Abstract: A seal apparatus for use as sealing devices for downhole applications in a wellbore, such as packers and bridge plugs, includes a seal element formed from an elastomeric material. The seal apparatus may include one or more end pieces, referred to as extraction limiting assemblies, which are provided to limit extrusion of the sealing element in direction(s) other than in a radial direction outward from the longitudinal axis of the tool body of the seal apparatus. The end pieces may include components included in a fabric barriers sleeve that encases components of the end caps, the fabric reinforcement barriers allowing for the expansion and contraction of the end caps and the sealing element but limiting or completely blocking debris from entering into any portion of the end caps.

Abstract: The subject matter disclosed and claimed herein, in one embodiment thereof, comprises a Stri-Lube device. The device is a specialized component for sucker and polished rods, designed to reduce burning of stuffing box packing elements. The Stri-Lube device comprises a body component that supplies clean oil and inhibitors in the right quantities to reduce corrosion and costly damage. The body component features a cover that covers the internal chambers of lubricating oil and corrosion inhibitors underneath a stuffing box to connect with the wellhead. The device also features adjusting screws to tighten rubber gaskets and accommodate longer wear life. Thus, once the device is connected to a wellhead, clean oil and inhibitors in the correct quantities can be supplied to reduce corrosion, damage, and burning.

Abstract: Systems, assemblies, and methods for completing a wellbore. A wellbore completion assembly has a production tubing, a first nipple, a first electrical connection, a second nipple, and a second electrical connection. The first nipple is positioned at a first location in the production tubing. The first nipple defines a first nipple profile. The first electrical connection is positioned at the first location. The first electrical connection is configured to couple to a first electrical submersible pump assembly. The second nipple is positioned at a second location in the production tubing. The second location is different than the first location. The second nipple defines a second nipple profile different than the first nipple profile. The second electrical connection is positioned at the second location. The second electrical connection is configured to couple to a second electrical submersible pump assembly.

Abstract: A bit for drilling a wellbore includes: a body; and a crown. The crown includes: a cone section and a shoulder section; a plurality of blades protruding from the body, each blade extending from a center of the crown and across the shoulder section; and a row of superhard cutters mounted along each blade, each cutter mounted in a pocket formed adjacent to a leading edge of the blade. Each row has a plurality of inner cutters located in the cone section. Each inner cutter has an inclined face oriented to decline toward the center of the crown for creating an effective negative side rake angle while drilling with the drill bit and a weight on bit (WOB) reducing effect. Each of the rest of the cutters are oriented such that an overall effect for the bit is the WOB reducing effect.

Abstract: Systems, methods, and apparatus for implementing a downhole motor assembly in a well system. The downhole motor assembly may include a first tubular housing configured to house a first portion of the downhole motor assembly, and a second tubular housing configured to house a second portion of the downhole motor assembly. The second tubular housing may be configured to axially join with the first tubular housing. One or more radially disposed fasteners may be coupled with the first tubular housing and the second tubular housing. The one or more radially disposed fasteners may be configured to secure a joint between the first tubular housing and the second tubular housing. Each of the one or more radially disposed fasteners may include a threaded portion and a cylindrical portion.

Abstract: A charge assembly includes a charge tube, shaped charges, and propellant charges. The charge tube is positionable in a downhole perforating tool. The shaped charges and the propellant charges are receivably supported in the charge tube. Each of the shaped charges includes a charge jacket and a charge material. The charge material has a detonation rate of greater than one microsecond. Each of the propellant charges includes a propellant jacket and a propellant material. The propellant charges have a detonation rate of less than one microsecond. An uphole portion of the propellant charges are positioned uphole from the shaped charges and a downhole portion of the propellant charges are positioned downhole from the shaped charges. The shaped charges are positioned between the uphole and the downhole portion. The shaped and the propellant charges are electrically connectable to a detonator for activation thereby.

Abstract: Provided herein is a system for determining a radius of invasion of a drilling fluid. The system can include a formation tester tool and at least one processor. The formation tester tool can be operable to be positioned in a wellbore. The formation tester tool can be operable to measure at least one property of a formation fluid within the wellbore. The at least one pump can be operable to pump a drilling fluid into the wellbore. The at least one processor can be configured to receive the at least one property of the fluid within the wellbore, a drilling pressure, a formation pressure, and at least one property of the drilling fluid, receive a drilling schedule including at least one change in an downhole environmental condition, and determine a radius of invasion of the drilling fluid based on the at least one property of the fluid, the drilling pressure, the formation pressure, the at least one property of the drilling fluid, and the drilling schedule.

Abstract: A tool may include a body having a rotational axis oriented in an axial direction. A tool may include a sensor positioned proximate to a window in a radially outward surface of the body, wherein the window defines a window outer diameter relative to the rotational axis. A tool may include a plurality of stabilizer pads positioned on the outward surface of the body in a downhole direction of the axial direction relative to the window, wherein the plurality of stabilizer pads defines a pad outer diameter relative to the rotational axis that is greater than the window outer diameter.

Abstract: Methods and systems are disclosed that use a temperature sensor integral to a drill bit while drilling. The temperature sensor is configured to measure temperature associated with a cutting element of the drill bit over time while drilling. The temperature sensor is used to generate time-series temperature data representing temperature of the cutting element of the drill bit over time while drilling. The time-series temperature data is processed to determine at least one condition of the wellbore and/or the drill bit while drilling, wherein the at least one condition relates to at least one of: i) detecting that a steering tool of the BHA of the drill bit is active and operating to control the direction of drilling, ii) detecting backwards whirling while drilling, and iii) detecting a transition between different types of reservoir rock while drilling.

Abstract: Apparatus and methods for coupling a rope socket with an armored cable. The armored cable includes a conductor core having one or more cables for transmitting electrical and/or optical signals and at least one layer of armor wires wound around the conductor core. The rope socket includes a housing having an uphole end through which the armored cable extends into the housing and a downhole end through which the conductor core extends from the housing to a component of downhole equipment suspended in a wellbore by the armored cable. The armor wires are arranged inside of the housing so that they are spaced apart at least locally from the conductor core. A plastic material disposed within the housing fills interstices each defined by one or more surfaces of one or more of the conductor core, one or more of the armor wires, and the housing.

Abstract: The current invention describes a plug that may be run into a well for example an electric submersible pump without the plug locking into the wellbore casing or setting. The plug may then be allowed to sit within the well for a predetermined period of time during which a dissolvable lock is removed from the plug. With the dissolvable lock removed further downward travel is prevented by the plug locking into place while the electrical submersible pump may be freely retrieved to the surface.

Abstract: Systems for protecting portions of a drill string and methods for manufacturing the same are disclosed. Embodiments protect measurement components, such as electronic sensors, for measuring conditions within the hole during drilling. Additional embodiments include hollow protective covers and/or sleeves that receive at least one component of a drill string and form one or more seals around a region configured to hold sensors. Some embodiments include a drill string component with one or more pockets and/or pockets into which the sensors may be positioned, and the pockets may be configured to minimize movement of the measurement components within the pockets/pockets during operation of the drill.

Abstract: A valve system can include a valve and a support. The valve can be positioned and can be actuated in a wellbore to control flow of fluid by being actuated to a closed position to prevent the flow of fluid in the wellbore. The support can be positioned to controllably override the valve to allow the flow of the fluid while the valve is being biased towards the closed position. The support can be degraded to allow the valve to prevent flow of fluid in the wellbore while being biased towards the closed position.

Abstract: Systems and methods are disclosed herein for simultaneously milling an obstructions and collecting the resulting debris within a wellbore in an oil-and-gas setting. An example debris collection tool can include a motor, centrifugal pump, gear boxes, bailers, and a pass-through milling bit. A series of shafts can pass through the internal components of the tool and cause various components to rotate when driven by the motor. The gear boxes can lower the speed and increase the torque of rotating downhole components. The tool therefore can simultaneously drive the pump and milling bit at different speeds and torques. The centrifugal pump can include a flow control mechanism at allows the tool to control the flow of drilling fluid from the centrifugal pump into the surrounding subsurface.

Abstract: An electrocrushing drilling apparatus may include a downhole electrocrushing drill assembly that is part of a bottomhole assembly coupled to a downhole end of a coiled tubing drill string. The coiled tubing drill string can be deployed into a wellbore of a hydrocarbon well to advance the wellbore by way of an electrocrushing drilling operation whereby formation rock is fractured by high voltage electrical energy pulses emitted by electrodes of a drill bit of the electrocrushing drill assembly. Potential damage to electronic or other components of the bottomhole assembly due to excess heat generated by power losses of electrocrushing drill assembly can be minimized or prevented by actively cooling the electronic or other components of the bottomhole assembly using a liquid coolant that is conveyed from an earth surface of the well downhole to the bottomhole assembly and passed through the electronic or other components of the bottomhole assembly.

Abstract: A method includes initiating a managed pressure drilling (MPD) operation in an MPD system including a rotating control device (RCD) including at least one sealing element and a plurality of pressures sensors placed relative to the at least one scaling element. The RCD is positioned in the MPD system so as to receive fluid exiting an annulus of a wellbore. Further, the method includes creating a pressure spike in the annulus of the wellbore during the MPD operation, and monitoring a pressure differential between the plurality of pressure sensors to determine whether there is a leakage within the RCD.

Abstract: A sub-surface safety valve (SSSV) for use in a low temperature downhole environment. The low temperature environment can be created by injection of fluid such as carbon dioxide. The low temperature downhole environment may be detrimental to the SSSV by damaging elastomer seals. The disclosed SSSV utilizes non-elastomeric seals and metal-to-metal seals between components. The SSSV utilizes metal-to-metal threads between body joints eliminating the need for an elastomers in the threads between body joints. Creating a SSSV with an elastomer seal reduces fatigue and damage in a low temperature environment.

Abstract: Some implementations include an apparatus comprising a finned insert configured for placement within at least a portion of an inner circumference of a slotted compressible tubular, the finned insert having a plurality of fins, wherein each fin of the plurality of fins is configured to fit within a slot of the slotted compressible tubular.

Abstract: Embodiments of the disclosure provide for methods and apparatus related to geological carbon capture systems. Aspects disclose methods and apparatus related to back pressure valves protecting geological based carbon capture systems. These methods and apparatus seek to enhance the efficiency and reliability of carbon capture by addressing the operational challenges posed by subsurface pressure variations. By employing advanced back pressure valve mechanisms, the systems ensure controlled injection and containment of carbon dioxide within geological formations, thereby minimizing the risk of leakage and contributing to long-term environmental sustainability.

Abstract: A drill cuttings composite core apparatus, system, and method that may utilize sieve shaker equipped with a solvent wash system to separate, clean, and size cuttings; a centrifugal mill equipped with a 12 tooth rotor and 1.0 mm ring sieve; a compactor mold that may be 1.5 inches in diameter and up to 6 inches long; dual piston compactor with independent air control valves; and a spacer on top of a bottom piston that may allow compacted core to be pushed up through top of mold for easy removal with no special tools or handling.