222 and the upper end 238 of the actuating member 202 is inserted into or otherwise adjacent to the actuated member 220. In such position, the engagement feature 230 is located adjacent the upper end 238 of the actuating member 202, and the engagement feature 232 is located at a distance from the bottom end 236 of the actuating member 202. While the actuating member 202 moves through the actuated members 220, 222, the engagement features 230, 232 slide within the engagement features 204, 206. However, because the engagement features 204, 206 extend at the angle 214 with respect to teach other, the engagement features 230, 232 are forced to move laterally away from each other, forcing the actuated members 220, 222 to rotate with respect to each other. In an example implementation of the torqueing tool 200, the angle 214 between the engagement features 204, 206 may range between about one degree and about twenty degrees, depending on torque and rotational speed requirements. A decrease in the angle 214 increases torque output and decreases rotational speed, and an increase in the angle 214 increases rotational speed and decreases torque output. For clarity and ease of understanding, FIGS. 4 and 5 show the actuated member 222 rotating with respect to the actuated member 220, as indicated by arrows 246. However, it is to be understood that the actuated member 220 may be caused to rotate with respect to the actuated member 222 or both actuated members 220, 222 may be caused to rotate relative to each other. In the second position of the torqueing tool 200, the engagement features 230, 232 and the corresponding actuated members 220, 222 are separated by an angle 244 that is substantially larger than the angle 240.
The actuating member 202 may also be moved axially upwards through or otherwise with respect to the actuated members 220, 222, as indicated by arrow 248, to return the torqueing tool 200 to the first position shown in FIGS. 2 and 3. While the actuating member 202 moves through the actuated members 220, 222, the engagement features 230, 232 slide with respect to the engagement features 204, 206 and are forced to move laterally toward each other, forcing the actuated members 220, 222 to rotate with respect to each other, as indicated by arrow 249, until the actuating member 202 returns to its initial position and the engagement features 230, 232 are separated by the angle 240. The gripping members 152, 154 may be released during such upward movement, as will be explained in more details below.
FIG. 6 is an exploded perspective view of a portion of an example implementation of a torqueing tool 300 according to one or more aspects of the present disclosure. The torqueing tool 300 may comprise one or more features of the torqueing tools 130, 200 shown in FIGS. 1-5, except as described below.
The torqueing tool 200 may comprise a shaft 302 having a plurality of sets of corresponding channels 304, 306 extending along an outer surface 308 of the shaft 302, such as in a spiral or helical manner. Each channel 304 may extend substantially parallel with respect to a longitudinal axis 310 of the shaft 302 and each channel 306 may extend at an angle 314 with respect to the longitudinal axis 310 and/or a corresponding channel 304. Although FIG. 6 shows three sets of the corresponding channels 304, 306, it is to be understood that the shaft 302 may comprise one, two, four, or more sets of the corresponding channels 304, 306. The torqueing tool 300 may further comprise sleeves 320, 322 operatively connected with the shaft 302 such that axial movement of the shaft 302 with respect to the sleeves 320, 322 causes relative rotation between the sleeves 320, 322. The sleeves 320, 322 may each comprise a corresponding inner surface 324, 326 defining an opening configured to slidably receive the shaft 302 therethrough. Each sleeve 320, 322 may comprise corresponding lugs 330, 332 (some of which are obstructed or cut from view) extending along the inner surface 324, 326 of each sleeve 320, 322.
FIGS. 7 and 8 are perspective views of the torqueing tool 300 shown in FIG. 6 at different stages of operation according to one or more aspects of the present disclosure. The following description refers to FIGS. 6-8, collectively.
The sleeves 320, 322 may be axially aligned and disposed adjacent each other, and the shaft 302 may be slidably disposed within the sleeves 320, 322 such that the lugs 330 are slidably disposed within the channels 304 and the lugs 332 are slidably disposed within the channels 306, thereby permitting axial movement between the sleeves 320, 322 and the shaft 302. FIG. 7 shows the torqueing tool 300 in a first position, in which an end 336 of the shaft 302 is disposed within the sleeve 322 adjacent the lugs 332 and an upper end 338 is located externally or otherwise at a distance from the sleeve 320 and the lugs 330. For clarity and ease of understanding, FIGS. 7 and 8 show reference markers 340, 342 indicative of relative rotational position between the sleeves 320, 322. In the first position, the reference markers 340, 342 are shown aligned. As shown in FIG. 8, the shaft 302 may be moved axially through or otherwise with respect to the sleeves 320, 322, as indicated by arrow 344, until the torqueing tool 300 is in a second position, in which the end 336 of the shaft 302 is located externally or otherwise at a distance from the sleeve 322 and the lugs 332, and the end 338 of the shaft 302 is disposed within the sleeve 320 adjacent the lugs 330. While the shaft 302 moves through the sleeves 320, 322, the lugs 330, 332 slide within the channels 304, 306. However, because the channels 304, 306 extend at an angle 314 with respect to teach other, the lugs 330, 332 are forced to move laterally away from each other while the lugs 330, 332 slide within the channels 304, 306, forcing the sleeve 322 to rotate with respect to the sleeve 320, as indicated by arrow 346 and the position of the reference marker 340 with respect to the reference marker 342. In an example implementation of the torqueing tool 300, the angle 314 between the channels 304, 306 may range between about one degree and about twenty degrees, depending on torque and rotational speed requirements. A decrease in the angle 314 increases torque output and decreases rotational speed, and an increase in the angle 314 increases rotational speed and decreases torque output.
The shaft 302 may also be moved axially in the opposing direction through or otherwise with respect to the sleeves 320, 322, as indicated by arrow 348, to return the torqueing tool 300 to the first position shown in FIG. 7. While the shaft 302 moves through the sleeves 320, 322, the lugs 330, 332 slide within the channels 304, 306 and are forced to move laterally toward each other, forcing the sleeve 322 to rotate with respect to the sleeve 320, as indicated by arrow 349, until the shaft 302 returns to its initial position and the reference markers 340, 342 are aligned.
FIGS. 9 and 10 are perspective views of at least a portion of example implementations of shafts 350, 370, such as may be utilized with the sleeves 320, 322 shown in FIGS. 6-8. The shafts 350, 370 may comprise one or more features of the shaft 302 shown in FIGS. 6-8, except as described below.
The shaft 350 may comprise one or more sets of corresponding channels 354, 356 extending along an outer surface 358 of the shaft 350, such as in a spiral or helical manner. The corresponding channels 354, 356 may extend at an angle 362 with respect to each other, such that the channels 354, 356 converge and diverge from each other in opposing directions along a longitudinal axis 360 of the shaft 350. Furthermore, unlike the shaft 302 shown in FIGS. 6-8, the channels 354, 356 of shaft 350 may both extend at corresponding angles 364, 366 with respect to the longitudinal axis 360. The channels 354, 356 may both form positive or negative angles, such as may both form right-handed or left-handed helixes along the outer surface 358 of the shaft 350.
The shaft 370 may comprise one or more sets of corresponding channels 374, 376 extending along an outer surface 378 of the shaft 370, such as in a spiral or helical manner. The corresponding channels 374, 376 may extend at an angle 382 with respect to each other, such that the channels 374, 376 converge and diverge from each other in opposing directions along a longitudinal axis 380 of the shaft 370. The channels 374, 376 may both extend at corresponding angles 384, 386 with respect to the longitudinal axis 380. However, unlike the channels 354, 356 of the shaft 350, the channels 374, 376 may each extend at opposite (i.e., positive and negative) angles, such that one of the channels 374, 376 forms a right-handed helix along the outer surface 378 of the shaft 370 and the other of the channels 374, 376 forms a left-handed helix along the outer surface 378 of the shaft 370. Although FIGS. 9 and 10 show the shafts 350, 370 each comprising three sets of corresponding channels 354, 356, 374, 376, it is to be understood that the shaft 350 may comprise one, two, four, or more sets of corresponding channels 354, 356, 374, 376.
FIGS. 11-13 are schematic sectional views of at least a portion of an example implementation of a downhole tool string 410 comprising a torqueing tool 400 and a linear actuator 412 according to one or more aspects of the present disclosure. The tool string 410 may be suspended within a wellbore 402 that extends from a wellsite surface 106 (shown in FIG. 1) into one or more subterranean formations 104 (shown in FIG. 1). The tool string 410 is shown disposed within a vertical portion of the wellbore 402. However, it is to be understood that the tool string 410 may also be utilized within a substantially horizontal or otherwise deviated portion of the wellbore 402. FIGS. 11-13 show the tool string 410 at different stages of torqueing operations. The following description refers to FIGS. 1 and 11-13, collectively.
The torqueing tool 400 may comprise one or more features of the torqueing tools 130, 200, 300 shown in FIGS. 1-10, except as described below. The torqueing tool 400 may be operable to engage and apply a torque to target downhole components or equipment 404 installed, stuck, or otherwise disposed within the wellbore 402 to operate, actuate, rotate, connect, disconnect, or otherwise impart movement to at least a portion of the downhole equipment 404. The downhole equipment 404 may be or comprise, for example, downhole tools, downhole tubulars, completion equipment, and production equipment, among other examples. Accordingly, the torqueing tool 400 may be operable to, for example, threadedly disengage an upper and lower portions 405, 406 of the downhole equipment 404 threadedly coupled together via corresponding threaded ends 407, 408.
The torqueing tool 400 may comprise upper and lower housings 416, 418 (e.g., rotative members) operable to rotate with respect to each other. Each housing 416, 418 may comprise a corresponding set of arms 420, 422 (e.g., gripping members) operably connected thereto and operable to selectively engage with the downhole equipment 402 to facilitate a temporary connection between each housing 416, 418 and a corresponding portion 405, 406 of the downhole equipment 404. Each one of the arms 420, 422 may be selectively operable to move radially (i.e., laterally) with respect to the corresponding housings 416, 418 to engage the downhole equipment 404. The upper set of arms 420 may be operable to engage the upper portion 405 of the downhole equipment 404 and the lower set of arms 422 may be operable to engage the lower portion 406 of the downhole equipment 404. Accordingly, the arms 420, 422 may permit transfer of torque from each housing 416, 418 to the corresponding portion 405, 406 of the downhole equipment 404 to rotatably move the corresponding portion 405, 406 of the downhole equipment 404.
The torqueing tool 400 may further comprise a shaft 430 having one or more engagement features (not shown) extending along an outer surface of the shaft 430. The housings 416, 418 may each comprise a corresponding inner surface 432, 434 defining an opening configured to receive the shaft 430 therethrough. Each housing 416, 418 may comprise one or more engagement features (not shown) extending along the inner surface 432, 434 of each housing 416, 418 operable to engage corresponding engagement features of the shaft 430 such that axial movement of the shaft 430 with respect to the housings 416, 418 causes relative rotation between the housings 416, 418. The tool string 410 may also comprise an end cap 436 or another sub coupled with the bottom housing 418 of the torqueing tool 400. The end cap 436 may comprise a cavity 438 configured to receive a portion of the shaft 430 during torqueing operations, as further described below.
The linear actuator 412 may be directly or indirectly coupled with the torqueing tool 400 and operable to axially move the shaft 430 of the torqueing tool 400 to cause the relative rotation between the housings 416, 418. The torqueing tool 410 may thus be operable to receive and convert a linear force imparted by the linear actuator 440, into a torque, and impart such torque to the downhole equipment 404, as described below. The linear actuator 412 may be or comprise a hydraulic linear actuator comprising a chamber 440 containing a piston 442 slidably disposed therein. The piston 442 may be connected with the shaft 430 via a rod 444 extending between the piston 442 and the shaft 430. The chamber 440 may be fluidly connected with a source (not shown) of pressurized hydraulic or another fluid via fluid pathways 446, 448 connected with opposing ends of the chamber 440. The linear actuator 412 and the torqueing tool 400 may be coupled together via a bearing 450 or another device operable to permit rotation of the housing 416 with respect to the linear actuator 412. The pressurized hydraulic fluid may be supplied from the power module 132 included in the tool string 410 or from the wellsite surface 106 via the conveyance means 112.
As shown in FIG. 11, the tool string 410 may be conveyed within the wellbore 402 such that the torqueing tool 400 is disposed within or otherwise adjacent the target downhole equipment 404 intended to be operated or otherwise rotated by the torqueing tool 400. The upper set of arms 420 may be extended outwardly to engage the upper portion 405 of the downhole equipment 404 and the lower set of arms 422 may be extended outwardly to engage the lower portion 406 of the downhole equipment 404 on opposing sides of the threaded ends 407, 408.
Example downhole operations may include the torqueing tool 400 being utilized to disassemble at least a portion of a production tubing string 404 that is maintained in position within the wellbore 402 via a plurality of packers 409. The torqueing tool 400 may be utilized to threadedly disengage (i.e., unscrew) an upper tubular 405 from a lower tubular 406 of the production tubing string 404, such as when a release system associated with a packer 409 fails. During downhole conveyance, a CCL tool or another depth correlation tool of the tool string 410 may be utilized to locate tubing joints (e.g., the threaded ends 407, 408) of the connected tubulars 405, 406 located just above the failed packer 409 and permit the torqueing tool 400 to be positioned adjacent the tubing joints 407, 408 such that each set of arms 420, 422 may engage a corresponding tubular 405, 406.
Thereafter, the linear actuator 412 may drive the torqueing tool 400 between a first position, shown in FIGS. 11 and 13, and a second position, shown in FIG. 12. For example, the linear actuator 412 may be operated to impart a downward linear force to the shaft 430, as indicated by arrow 452, which in turn imparts torque to the housings 416, 418, as indicated by arrows 454. The linear actuator 412 may be operated by pumping the pressurized hydraulic fluid into an upper portion of the chamber 440 via the fluid pathway 446, as indicated by arrow 456, causing the piston 442 to push both the rod 444 and the shaft 430 in a downward direction, as indicated by the arrow 452. The hydraulic fluid may be evacuated from a lower portion of the chamber 440 via the fluid pathway 448, as indicated by arrow 458. The generated torque may be transferred from the torqueing tool 400 to the downhole equipment 404 via the arms 420, 422. For example, the torque may be transferred to the upper portion 405 of the downhole equipment 404 via the arms 420 and to the lower portion 406 of the downhole equipment 404 via the arms 422. The torque imparted to the downhole equipment 404 may cause the connection between the threaded ends 407, 408 to loosen and the upper portion 405 to rotate with respect to the lower portion 406, as indicated by arrow 460, to threadedly disengage the threaded ends 407, 408. When the torqueing tool 400 reaches its second position, the axial movement of the shaft 430 stops and the relative movement between the housings 416, 418 ceases.
As shown in FIG. 13, the linear actuator 412 may be further operated to impart an upward linear force to the shaft 430, as indicated by arrow 462, which in turn imparts opposing torque to the housings 416, 418, as indicated by arrows 464. The linear actuator 412 may be operated by pumping the pressurized hydraulic fluid into the lower portion of the chamber 440 via the fluid pathway 448, as indicated by arrow 466, causing the piston 442 to pull both the rod 444 and the shaft 430 in an upward direction, as indicated by the arrow 462. The hydraulic fluid may be evacuated from the upper portion of the chamber 440 via the fluid pathway 446, as indicated by arrow 468. During the upward movement of the shaft 430, the torqueing tool 400 may be “reset” to permit the torqueing tool 400 to further loosen (i.e., unscrew) the threaded connection between the threaded ends 407, 408 until the upper portion 405 of the downhole equipment 404 is fully disconnected from the lower portion 406. During such reset operations, the arms 420, 422 may disengage from the downhole equipment 404, such as not to threadedly reengage (i.e., tighten) the threaded ends 407, 408 of the downhole equipment 404. When the linear actuator 412 moves the torqueing tool 400 back to its first position, the arms 420, 422 may reengage the downhole equipment 404, as shown in FIG. 11. Thereafter, the linear actuator 412 may be again operated to impart a downward linear force to the shaft 430, as indicated by the arrow 452, which in turn imparts torque to the housings 416, 418, as indicated by the arrows 454, to further loosen the threaded connection between the threaded ends 407, 408, as shown in FIG. 12. The operations described above and shown in FIGS. 11-13 may be repeated until the upper portion 405 of the downhole equipment 404 is fully disconnected (i.e., unscrewed) from the lower portion 406. When the upper portion 405 is fully disconnected from the lower portion 406, the tool string 410 and the upper portion 405 may be retrieved to the wellsite surface.
Although the linear actuator 412 is shown as a separate and distinct device operatively connected with the torqueing tool 400, the linear actuator 412 or another linear actuator configured to axially move the shaft 430, may be integrated with or otherwise form a portion of the torqueing tool 400. For example, a linear actuator within the scope of the present disclosure may be disposed within and/or otherwise connected with one of the housings 416, 418. Furthermore, although the upward and downward axial movements of the shaft 430 are shown being facilitated by a double acting hydraulic linear actuator 412, the upward and downward axial movements may each be facilitated via different means. For example, the downward movement of the shaft 430 operable to generate torque for operating the downhole equipment 404 may be facilitated by a single acting hydraulic or electrical linear actuator configured to generate just the downward axial movement, wherein the upward axial movement for resetting the torqueing tool 400 may be imparted by a biasing means, such as a spring, operatively connected with the shaft 430, such as within the cavity 438 or within the chamber 440 below the piston 442.
FIGS. 14 and 15 are sectional axial views of an example implementation of a torqueing tool 500 according to one or more aspects of the present disclosure and FIGS. 16 and 17 are sectional axial views of the torqueing tool 500 in a different stage of operation. The torqueing tool 500 may comprise one or more similar features of the torqueing tools 130, 200, 300, 400 described above and shown in FIGS. 1-13, except as described below. The following description refers to FIGS. 14-17, collectively.
The torqueing tool 500 may comprise a shaft 502 having two sets of corresponding engagement features 504, 506 extending along an outer surface of the shaft 502. The torqueing tool 500 may further comprise an upper housing 508 and a lower housing 510, each having an inner surface defining an opening containing the shaft 502. The upper housing 508 may comprise engagement features 512 extending along the inner surface of the upper housing 508 slidably engaging the engagement features 504 of the shaft 502, and the lower housing 510 may comprise engagement features 514 extending along the inner surface of the lower housing 510 slidably engaging the engagement features 506 of the shaft 502. The torqueing tool 500 may further comprise a plurality of upper arms 520 operatively connected with the upper housing 508 and a plurality of lower arms 522 operatively connected with the lower housing 510. The arms 520, 522 may be selectively operable to engage with downhole equipment 516 disposed within a wellbore 518 to facilitate a temporary connection between the downhole equipment 516 and the torqueing tool 500.
The arms 520, 522 may be or comprise gripping slips or other gripping members pivotally connected with the corresponding housings 508, 510 via pivot pins 524. The arms 520, 522 may be operable to engage (i.e., grip) the downhole equipment 516 when being moved in one direction with respect to the downhole equipment 516, and to permit slippage when being moved in an opposing direction with respect to the downhole equipment. The upper arms 520 may be selectively operable to engage a corresponding upper portion 526 of the downhole equipment 516 adjacent the upper arms 520, and the lower arms 522 may be selectively operable to engage a corresponding lower portion 528 of the downhole equipment 516 adjacent the lower arms 522. The arms 520, 522 may be operated between a retracted position, shown in FIGS. 16 and 17, in which the arms 520, 522 are maintained within an outer profile of the corresponding housings 508, 510 and, thus, disengaged from the downhole equipment 516, and an extended position, shown in FIGS. 14 and 15, in which the arms 520, 522 are extended radially outwards to engage the downhole equipment 516. The arms 520, 522 may be maintained in the retracted position via corresponding springs (not shown) and may be selectively rotated to the extended position via corresponding actuators 530. Accordingly, during downhole conveyance of the torqueing tool 500, the arms 520, 522 may be maintained in the retracted position and during torqueing operations, the arms 520, 522 may be operated to the extended position.
The torqueing tool 500 may form or otherwise operate as a ratcheting flywheel mechanism by reciprocating the housings 508, 510 back-and-forth in opposing rotational directions to continually rotate (and perhaps disconnect) one of the upper portion 526 and the lower portion 528 of the downhole equipment 516 with respect to the other of the upper portion 526 and lower portion 528 of the downhole equipment 516. For example, when the shaft 502 is moved axially in a first axial direction, torque may be imparted to the upper housing 508 in a first rotational direction, as indicated by arrow 532, causing the upper arms 520 to engage (i.e., grip) and transfer torque to the upper portion 526 of the downhole equipment 516 to rotate the upper portion 526 of the downhole equipment 516, as indicated by the arrow 534. Simultaneously, torque may be imparted to the lower housing 510 in a second rotational direction, opposite the first rotational direction, as indicated by arrow 536, causing the arms 522 to engage and transfer the torque to the corresponding lower portion 528 of the downhole equipment 516, such as to counteract the torque transferred to the upper portion 526 of the downhole equipment 516.
After the shaft 502 moves to its final position in the first axial direction, the shaft 502 may be moved axially in an opposing second axial direction causing torque to be imparted to the upper housing 508 in the second rotational direction, as indicated by arrow 538. The upper arms 520 may be disengaged (i.e., disconnected) from the upper portion 526 of the downhole equipment 516, permitting the upper housing 508 to rotate (i.e., reset) without rotating the upper portion 526 of the downhole equipment 510. Simultaneously, torque may be imparted to the lower housing 510 in the first rotational direction, as indicated by arrow 540, and the lower arms 522 may be disengaged from the lower portion 528 of the downhole equipment 516, permitting the lower housing 510 to rotate without imparting torque to the lower portion 528 of the downhole equipment 516. The arms 520, 522 may be disengaged from the downhole equipment 516 by retracting the actuators 530 to permit the arms 520, 522 to retract. The arms 520, 522 may also or instead be disengaged from the downhole equipment 516 via slippage between the arms 520, 522 and the downhole equipment 516 without fully or partially retracting the actuators 530. During movement of the shaft 502 in the second axial direction, the torqueing tool 500 may “reset” to permit the torqueing tool 500 to again impart torque to the downhole equipment 516, as shown in FIGS. 14 and 15.
After the shaft 502 moves back to its final position in the second axial direction, the arms 520, 522 may reengage the downhole equipment 516, as shown in FIGS. 14 and 15. Thereafter, the shaft 502 may be again moved in the first axial direction to impart torque to the housings 508, 510, as indicated by the arrows 532, 536, to impart torque to and rotate the corresponding upper portion 526 of the downhole equipment 516. The operations described above in association with FIGS. 14-17 may be repeated until the upper portion 526 of the downhole equipment 516 is fully operated or actuated (e.g., disconnected) with respect to the lower portion 528.
Various portions of the apparatus described above and shown in FIGS. 1-17, may collectively form and/or be controlled by a control system, such as may be operable to monitor, cause, and/or otherwise facilitate the methods and operations of the wellsite system and/or tool strings, including the torqueing tools, described above. FIG. 18 is a schematic view of at least a portion of an example implementation of such a control system 600 according to one or more aspects of the present disclosure. The following description refers to one or more of FIGS. 1-18.
The control system 600 may comprise a controller 610, which may be in communication with various portions of the wellsite system 100, including the tool string 110 and the surface equipment 116. For example, the controller 610 may be in signal communication with the surface equipment 116, the tensioning device 114, the telemetry/control tool 128, the power module 132, the linear actuator 134, the torqueing tool 130, including the actuators 530 and the torque and position sensors 162, 164, and/or other actuators and sensors of the wellsite system 100. For clarity, these and other components in communication with the controller 610 will be collectively referred to hereinafter as “actuator and sensor equipment.” The controller 610 may be operable to receive coded instructions 632 from the wellsite operator and signals generated by the torque sensors 162 and the position sensors 164, process the coded instructions 632 and the signals, and communicate control signals to the surface equipment 116, the tensioning device 114, the power module, 132, the linear actuator 134, and the torqueing tool 130, to execute the coded instructions 632 to implement at least a portion of one or more example methods and/or processes described herein, and/or to implement at least a portion of one or more of the example systems described herein. The controller 610 may also or instead cause the signals generated by the torque sensors 162 and the position sensors 164 to be displayed on an output device to be viewed by the wellsite operator, such as may permit the wellsite operator to manually control the surface equipment 116, the tensioning device 114, the power module, 132, the linear actuator 134, and the torqueing tool 130 to implement at least a portion of one or more example methods and/or processes described herein. The controller 610 may be or comprise one or more of the surface and downhole control systems 118, 122 described above.
The controller 610 may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers) personal digital assistant (PDA) devices, smartphones, internet appliances, and/or other types of computing devices. The controller 610 may comprise a processor 612, such as a general-purpose programmable processor. The processor 612 may comprise a local memory 614, and may execute coded instructions 632 present in the local memory 614 and/or another memory device. The processor 612 may execute, among other things, the machine-readable coded instructions 632 and/or other instructions and/or programs to implement the example methods and/or processes described herein. The programs stored in the local memory 614 may include program instructions or computer program code that, when executed by an associated processor, facilitate the wellsite system 100 and the tool string 110 to perform the example methods and/or processes described herein. The processor 612 may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Of course, other processors from other families are also appropriate.
The processor 612 may be in communication with a main memory 617, such as may include a volatile memory 618 and a non-volatile memory 620, perhaps via a bus 622 and/or other communication means. The volatile memory 618 may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory 620 may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 618 and/or non-volatile memory 620.
The controller 610 may also comprise an interface circuit 624. The interface circuit 624 may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others. The interface circuit 624 may also comprise a graphics driver card. The interface circuit 624 may also comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.). One or more of the actuator and sensor equipment may be connected with the controller 610 via the interface circuit 624, such as may facilitate communication between the actuator and sensor equipment and the controller 610.
One or more input devices 626 may also be connected to the interface circuit 624. The input devices 626 may permit the wellsite operator to enter the coded instructions 632, including control commands, operational set-points, and/or other data for use by the processor 612. The input devices 626 may be, comprise, or be implemented by a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples.
One or more output devices 628 may also be connected to the interface circuit 624. The output devices 628 may be, comprise, or be implemented by display devices (e.g., a liquid crystal display (LCD), a light-emitting diode (LED) display, or cathode ray tube (CRT) display), printers, and/or speakers, among other examples. The controller 610 may also communicate with one or more mass storage devices 630 and/or a removable storage medium 634, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.
The coded instructions 632 may be stored in the mass storage device 630, the main memory 617, the local memory 614, and/or the removable storage medium 634. Thus, the controller 610 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor 612. In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor 612.
The coded instructions 632 may include program instructions or computer program code that, when executed by the processor 612, may cause the wellsite system 100, including the tool string 110 and the surface equipment 116 to perform methods, processes, and/or routines described herein. For example, the controller 610 may receive, process, and record the commands entered by the wellsite operator and the signals generated by the sensors 162, 164. Based on the received commands and the signals generated by the sensors 162, 164, the controller 610 may send signals or information to the surface equipment 116, the tensioning device 114, the power module 132, the linear actuator 134, the torqueing tool 130, and/or other portions of the wellsite system 100 to automatically perform and/or undergo one or more operations or routines described herein or otherwise within the scope of the present disclosure. The controller 610 may also or instead cause the signals generated by the torque sensors 162 and the position sensors 164 to be displayed on the output device 628 to be viewed by the wellsite operator, such as may permit the wellsite operator to manually control the wellsite system 100 to implement at least a portion of one or more example methods and/or processes described herein.
In view of the entirety of the present disclosure, including the claims and the figures, a person having ordinary skill in the art will readily recognize that the present disclosure introduces an apparatus comprising a downhole tool for moving downhole equipment disposed within a wellbore, wherein the downhole tool comprises: a first member comprising a first engagement feature and a second engagement feature each extending along an outer surface of the first member; a second member comprising a third engagement feature extending along a surface of the second member; and a third member comprising a fourth engagement feature extending along a surface of the third member; wherein the first and third engagement features are engaged and the second and fourth engagement features are engaged such that axial movement of the first member with respect to the second and third members causes relative movement between the second and third members.
The first member may be or comprise a shaft, the outer surface of the first member may be an outer surface of the shaft, and the first and second engagement features may extend along the outer surface of the shaft. The second member may be or comprise a first sleeve, the surface of the second member may be an inner surface of the first sleeve, the third engagement feature may extend along the inner surface, and the first sleeve may be slidably disposed about the shaft such that the first and third engagement features engage. The third member may be or comprise a second sleeve, the surface of the third member may be an inner surface of the second sleeve, the fourth engagement feature may extend along the inner surface of the second sleeve, and the second sleeve may be slidably disposed about the shaft such that the second and fourth engagement features engage. Consequently, the axial movement of the shaft with respect to the first and second sleeves may cause relative rotational movement between the first and second sleeves.
The first engagement feature may extend at a first angle with respect to a longitudinal axis of the first member, the second engagement feature may extend at a second angle with respect to the longitudinal axis of the first member, and the first and second angles may be different.
The downhole tool may further comprise a linear actuator operatively connected with the first member and operable to axially move the first member with respect to the second and third members.
The downhole tool may be operable to: impart an axial force to the first member to generate a relative torque between the second and third members causing the relative rotational movement between the second and third members; and engage the downhole equipment to transfer the relative torque from the second and third members to the downhole equipment causing rotational movement of the downhole equipment.
The downhole tool may further comprise a gripping member connected with the second member and operable to engage the downhole equipment disposed within the wellbore, and the relative movement between the second and third members may cause movement of the downhole equipment when the gripping member is engaged with the downhole equipment.
The downhole equipment may be a first downhole equipment, and the downhole tool may comprise a first gripping member connected with the second member and operable to engage the first downhole equipment, wherein the downhole tool further comprises a second gripping member connected with the third member and operable to engage a second downhole equipment, and wherein the relative rotational movement between the second and third members causes rotational movement of the first downhole equipment within the wellbore when the first gripping member is engaged with the first downhole equipment and the second gripping member is engaged with the second downhole equipment In an embodiment, the second downhole equipment may be or comprise a casing or a second tubular member containing the downhole equipment. In another embodiment, the first downhole equipment may be or comprise a first tubular member, and the second downhole equipment may be or comprise a second tubular member threadedly connected to the first tubular member.
The downhole equipment may be or comprise a sliding sleeve, a safety valve, a threaded tubular, or a threaded member of downhole completion equipment.
The downhole tool may further comprise a first ratcheting flywheel mechanism having a first gripper connected with the second member. The first gripper may be operable to: engage a first portion of the downhole equipment when the second member is rotating in a first rotational direction; and disengage from the first portion of the downhole equipment when the second member is rotating in a second rotational direction opposite from the first rotational direction. The downhole tool may further comprise a second ratcheting flywheel mechanism having a second gripper connected with the third member. The second gripper may be operable to: engage a second portion of the downhole equipment when the third member is rotating in the second rotational direction; and disengage from the second portion of the downhole equipment when the third member is rotating in the first rotational direction.
The present disclosure also introduces an apparatus comprising a downhole tool for rotating a first downhole equipment disposed within a wellbore, wherein the downhole tool comprises: a first rotative member; a second rotative member, wherein the first and second rotative members are operable to rotate relative to each other along an axis of the downhole tool; a first gripping member connected with the first rotative member, wherein the first gripping member is operable to engage the first downhole equipment; a second gripping member connected with the second rotative member, wherein the second gripping member is operable to engage a second downhole equipment; and an actuator operable to impart a force to cause the relative rotation between the first and second rotative members thereby causing rotation of the first downhole equipment when the first gripping member is connected with the first downhole equipment and the second gripping member is connected with the second downhole equipment.
The first downhole equipment may be or comprise a first tubular, the second downhole equipment may be or comprise a second tubular, and the rotation of the first downhole equipment with respect to the second downhole equipment may threadedly engage or disengage the first and second tubulars.
The downhole tool may further comprise a shaft comprising a first engagement feature and a second engagement feature each extending along an outer surface of the shaft. The first rotative member may comprise a third engagement feature extending along a surface of the first rotative member, the second rotative member may comprise a fourth engagement feature extending along a surface of the second rotative member, the first and third engagement features may be engaged and the second and fourth engagement features may be engaged such that axial movement of the shaft with respect to the first and second rotative members causes the relative rotation between the first and second rotative members, and the actuator may be a linear actuator operatively connected with the shaft and operable to axially move the shaft with respect to the first and second rotative members to cause the relative rotation between the first and second rotative members.
The downhole tool may further comprise a shaft, the first rotative member may be or comprise a first sleeve disposed about the shaft, the second rotative member may be or comprise a second sleeve disposed about the shaft, and the actuator may be operable to impart the force to the shaft to axially move the shaft with respect to the first and second sleeves to cause the relative rotation between the first and second sleeves.
The present disclosure also introduces a method comprising conveying a downhole tool within a wellbore, wherein the downhole tool comprises a first rotative member, a second rotative member, a first gripping member connected with the first rotative member, and a second gripping member connected with the second rotative member; engaging the first gripping member with a first downhole equipment within the wellbore; engaging the second gripping member with a second downhole equipment within the wellbore; and operating the downhole tool to rotatably move the first and second downhole equipment relative to each other by rotatably moving the first and second rotative members relative to each other.
The downhole tool may further comprise an actuator, and operating the downhole tool may comprise operating the actuator to impart a force to cause the relative rotational movement of the first and second rotative members thereby causing the relative rotational movement of the first and second downhole equipment.
The downhole tool may further comprise a shaft, the first rotative member may be or comprise a first sleeve disposed about the shaft, the second rotative member may be or comprise a second sleeve disposed about the shaft, and operating the downhole tool may comprise axially moving the shaft with respect to the first and second sleeves to rotatably move the first and second sleeves relative to each other. The shaft may comprise a first engagement feature and a second engagement feature each extending along an outer surface of the shaft. The first sleeve may comprise a third engagement feature extending along an inner surface of the first sleeve and slidably engaged with the first engagement feature, and the second sleeve may comprise a fourth engagement feature extending along an inner surface of the second sleeve and slidably engaged with the second engagement feature. Operating the downhole tool may comprise: axially moving the shaft in a first axial direction with respect to the first and second sleeves, thereby causing relative rotational movement between the first and second sleeves in a first relative rotational direction; releasing the first and second gripping members; and axially moving the shaft in a second axial direction with respect to the first and second sleeves that is opposite from the first axial direction, thereby causing relative rotational movement between the first and second sleeves in a second relative rotational direction that is opposite from the first relative rotational direction.
The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.
The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

What is claimed is:

1. An apparatus comprising:

a downhole tool for moving downhole equipment disposed within a wellbore, wherein the downhole tool comprises:

a first member comprising a first engagement feature and a second engagement feature each extending along an outer surface of the first member;

a second member comprising a third engagement feature extending along a surface of the second member; and

a third member comprising a fourth engagement feature extending along a surface of the third member;

wherein the first and third engagement features are engaged and the second and fourth engagement features are engaged such that axial movement of the first member with respect to the second and third members causes relative movement between the second and third members.

2. The apparatus of claim 1 wherein:

the first member is or comprises a shaft, the outer surface of the first member is an outer surface of the shaft, and the first and second engagement features extend along the outer surface of the shaft;

the second member is or comprises a first sleeve, the surface of the second member is an inner surface of the first sleeve, the third engagement feature extends along the inner surface, and the first sleeve is slidably disposed about the shaft such that the first and third engagement features engage;

the third member is or comprises a second sleeve, the surface of the third member is an inner surface of the second sleeve, the fourth engagement feature extends along the inner surface of the second sleeve, and the second sleeve is slidably disposed about the shaft such that the second and fourth engagement features engage; and

the axial movement of the shaft with respect to the first and second sleeves causes relative rotational movement between the first and second sleeves.

3. The apparatus of claim 1 wherein the first engagement feature extends at a first angle with respect to a longitudinal axis of the first member, wherein the second engagement feature extends at a second angle with respect to the longitudinal axis of the first member, and wherein the first and second angles are different.

4. The apparatus of claim 1 wherein the downhole tool further comprises a linear actuator operatively connected with the first member and operable to axially move the first member with respect to the second and third members.

5. The apparatus of claim 1 wherein the downhole tool is operable to:

impart an axial force to the first member to generate a relative torque between the second and third members causing the relative rotational movement between the second and third members; and

engage the downhole equipment to transfer the relative torque from the second and third members to the downhole equipment causing rotational movement of the downhole equipment.

6. The apparatus of claim 1 wherein the downhole tool further comprises a gripping member connected with the second member and operable to engage the downhole equipment disposed within the wellbore, and wherein the relative movement between the second and third members causes movement of the downhole equipment when the gripping member is engaged with the downhole equipment.

7. The apparatus of claim 1 wherein the downhole equipment is a first downhole equipment, wherein the downhole tool further comprises a first gripping member connected with the second member and operable to engage the first downhole equipment, wherein the downhole tool further comprises a second gripping member connected with the third member and operable to engage a second downhole equipment, and wherein the relative rotational movement between the second and third members causes rotational movement of the first downhole equipment within the wellbore when the first gripping member is engaged with the first downhole equipment and the second gripping member is engaged with the second downhole equipment.

8. The apparatus of claim 7 wherein the second downhole equipment is or comprises a casing or a tubular member containing the first downhole equipment.

9. The apparatus of claim 7 wherein the first downhole equipment is or comprises a first tubular member, and wherein the second downhole equipment is or comprises a second tubular member threadedly connected to the first tubular member.

10. The apparatus of claim 1 wherein the downhole equipment is or comprises a sliding sleeve, a safety valve, a threaded tubular, or a threaded member of downhole completion equipment.

11. The apparatus of claim 1 wherein:

the downhole tool further comprises a first ratcheting flywheel mechanism having a first gripper connected with the second member;

the first gripper is operable to:

engage a first portion of the downhole equipment when the second member is rotating in a first rotational direction; and

disengage from the first portion of the downhole equipment when the second member is rotating in a second rotational direction opposite from the first rotational direction;

the downhole tool further comprises a second ratcheting flywheel mechanism having a second gripper connected with the third member; and

the second gripper is operable to:

engage a second portion of the downhole equipment when the third member is rotating in the second rotational direction; and

disengage from the second portion of the downhole equipment when the third member is rotating in the first rotational direction.

12. An apparatus comprising:

a downhole tool for rotating a first downhole equipment disposed within a wellbore, wherein the downhole tool comprises:

a first rotative member;

a second rotative member, wherein the first and second rotative members are operable to rotate relative to each other along an axis of the downhole tool;

a first gripping member connected with the first rotative member, wherein the first gripping member is operable to engage the first downhole equipment;

a second gripping member connected with the second rotative member, wherein the second gripping member is operable to engage a second downhole equipment; and

an actuator operable to impart a force to cause the relative rotation between the first and second rotative members thereby causing rotation of the first downhole equipment when the first gripping member is connected with the first downhole equipment and the second gripping member is connected with the second downhole equipment.

13. The apparatus of claim 12 wherein the first downhole equipment is or comprises a first tubular, wherein the second downhole equipment is or comprises a second tubular, and wherein the rotation of the first downhole equipment with respect to the second downhole equipment threadedly engages or disengages the first and second tubulars.

14. The apparatus of claim 12 wherein:

the downhole tool further comprises a shaft comprising a first engagement feature and a second engagement feature each extending along an outer surface of the shaft;

the first rotative member comprises a third engagement feature extending along a surface of the first rotative member;

the second rotative member comprises a fourth engagement feature extending along a surface of the second rotative member;

the first and third engagement features are engaged and the second and fourth engagement features are engaged such that axial movement of the shaft with respect to the first and second rotative members causes the relative rotation between the first and second rotative members;

the actuator is a linear actuator operatively connected with the shaft and operable to axially move the shaft with respect to the first and second rotative members to cause the relative rotation between the first and second rotative members.

15. The apparatus of claim 12 wherein the downhole tool further comprises a shaft, wherein the first rotative member is or comprises a first sleeve disposed about the shaft, wherein the second rotative member is or comprises a second sleeve disposed about the shaft, and wherein the actuator is operable to impart the force to the shaft to axially move the shaft with respect to the first and second sleeves to cause the relative rotation between the first and second sleeves.

16. A method comprising:

conveying a downhole tool within a wellbore, wherein the downhole tool comprises:

a first rotative member;

a second rotative member;

a first gripping member connected with the first rotative member; and

a second gripping member connected with the second rotative member;

engaging the first gripping member with a first downhole equipment within the wellbore;

engaging the second gripping member with a second downhole equipment within the wellbore; and

operating the downhole tool to rotatably move the first and second downhole equipment relative to each other by rotatably moving the first and second rotative members relative to each other.

17. The method of claim 16 wherein the downhole tool further comprises an actuator, wherein operating the downhole tool comprises operating the actuator to impart a force to cause the relative rotational movement of the first and second rotative members thereby causing the relative rotational movement of the first and second downhole equipment.

18. The method of claim 16 wherein the downhole tool further comprises a shaft, wherein the first rotative member is or comprises a first sleeve disposed about the shaft, wherein the second rotative member is or comprises a second sleeve disposed about the shaft, and wherein operating the downhole tool comprises axially moving the shaft with respect to the first and second sleeves to rotatably move the first and second sleeves relative to each other.

19. The method of claim 18 wherein the shaft comprises a first engagement feature and a second engagement feature each extending along an outer surface of the shaft, wherein the first sleeve comprises a third engagement feature extending along an inner surface of the first sleeve and slidably engaged with the first engagement feature, and wherein the second sleeve comprises a fourth engagement feature extending along an inner surface of the second sleeve and slidably engaged with the second engagement feature.

20. The method of claim 18 operating the downhole tool comprises:

axially moving the shaft in a first axial direction with respect to the first and second sleeves thereby causing relative rotational movement between the first and second sleeves in a first relative rotational direction;

releasing the first and second gripping members; and

axially moving the shaft in a second axial direction with respect to the first and second sleeves that is opposite from the first axial direction thereby causing relative rotational movement between the first and second sleeves in a second relative rotational direction that is opposite from the first relative rotational direction.