Patent Description:
Oil and gas wells are drilled into Earth's surface or ocean bed to recover natural deposits of oil, gas, and materials that are trapped within subterranean geological formations. After a wellbore is drilled, a metal casing may be inserted therein and secured via cement, such as to protect the sidewall of the wellbore, isolate different geological formations, and maintain control of formation fluids and well pressure during various subsequent downhole operations. Thereafter, additional metal tubular strings may be inserted within the wellbore to facilitate delivery of treatment fluid downhole and transfer formation fluid to the surface. After the well is completed, various intervention operations may be performed to repair and maintain the well or otherwise optimize well productivity.

During production operations, when reservoir pressure is insufficient to force hydrocarbons from a subterranean reservoir to the wellsite surface, gas may be injected into a production tubing string to reduce density of the hydrocarbons located within. When density of the hydrocarbons is reduced, the reservoir pressure may then be sufficient to raise the column of hydrocarbons within the production tubing to the wellsite surface. The gas may be conveyed downhole along an annulus between the casing and production tubing and injected into the production tubing via a plurality of gas lift valves positioned along the production tubing. Each gas lift valve may be installed within a side pocket of a corresponding side pocket mandrel connected along the production tubing.

A kickover tool is used to install and retrieve a gas lift valve into and from a side pocket of a gas lift mandrel. The kickover tool comprises gas lift valve holder configured to grab and hold a gas lift valve. The kickover tool is conveyed downhole into a gas lift mandrel adjacent its side pocket. The holder is then extended laterally into the side pocket to install a new gas lift valve within the side pocket or retrieve an old gas lift valve from the side pocket. The kickover tool further comprises a holder displacement mechanism that engages a trigger recess along the side pocket mandrel and moves the holder into alignment with the side pocket. During operations, the kickover tool is conveyed into the gas lift mandrel past the trigger recess and then pulled uphole until a latch of the displacement mechanism engages the recess. Thereafter, an uphole pull of the kickover tool operates the displacement mechanism, causing the holder to be moved laterally into the side pocket. The kickover tool is then lowered downhole to install a new gas lift valve into the side pocket or grab an old gas lift valve installed within the side pocket. Current holder displacement mechanisms are complicated and, thus, more susceptible to malfunctions. Current holder displacement mechanisms also require special tools and/or partial disassembly to permit such holder displacement mechanisms to be reset to their retracted position.

Patent No. <CIT> discloses a positioning tool for use in placing a valve or removing a valve selectively from a mandrel in a tubing string. The positioning tool includes an elongated cylindrical body member with an elongated plunger telescopically and non rotatably arranged therein. Spring means abuts spaced shoulder means on the body member and elongated plunger to tend to urge the plunger and body member into abutting relationship adjacent their upper ends. A guide key is pivotally mounted on the body member by a shear pin and projects outwardly of a slot in the body member so that it may be engaged with a shoulder of an orientation sleeve mounted in the tubing string to align the positioning tool relative to a desired mandrel for placing a valve therein or removing a valve therefrom. A shifting tool is pivotally supported by the plunger and adapted to support a valve to be positioned in the mandrel and cooperating means on the plunger and shifting tool retain the plunger and shifting tool axially aligned in the main bore, but is operable on movement of the plunger relative to the body member for shifting the shifting tool means into the mandrel for positioning the valve therein. After the valve has been positioned in the mandrel the positioning tool may be realigned axially in the tubing string to enable it to be more readily withdrawn from the tubing.

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 comprising a downhole tool for installing a gas lift valve in a well, wherein the downhole tool comprises a housing, a mandrel movably disposed with respect to the housing, a holder configured to hold the gas lift valve, and an arm supporting the holder. The arm is operable to pivot between a retracted position in which the holder is adjacent the housing and an extended position in which the holder is disposed away from the housing. The mandrel and the arm are operatively connected via a pin-slot joint comprising a pin disposed within a slot. The slot comprises a first slot portion and a second slot portion. The pin-slot joint prevents the arm from pivoting when the pin is within the first slot portion. The pin-slot joint permits the arm to pivot when the pin is within the second slot portion.

The present disclosure also introduces an apparatus, which is not part of the claimed invention, comprising a downhole tool for installing a gas lift valve in a well, wherein the downhole tool comprises a housing, a mandrel movably disposed with respect to the housing, a first biasing member, a second biasing member, an arm pivotably connected to the housing, and a holder connected to the arm and configured to hold the gas lift valve. The arm is operable to pivot between a retracted position in which the holder is adjacent the housing and an extended position in which the holder is disposed away from the housing. The mandrel and the arm are operatively connected via a pin-slot joint comprising a pin disposed within a slot. The slot comprises a first slot portion and a second slot portion. The first slot portion and the second slot portion extend at an angle with respect to each other. The first biasing member is operable to bias the mandrel and the housing toward a predetermined relative position causing the pin to be maintained within the first slot portion to thereby prevent the arm from pivoting from the retracted position to the extended position. The second biasing member is operable to pivot the arm from the retracted position to the extended position when the pin is within the second slot portion.

The present disclosure also introduces an apparatus comprising a downhole tool for installing a gas lift valve in a well, wherein the downhole tool comprises a housing, a mandrel movably disposed with respect to the housing, a holder configured to hold the gas lift valve, and an arm supporting the holder. The arm is operable to pivot between a retracted position in which the holder is adjacent the housing and an extended position in which the holder is disposed away from the housing. The arm comprises a slot having a first slot portion and a second slot portion. The mandrel comprises a pin disposed within the slot. The pin prevents the arm from pivoting from the retracted position to the extended position when the pin is within the first slot portion.

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 material 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.

The present disclosure is best understood from the following detailed description when read with the accompanying figures.

<FIG> is a schematic view of at least a portion of an example implementation of a wellsite system <NUM> representing an example environment in which one or more aspects of the present disclosure may be implemented. The wellsite system <NUM> is depicted in relation to a wellbore <NUM> formed by rotary and/or directional drilling and extending from a wellsite surface <NUM> into a subterranean formation <NUM>. The wellsite system <NUM> may be utilized to facilitate the recovery of oil, gas, and/or other materials that are trapped in the formation <NUM> via the wellbore <NUM>. The wellbore <NUM> comprises a casing <NUM> secured by cement <NUM>. It is noted that although the wellsite system <NUM> is depicted as an onshore implementation, it is to be understood that the aspects described below are also generally applicable or readily adaptable to offshore implementations.

The wellsite system <NUM> includes surface equipment <NUM> located at the wellsite surface <NUM> and a downhole intervention and/or sensor assembly, referred to as a tool string <NUM>, conveyed within the wellbore <NUM> along one or more formations <NUM> via a conveyance means <NUM> operably coupled with one or more pieces of the surface equipment <NUM>. The conveyance means <NUM> may be operably connected with a conveyance device <NUM> operable to apply adjustable downward and/or upward forces to the tool string <NUM> via the conveyance means <NUM> to convey the tool string <NUM> within the wellbore <NUM>. The conveyance means <NUM> may be or comprise a cable, a wireline, a slickline, a multiline, an e-line, coiled tubing, and/or other conveyance means. The conveyance device <NUM> may be, comprise, or form at least a portion of a sheave or pulley, a winch, a drawworks, an injector head, and/or other device operable to guide and/or move the conveyance means <NUM> to thereby convey the tool string <NUM> within the wellbore <NUM>. The conveyance device <NUM> may be supported above the wellbore <NUM> via a mast, a derrick, a crane, and/or other support structure <NUM>. The surface equipment <NUM> may further comprise a reel or drum <NUM> configured to store thereon a wound length of the conveyance means <NUM>, which may be selectively wound and unwound by the conveyance device <NUM> to selectively convey the tool string <NUM> into, within, and out of the wellbore <NUM>.

Instead of or in addition to the conveyance device <NUM>, the surface equipment <NUM> may comprise a winch conveyance device <NUM> comprising or operably connected with the drum <NUM> and operable to selectively apply tension to the conveyance means <NUM> to convey the tool string <NUM> within the wellbore <NUM>. The winch conveyance device <NUM> may comprise the drum <NUM> and a rotary actuator <NUM> (e.g., an electric motor) operatively connected to the drum <NUM>. The rotary actuator <NUM> may rotate the drum <NUM> to selectively unwind and wind the conveyance means <NUM> to thereby apply an adjustable tensile force to the tool string <NUM> and, thus, selectively convey the tool string <NUM> into, within, and out of the wellbore <NUM>.

The conveyance means <NUM> may comprise one or more metal support wires or cables configured to support the weight of the downhole tool string <NUM>. The conveyance means <NUM> may also comprise one or more insulated electrical and/or optical conductors <NUM> operable to transmit electrical energy (i.e., electrical power) and/or electrical and/or optical signals (e.g., information, data, etc.) between the tool string <NUM> and one or more of the surface equipment <NUM>, such as a power and control system <NUM>. The conveyance means <NUM> may comprise and/or be operable in conjunction with means for communication between the tool string <NUM>, the conveyance device <NUM>, the winch conveyance device <NUM>, and/or one or more other portions of the surface equipment <NUM>, including the power and control system <NUM>.

The wellbore <NUM> may be capped by a plurality (e.g., a stack) of fluid control devices <NUM>, which may include fluid control valves, spools, and fittings individually and/or collectively operable to direct and control the flow of formation fluid out of the wellbore <NUM>. The fluid control devices <NUM> may also or instead comprise a blowout preventer (BOP) stack operable to prevent the flow of the formation fluid out of the wellbore <NUM>. The fluid control devices <NUM> may be mounted on a wellhead <NUM>.

The surface equipment <NUM> may further comprise a sealing and alignment assembly <NUM> mounted on the fluid control devices <NUM> and operable to seal the conveyance line <NUM> during deployment, conveyance, intervention, and other wellsite operations. The sealing and alignment assembly <NUM> may comprise a lock chamber (e.g., a lubricator, an airlock, a riser, etc.) mounted on the fluid control devices <NUM> and a stuffing box operable to seal around the conveyance line <NUM>, although such details are not shown in <FIG>. The stuffing box may be operable to seal around an outer surface of the conveyance line <NUM>, for example via annular packings applied around the surface of the conveyance line <NUM> and/or by injecting a fluid between the outer surfaces of the conveyance line <NUM> and an inner wall of the stuffing box. The tool string <NUM> may be deployed into or retrieved from the wellbore <NUM> via the conveyance device <NUM> and/or winch conveyance device <NUM> through the wellhead <NUM>, the control devices <NUM>, and/or the sealing and alignment assembly <NUM>.

The power and control system <NUM> (e.g., a control center) may be utilized to monitor and control various portions of the wellsite system <NUM>. The power and control system <NUM> may be located at the wellsite surface <NUM> or on a structure located at the wellsite surface <NUM>. However, the power and control system <NUM> may instead be located remote from the wellsite surface <NUM>. The power and control system <NUM> may include a source of electrical power <NUM>, a memory device <NUM>, and a surface controller <NUM>. The electrical power source <NUM> (e.g., a battery, an electric generator, etc.) may supply electrical power to various equipment of the wellsite system <NUM>, including the memory device <NUM>, the surface controller <NUM>, the tool string <NUM>, the conveyance device <NUM>, and/or the winch conveyance device <NUM>. The surface controller <NUM> (e.g., a processing device, a computer, etc.) may store executable programs and/or instructions, including for implementing one or more aspects of methods, processes, and operations described herein. The surface controller <NUM> may be communicatively connected with various equipment of the wellsite system <NUM>, such as may permit the surface controller <NUM> to monitor operations of one or more portions of the wellsite system <NUM> and/or to provide automatic control of one or more portions of the wellsite system <NUM>, including the electrical power source <NUM>, the tool string <NUM>, the conveyance device <NUM>, and/or the winch conveyance device <NUM>. The surface controller <NUM> may also or instead be used by wellsite personnel (i.e., a human operator) to manually control one or more portions of the wellsite system <NUM>, including the tool string <NUM>, the conveyance device <NUM>, and/or the winch conveyance device <NUM>. The surface controller <NUM> may include input devices for receiving commands from the wellsite personnel and output devices for displaying information to the wellsite personnel.

Production tubing <NUM> may be installed within the wellbore <NUM>, defining an annulus <NUM> (i.e., an annular space) between an inner surface of the casing <NUM> and an outer surface of the production tubing <NUM>. A plurality of gas lift mandrels <NUM> (i.e., side pocket mandrels) (only one shown) may form portions of or be connected along the production tubing <NUM>. Each gas lift mandrel <NUM> may comprise a side pocket <NUM> laterally (or radially) offset from a main production bore <NUM> of the gas lift mandrel <NUM> and configured to receive or otherwise hold a gas lift valve <NUM> for injecting a gas (e.g., nitrogen) into the production tubing <NUM> during hydrocarbon production operations. The gas may be injected into the annulus <NUM> at the wellsite surface <NUM> via the wellhead <NUM> or a fluid control device <NUM> and transferred downhole via the annulus <NUM> to the gas lift valves <NUM>. The gas may then pass into each gas lift valve <NUM> via an opening <NUM> extending through a wall of the gas lift mandrel <NUM> between the annulus <NUM> and the side pocket <NUM> containing the gas lift valve <NUM>. Each gas lift valve <NUM> may inject the gas into the main production bore <NUM> of the gas lift mandrel <NUM> and the production tubing <NUM> to decrease the density of formation fluid comprising the hydrocarbons within the production tubing <NUM> to increase the flow of formation fluid to the wellsite surface <NUM>. Each gas lift mandrel <NUM> may further comprise a receptacle <NUM> (e.g., a recess) or other feature within, extending into, or located on an inner surface of the gas lift mandrel <NUM> along the main production bore <NUM>.

The tool string <NUM> may be conveyed within the wellbore <NUM> through the production tubing <NUM> to perform various intervention and other downhole operations. The tool string <NUM> may comprise one or more downhole tools <NUM> (e.g., devices, modules, subs, etc.) operable to perform such downhole operations. The conductors <NUM> may extend through or along at least a portion of the tool string <NUM>, such as to communicatively and/or electrically connect one or more downhole tools <NUM> of the tool string <NUM> with the power and control system <NUM>. The conductors <NUM> extending through the tool string <NUM> may also facilitate electrical communication between two or more tools <NUM>. One or more of the downhole tools <NUM> may comprise corresponding electrical conductors, connectors, and/or interfaces forming a portion of the conductor <NUM> extending through the tool string <NUM>. The conductor <NUM> may extend through the conveyance means <NUM> and externally from the conveyance means <NUM> at the wellsite surface <NUM> via a rotatable joint or coupling (e.g., a collector) (not shown) carried by the drum <NUM>.

The tools <NUM> of the tool string <NUM> may comprise a cable head <NUM> (e.g., a logging head, a cable termination sub, etc.) operable to physically and/or electrically connect the conveyance means <NUM> with the tool string <NUM>. The cable head <NUM> may thus permit the tool string <NUM> to be suspended and conveyed within the wellbore <NUM> via the conveyance means <NUM>. The tools <NUM> may comprise one or more of a jarring tool, a stroker tool, and a release tool. The tools <NUM> may comprise a telemetry tool, such as may facilitate communication between the tool string <NUM> and the surface controller <NUM>. The tools <NUM> may comprise one or more inclination and/or directional sensors (not shown), such as one or more accelerometers, magnetometers, gyroscopic sensors (e.g., micro-electro-mechanical system (MEMS) gyros), and/or other sensors for determining the orientation and/or direction of the tool string <NUM> within the wellbore <NUM>. The tools <NUM> may comprise a depth correlation tool, such as a casing collar locator (CCL) tool for detecting the ends of casing collars by sensing a magnetic irregularity caused by the relatively high mass of an end of a collar of the casing <NUM>. The depth correlation tool may also or instead be or comprise a gamma ray (GR) tool that may be utilized for depth correlation.

One or more of the tools <NUM> may comprise a downhole controller <NUM> communicatively connected with the surface controller <NUM> via the conductors <NUM> and with other portions of the tool string <NUM>. The downhole controller <NUM> may be further operable to store and/or communicate to the tool string control system <NUM> signals or information generated by one or more sensors or instruments of the tool string <NUM>. The downhole controller <NUM> may be operable to control one or more portions of the tool string <NUM>. For example, the downhole controller <NUM> may be operable to receive, store, and/or process control commands from the power and control system <NUM> for controlling one or more tools <NUM> of the tool string <NUM>.

The tool string <NUM> may comprise a kickover tool <NUM> operable to install (new) gas lift valves <NUM> within the side pockets <NUM> of the gas lift mandrels <NUM> and to retrieve (old) gas lift valves <NUM> from the side pockets <NUM> of the gas lift mandrels <NUM>. The kickover tool <NUM> may comprise a housing <NUM>, a latch <NUM>, an arm <NUM>, and a valve holder <NUM> connected to or otherwise carried by the arm <NUM>. The tool string <NUM> (including the kickover tool <NUM>) may be conveyed downhole to a position within the main bore <NUM> and adjacent the side pocket <NUM> of a predetermined gas lift mandrel <NUM>. The arm <NUM> may then be selectively operated to extend the valve holder <NUM> away (e.g., laterally or radially) from the housing <NUM> into alignment with the side pocket <NUM>. Extension of the arm <NUM> and the valve holder <NUM> may be triggered when the tool string <NUM> (including the kickover tool <NUM>) is conveyed uphole, causing the latch <NUM> to engage (e.g., enter, latch against, contact, etc.) the receptacle <NUM> or other feature of the gas lift mandrel <NUM>.

During gas lift valve installation operations, the valve holder <NUM> may initially hold a new gas lift valve <NUM>. After the kickover tool <NUM> is adjacent the side pocket <NUM> of a predetermined gas lift mandrel <NUM>, the arm <NUM> may be operated to extend the valve holder <NUM> and the new gas lift valve <NUM> away from the housing <NUM> into alignment with the side pocket <NUM>. The tool string <NUM> (including the kickover tool <NUM>) may then be moved downhole to install the new gas lift valve <NUM> into an empty side pocket <NUM>. The tool string <NUM> may then be retrieved to the wellsite surface <NUM>. During gas lift valve retrieval operations, the valve holder <NUM> may initially be empty. After the kickover tool <NUM> is adjacent the side pocket <NUM> of a predetermined gas lift mandrel <NUM>, the arm <NUM> may be operated to extend the empty valve holder <NUM> away from the housing <NUM> into alignment with the side pocket <NUM> containing an old gas lift valve <NUM>. The tool string <NUM> (including the kickover tool <NUM>) may then be moved downhole to connect the empty valve holder <NUM> to the old gas lift valve <NUM> installed within the side pocket <NUM>. The tool string <NUM> (including the old gas lift valve <NUM>) may then be retrieved to the wellsite surface <NUM>.

<FIG> is a sectional view of at least a portion of an example implementation of a kickover tool <NUM> according to one or more aspects of the present disclosure. <FIG> is another sectional view of a portion of the kickover tool <NUM> shown in <FIG>, from the perspective indicated in <FIG>. <FIG> are sectional views of the kickover tool <NUM> shown in <FIG> and <FIG> in various stages of downhole operations according to one or more aspects of the present disclosure. The kickover tool <NUM> may be an example implementation of the kickover tool <NUM> described above and shown in <FIG> and may comprise one or more features of the kickover tool <NUM>. Accordingly, the following description refers to <FIG>, collectively.

The kickover tool <NUM> may comprise a housing (or body) <NUM> defining or otherwise encompassing a plurality of internal spaces or volumes containing various components of the kickover tool <NUM>. Although the housing <NUM> is shown as comprising a single unitary member, it is to be understood that the housing <NUM> may be or comprise a housing assembly having a plurality of housing sections coupled together to form the housing <NUM>. An upper (uphole) end of the kickover tool <NUM> may include an upper interface, a sub, a crossover, and/or other coupler <NUM> for mechanically and/or electrically coupling the kickover tool <NUM> with a corresponding interface (not shown) of a downhole tool <NUM> or other portion of a tool string <NUM>. The coupler <NUM> may be a part of the housing <NUM> or directly or indirectly coupled with the housing <NUM>, such as via a threaded connection.

The kickover tool <NUM> may further comprise a gas lift valve holder <NUM> (i.e., a grabber, a knuckle, etc.) configured to receive and hold a gas lift valve <NUM>. For example, the holder <NUM> may comprise a receptacle <NUM> configured to receive and hold an end of the gas lift valve <NUM>. The kickover tool <NUM> may further comprise a displacement mechanism <NUM> operable to move the holder <NUM> from a retracted (i.e., run-in) position (shown in <FIG> and <FIG>), in which the holder <NUM> is disposed adjacent or within the housing <NUM>, to an extended (i.e., deployed, displaced, etc.) position (shown in <FIG> and <FIG>), in which the holder <NUM> is laterally (or radially) offset or otherwise disposed away (i.e., spaced away) from the housing <NUM>.

The displacement mechanism <NUM> may comprise an arm <NUM> directly or indirectly connected with the holder <NUM>. Although the arm <NUM> is shown as comprising a single unitary member, it is to be understood that the arm <NUM> may be or comprise an arm assembly having a plurality of arm sections coupled together to form the arm <NUM>. The arm <NUM> may be pivotably connected with the housing <NUM> at an upper (uphole) end of the arm <NUM>. The holder <NUM> may be pivotably connected with the arm <NUM> at a lower (downhole) end of the arm <NUM>. The arm <NUM> may be pivotably connected with the housing <NUM> at an upper pivot point located at the upper end of the arm <NUM>, opposite from the lower end of the arm <NUM> connected with the holder <NUM>. The upper pivot point may be defined by an upper pivot pin <NUM> extending through at least a portion of the housing <NUM> and the arm <NUM> to pivotably connect the arm <NUM> to the housing <NUM>. The holder <NUM> may be pivotably connected with the arm <NUM> at a lower pivot point located at the lower end of the arm <NUM>, opposite from the upper end of the arm <NUM>. The lower pivot point may be defined by a lower pivot pin <NUM> extending through at least a portion of the holder <NUM> and the arm <NUM> to pivotably connect the holder <NUM> to the arm <NUM>.

While the displacement mechanism <NUM> is in the retracted position, the arm <NUM>, the holder <NUM>, and the gas lift valve <NUM> connected to the holder <NUM> may each be axially aligned with a longitudinal axis (e.g., a central axis) of the kickover tool <NUM> such that the arm <NUM>, the holder <NUM>, and the gas lift valve <NUM> are disposed adjacent to or within an open portion <NUM> (e.g., a cavity, a receptacle, etc.) of the housing <NUM>. The open portion <NUM> of the housing <NUM> may comprise or be defined by an opening <NUM> (e.g., a slot, a channel, etc.) extending laterally (or radially) through a sidewall of the housing <NUM> and longitudinally along the housing <NUM>. The open portion <NUM> of the housing <NUM> may extend below the arm <NUM> and the holder <NUM> to accommodate the gas lift valve <NUM> while the kickover tool <NUM> is conveyed within the production tubing <NUM> installed within the wellbore <NUM>. A lower end <NUM> of the kickover tool <NUM> (or the housing <NUM>) may be or comprise a receptacle <NUM> for catching the gas lift valve <NUM> when the gas lift valve <NUM> becomes disconnected from the holder <NUM> during conveyance or other operations. While the displacement mechanism <NUM> is in the extended position, the arm <NUM> may extend (i. , protrude) laterally away from the housing <NUM> via the opening <NUM> of the open portion <NUM> of the housing <NUM> and the holder <NUM> may be laterally (or radially) offset from the housing <NUM> and axially aligned with a side pocket <NUM> of a gas lift mandrel <NUM>. Such positioning may permit a new gas lift valve <NUM> connected to the holder <NUM> to be installed within an empty side pocket <NUM>. Such positioning may also permit an empty holder <NUM> to couple with (e.g., grab and hold) an old gas lift valve <NUM> installed within the side pocket <NUM>, thereby permitting the old gas lift valve <NUM> to be retrieved to the wellsite surface <NUM>.

The kickover tool <NUM> may further comprise a chamber <NUM> within the housing <NUM> containing at least a portion of the displacement mechanism <NUM>. The chamber <NUM> may be connected with or extend to the open portion <NUM> of the housing <NUM>. The displacement mechanism <NUM> may further comprise a movable member <NUM> slidably or otherwise movably connected with or otherwise disposed with respect to the housing <NUM>. At least a portion of the movable member <NUM> may be slidably or otherwise movably disposed within the chamber <NUM> and extend into the open portion <NUM> of the housing <NUM>. The movable member <NUM> may be or comprise a mandrel, a rod, a shaft, or other member movably connected with or otherwise disposed with respect to the housing <NUM>. The movable member <NUM> may have a generally cylindrical geometry. It is to be understood that item <NUM> is referred to as a "movable member" for clarity and ease of understanding because the movable member <NUM> is movably connected with and, thus, movable with respect to the housing <NUM>. However, it is also to be understood that during dowhole operations within the scope of the present disclosure, the movable member <NUM> may remain fixed or be locked in a fixed vertical position along or with respect to the wellbore <NUM> (e.g., the production tubing <NUM>) while the housing <NUM> is vertically moved along or with respect to the wellbore <NUM> and the movable member <NUM>.

The displacement mechanism <NUM> may further comprise a biasing means <NUM> disposed in association with the arm <NUM>. The biasing means <NUM> may be configured to bias the arm <NUM> from a retracted (i.e., run-in) position (shown in <FIG> and <FIG>), in which the arm <NUM> extends substantially parallel to or longitudinally along or within the housing <NUM>, toward an extended (i.e., deployed, pivoted, etc.) position (shown in <FIG> and <FIG>), in which the arm <NUM> extends laterally (e.g., diagonally) away from or otherwise with respect to the housing <NUM>. The arm <NUM> may be operable to move the holder <NUM> from its retracted position to its extended position, such that when the arm <NUM> is in its retracted position, the holder <NUM> is also in its retracted position, and when the arm <NUM> is in its extended position, the holder <NUM> is also in its extended position. The biasing means <NUM> may comprise a plurality of leaf springs, each disposed on an opposing side of a backing member. While the arm <NUM> is in its retracted position, one or more of the leaf springs may push against the backing member and the housing <NUM>, and other one or more of the leaf springs may push against the backing member and the arm <NUM> to therefore collectively bias the arm <NUM> from its retracted position toward its extended position during the gas lift valve installation or retrieval operations. The biasing means <NUM> may instead comprise a coiled spring disposed in association with (e.g., within, around, etc.) telescoping guide members collectively operable to stabilize the coiled spring along its central axis while the coiled spring is compressed. While the arm <NUM> is in its retracted position, one end of the coiled spring may push against the housing <NUM> and the other end of the coiled spring may push against the arm <NUM> to therefore bias the arm <NUM> from its retracted position toward its extended position during the gas lift valve installation or retrieval operations.

The movable member <NUM> and the arm <NUM> may be mechanically or otherwise operatively connected and relatively movable between a first relative position in which the movable member <NUM> prevents the arm <NUM> from pivoting from its retracted position to its extended position and a second relative position in which the movable member <NUM> permits the arm <NUM> to pivot from its retracted position to its extended position. For example, the movable member <NUM> and the arm <NUM> may each be configured to engage while in the first relative position to prevent the arm <NUM> from pivoting from its retracted position to its extended position and to disengage while in the second relative position to permit the arm <NUM> to pivot from its retracted position to its extended position. Thus, relative movement between the movable member <NUM> and the arm <NUM> may cause the movable member <NUM> and the arm <NUM> to engage, preventing the arm <NUM> from pivoting from its retracted position to its extended position, and to disengage, permitting the arm <NUM> to pivot from its retracted position to its extended position.

A lower end of the movable member <NUM> may comprise a pin <NUM> (e.g., a key, a protrusion, a circular outer profile, etc.) extending therefrom. The lower end of the movable member <NUM> may comprise a slit <NUM> extending longitudinally and laterally through the movable member <NUM>. The pin <NUM> may extend through the lower end of the movable member <NUM> across the slit <NUM>. The arm <NUM> may comprise a curved (or deviated) slot <NUM> (e.g., a curved channel, a curved receptacle, a curved inner profile, etc.) configured to receive the pin <NUM>. The pin <NUM> and the slot <NUM> may collectively be or form a pin-slot joint <NUM> (also known as a pin-in-slot joint).

The curved slot <NUM> may comprise a first slot portion <NUM> and a second slot portion <NUM> connected to each other and extending laterally (e.g., diagonally, perpendicularly, etc.) or otherwise at an angle with respect to each other. The first slot portion <NUM> may extend along a longitudinal axis of the arm <NUM> and the second slot portion <NUM> may extend laterally (e.g., diagonally, perpendicularly, etc.) or otherwise at an angle with respect to the longitudinal axis of the arm <NUM>. The second slot portion <NUM> may extend partially around the pivot point defined by the pivot pin <NUM>. For example, the second slot portion <NUM> may extend circumferentially around the pivot point by or along a predetermined angle <NUM> (i.e., angular distance), starting at an initial angle (e.g., zero degrees) aligned with the first slot portion <NUM>, and terminating at the predetermined angle <NUM> around the pivot point. The second slot portion <NUM> may thus comprise a radius <NUM> extending to the pivot point. The curved slot <NUM> may extend through (penetrate) the arm <NUM> and accommodate the pin <NUM> therethrough (or contain the pin therein). The slot <NUM> may be located at an upper end of the arm <NUM> above the pivot pin <NUM>, such that the pivot pin <NUM> is located between the slot <NUM> and the holder <NUM>. The upper end of the arm <NUM> may be disposed within the slit <NUM> of the movable member <NUM> such that the pin <NUM> is disposed within the slot <NUM>.

The movable member <NUM> and the arm <NUM> may be mechanically or otherwise operatively connected via the pin-slot joint <NUM> and relatively movable between a first relative position in which the pin-slot joint <NUM> prevents the arm <NUM> from pivoting from its retracted position to its extended position and a second relative position in which the pin-slot joint <NUM> permits the arm <NUM> to pivot from its retracted position to its extended position. Thus, during different stages of downhole operations, the movable member <NUM> and the arm <NUM> may be movable with respect to each other to permit, cause, or otherwise facilitate relative movement between the pin <NUM> and the slot <NUM> of the pin-slot joint <NUM> to thereby control position of the arm <NUM>. For example, when the movable member <NUM> and the arm <NUM> are moved away from each other (e.g., the movable member <NUM> moves upward (uphole) away from the arm <NUM>), the pin <NUM> and the first slot portion <NUM> may engage (e.g., latch, mesh, interlock, etc.). In such position, the pin <NUM> may be disposed within the first slot portion <NUM> such that the side walls of the first slot portion <NUM> contact the pin <NUM>. In such position, the pin <NUM> latches the arm <NUM> and prevents the arm <NUM> from pivoting from its retracted position to its extended position. However, when the movable member <NUM> and the arm <NUM> are moved toward each other (e.g., the movable member <NUM> moves downward (downhole) toward the arm <NUM>), the pin <NUM> and the first slot portion <NUM> may disengage, whereby the pin moves out of the first slot portion <NUM> into the second slot portion <NUM>. In such position, the pin <NUM> does not prevent the arm <NUM> from pivoting, thereby permitting the biasing means <NUM> to pivot the arm <NUM> about the pivot pin <NUM> from its retracted position to its extended position. While the arm <NUM> pivots about the pivot pin <NUM>, the pin <NUM> moves along the second slot portion <NUM> until the pin <NUM> reaches the end of the second slot portion <NUM>, causing the arm <NUM> to stop pivoting. The angle <NUM> through which the first slot portion <NUM> extends around the pivot pin <NUM> limits the angle through which the arm <NUM> pivots to reach its extended position. For example, if the first slot portion <NUM> extends <NUM> degrees around the pivot pin <NUM>, the arm <NUM> may also pivot <NUM> degrees from its retracted position to its extended position.

The displacement mechanism <NUM> may further comprise a biasing member <NUM> (e.g., a coiled spring) movably or otherwise operatively connecting the housing <NUM> with the movable member <NUM> and, thus, also operatively connecting the housing <NUM> with the arm <NUM>. For example, the biasing member <NUM> may bias the movable member <NUM> upward with respect to the arm <NUM> and, thus, bias the movable member <NUM> against or into contact with the arm <NUM> to therefore engage the movable member <NUM> with the arm <NUM>. For example, the biasing member <NUM> may bias the pin <NUM> of the movable member <NUM> upward such that the pin <NUM> engages (e.g., enters, meshes with, interlocks with, connects with, etc.) the first slot portion <NUM> of the slot <NUM> while the arm <NUM> is in its retracted position. As described above, while the pin <NUM> of the movable member <NUM> engages the first slot portion <NUM> of the slot <NUM>, the pin <NUM> latches the arm <NUM> in its retracted position, preventing the arm <NUM> from pivoting to its extended position. Accordingly, the first slot portion <NUM> of the slot <NUM> may be or operate as a detent (or receptacle) and the pin <NUM> may be or operate as a follower, collectively preventing the arm <NUM> from pivoting when the pin <NUM> engages (is disposed within) the first slot portion <NUM> and permitting the arm <NUM> to pivot when the pin <NUM> disengages (exits) the first slot portion <NUM> and moves into the second slot portion <NUM>.

The displacement mechanism <NUM> may further comprise a latch (e.g., a trigger) <NUM> directly or indirectly connected with the movable member <NUM>. The latch <NUM> may be biased by a biasing member (e.g., a leaf spring) <NUM> to extend out of the housing <NUM> through a slot opening <NUM> in the housing <NUM>. The latch <NUM> may be configured to engage (e.g., enter, lock with, latch against, etc.) a receptacle <NUM> along a main bore <NUM> of a gas lift mandrel <NUM> while the kickover tool <NUM> moves through the main bore <NUM> of the gas lift mandrel <NUM>. The latch <NUM> may be connected to the movable member <NUM> via an intermediate movable member <NUM> slidably disposed within the chamber <NUM> of the housing <NUM>. The latch <NUM> may be pivotably connected with the intermediate movable member <NUM> at a pivot point defined by a pivot pin <NUM>, permitting the latch <NUM> to be forced or otherwise moved into the chamber <NUM> via the slot opening <NUM>.

The intermediate movable member <NUM> may be threadedly or otherwise fixedly connected with the movable member <NUM>, such as may permit the movable members <NUM>, <NUM> to move as a single member or otherwise in unison within the chamber <NUM>. The intermediate movable member <NUM> may comprise opposing upper and lower shoulders (e.g., flanges) <NUM>, <NUM> having larger outer diameters than the movable member <NUM>. The shoulders <NUM>, <NUM> may be configured to abut corresponding shoulders <NUM>, <NUM> or other surfaces of the housing <NUM> to limit movement of the movable members <NUM>, <NUM> within the chamber <NUM> and, thus, with respect to the housing <NUM> and the arm <NUM>. The biasing member <NUM> may be disposed within the chamber <NUM> and extend around the movable member <NUM>. The biasing member <NUM> may be compressed between a shoulder <NUM> of the housing <NUM> and the shoulder <NUM> of the intermediate movable member <NUM>, thereby applying an upward biasing force to the movable members <NUM>, <NUM> with respect to the housing <NUM> and the arm <NUM>. As described above, the biasing member <NUM> applies an upward biasing force to the pin <NUM> connected to the movable member <NUM>, biasing the pin <NUM> to remain engaged with (disposed within) the first slot portion <NUM> in the arm <NUM>.

Although the movable member <NUM> is shown and described as comprising the pin <NUM> and the arm <NUM> is shown and described as comprising the slot <NUM>, it is to be understood that in a different implementation of the kickover tool within the scope of the present disclosure, the movable member <NUM> may comprise a curved slot (e.g., a channel, a receptacle, etc.), such as the curved slot <NUM>, and the arm <NUM> may comprise a follower pin (e.g., a key, a protrusion, etc.), such as the pin <NUM>. For example, the upper end of the arm <NUM> may comprise a slit and the follower pin extending across the slit. A lower end of the movable member <NUM> may comprise the curved (or deviated) slot accommodating the follower pin. The lower end of the movable member <NUM> may be disposed within the slit of the arm <NUM> such that the follower pin is disposed within the curved slot. The curved slot may comprise a first slot portion extending along a longitudinal axis of the movable member <NUM> and a second slot portion extending laterally (e.g., diagonally, perpendicularly, etc.) with respect to the longitudinal axis of the movable member <NUM>. The second slot portion may extend partially around the pivot point of the arm <NUM> defined by the pivot pin <NUM> when the follower pin is located within the second slot portion. For example, the second slot portion may extend circumferentially around the pivot point by or along a predetermined angle (i.e., angular distance), starting at an initial angle (e.g., zero degrees) aligned with the first slot portion, and terminating at the predetermined angle around the pivot point. The second slot portion may thus comprise a radius extending to the pivot point. The curved slot may extend through (penetrate) the movable member <NUM> and accommodate the follower pin therethrough. The follower pin may be located at an upper end of the arm <NUM> above the pivot pin <NUM>, such that the pivot pin <NUM> is located between the follower pin and the holder <NUM>.

A rotating member <NUM> (e.g., a roller, a wheel, a ball bearing, etc.) or other friction reducing member (e.g., a friction reducing plate) may be rotatably connected to or otherwise carried by the arm <NUM>, such as to reduce friction between the arm <NUM> and an inner surface of the production tubing <NUM> after the arm <NUM> pivots to its extended position. The rotating member <NUM> may project or extend past an outer surface of the arm <NUM> and be located at a lower end of the arm <NUM> to facilitate contact with the production tubing <NUM> after the arm <NUM> pivots to its extended position. The rotating member <NUM> may be disposed within a cavity <NUM> in the arm <NUM> or the rotating member <NUM> may be connected with the arm <NUM> via a bracket or base (not shown) connected to or otherwise extending from the arm <NUM>. The rotating member <NUM> may comprise a spherical geometry or a cylindrical geometry. The rotating member <NUM> may be one of a plurality of rotating members <NUM> rotatably connected to or otherwise carried by the arm <NUM>.

The present disclosure is further directed to methods, which are not part of the claimed invention, of using or operating the kickover tool <NUM> to install a new gas lift valve <NUM> into the side pocket <NUM> of a gas lift mandrel <NUM> located along the production tubing <NUM> within the wellbore <NUM> and to retrieve an old (or used) gas lift valve <NUM> from the side pocket <NUM> of a gas lift mandrel <NUM>. For example, to install the new gas lift valve <NUM>, a tool string <NUM> comprising the kickover tool <NUM> carrying the new gas lift valve <NUM> may be conveyed within the production tubing <NUM>, while the holder <NUM> with the new gas lift valve <NUM> is in its retracted position, until the kickover tool <NUM> is disposed within an intended gas lift mandrel <NUM> in which the new gas lift valve <NUM> is to be installed. The kickover tool <NUM> may be conveyed downhole until the latch <NUM> is located adjacent to or below the receptacle <NUM> along the sidewall of the gas lift mandrel <NUM>. The tool string <NUM> may then be pulled uphole until the latch <NUM> engages (e.g., enters, latches against, etc.) the receptacle <NUM>, as shown in <FIG>, thereby locking in position the latch <NUM> and other portions of the displacement mechanism <NUM> connected with the latch <NUM>, including the movable members <NUM>, <NUM>.

The tool string <NUM> may be pulled further uphole to trigger the displacement mechanism <NUM> to cause the holder <NUM> and the new gas lift valve <NUM> to move to the extended position and, thus, permit the new gas lift valve <NUM> to be installed within the side pocket <NUM> of the gas lift mandrel <NUM>. As shown in <FIG>, pulling of the kickover tool <NUM> uphole causes the housing <NUM> to move uphole while the movable members <NUM>, <NUM> remain in a static vertical position (i.e., at a static depth) with respect to the gas lift mandrel <NUM>, thereby compressing the biasing means <NUM> between the housing <NUM> and the movable member <NUM>. Because the arm <NUM> is connected with the housing <NUM>, uphole movement of the housing <NUM> causes the arm <NUM> to move in the uphole direction with respect to the movable member <NUM>, thereby causing the pin <NUM> of the movable member <NUM> to progressively disengage (i.e., exit) the first slot portion <NUM> and move into the second slot portion <NUM>. The housing <NUM> and the arm <NUM> may continue to move uphole until the shoulder <NUM> of the intermediate movable member <NUM> contacts the shoulder <NUM> of the housing <NUM>. At such position, the pin <NUM> of the movable member <NUM> fully disengages the first slot portion <NUM> and enters into the second slot portion <NUM>.

As shown in <FIG>, when the pin <NUM> of the movable member <NUM> fully disengages the first slot portion <NUM> and enters the second slot portion <NUM>, the pin <NUM> no longer prevents the arm <NUM> from pivoting, thereby permitting the biasing means <NUM> to pivot the arm <NUM> and the holder <NUM> with the new gas lift valve <NUM> toward their extended position within the side pocket <NUM>. While the arm <NUM> and the holder <NUM> move toward their extended position, the holder <NUM> and the new gas lift valve <NUM> may pivot into alignment with the side pocket <NUM> via contact of the holder <NUM> and/or the new gas lift valve <NUM> with a sidewall <NUM> of the side pocket <NUM>, causing the holder <NUM> and the new gas lift valve <NUM> to pivot into alignment with the side pocket <NUM>.

When the arm <NUM> and the holder <NUM> reach their extended position and the holder <NUM> and the new gas lift valve <NUM> are aligned with the side pocket <NUM>, the tool string <NUM> may then be moved downhole to insert the new gas lift valve <NUM> within the side pocket <NUM>. After the new gas lift valve <NUM> is inserted within the side pocket <NUM>, the tool string <NUM> may be conveyed to the wellsite surface <NUM> via the production tubing <NUM>. Another new gas lift valve <NUM> may then be connected with the holder <NUM> and the tool string <NUM> may again be conveyed downhole to another gas lift mandrel <NUM> to install the new gas lift valve <NUM>. While the tool string <NUM> is conveyed to the wellsite surface <NUM>, the arm <NUM> may still be extended and, thus, contact the inner surface of the production tubing <NUM>. The rotatable member <NUM> may contact and roll along the inner surface of the production tubing <NUM> to reduce friction between the arm <NUM> and the production tubing <NUM>.

When the kickover tool <NUM> reaches the wellsite surface <NUM>, a new gas lift valve <NUM> may be connected with the holder <NUM>, and the arm <NUM> and the holder <NUM> may be moved to their retracted position by performing displacement mechanism resetting operations. During such resetting operations, the pin <NUM> and the first slot portion <NUM> may be engaged by pivoting the arm <NUM> from its extended position to its retracted position until the pin <NUM> engages (e.g., moves onto) the first slot portion <NUM>. Such operations may be performed manually by hand, without the use of hand or other mechanical tools. During the resetting operations, the arm <NUM> may be manually pivoted toward its retracted position by overcoming the force of the biasing means <NUM>. During the resetting operations, the biasing member <NUM> may force (e.g., pull) the movable member <NUM> upward, thereby causing the pin <NUM> to slide along a sidewall of the second slot portion <NUM> while the arm <NUM> is being rotated. When the arm <NUM> reaches its retracted position, the pin <NUM> may engage (move into) the first slot portion <NUM>, engaging the arm <NUM> with the movable member <NUM> to prevent the arm <NUM> from pivoting back to its extended position.

To retrieve an old gas lift valve <NUM> from a side pocket <NUM> of a gas lift mandrel <NUM>, the operations or actions described above may be performed, but without a gas lift valve <NUM> connected to the holder <NUM>. For example, the kickover tool <NUM> with an empty holder <NUM> may be conveyed within the production tubing <NUM>, while the empty holder <NUM> is in a retracted position, until the kickover tool <NUM> is disposed within an intended gas lift mandrel <NUM> in which the old gas lift valve <NUM> is installed. Thereafter, the tool string <NUM> may be pulled uphole until the latch <NUM> engages the receptacle <NUM> and the displacement mechanism <NUM> moves the arm <NUM> and the holder <NUM> to their extended position and into alignment with the old gas lift valve <NUM> within the side pocket <NUM>. Thereafter, the tool string <NUM> may be moved downhole to connect the holder <NUM> with the old gas lift valve <NUM>. The tool string <NUM> may then be pulled uphole to remove the old gas lift valve <NUM> from the side pocket <NUM> and conveyed back to the wellsite surface <NUM>.

When the old gas lift valve <NUM> is stuck within the side pocket <NUM>, a jarring tool (i.e., an impact jar) coupled within the tool string <NUM> above the kickover tool <NUM> may be utilized to impart one or more impacts to the stuck old gas lift valve <NUM> to free the stuck old gas lift valve <NUM>. Because the jarring tool is located uphole from the kickover tool <NUM>, the impact force will be transferred from the jarring tool to the stuck old gas lift valve <NUM> via the housing <NUM>, the arm <NUM>, and the holder <NUM> of the kickover tool <NUM>.

When the tool string <NUM> with the kickover tool <NUM> reaches the wellsite surface <NUM>, the arm <NUM> and the holder <NUM> are in their extended position. The old gas lift valve <NUM> may be disconnected from the holder <NUM>, and the arm <NUM> and the empty holder <NUM> may be moved to their retracted position by performing the displacement mechanism resetting operations. The tool string <NUM> may then again be conveyed downhole to retrieve another old gas lift valve <NUM>.

In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily appreciate that the present disclosure introduces an apparatus comprising a downhole tool for installing a gas lift valve in a well, wherein the downhole tool comprises a housing, a mandrel movably disposed with respect to the housing, a holder configured to hold the gas lift valve, and an arm supporting the holder. The arm is operable to pivot between a retracted position in which the holder is adjacent the housing and an extended position in which the holder is disposed away from the housing. The mandrel and the arm are operatively connected via a pin-slot joint comprising a pin disposed within a slot. The slot comprises a first slot portion and a second slot portion. The pin-slot joint prevents the arm from pivoting when the pin is within the first slot portion. The pin-slot joint permits the arm to pivot when the pin is within the second slot portion.

The arm may comprise the slot and the mandrel may comprise the pin. The first slot portion may extend longitudinally along the arm. The second slot portion may extend laterally with respect to a longitudinal axis of the arm. The arm may be pivotably connected with the housing at a pivot point, and the second slot portion may extend partially around the pivot point.

The first slot portion and the second slot portion may extend at an angle with respect to each other.

The arm may be pivotably connected with the housing at a pivot point, and the pivot point may be located between the slot and the holder.

The arm may be pivotably connected with the housing, and the downhole tool may further comprise a biasing member operable to bias the mandrel and the housing toward a predetermined relative position causing the pin to be maintained within the first slot portion to thereby prevent the arm from pivoting from the retracted position to the extended position.

The downhole tool may further comprise a biasing member disposed in association with the arm, and the biasing member may be operable to pivot the arm from the retracted position to the extended position when the pin is within the second slot portion.

Relative movement between the mandrel and the housing may cause the pin to move out of the first slot portion and into the second slot portion, thereby permitting the arm to pivot from the retracted position to the extended position.

The arm may comprise the slot and the mandrel may comprise the pin. The first slot portion may extend along a longitudinal axis of the arm, and the second slot portion may extend laterally with respect to the longitudinal axis of the arm. The second slot portion may be curved.

The first slot portion may extend along a longitudinal axis of the arm, and the second slot portion may extend laterally with respect to the longitudinal axis of the arm.

Claim 1:
An apparatus comprising:
a downhole tool (<NUM>) for installing a gas lift valve (<NUM>) in a well (<NUM>), wherein the downhole tool comprises:
a housing (<NUM>);
a mandrel (<NUM>) movably disposed with respect to the housing;
a holder (<NUM>) configured to hold the gas lift valve; and
an arm (<NUM>) supporting the holder, wherein:
the arm is operable to pivot between a retracted position in which the holder is adjacent the housing and an extended position in which the holder is disposed away from the housing;
the mandrel and the arm are operatively connected via a pin-slot joint (<NUM>) comprising a pin (<NUM>) disposed within a slot (<NUM>);
the slot comprises a first slot portion (<NUM>) and a second slot portion (<NUM>);
the pin-slot joint prevents the arm from pivoting when the pin is within the first slot portion; and
the pin-slot joint permits the arm to pivot when the pin is within the second slot portion.