Abstract: A shaped cutter has a plurality of peripheral cutting teeth to enhance drilling. The shaped cutter may enhance rock failure modes in addition to shearing, such as by indentation, impacting, scraping and grinding. The peripheral cutting teeth are located along the periphery, where cutting energy and forces may be highest. An open region radially inward of the peripheral cutting teeth may be axially recessed to increase the proportion of cutting load on the peripheral cutting teeth. The cutting table may be tapered to modify a back rake angle. The flared periphery may result in a sharper indentation angle and/or larger radius of contact. The plurality of cutting teeth may also exploit vibrations in the drill string to enhance rock failure.

Abstract: A shaped cutter has a plurality of ridges extending in parallel across a cutting face to enhance drilling. The cutting table is also multi-tapered, being convex along a first cross-section perpendicular to the ridges and concave along a second cross-section parallel with the ridges. The shaped cutter may enhance rock failure modes in addition to shearing, such as by indentation, impacting, scraping and grinding. The plurality of ridges may also exploit vibrations in the drill string to enhance rock failure. The cutting table may be positioned on a drill bit to define an internal back rake angle with respect to a slope angle where the cutting table is concave. The cutting table may include a flared periphery, resulting in a sharper indentation angle and/or larger radius of contact with the formation.

Abstract: Various shaped cutters are disclosed for use on a drill bit or other wellbore forming tool. In one aspect, the shaped cutter includes a plurality of radial ridge sets. Each radial ridge set includes a plurality of ridges radially extending along the cutting table between a periphery of the cutting table and the cutter axis. The cutter may be positioned on the drill bit with one of the radial ridge sets exposed to the formation so the ridges may generate multiple cracks in the formation while drilling. After the current radial ridge set becomes worn, the cutter may be repositioned on the drill bit to expose another one of the radial ridge sets, such as during a repair, refurbish, or maintenance operation. The plurality of ridges may also exploit vibrations in the drill string to enhance rock failure.

Abstract: The present disclosure relates to a tank of a high-voltage generator including a tank body and a tank lid. There is an opening in the tank lid. The opening is connected to the bellows so as to counteract the volume change of the transformer oil and avoid generation of bubbles. The tank includes a positive transformer, a negative transformer, a bellows, and other components. The high-voltage winding is embedded in the PCBs. The outer insulating bushing is covered by the PCBs so as to improve the insulativity between the turns of the high-voltage winding. In addition, oil barriers may be placed between the positive and the negative transformers, or between the transformers and the ground so as to eliminate the bridge breakdown effect and make the electric field uniform. By means of said measures, the present disclosure improves the stability of the high-voltage generator.

Abstract: A method and a system for a confined compressive strength (CCS) and an unconfined compressive strength (UCS) for one or more bedding layers. The method may include identifying a depth interval during a drilling operation as a distance between a first depth and a second depth, measuring one or more drill bit responses within the depth interval using a sensor package disposed on the drill bit, identifying one or more torsional bit vibrations, and identifying one or more bedding layers of the formation within the depth interval from the one or more torsional bit vibrations. The method may further include identifying the (CCS) and the (UCS) for each of the one or more bedding layers and identifying a bit wear of the drill bit within each of the one or more bedding layers using the one or more drill bit responses and the one or more torsional bit vibrations.

Abstract: A method and a system for a confined compressive strength (CCS) and an unconfined compressive strength (UCS) for one or more bedding layers. The method may include identifying a depth interval during a drilling operation as a distance between a first depth and a second depth, measuring one or more drill bit responses within the depth interval using a sensor package disposed on the drill bit, identifying one or more torsional bit vibrations, and identifying one or more bedding layers of the formation within the depth interval from the one or more torsional bit vibrations. The method may further include identifying the (CCS) and the (UCS) for each of the one or more bedding layers and identifying a bit wear of the drill bit within each of the one or more bedding layers using the one or more drill bit responses and the one or more torsional bit vibrations.

Abstract: Design parameters for PDC drill bit are correlated to instances of backward whirl, where backward whirl is detected along a lateral axis in the frequency domain during downhole drilling. Two regimes of backward whirl are described and detected—cutting-induced backward whirl and friction-induced backward whirl—where each regime has different characteristic frequencies, detection methods, and mitigation guidelines. Design parameters are quantified by gauge fullness, drilling efficiency (DE), and whirl index (WI). Design guidelines to mitigate backward whirl are generated by correlating design parameter quantifiers and instances of backward whirl, including both cutting-induced backward whirl and friction-induced backward whirl. Potential drill bit designs are then validated against the generated guidelines in order to mitigate backward whirl in future drilling runs.

Abstract: A method comprises determining an initial bit profile of a drill bit prior to the drill bit being used for drilling a wellbore. The method comprises determining a wear depth for at least one element of the drill bit after the drill bit has drilled at least a portion of the wellbore and determining a final bit profile of the drill bit based on the wear depth for the at least one element of the drill bit. The method comprises performing the following for each of one or more intermediate steps between the initial bit profile and the final bit profile, determining an intermediate bit profile of the drill bit and determining at least one wear parameter for the at least one element based on the intermediate bit profile of the drill bit.

Abstract: A method comprises determining an initial element wear profile of at least one element of a drill bit prior to the drill bit being used for drilling a wellbore and determining a wear depth for each of the at least one element of the drill bit after the drill bit has drilled at least a portion of the wellbore. The method includes determining a final element wear profile of the at least one element of the drill bit based on the wear depth of at least one element of the drill bit. The method includes performing the following for each of one or more intermediate steps between the initial element wear profile and the final element wear profile, determining an intermediate element wear profile of the at least one element; and determining at least one wear parameter for the at least one element based on the intermediate element wear profile.

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 drill bit design generator uses drill bit metrics to generate drill bit designs with reduced 3D coupled vibration. The drill bit design generator generates an initial set of drill bit designs that are simulated in a deployed or artificial environment. Simulated drill bits according to the initial drill bit designs have gyroscopic sensors that detect the presence of 3D coupled vibration. A drill bit simulator tracks metrics such as side cutting efficiency and drilling efficiency during simulations and correlates these metrics with 3D coupled vibration. The drill bit design generator determines thresholds for these metrics using correlations with 3D coupled vibration and generates updated/new drill bit designs using the metric thresholds.

Abstract: Systems and methods are disclosed for selecting a drill bit design that reduces or eliminates bit induced stick-slip. In some embodiments, each of a set of test drill bits is correlated with stick-slip events, wherein each of the test drill bits has a different design pattern comprising a combination of structural attributes. The design pattern stick-slip correlation includes, for each of the test drill bits, detecting variations in motion of the test drill bit during drilling operation. Stick-slip for each of the test drill bits is detected based on the detected variations in motion of the test drill bits during operation. The correlation further includes in response to detecting stick-slip, recording a stick-slip event in association with the corresponding test drill bit.

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 method comprises acquiring measurements of a force and a rotational velocity experienced by a drill bit while the drill bit is positioned in a wellbore; and identifying, by at least one processor, a type of dysfunction experienced by the drill bit based on a relationship of the measurement of the force and a measurement of the rotational velocity.

Abstract: Based on measurements of forces and rotational velocity experienced by a drill bit during drilling, drilling behavior is detected and identified. Measurements of forces on a drill bit including torque on bit (TOB), weight on bit (WOB), etc. and measurements of rotational velocity (rotations per minute or RPM) are acquired in real time at the drill bit. Various measurements are correlated to produce related combinations of measurements, such as WOB-RPM, TOB-RPM, and RPM-time. Based on fitting between the combinations of measurements and curves corresponding to predetermined torsional behavior trends, torsional, axial, and rotational behaviors are classified as functional or dysfunctional.

Abstract: Drill bit vibration data for lateral, axial, and torsional directions of a drill bit is collected for a simulated or deployed drill bit for visualization of 3D coupled vibration. A frequency converter transforms the drill bit vibration data into frequency vibration data. A drill bit analyzer identifies local maxima (“peaks”) in the frequency vibration data in each of the lateral, axial, and torsional directions. Common peaks across all 3 directions with sufficiently high frequency and sufficiently high bit rotation speed are indicated as 3D coupled vibration. A drill bit data visualizer uses the indications of 3D coupled vibration in addition to the vibration data and frequency vibration data to generate visualizations of 3D coupled vibration in the drill bit.

Abstract: Based on measurements of forces and rotational velocity experienced by a drill bit during drilling, drilling behavior is detected and identified. Measurements of forces on a drill bit including torque on bit (TOB), weight on bit (WOB), etc. and measurements of rotational velocity (rotations per minute or RPM) are acquired in real time at the drill bit. Various measurements are correlated to produce related combinations of measurements, such as WOB-RPM, TOB-RPM, and RPM-time. Based on fitting between the combinations of measurements and curves corresponding to predetermined torsional behavior trends, torsional, axial, and rotational behaviors are classified as functional or dysfunctional.

Abstract: Methods for simulating a downhole drilling operation include estimating the geometry, i.e., the shape, size of rock chips generated by engagement of a drill bit with a geologic formation. Each cutting element on the drill bit may produce rock chips of different geometry, and the geometry of rock chips generated by a particular cutting element may change over a predetermined interval. The geometry and other properties rock chips predicted for an interval may be recorded, and a distribution may be calculated based on categorizing each of the predicted rock chips into predefined categories and determining the relative number of rock chips in each category. The distribution may be useful in drill bit design, determining required mud flow characteristics for a drilling operation, and facilitating rotation of a drill string by preventing undesirable interactions of the rock chips with the drill bit and other downhole equipment.

Abstract: Disclosed are an oxazoline compound, a synthesis method therefor and an application thereof. The oxazoline compound has a structure represented by formula (I), wherein in the formula (I), R is selected from groups represented by formula (I-1), formula (I-2), and formula (I-3), where an oxazoline derivative having a novel molecular structure is obtained by introducing a nitrogen heterocycle, an ether bond or a sulfonate structure into the oxazoline compound. The oxazoline derivative is useful in the field of agricultural protection, and has higher acaricidal activity than etoxazole, can inhibit the synthesis of chitin from mites, and can effectively control the embryogenesis and development of eggs of Tetranychus cinnabarinus, as well as the ecdysis process from larvae to adults, and therefore has a significant effect in killing mite eggs and larvae.