Abstract: A drilling system may determine a change in motor torque and/or a pressure drop of a downhole motor based on a flow of a drilling fluid through the downhole motor. The drilling system may determine a change in bit torque of a bit with respect to a change in a weight on bit of the bit. Based at least in part on the change in motor pressure and the change in bit torque of the bit with respect to the change in the weight on bit of the bit, the drilling system may adjust a flow rate of the drilling fluid through the downhole motor to reduce a frequency of motor stalls of the downhole motor.

Abstract: A cutting element assembly includes a cutter support including a cutter bore. A cutting element is in the cutter bore and a resilient element is integral with the cutter support. The resilient element is longitudinally compressible and has a displacement of greater than 0.1 mm and optionally less than 2 mm. Another cutting assembly includes a cutter support coupled to multiple cutting elements. A resilient element of the cutter support is compressible based on a force applied to the cutter support through one or more of the cutting elements. The resilient element can include a slit in the cutter support. A slit may, for instance, extend perpendicular or transverse to an axis of the cutting elements and allow the cutter support to flex and close off or reduce a size of the slit when forces act on one or more of the cutting elements.

Abstract: Methods and systems are provided that determine data characterizing spatial variation of vibrational dysfunction (such as HFTO) along the BHA of a drilling system. In embodiments, such data can be determined from a minimal set of measurements of any or all of four variables that include: vibration amplitude; vibration wavelength; vibration frequency; and the axial position of the first vibrational node. In embodiments, such data can be determined from measurements of vibration amplitude and vibration frequency of a BHA at two fixed positions along the BHA (e.g., with two sensors offset axially along the BHA). In other embodiments, such data can be generated from the estimated position of the first vibrational node and measurements of vibration amplitude and vibration frequency by a single sensor disposed at a fixed axial position along the BHA.

Abstract: In a drill bit which has hard-faced cutting or gauge protection elements positioned to be in direct contact with subterranean formation as the bit is rotated, at least one of these elements includes a window positioned to be in direct contact with the formation or cuttings from the formation as the bit rotates and moves forward to drill into the formation. Electromagnetic radiation with wavelength in the range from 100 nm to 2600 nm is transmitted through the window to the formation in contact with the window. Electromagnetic radiation such as fluorescence that returns through the same window is received by a spectrometer. The source and receiver of electromagnetic radiation are both accommodated within the downhole drilling equipment but spaced from the windowed element. The electromagnetic radiation travels along light guides from the source to the window and from the window to the receiver.

Abstract: A stabilizer can include an outer collar, an inner sleeve, and a locking mechanism. The locking mechanism is changeable between a first mode in which the outer collar is rotationally fixed to the inner sleeve and a second mode in which the outer collar is rotationally isolated relative to the inner sleeve. The stabilizer may include an active or passive system for changing modes. An example passive device may include a magnetic clutch where the detected force overcomes magnetic forces to change mode. The stabilizer can be used to mitigate whirl on a rotating device by switching the rotating device between a rotating mode and a non-rotating mode. In the rotating mode, outer collar may rotate with the inner sleeve. In the non-rotating mode, the outer collar may be rotationally isolated from the inner sleeve.

Abstract: A rotary tool for operation within an underground borehole or within tubing in a borehole has a tool body and at least one sensor-containing unit attached to the tool body and positioned to contact the conduit wall. The sensor-containing unit includes an exterior portion to contact the borehole or tubing wall and one or more sensors is located in a cavity between the exterior portion and the tool body. The sensor-containing unit may be formed from the exterior portion, an attachment portion for attachment to the tool body, and one or more connecting portions extending between the attachment and exterior portions, with the sensor-containing cavity between the attachment and exterior portions. Possible rotary tools include drill bits, reamers, mills, stabilizers, and rotary steerable systems.

Abstract: A method for measuring at least one property of a sample includes obtaining a sample of fluid including at least fines from a downhole environment, exposing the sample to a magnetic field, measuring a magnetic susceptibility of the fines in the sample in response to the magnetic field, and identifying at least one mineral present in the fines based at least partially on the magnetic susceptibility.

Abstract: A rotary tool for operation within an underground wellbore or within tubing in a wellbore has at least one force-sensitive element attached to the tool body and positioned to contact the conduit wall, wherein the force-sensitive element comprises an outer portion to contact the wellbore or tubing wall, at least one connecting portion which is more compliant than the outer portion and through which the outer portion is connected to the tool body, and at least one sensor responsive to force on the outer portion transmitted through the force-sensitive element to the tool body. The sensors may resolve forces into measurable forces on three axes. Possible rotary tools include drill bit, reamer, mill, stabilizer and rotary steerable system for a drill bit.

Abstract: A stabilizer can include an outer collar, an inner sleeve, and a locking mechanism. The locking mechanism is changeable between a first mode in which the outer collar is rotationally fixed to the inner sleeve and a second mode in which the outer collar is rotationally isolated relative to the inner sleeve. The stabilizer may include an active or passive system for changing modes. An example passive device may include a magnetic clutch where the detected force overcomes magnetic forces to change mode. The stabilizer can be used to mitigate whirl on a rotating device by switching the rotating device between a rotating mode and a non-rotating mode. In the rotating mode, outer collar may rotate with the inner sleeve. In the non-rotating mode, the outer collar may be rotationally isolated from the inner sleeve.

Abstract: High frequency oscillation (HFO) comes in at least two types. Type 1 HFO is lower frequency and often associated with a motor. Type 2 HFO is higher frequency and often independent of a motor. To mitigate torsional strain due to Type 2 HFO, an HFO mitigation mechanism can be placed based on an oscillation node location to move the oscillation node to a new position which may be uphole of a tool or the BHA, or to a less vulnerable location. Mitigation can also include placing an energy damping component based on the oscillation node. This may be at a high displacement location distanced from the oscillation node, or may include placement at the oscillation node with an additional HFO mitigation mechanism to move the oscillation node away from the installation location. Oscillations may be damped by using any combination of flow restrictions, fluid bypasses, or axially compliant elements.

Abstract: In a drill bit which has hard-faced cutting or gauge protection elements positioned to be in direct contact with subterranean formation as the bit is rotated, at least one of these elements includes a window positioned to be in direct contact with the formation or cuttings from the formation as the bit rotates and moves forward to drill into the formation. Electromagnetic radiation with wavelength in the range from 100 nm to 2600 nm is transmitted through the window to the formation in contact with the window. Electromagnetic radiation such as fluorescence that returns through the same window is received by a spectrometer. The source and receiver of electromagnetic radiation are both accommodated within the downhole drilling equipment but spaced from the windowed element. The electromagnetic radiation travels along light guides from the source to the window and from the window to the receiver.

Abstract: A method of mitigating whirl on a rotating device includes detecting force on a outer surface of the rotating device and switching the rotating device between a rotating mode and a non-rotating mode. In the rotating mode, the outer surface may rotate with an inner sleeve. In the non-rotating mode, the outer surface may be rotationally isolated from the inner sleeve. The rotating device may include a stabilizer with an active or passive system for switching modes. The stabilizer can include an outer collar, an inner sleeve, and a locking mechanism. The locking mechanism is changeable between a first mode in which the outer collar is rotationally fixed to the inner sleeve and a second mode in which the outer collar is rotationally isolated relative to the inner sleeve. An example passive device may include a magnetic clutch where the detected force overcomes magnetic forces to change mode.

Abstract: A rotary tool for operation within an underground borehole or within tubing in a borehole has a tool body and at least one sensor-containing unit attached to the tool body and positioned to contact the conduit wall. The sensor-containing unit includes an exterior portion to contact the borehole or tubing wall and one or more sensors is located in a cavity between the exterior portion and the tool body. The sensor-containing unit may be formed from the exterior portion, an attachment portion for attachment to the tool body, and one or more connecting portions extending between the attachment and exterior portions, with the sensor-containing cavity between the attachment and exterior portions. Possible rotary tools include drill bits, reamers, mills, stabilizers, and rotary steerable systems.

Abstract: A method for generating a drilling plan for drilling a wellbore at a field includes receiving data. The data includes one or more of geological properties at the field, wellbore properties, drilling tool parameters, rig characteristics of drilling rigs, and working practices of a plurality of drilling crews. The method also includes generating a plurality of candidate drilling plans for drilling the wellbore at the field. The method also includes estimating one or more outputs for the candidate drilling plans based at least partially upon the data. The one or more outputs include an amount of emissions generated to drill the wellbore using the candidate drilling plans. The method also includes presenting for selection one or more of the candidate drilling plans based at least partially upon the one or more outputs.

Abstract: Lost circulation events are mitigated by determining a size and extent of a formation feature causing the loss of circulation. The formation feature may be determined based on surface drilling parameters, and can apply one or more of a mechanical specific energy, hydraulic, or aperture model. Using such model(s), the size of a fracture/void/aperture can be estimated and a treatment plan for a lost circulation vent can be determined. For instance, a mechanical specific energy of zero can indicate the presence of a void, the pressure at the standpipe can an extent of a formation feature, or the size of the formation feature can be estimated using drilling fluid flow rate, volume, pressure, or rheology. Determining a treatment plan can include selecting or designing a lost circulation material, a volume of lost circulation material, or alternative drilling methods.

Abstract: A rotary tool for operation within an underground borehole or within tubing in a borehole has a tool body and at least one sensor-containing unit attached to the tool body and positioned to contact the conduit wall. The sensor-containing unit includes an exterior portion to contact the borehole or tubing wall and one or more sensors is located in a cavity between the exterior portion and the tool body. The sensor-containing unit may be formed from the exterior portion, an attachment portion for attachment to the tool body, and one or more connecting portions extending between the attachment and exterior portions, with the sensor-containing cavity between the attachment and exterior portions. Possible rotary tools include drill bits, reamers, mills, stabilizers, and rotary steerable systems.

Abstract: A surface rig system includes components that consume power (e.g., using electrical motors). The power consumption of the components is monitored and used to infer other operational parameters. Illustratively, power consumption (e.g., current draw) of a shale shaker is monitored and used to infer: the volume of cuttings on the screen; changes in fluid viscosity, density, or rheology; health of the shaker screen; fluid cycle times; or screen clogging/blinding. Power consumption of pumps, fluid agitators, draw works, and other devices can also be monitored and used to infer parameters such as: fluid viscosity, density or rheology; hook load, or fluid slugging. Based on inferred parameters, changes may be made or advised for operation of equipment, including a shale shaker, downhole tool, pump, shaker screen, top drive, drilling fluid, or draw works.

Abstract: A directional drilling system that includes a drill bit that drills a bore through rock. The drill bit includes an outer portion of a first material and an inner portion coupled to the outer portion. The inner portion includes a second material.

Abstract: A drilling system that includes a drill bit that drills a bore through rock. A shaft coupled to the drill bit, wherein the shaft transfers rotational power to the drill bit. A housing that receives at least part of the shaft. A rotary steering system that controls a drilling direction of the drill bit. The rotary steering system includes a steering sleeve that couples to and uncouples from the housing to control a drilling direction of the drill bit.

Abstract: A method of mitigating whirl on a rotating device includes detecting force on a outer surface of the rotating device and switching the rotating device between a rotating mode and a non-rotating mode. In the rotating mode, the outer surface may rotate with an inner sleeve. In the non-rotating mode, the outer surface may be rotationally isolated from the inner sleeve. The rotating device may include a stabilizer with an active or passive system for switching modes. The stabilizer can include an outer collar, an inner sleeve, and a locking mechanism. The locking mechanism is changeable between a first mode in which the outer collar is rotationally fixed to the inner sleeve and a second mode in which the outer collar is rotationally isolated relative to the inner sleeve. An example passive device may include a magnetic clutch where the detected force overcomes magnetic forces to change mode.