Abstract: An active system is provided that changes the mechanical stiffness of a BHA during drilling to prevent/reduce damage to a BHA due to vibrations. The active system uses a combination of mechanical and electronic systems to change the physical characteristics of a BHA that govern the natural frequencies thereof. The active system can change the mechanical stiffness of a BHA by switching between two different coupling modes for connecting sections or portions of the BHA. An active torsional isolator and damper (ATID) can be used to switch between the different coupling modes. In one example, the ATID includes: (1) a dynamic coupler configured to connect a first portion of a BHA to a second portion of the BHA according to different coupling modes, and (2) a processor configured to control switching of the dynamic coupler between the different coupling modes during a drilling operation of a drill bit.

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: As a wellbore is extended into a formation, hydrostatic and hydrodynamic pressures change due to variations in drilling mud weight, fluid density, etc. Strain gauges downhole measure forces experienced by drilling equipment. During drilling, a strain gauge measures strain applied between the drill string and the formation. When off bottom, the strain gauge measures forces experienced by the drill string other than drilling forces. A pressure calculator converts off bottom strain gauge measurements into measurements of hydrostatic pressure for periods without fluid flow (i.e., when drilling motors are paused) and into measurements of hydrodynamic pressure for periods with fluid flow (i.e., when mud motors are operating). The pressure calculator correlates strain measurements (usually in voltages) to pressure based on a predetermined relationship for a given wellbore geometry (e.g., hole diameter, drill bit diameter, drill pipe diameter, etc.).

Abstract: A drilling system, assembly, and method may help optimize drilling in a system that involves more than one rotary tool that engages the formation. A rotary tool may be a rotary cutting tool, such as a drill bit or reamer, or some other rotary tool (e.g. stabilizer or rotary steerable tool) that has the potential to drag on the wall of the hole being drilled and take energy away from cutting. In an example, a wellbore or portion thereof is formed by rotating a first rotary cutting tool having a first cutting structure in engagement with one portion of the formation together with a second rotary cutting tool having a second cutting structure in engagement with another portion of the formation. Forces are obtained above and below the second cutting structure. One or more drilling parameter or drill bit design parameter are adjusted in relation to a force differential between the forces above and below the second cutting structure.

Abstract: Disclosed herein are embodiments of a method and system for determining a critical torque on bit to reduce the occurrence of high frequency torsional oscillation (HFTO). In one embodiment, a method includes detecting at least one drilling parameter of an offset drill bit for a type of drilling system during an offset drilling operation using at least one in-bit sensor; determining a critical torque on bit (TOB) that is to excite HFTO of the offset drill bit based on the at least one drilling parameter and based on the type of drilling system; measuring, for a current drilling operation, a current TOB and a current weight on bit (WOB) of a current drill bit having a same type of drilling system as the type of drilling system for the offset drilling operation; determining whether current TOB exceeds critical TOB; and mitigating the HFTO for the current drill bit.

Abstract: A fixed cutter drill bit may include a bit body defining a bit axis and having a plurality of blades extending therefrom. A plurality of cutters are secured to the blades at different circumferential positions relative to the bit axis. Each cutter may define a cutter sweep profile as the bit body rotates about the bit axis. One or more of the cutters may form overlapping cutter sweep profiles to define a kerf therebetween. The cutters include a shaped cutter comprising a cutting face and a shaped portion on the cutting face aligned for engaging and removing the kerf.

Abstract: Some implementations include a method for eliminating bias in strain data produced by one or more strain gauges in a drill bit of a drill string. The method may include drilling a borehole with the drill bit. The method may include determining a bias in strain data based on drilling parameters detected during the drilling. The method may include removing the bias from a biased downhole drill bit measurement to indicate an unbiased downhole drill bit measurement.

Abstract: A sealing element for a rotating control device is described. The sealing element includes an elastomeric body having a central bore for sealing against a pipe passing therethrough. The elastomeric body has an upper portion which is internally reinforced with a frame and a lower portion formed with a plurality of protrusions. The radial protrusions provide columnar support to the lower portion permitting the lower portion to resist centrifugal and frictional forces against the lower portion during drilling and other operations. The sealing element may be used to form an assembly with reusable parts for connecting the sealing element to a mandrel of a rotating control device.

Abstract: A sealing element for a rotating control device includes an elastomeric body having a central bore for sealing against a pipe passing therethrough. The elastomeric body has an upper portion which is internally reinforced with a frame and a lower portion formed with a plurality of protrusions. The radial protrusions provide columnar support to the lower portion permitting the lower portion to resist centrifugal and frictional forces against the lower portion during drilling and other operations. The sealing element may be used to form an assembly with reusable parts for connecting the sealing element to a mandrel of a rotating control device.

Abstract: A system may include a strain gauge bar securable within a puck recess formed in an outer surface of a downhole drill bit. The strain gauge bar may be configured to collect data indicating a downhole force applied to the downhole drill bit during drilling operations. Further, the strain gauge bar may have a body portion and at least one wedge feature protruding from the body portion. The at least one wedge feature may be insertable into at least one wedge recess formed in the bottom surface of the puck recess. The system may also include a strain puck cap securable within the puck recess. The strain puck cap may be configured to apply pressure to the strain gauge bar to drive the at least one wedge feature of the strain gauge bar into the at least one wedge recess and pre-load the strain gauge bar.

Abstract: A method for downhole cutting structure design. The method comprises executing a first computer-simulated drilling by at least one downhole cutting structure of a wellbore into a subsurface formation based on an original data set that includes at least one drilling parameter and at least one downhole cutting structure attribute associated with an actual drilling of the wellbore using the at least one downhole cutting structure into the subsurface formation. The method comprises recursively performing the following operations until a drilling performance threshold is satisfied, changing at least one of the at least one drilling parameter and the at least one downhole cutting structure attribute in the original data set to create a modified data set and executing a second computer-simulated drilling by the at least one downhole cutting structure of the wellbore into the subsurface formation based and the modified data set.

Abstract: Transmitting and receiving mud pulse pressure waves at a downhole device. The mud pulse pressure waves may be transmitted from a surface mud pulser and/or by a downhole mud pulser to a downhole device. The mud pulse pressure waves may be detected directly by a transducer or indirectly by detecting physical changes induced in the downhole tool by the pressure waves of the mud pulse. The detected physical changes can be converted to a digital signal for use by the downhole tool. The mud pulse pressure waves may encode information including data, or instructions to the downhole devices.

Abstract: A drilling system, assembly, and method may help optimize drilling in a system that involves more than one rotary tool that engages the formation. A rotary tool may be a rotary cutting tool, such as a drill bit or reamer, or some other rotary tool (e.g. stabilizer or rotary steerable tool) that has the potential to drag on the wall of the hole being drilled and take energy away from cutting. In an example, a wellbore or portion thereof is formed by rotating a first rotary cutting tool having a first cutting structure in engagement with one portion of the formation together with a second rotary cutting tool having a second cutting structure in engagement with another portion of the formation. Forces are obtained above and below the second cutting structure. One or more drilling parameter or drill bit design parameter are adjusted in relation to a force differential between the forces above and below the second cutting structure.

Abstract: A drill bit may comprise a bit body including an electronic housing, one or more electronics coupled within the electronic housing, a transducer housing coupled to the electronic housing, a first transducer seated in the transducer housing, a first pressure tube extending through the bit body and coupled to the transducer housing, and a floating ball in the first pressure tube. A method may comprise allowing a drilling fluid to move through a first entrance and into a pressure tube formed in a bit body of the drill bit, allowing the drilling fluid to exert a force on a floating ball placed within the pressure tube, allowing the floating ball to transmit the force to a fluid placed within the pressure tube on an opposing side of the floating ball from the drilling fluid, and measuring pressure of the fluid with a first transducer.

Abstract: Design parameters for PDC drill bit including in-cone depth of cut controllers (DOCCs) are correlated to instances of coupled vibrations in the axial, lateral, and torsional directions occurring during downhole drilling. Design parameters are quantified by drilling efficiency (DE), average in-cone DOCC contact area, average weight on bit (WOB) taken off by in-cone DOCC, and average torque on bit (TOB) taken off by in-cone DOCC. Design guidelines to mitigate coupled vibrations are generated by correlating design parameter quantifiers and instances of coupled vibrations. Potential drill bit designs are then validated against the generated guidelines in order to mitigate vibration in future drilling runs.

Abstract: A drilling system, assembly, and method may help optimize drilling in a system that involves more than one rotary tool that engages the formation. A rotary tool may be a rotary cutting tool, such as a drill bit or reamer, or some other rotary tool (e.g. stabilizer or rotary steerable tool) that has the potential to drag on the wall of the hole being drilled and take energy away from cutting. In an example, a wellbore or portion thereof is formed by rotating a first rotary cutting tool having a first cutting structure in engagement with one portion of the formation together with a second rotary cutting tool having a second cutting structure in engagement with another portion of the formation. Forces are obtained above and below the second cutting structure. One or more drilling parameter or drill bit design parameter are adjusted in relation to a force differential between the forces above and below the second cutting structure.

Abstract: A method for using a mud motor may comprise drilling a borehole into a formation using a drill string connected to the mud motor and the mud motor is connected to a drill bit, measuring one or more parameters of the mud motor in the borehole, and sending the one or more parameters to surface. A system may comprise a mud motor connected to a drill string, a drill bit connected to the mud motor, a strain gauge, and in information handling system. The strain gauge may be connected to the drill bit and configured to take one or more parameters of the mud motor. The information handling system may be in communication with the strain gauge and configured to record the one or more parameters from the strain gauge.

Abstract: A method for developing design rules for mitigating cutting-induced stick-slip vibration includes determining at least one value for one or more drill bit performance parameters for a design of a drill bit. The one or more drill bit performance parameters include a functional characteristic of a depth of cut controller of the drill bit. The method includes correlating one or more instances of cutting-induced stick-slip vibration for at least one prior drilling operation to the at least one value for the one or more drill bit performance parameters. The method includes generating drill bit design rules that mitigate cutting-induced stick-slip vibration based on the correlating.

Abstract: A clamp assembly device for connecting a rotating control device bearing assembly to a main body of a rotating control device. The device includes clamp members configured to retain the bearing assembly in place on the main body, a clamp actuator for driving clamping and unclamping of the clamp members and a lock pin controlled by a lock pin actuator. The lock pin actuator is configured to lock and unlock the clamp assembly device by moving the pin between locked and unlocked positions along an axis substantially parallel with the axis of rotation of the bearing assembly.

Abstract: The present disclosure provides a fixed-cutter drill bit including a bit body defining a bit rotational axis, a plurality of blades each having an inner end that is radially closer to the bit rotational axis than a remainder of the respective blade, a central bit surface, and a plurality of cutters disposed on the blades and including an innermost cutter located closest among all of the plurality of cutters to the bit rotational axis and having a flattened cutting surface, a cutting arc, and a relief having ends which is located within and interrupts the cutting arc such that the cutting arc includes at least two portions located on opposite ends of the relief. The disclosure also provides a drilling system including the drill bit and a drill string attached to the drill bit and a surface assembly to rotate the drill string and drill bit.