Abstract: A wellbore assembly includes a cable and a wellbore tool. The wellbore tool is coupled to the downhole end of the cable. The wellbore tool includes a housing, one or more sensors, a packer, and a controller. The one or more sensors are coupled to the housing or to the cable or both. The sensors detect one or more parameters of the wellbore tool or the cable or both. The controller is coupled to the housing. The controller is electrically coupled to one or more sensors and is operationally coupled to the packer. The controller determines, with the wellbore tool parted from the cable and based on information received from the one or more sensors, an indication of the wellbore tool in free fall. The controller activates, based on the determination, the packer to expand the packer and set the wellbore tool on a wall of the wellbore.

Abstract: A method of cementing a casing in a wellbore includes lowering the casing in the wellbore. The casing includes multiple pipes each of progressively smaller diameters, and a transition point where a first pipe overlaps a second pipe. The method also includes flowing cement into the casing and deploying, by fluidic pressure, a wiper plug assembly in the casing upstream of the cement to push downhole the cement with the wiper plug assembly. The wiper plug assembly includes a hollow wiper plug and a solid wiper plug releasably coupled to the hollow wiper plug. The deploying includes applying fluidic pressure until the hollow wiper plug reaches and is retained at the transition point and the solid wiper plug is released from the hollow wiper plug to flow downhole in the casing to a downhole end of the casing and push the cement out of the casing.

Abstract: A system may include a control system disposed on a well surface, a casing disposed in a wellbore, a first electrical wiring coupled to the control system and the casing within a first section of the wellbore, and a second electrical wiring coupled to various flow control devices in a second section of the wellbore. The first section of the wellbore may be disposed at a first predetermined direction that is different than a second predetermined direction of the second section of the wellbore. The system may further include an electrical connector coupled to the first electrical wiring and the second electrical wiring. The electrical connector may include a mechanical receiver that couples with the first electrical wiring, and a stinger assembly coupled with the second electrical wiring and that connects to the mechanical receiver.

Abstract: A downhole perforation tool includes an upper sub-assembly configured to couple to a downhole conveyance within a wellbore that is formed from a terranean surface toward a subterranean formation; a plurality of perforation sub-assemblies, where each perforation sub-assembly includes one or more perforation guns, and one or more ports configured to fluidly couple the wellbore with a bore that extends from the one or more ports to the upper sub-assembly; a main wellbore seal positioned between the upper sub-assembly and the plurality of perforation sub-assemblies, the main wellbore seal actuatable to anchor the downhole perforation tool to a casing in the wellbore; and at least one secondary wellbore seal positioned between adjacent perforation sub-assemblies of the plurality of perforation sub-assemblies, the at least one secondary wellbore seal actuatable to fluidly isolate a portion of an annulus of the wellbore from another portion of the annulus of the wellbore.

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: Techniques for separating cuttings from liquid include circulating a drilling fluid that comprises a liquid and formation cuttings to a scree of a screen assembly that includes screen sections; vibrating the screen assembly during circulation of the drilling fluid; while vibrating the screen assembly, separating the liquid from the plurality of formation cuttings; while vibrating the screen assembly, separating a first portion of the formation cuttings of a first size from the drilling fluid with a first screen section; rotating the screen assembly; subsequent to rotating the screen assembly and while vibrating the screen assembly, separating a second portion of the formation cuttings of a second size different than the first size from the drilling fluid with a second screen section; directing the separated liquid through the screen assembly to a liquid outlet; and directing at least one of the first or second portions of the formation cuttings to a cuttings outlet formed in the screen.

Abstract: A well tool for milling a tubular includes a well tubing disposed in a wellbore and including a circulation fluid pathway through an interior of the well tubing, a first milling tool coupled to the well tubing at a first longitudinal end of the well tubing, a second milling tool coupled to the well tubing at a location longitudinally uphole from the first milling tool, and a third milling tool coupled to the well tubing at a location longitudinally uphole from the second milling tool. Each of the milling tools include a mill bit and a circulation sub fluidly connected to the circulation fluid pathway. The first milling tool mills a first portion of the tubular, the second milling tool mills a second portion of the tubular, and the third milling tool mills a third portion of the tubular.

Abstract: A system includes a deployment device and an adjustable mill. The deployment device has a box end with internal threads. The adjustable mill has a tubular body, a cylinder, and a lock ring. The tubular body has a lateral end and a pin end. The pin end has external threads, the lateral end is partially enveloped by cutters, and the lateral end comprises an inner wall defining an orifice. The cylinder is movably disposed within the orifice. The cylinder is partially enveloped by the cutters. The lock ring is disposed circumferentially around the cylinder. The lock ring interacts with a lock ring seat machined into the inner wall of the lateral end to place the adjustable mill in a mode. The internal threads of the adjustable mill and the external threads of the deployment device interact to form a connection between the adjustable mill and the deployment device.

Abstract: A system includes production tubing, a telescoping joint, a pump sub, a lock ring, and a crossover. The production tubing provides a hydraulic connection from a surface location to a well. The telescoping joint has a housing and a by-pass hanger having a head. An opening of the housing is larger than the by-pass hanger and smaller than the head and the head is moveably located within the housing. The lock ring is disposed around the by-pass hanger directly beneath the opening of the housing. The lock ring absorbs a compressive force and prevents the by-pass hanger from moving in an upwards direction. The crossover component is hydraulically connected to the production tubing and provides the hydraulic connection to the telescoping joint and the pump sub. The pump sub is located parallel to the telescoping joint, and the pump sub is connected to an electric submersible pump string.

Abstract: A system includes a deployment device and an adjustable mill. The deployment device has a box end with internal threads. The adjustable mill has a tubular body, a cylinder, and a lock ring. The tubular body has a lateral end and a pin end. The pin end has external threads, the lateral end is partially enveloped by cutters, and the lateral end comprises an inner wall defining an orifice. The cylinder is movably disposed within the orifice. The cylinder is partially enveloped by the cutters. The lock ring is disposed circumferentially around the cylinder. The lock ring interacts with a lock ring seat machined into the inner wall of the lateral end to place the adjustable mill in a mode. The internal threads of the adjustable mill and the external threads of the deployment device interact to form a connection between the adjustable mill and the deployment device.

Abstract: A fluid pit safety system is disclosed to prevent drowning incidents in a fluid pit filled with a fluid. The system comprises a plurality of sensors spatially disposed adjacent the fluid pit, a perimeter detection sub-system defining a perimeter arranged around an edge of the fluid pit, and a rescue device arranged in the fluid pit. The plurality of sensors are configured to detect a change in fluid height in the fluid pit. The perimeter detection sub-system is configured to detect a disruption in the perimeter. The rescue device is configured to move towards a surface of the fluid in the fluid pit in response to the plurality of sensors detecting the change in the fluid height in the fluid pit and the perimeter detection sub-system detecting the disruption in the perimeter.

Abstract: A well system includes a tubular string comprising a plurality of tubular segments and positioned in a wellbore drilled into a subterranean zone, and a landing sub connected to a bottom end of one of the plurality of tubular segments. The landing sub includes a landing sub central bore and a landing sub locking profile on an inner surface of the landing sub central bore. The well system also includes a valve assembly configured to be pumped down the tubular string by fluid flowing in a downhole direction through the tubular string and to land within the landing sub central bore. The valve assembly includes a main body with a valve central bore and a flapper configured to pivot between an open position and a closed position. In the closed positon the flapper seals against a flapper seat and blocks fluid from flowing in an uphole direction through the valve central bore.

Abstract: Techniques for removing a tubular from a wellbore include running a downhole tool on a downhole conveyance into a wellbore formed from a terranean surface into a subterranean formation; activating a piston sub-assembly to repeatedly move pistons to contact a portion of a casing installed in the wellbore to at least de-bond a cement layer installed between the portion of the casing and the subterranean formation from the portion of the casing; activating a cutting sub-assembly to move a cutting blade to cut through the portion of the casing adjacent the de-bonded portion of the cement layer; activating a hanger sub-assembly to move a set of slips into contacting engagement with the cut portion of the casing; and running the downhole tool on the downhole conveyance out of the wellbore with the cut portion of the casing engaged with the set of slips.

Abstract: A wellbore assembly includes a cable and a wellbore tool. The wellbore tool is coupled to the downhole end of the cable. The wellbore tool includes a housing, one or more sensors, a packer, and a controller. The one or more sensors are coupled to the housing or to the cable or both. The sensors detect one or more parameters of the wellbore tool or the cable or both. The controller is coupled to the housing. The controller is electrically coupled to one or more sensors and is operationally coupled to the packer. The controller determines, with the wellbore tool parted from the cable and based on information received from the one or more sensors, an indication of the wellbore tool in free fall. The controller activates, based on the determination, the packer to expand the packer and set the wellbore tool on a wall of the wellbore.

Abstract: A downhole sealant injection system includes a first casing configured to be positioned in a wellbore and a second casing configured to be positioned in the wellbore within the first casing. Cement at least partially fills an annulus between the interior of the first casing and the exterior of the second casing. A first sealant injection tool is configured to be attached to the exterior of the second casing, and is positioned at a downhole location and within an annulus between the interior of the first casing and the exterior of the second casing. The sealant injection tool includes a plurality of nozzles configured to inject sealant into voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.

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 system includes an upper section, having a first lateral end. The upper section has upper production tubing configured to be a conduit for production fluids, an upper electrical cable configured to transmit electricity, and a sub-surface safety valve fixed to the upper production tubing. The system further includes a lower section having a second lateral end, lower production tubing configured to be a conduit for the production fluids, a lower electrical cable configured to transmit electricity, an electric submersible pump assembly, and an anchor configured to hold the lower section within the casing string. A stinger assembly is fixed to the first lateral end of the upper section, and a stinger receptacle is fixed to the second lateral end of the lower section. The stinger receptacle is configured to receive the stinger assembly and create an electrical connection between the upper section and the lower section.

Abstract: Systems and methods for accessing a wellbore of a subterranean well downhole of abandoned subterranean wellbore equipment include a re-entry guide secured to an uphole end of an overshot. The re-entry guide and overshot together form a re-entry tool. The overshot has an inner diameter gripping assembly sized to grip a tubing stub. The re-entry guide has an outer diameter sized to match a drift inner diameter of a casing of the subterranean well.

Abstract: Techniques for removing a tubular from a wellbore include running a downhole tool on a downhole conveyance into a wellbore formed from a terranean surface into a subterranean formation; activating a piston sub-assembly to repeatedly move pistons to contact a portion of a casing installed in the wellbore to at least de-bond a cement layer installed between the portion of the casing and the subterranean formation from the portion of the casing; activating a cutting sub-assembly to move a cutting blade to cut through the portion of the casing adjacent the de-bonded portion of the cement layer; activating a hanger sub-assembly to move a set of slips into contacting engagement with the cut portion of the casing; and running the downhole tool on the downhole conveyance out of the wellbore with the cut portion of the casing engaged with the set of slips.

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.