Abstract: A downhole welding tool includes a tool body and a welding device coupled to the tool body. The welding device includes a carrier arm reversibly pivotable between a collapsed configuration of the welding device in which the carrier arm is oriented parallel to the tool body and an extended configuration of the welding device in which the carrier arm projects outward from the tool body at an acute angle relative to the tool body, as well as a consumable welding tip secured to the carrier arm. The downhole welding tool also includes a rotatable actuator coupled to the tool body adjacent the welding device and configured to adjust the carrier arm between the collapsed configuration and the extended configuration.

Abstract: Tools and methods are described for removing a packer beyond a restriction in a casing of a wellbore. A packer milling tool includes: a milling body with an outer diameter; milling blocks positioned at intervals around a circumference of the milling body, each milling block pivotably attached to the milling body and pivotable between a running position and a milling position; and a wash pipe extending from a downhole end of the milling body. The milling blocks have a rotational circumference with a rotational diameter that is less than the outer diameter of the milling body when in the running position and the rotational diameter is more than the outer diameter of the milling body and less than the inner diameter of the casing when in the milling position.

Abstract: A system for drilling a well includes a gripping unit provided at a rig above a surface of the well for holding a top end of a drill string in the well, a liner releasably connected to the drill string, and a downhole motor installed on the drill string in an axial position between the surface of the well and the liner, where the downhole motor has a stator connected to the drill string and a rotor operatively connected to an axial end of the liner closest to the surface of the well.

Abstract: A packer assembly includes a tubing string disposed in a wellbore and a packer releasably coupled to the tubing string. The packer includes a housing releasably coupled to the tubing string, a packer slip, a flexible sealing element, a piston coupled to the housing, a locking member, and a mandrel disposed inside the housing. The piston moves to activate the packer slip and the flexible sealing element to set the packer on a wall of the wellbore. The locking member engages the piston to constrain movement of the piston to keep the packer set on the wall of the wellbore. The mandrel connects to the tubing string when the tubing string is released from the housing. The locking member is collapsible to disengage the piston to unset the packer slip and the flexible sealing element responsive to shear force applied by the mandrel to the locking member.

Abstract: A downhole tool includes a streamlined housing sized to freely move through a wellbore formed from a terranean surface to a subterranean formation; an explosive material enclosed within an interior volume of the housing, the explosive material sufficient to cut at least a portion of a tubular positioned in the wellbore upon detonation; a detonator coupled to the explosive material; and a detonator control system communicably coupled to the detonator and configured to activate the detonator with a detonation signal to detonate the explosive material.

Abstract: A drilling fluid shaker screen system includes a screen assembly that includes a screen including a plurality of screen sections. A first screen section includes a first screen mesh size and a second screen section includes a second screen mesh size different than the first screen mesh size. The drilling fluid shaker screen system further includes a rotation assembly mounted to the screen assembly. The rotation assembly includes one or more rollers moveable to rotate the screen assembly about an axis of rotation. The drilling fluid shaker screen system further includes a motor assembly coupled to the screen assembly and configured to vibrate the screen assembly. A housing includes a cuttings outlet that is fluidly coupled to a cuttings inlet formed in the screen and a liquid outlet separate from the cuttings outlet that is fluidly coupled to the plurality of screen sections.

Abstract: Wellbore tool assembly to open collapsed tubing includes a chisel head having a first end configured to be positioned within an end of a collapsed tubing portion of a tubular member. The chisel head has a second end opposite the first end. The second end has an outer diameter smaller than an outer diameter of an uncollapsed tubing portion of the tubular member. The chisel head is configured to expand a diameter of the collapsed tubing portion responsive to a movement of the chisel head toward the collapsed tubing portion. The assembly includes a packer attached to the chisel head. The packer is configured to expand responsive to fluidic pressure and to further expand the diameter of the collapsed tubing portion.

Abstract: One downhole-type tool of a set of interchangeable downhole-type tools is interchangeably received by a pump-down adapter. The downhole-type tool is positioned by the pump-down adapter within a wellbore tubular. The downhole-type tool is released by the pump-down adapter.

Abstract: A fluid management device includes a seal and a piston coupled to the seal and movable to an activated position to adjust the seal to an activated state. The seal includes first sealing elements extending radially inward towards a central axis of the fluid management device and second sealing elements extending radially inward towards the central axis, the first and second sealing elements together defining an opening sized to surround first and second pipes disposed within a wellbore containing wellbore fluid. In the activated state, the first sealing elements contact each other within the opening between the first and second pipes and seal against a first inner portion of the first pipe and a second inner portion of the second pipe to close the opening between the first and second pipes and a closed state of the opening prevents the wellbore fluid from exiting the wellbore through the opening.

Abstract: A method of performing a logging operation at a wellbore includes providing first and second pipe segments respectively including a first internal electrical cable and a second internal electrical cable, connecting a first end of the first internal electrical cable to a wireline cable of a logging tool to form a drill pipe string, lowering the drill pipe string, including the logging tool and the first pipe segment, into the wellbore, connecting a first end of the second internal electrical cable to a second end of the first internal electrical cable to add the second pipe segment to the drill pipe string, lowering the drill pipe string, including the logging tool, the first pipe segment, and the second pipe segment, into the wellbore, and connecting a second end of the second internal electrical cable to a surface logging unit to couple the surface logging unit to the drill pipe string.

Abstract: A pipe segment includes an outer pipe including a shaft wall, a first connector disposed at a first end of the shaft wall, and a second connector disposed at a second end of the shaft wall opposite the first end. The pipe segment further includes an electrical cable extending through the shaft wall along a length of the outer pipe between the first and second connectors and an inner pipe positioned within the outer pipe and surrounding the electrical cable, the inner pipe being movable axially with respect to the outer pipe, and the outer pipe being movable rotationally with respect to the inner pipe.

Abstract: A method of plugging a formation fracture includes drilling, with a drill string configured to flow drilling fluid, a wellbore, where, at a downhole location, the drilling fluid is lost through a formation fracture. The method also includes deploying, through the drill string, a plugging assembly to the downhole location of the wellbore. The plugging assembly includes a flexible fiber sheet releasably coupled to a pumpable dart such that when the plugging assembly reaches the downhole location, the flexible fiber sheet is released from the dart to flow, with the drilling fluid, to the formation fracture to at least partially overlay the formation fracture. The method also includes adding, to the drilling fluid, lost circulation material configured to accumulate on a portion of the flexible fiber sheet to at least partially fluidically plug the formation fracture.

Abstract: An apparatus includes a housing, engagement slips, a tubular, a taper tap, a pin, and a slip activation member. The housing includes a profile that defines a path including a first end and a second end. The engagement slips are attached to the housing. The tubular passes through an opening of the housing. The taper tap is rotatable and connected to the housing. The pin is connected to the tubular and received by the profile of the housing. The tubular is translatable with respect to the housing based on the pin translating along the path defined by the profile. The slip activation member is connected to the tubular. The slip activation member is configured to move each of the engagement slips radially outward with respect to the housing when the pin translates to the second end of the path.

Abstract: A swivel includes a male segment, a female segment, and a lock pin. The male segment can mate with the female segment, and the lock pin can pass through the female segment and engage with the male segment to prevent relative axial movement of the male segment and the female segment while allowing relative rotational movement of the male segment and the female segment. The male segment includes a first conductive ring configured to couple to a first wire. The female segment includes a second conductive ring configured to couple to a second wire. Contact between the first and second conductive rings establishes an electrical connection between the first and second wires.

Abstract: A fluid management system for controlling fluid flow at a wellbore includes a closing element formed complementary to a drill pipe disposed within the wellbore and an activation system. The activation system is configured to move the closing element into an activated position against the drill pipe to close the wellbore around the drill pipe for preventing fluid from flowing out of the wellbore. The activation system includes an activation shaft coupled to the closing element and a rotatable drive shaft configured to cause translation of the activation shaft to push the closing element into the activated position against the drill pipe.

Abstract: A cellar around a wellbore is formed or deepened with an excavating system that is capable of being assembled around an existing wellbore. The system includes an excavating unit having an annular body with a cutting surface that excavates cuttings from ground around the wellbore. The cuttings are directed up through a slot in the body, and are collected inside a receptacle set in a recess of the body. An opening is formed in a side of the receptacle when in the body, and through which the cuttings pass from the slot into the receptacle. The receptacle is removable from within the recess and cuttings collected within are emptied. When the receptacle is removed from the recess, the opening is automatically covered to retain the cuttings inside the receptacle. Another cellar around a different wellbore is formed by disassembling the excavating system and relocating it to the different wellbore.

Abstract: A wellhead assembly that includes a wellhead disposed at a surface of a wellbore, a production tree fluidically coupled to the wellhead, and a telescopic adaptor assembly residing between and fluidically coupled to the wellhead and the production tree. The telescopic adaptor assembly extends or retracts to change an elevation of the production tree with respect to the wellhead and rotates to change a radial position of the production tree with respect to the wellhead. The telescopic adaptor assembly includes a flange attached to the wellhead and a first pipe rotationally coupled to the flange. The first pipe is rotational about a longitudinal axis of the first pipe. The telescopic adaptor assembly includes a second pipe attached to the production tree and is disposed concentrically inside the first pipe. The second pipe is movable along the longitudinal axis with respect to the first pipe.

Abstract: Wellbore tool assembly to open collapsed tubing includes a chisel head having a first end configured to be positioned within an end of a collapsed tubing portion of a tubular member. The chisel head has a second end opposite the first end. The second end has an outer diameter smaller than an outer diameter of an uncollapsed tubing portion of the tubular member. The chisel head is configured to expand a diameter of the collapsed tubing portion responsive to a movement of the chisel head toward the collapsed tubing portion. The assembly includes a packer attached to the chisel head. The packer is configured to expand responsive to fluidic pressure and to further expand the diameter of the collapsed tubing portion.

Abstract: An apparatus includes a housing, engagement slips, a tubular, a taper tap, a pin, and a slip activation member. The housing includes a profile that defines a path including a first end and a second end. The engagement slips are attached to the housing. The tubular passes through an opening of the housing. The taper tap is rotatable and connected to the housing. The pin is connected to the tubular and received by the profile of the housing. The tubular is translatable with respect to the housing based on the pin translating along the path defined by the profile. The slip activation member is connected to the tubular. The slip activation member is configured to move each of the engagement slips radially outward with respect to the housing when the pin translates to the second end of the path.

Abstract: A cutting assembly is housed within a main body. The cutting assembly includes a rotary blade mounted vertically within the main body. A blade motor is coupled to the rotary blade. The blade motor is configured to rotate the rotary blade with sufficient speed and torque to cut through a wellbore tubular. The blade motor is supported by a blade motor mount. A lead screw is coupled to the blade motor mount. The lead screw is rotatable to control a vertical position of the rotary blade. A lead screw motor is rotably coupled to the lead screw. The lead screw motor is configured to rotate the lead screw to adjust the vertical position of the rotary blade. A guide is located within the main body. The guide includes a profile that controls a horizontal position of the blade based on the vertical position of the rotary blade.