Abstract: A method for designing, monitoring, and updating a trajectory of a wellbore at a wellsite. The method includes receiving a plurality of inputs related to the trajectory for the wellbore. The inputs may include a starting point of the trajectory. A zone may be defined within a subsurface beneath the wellsite as safe. The method further includes defining a first set of control points within the zone of the subsurface, and generating a proposed path of the trajectory by connecting the starting point of the trajectory to a plurality of trajectory targets via the first set of control points. The method also includes validating that the proposed path of the trajectory is within the zone of the subsurface.

Abstract: Aspects of the subject technology relate to tools, system and methods related to a drilling tool that is fabricated using a bimetallic member that is subjected to an infiltration process. The method can include having an amount of precipitation hardenable steel and an amount of another type of steel. The precipitation hardenable steel and the other type of steel are metallurgically bonded to form a bimetallic member including a casting mandrel portion and a drill string connection portion. A reinforcing powder is infiltrated with a binder while in contact with the casting mandrel portion to form a metal matrix composite about the casting mandrel portion. A cutting structure is fabricated into the metal matrix composite of the drilling tool.

Abstract: A method for estimating and reducing high-frequency torsional oscillations (HFTO) during a downhole drilling operation includes estimating an HFTO propensity of an initial BHA configuration using a model that relates the HFTO propensity to at least a rock strength of a subterranean formation, a radius or diameter of the borehole, a drill bit body density, and a drill bit body radius or diameter. The estimated HFTO propensity is compared with an HFTO propensity threshold. The model is used to select a modified drill bit or bottom hole assembly (BHA) configuration that reduces the estimated HFTO propensity to a value below the HFTO propensity threshold. The modified drill bit or BHA configuration has an increased polar moment of inertia as compared to the initial drill bit or BHA configuration.

Abstract: An earth-boring tool includes a bit body having blades. Each blade has a rotationally leading surface, a rotationally trailing surface, and a formation facing surface therebetween. Each blade also has fluid courses formed between the rotationally leading surfaces and the rotationally trailing surfaces of rotationally adjacent blades. The fluid courses have a fluid course surface. The tool also includes cutting elements disposed on at least one of the blades and at least one nozzle disposed on the bit body within at least one of the fluid courses. The nozzle is adapted to be in fluid communication with a source of drilling fluid. The nozzle protrudes from the fluid course surface such that a tip of the nozzle is disposed at a distance from the fluid course surface that is greater than or equal to about 90% of a depth of the at least one of the fluid courses.

Abstract: Provided is a downhole tool and a well system. The downhole tool, in one aspect, includes a tubular providing one or more production fluid flow paths for a production fluid. The downhole tool, according to this aspect, further includes one or more float chambers located within the tubular, and two or more floats located within the one or more float chambers. In one aspect, a first of the two or more floats has a first density (?1) between a density of gas (?g) and a density of oil (?o), and a second of the two or more floats has a second density (?2) between the density of oil (?o) and a density of water (?w). The downhole tool, according to this aspect, further includes two or more non-contact proximity sensors configured to sense a radial location of the two or more floats to determine a gas:oil ratio and oil:water ratio.

Abstract: A vibratory grouting rod with drilling and vibrating functions includes: a drill bit, a vibration part, a flexible shock absorption device, a slotted connection part, a connection tail part, and a rigid-flexible conversion device; wherein the vibration part, the flexible shock absorption device, the slotted connection part and the connection tail part are sequentially jointed to form a grouting rod body, and the grouting rod body has a holding cavity; the drill bit is provided at a front end of the vibration part; and the rigid-flexible conversion device is movably sleeved on the flexible shock absorption device, which is configured to move up and down in a bar-shaped slot of the slotted connection part. The rigid-flexible conversion device can be pushed down to a rigid mode for drilling, and pulled up to a flexible mode for grouting with vibration concentrated around the vibration part.

Abstract: A leak detection and collection system includes a cap configured to couple to a wellbore component. The system also includes an alert system removably coupled to the cap and a packer coupled to the cap. The packer extends into a bore of the wellbore component and the packer is actuated to seal against the wellbore component and to block flow through the bore. The system further includes a release mechanism coupled to the alert system, a first flow path, an accumulator, and a second flow path. The release mechanism is activated at a first pressure above a first threshold to release the alert system and the second flow path directs flow to the accumulator at a second pressure above a second threshold.

Abstract: A horizontal directional drilling machine having a modular pipe loader system. The system comprises a first and second pipe loader assembly supported on a drill frame. Each assembly supports a shuttle arm. The shuttle arms are configured to move independently of one another along a shuttle path that is traverse to a longitudinal axis of the drill frame. Movement of each shuttle arm is powered by an actuator supported on each pipe loader assembly. Each pipe loader assembly includes a sensor used to measure parameters related to the position of each shuttle arm relative to the drill frame. A controller analyzes the measured parameters and directs operation of each actuator in order to keep the shuttle arms moving in unison during operation.

Abstract: Systems and methods for downhole drilling and, more particularly, hydraulic control systems and methods for hydraulically locking and unlocking moveable elements of a drill bit are provided. A drill bit may include a body; a moveable element secured to the body, wherein the moveable element is configured to extend or retract from a surface of the drill bit; a communication channel from the moveable element to a bore in the body; and a hydraulic control system at least partially disposed in the body, wherein the hydraulic control system is configured to at least provide fluid communication from the bore to the communication channel to thereby lock or unlock the moveable element.

Abstract: Provided herein are PDC drill bits for engaging subterranean formations and for drilling wellbores, wherein the PDC drill bits are adapted to reduce erosion of a bit head face by the inclusion of openings in a portion of the shank of a PDC drill bit. The present disclosure also relates to systems and methods of drilling subterranean formations using the PDC drill bits disclosed herein.

Abstract: A rotary flow control apparatus may comprise a rotary drive mechanism coupled to a ball controller comprising a ball disposed within a cavity. The apparatus may be disposed within a tubing string in a wellbore. Fluid flow is provided though the tubing, causing the rotation of the rotary drive mechanism. The flow passes through a ball cage above a seat disc that incorporates a flow port. The ball orbits around the cavity in response to the motion of an axially extending surface or “kicker.” When the ball obstructs the flow port, it substantially blocks the flow of fluid through the assembly, generating a water hammer impulse in the tubing above the rotary drive mechanism. The rotating kicker moves the ball off the flow port at one angular position and then allows the ball to reseat at a second angular position.

Abstract: A thrust bearing for an electric submersible pump includes a housing including an axial surface and an inner circumferential surface. Holes and bores are formed in the axial surface. The thrust bearing further includes sockets respectively disposed in the holes and pads each including a fluid interface surface. Two open counterbores are formed in each of the pads. The inner circumferential surface radially constrains the pads. The thrust bearing further includes balls each engaging one of the sockets and one of the pads and retaining bolts each including a head and a shaft extending from the head. Each of the shafts is disposed in one of the bores. The thrust bearing further includes biasing members each disposed between a bearing surface of one of the heads and bottom surfaces of two of the open counterbores. The pads are able to pivot on the ball.

Abstract: Embodiments disclosed herein are directed to a flow pulsing system including a rotor, a stator, a dart which is configured to releasably couple with the rotor, and a nozzle releasably coupled to the rotor which is configured to control a fluid flow through the rotor. In some embodiments, the system uses a screen disposed therein which includes an inner bore in fluid communication with a plurality of lobe cavities along the rotor. In some embodiments, the system uses a stationary valve and an oscillating valve having a plurality of oscillating valve ports which are in fluid communication with the plurality of lobe cavities.

Abstract: A cutter element for a fixed cutter drill bit has a central axis and includes a cylindrical substrate and a cutting layer mounted to the substrate. The cutting layer includes a first end engaged with the substrate, a second end opposite the first end, and a radially outer surface extending axially between the first and second ends. In addition, the cutting layer includes a cutting surface positioned at the second end and a cutting tip positioned between the cutting surface and the radially outer surface. Further, the cutting layer includes a first region on the cutting surface having a first surface roughness, and a second region on the cutting surface having a second surface roughness that is higher than the first surface roughness. The second region covers the central axis along the cutting surface, and the first region extends from the second region to the cutting tip.

Abstract: An insert for a slip in a hydraulic spider, including an engagement body. The engagement body including an engagement surface. The engagement surface including a first concave surface portion and a second concave surface portion. The first concave surface portion including teeth with a first radius of curvature. The second concave surface portion including teeth with a second radius of curvature that is different than the first radius of curvature.

Abstract: A downhole drilling system comprises a drill string and a drill bit coupled to the drill string. The drill bit comprises a bit body with primary and secondary blades disposed thereon. Some of the secondary blades are alternately disposed between some of the primary blades. Two first layer cutting elements are disposed on different ones of the primary blades, and substantially diametrically opposed to each other along a first track set radius of the bit body, while two second layer cutting elements are disposed on different ones of the secondary blades, and substantially diametrically opposed to each other along the first track set radius. The second layer cutting elements are sized to provide a selected amount of underexposure greater than zero with respect to the first layer cutting elements.

Abstract: A drill-bit may include a head which includes a face and a gage. The face may include a plurality of face button bits. The gage may include a plurality of gage button bits evenly spaced around the head. A plurality of major chip gage gashes may be evenly spaced around the head. A plurality of minor chip gage gashes may be evenly spaced around the head. An axis extending through centers of the plurality of face button bits may extend through one of the plurality of major chip gage gashes and one of the plurality of minor chip gage gashes. The plurality of major chip gage gashes may alternate with the plurality of minor chip gage gashes around the head. One of the plurality of gage button bits may be disposed in-between every set of the alternating major chip gage gashes and minor chip gage gashes.

Abstract: System and method for determining an updated location of a bottom hole assembly (BHA) during drilling of a well are provided. During drilling, a computer system may receive tool face updates and may determine build rate estimates and a borehole depth increase during a toolface update period. The computer system may also calculate an updated estimate of the borehole position.

Abstract: The present invention relates to a method and apparatus for cleaning an oil and gas well riser section or assembly. Even more particularly, the present invention relates to an improved method and apparatus for cleaning oil and gas well riser sections wherein a specially configured cap or pair of caps are fitted to the ends of the riser which enable pressure washing cleaning tools (or a camera) to be inserted into and through the riser cleaner fluid continuously recirculates so that relatively small volume of cleaning fluid (for example between about 700 and 1,000 gallons) is required. The cleaning process uses a volume of cleaning fluid that is discharged from the riser pipe at a relatively high temperature of about between 10° and 180° F. Such a high temperature cleaning fluid could possibly damage the pump that is used for supplying pressurized fluid to the cleaning tool.

Abstract: A cutting element may include a substrate having a base. A cutting element may include an ultrahard layer bonded to the substrate, the ultrahard layer formed from an ultrahard material, the ultrahard layer including: a side surface adjacent to the base, the side surface including a plurality of cutting surfaces; and an upper surface extending into the ultrahard layer.