Halliburton Energy Services, Inc.

Multi-chem Group, LLC

Shilin Chen

Robert W Arfele

Michael Thomas Pelletier

Robert Paul Freese

Gary Eugene Weaver

James R Ashby

Ping Sui

Riun Ashlie

William W King

Bradley David Dunbar

Gregory Christopher Grosz

Curtis Clifford Lanning

Christopher Charles Propes

James S Dahlem

Dale E Jamison

John Ransford Hardin, Jr

Van Jordan Brackin

Micheal Burl Crawford

Mark Evans Williams

John Leslie Wisinger, Jr

Jay Stuart Bird

Robert I Clayton

Guy James Lefort

Zakaria Maouche

Stefano Mancini

Luk Servaes

Shiwei Qin

Yonggui Guo

Eric Lawrence Helgesen

Eric Lauret

Oliver Matthews

Jonathan Kollar

John Ransford Hardin

An apparatus includes a processor and a machine-readable medium having program code executable by the processor to cause the apparatus to determine a first parameter based on a walk force of a drill bit. The program code also includes instructions to generate a whirl index value that comprises a ratio of drilling parameters, wherein at least one parameter of the ratio of drilling parameters is the first parameter. Based on a determination that the whirl index value exceeds a whirl index threshold, the program code includes instructions to determine that a drilling operation induces backward whirl, wherein the drilling operation is characterized by the drilling parameters.

Reduction of backward whirl during drilling

A method performed while drilling a wellbore in a subsurface formation with a drill bit. The method comprises obtaining sonic logs of the subsurface formation proximate the drill bit. The method comprises determining mechanical specific energy based on drilling parameters. The method comprises comparing respective trends of the sonic logs and the mechanical specific energy of the drill bit to identify a cause for a change in drilling performance of the drill bit. The method comprises performing a drilling operation based on the cause for the change in the drilling performance.

Identifying bit wear and justifying bit trip

A vibrational disfunction machine learning model trainer trains a vibrational disfunction classifier to identify one or more types of vibrational disfunction, or normal drilling, based on measurements of at least one of displacement, velocity, acceleration, angular displacement, angular velocity, and angular acceleration acquired for the drill bit. The vibrational disfunction machine learning model trainer trains the algorithm based on data sets corresponding to characteristic behavior for one or more types of vibrational disfunction and normal drilling. The vibrational disfunction classifier operates in real time, and can operate at the drill bit and communicate vibrational disfunction identification in real time, allowing mitigation of vibrational disfunction through adjustment of drilling parameters.

Classification and control of detected drilling vibrations using machine learning

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.

Shaped cutter with ridges and multi-tapered cutting face

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.

Shaped cutter with peripheral cutting teeth and tapered open region

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.

Shaped cutter with multiple radial ridge sets

A device includes a drill bit body defining an axis of rotation, a plurality of drill blades on the drill bit body, and a shaped cutter secured to at least one of the plurality of drill blades. The shaped cutter including an engagement surface having an exposed partially flattened boundary, wherein a contact point of the engagement surface during drilling is off-centered with respect to a center of the exposed partially flattened boundary.

Shaped cutter arrangements

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.

Monitoring drilling conditions and estimating rock properties

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.

Mitigation of backward whirl in drill bits

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.

Mitigation of high frequency coupled vibrations in PDC bits using in-cone depth of cut controllers

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.

Drill bit design with reduced 3D coupled vibration

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. The method further includes determining a performance efficiency value for each of the plurality of test drill bits and correlating the determined performance efficiency values with the stick-slip events to determine a threshold performance efficiency value. A design pattern for a drill bit is selecting or determined based, at least in part, on the threshold performance efficiency value.

Drill bit design selection and use

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.

Mitigation of cutting-induced stick-slip vibration during drilling with drill bits having depth of cut controllers

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. A dysfunction identifier then identifies drill bit dysfunctions, such as high-frequency torsional noise, cutting-induced stick-slip, friction-inducted stick-slip, pipe-induced stick-slip, three-dimensional (3D) coupled vibrations (including subsets high-frequency torsional oscillations and low-frequency torsional oscillations), low-frequency torsional vibration, high-frequency torsional vibration, etc.) based on the functionality of the torsional, axial, and rotational behaviors. Based on drill bit dysfunction identification, dysfunctional drilling behavior can be mitigated.

Drill bit dysfunction identification based on compact torsional behavior encoding

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.

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Montgomery, TX, United States of America

Shilin Chen