Halliburton Energy Services, Inc.

Bradley David Dunbar

John Leslie Wisinger, Jr

Matt Barnes

Shilin Chen

Van Jordan Brackin

Curtis Clifford Lanning

Robert W Arfele

John Gerard Evans

Christopher Charles Propes

Brody Dunn

William Brian Atkins

Gregory Christopher Grosz

Seth Garrett Anderle

Yi Pan

Gustav Edward Lange

Jean-Pierre Lassoie

Douglas Caraway

Kelley Leigh Plunkett

Paul Gerard Cairns

Ludovic Delmar

Robert Warner

William Browning Bradford

David Wayne Cawthon

Roddy Harwell

Lyn Duane Labahn

Chris Propes

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.

Multiple selectable pressure driven devices on a drill bit

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.).

Downhole pressure calculation based on strain gauge measurements

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.

Force measurements about secondary contacting structures

A drill bit for a drilling system. The drill bit may include blades and a first depth of cut sensor. The blades may each comprise cutters. The first depth of cut sensor may be coupled to one of the blades and positioned to measure a distance between the first depth of cut sensor and a downhole surface of the borehole and transmit the distance measurement to a control system of the drilling system.

Systems and methods for drilling a borehole using depth of cut measurements

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.

Drill bit cutter with shaped portion matched to kerf

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.

Mechanically attached strain device

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.

System and method for communicating with a downhole tool

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.

Floating ball pressure sensor

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 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.

Downhole dynamometer

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

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.

Fixed-cutter drill bits with reduced cutting arc length on innermost cutter

A downhole drilling tool comprises an earth-boring drill bit including a bit body and a shank coupled to the bit body. The drill bit includes a motion puck positioned in a cavity of the shank, wherein the motion puck includes a motion sensor to detect movement indicating a force applied to the earth-boring drill bit during a drilling operation. The drill bit includes a strain puck positioned in the cavity of the shank, wherein the strain puck includes a strain gauge to measure the force applied to the earth-boring drill bit during the drilling operation. The drill bit includes a plurality of blades disposed on exterior portions of the bit body, each blade having respective cutting elements disposed thereon.

Dual synchronized measurement puck for downhole forces

A drill bit can include a bit body having an upper portion, a central bore, and an adjustable inner gauge. The central bore can define a bore surface, and the bit body can include a plurality of fixed cutters formed on the upper portion. The adjustable inner gauge may be movably positioned within the bit body central bore to increase or decrease an exposed area of the bore surface for adjusting stability or steerability of the drill bit while forming the wellbore.

Growing community of inventors

The Woodlands, TX, United States of America

Bradley David Dunbar