Halliburton Energy Services, Inc.

Doublebarrel Downhole Technologies LLC

National Oilwell Varco, L.p.

National Oilwell Dht, L.p.

Intrepid Rss, LLC

Curtis Clifford Lanning

Van Jordan Brackin

Kelley Leigh Plunkett

Aaron E Schen

Christopher Charles Propes

Kevin Clark

Shilin Chen

William Brian Atkins

Bradley David Dunbar

Jacob Daniel Riddel

Jacob H Kronman

Sassan Dehlavi

Jeff Kurthy

Daniel Brendan Voglewede

Douglas Caraway

Trung Quoc Huynh

Andrew D Lake

John William Varner

Dong P Phung

John Harman

Michael Pregeant

Dan Seutter

Darien Louis Gurka, Jr

Robert Kelly Owen

Daniel Seutter

Nicholas Grant Allison

A cutting element includes a substrate configured to couple to a pocket formed in a blade of a downhole drill bit and a polycrystalline diamond portion secured to the substrate. The polycrystalline diamond portion includes a cutting face, a radial sidewall, and a cutting edge formed at a transition from the radial sidewall to the axial the cutting face. The cutting face includes a plow feature disposed at a center of the cutting face. The plow feature has a face portion and a shoulder portion. The shoulder portion extends radially outward from the face portion and axially downward toward the substrate. Additionally, the cutting face includes a recessed portion extending between the cutting edge and a radially outer edge of the shoulder portion.

Polycrystalline diamond compact cutter with plow feature

An activation control module utilizes gravity and/or centrifugal acceleration to move a mechanical element that controls, activates or deactivates a mechanical or hydraulic mechanism, for use with a downhole tool such as a drilling tool or reamer in a wellbore. In embodiments, the activation control module described herein may utilize a combination of centrifugal acceleration and/or gravity due to an inclination of the downhole tool to move a valve, which turns off pressure to a hydro-mechanical system. The activation control modules may be utilized in applications where very little space is available for larger mechanisms. Further, the activation control modules do not require expensive and complex electro-mechanical systems, reducing or eliminating the need for batteries, wiring, electronics, motors, pumps and the like. Moreover, the activation control modules described herein do not require the use of a turbine, a centrifugal clutch or a linear actuator.

Activation of downhole mechanical device with inclination and/or change in RPM

In general, in one aspect, embodiments relate to a drill bit, that includes a bit body, a plurality of cutters secured to the bit body, an axial reciprocating assembly, a lateral reciprocating assembly, and a sliding interface that includes a first contact surface and a second contact surface in direct sliding engagement with the first contact surface inside the bit body, such that an exposure of the first borehole engagement member varies with an exposure of the second borehole engagement member.

Depth of cut control responsive to borehole trajectory

Disclosed is a downhole tool and method suitable for geosteering within a lateral formation. The downhole tool includes a gamma sensor for monitoring gamma radiation within the lateral formation. The method provides for monitoring of the location of the drill bit or a RSS within a borehole and correcting the angle of inclination to maintain the drill bit or RSS within the target zone of the lateral formation.

Geosteering in a lateral formation

A drill bit has a plurality of cutters secured to the bit body, including a gauge cutter defining a gauge diameter of the drill bit. A reciprocating gauge assembly on the bit comprises a cavity defined in the bit body, a piston reciprocably disposed in the cavity, a wear element on an outwardly facing end of the piston, a piston retainer for moveably retaining the piston in the cavity, and a spring biasing the piston outwardly to a neutral position of the wear element with respect to the gauge diameter. The wear element and piston may be urged inwardly in response to an applied load at the drill bit gauge pad, increasing the lateral depth of cut and thereby controlling the aggressiveness of the bit in response to the load.

Drill bit with reciprocating gauge assembly

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

The disclosure provides a drill bit including a bit body and a blade extending from the bit body. The blade includes a first element protruding from a surface of the blade and a second element protruding from the surface of the blade. The first element and the second element are each configured to extend or retract relative to the surface of the blade and are coupled to each other such that when the second element retracts relative to the surface of the blade, the first element extends relative to the surface of the blade. The first element is disposed within a first pocket formed in the surface of the blade, and the second element is disposed within a second pocket formed in the surface of the blade. A communication channel is formed between the first pocket and the second pocket.

Depth of cut control activation system

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

Disclosed are methods for transmitting data to a downhole tool. The methods include the option of confirming receipt and implementation of the transmitted data by the downhole tool. The disclosed methods utilize changes in RPM of the tool to convey the data through three separate changes in RPM. The changes in RPM are used to generate pulses suitable for identifying preprogrammed actions found within the memory of the downhole tool.

Verifiable downlinking method

A rolling depth of cut controller (DOCC) includes a first retainer including a body portion having an arcuate inner surface. The body portion extends partially around a central axis between the inner surface and an outer surface from a mating surface to an engagement surface. Further, the body portion extends axially along the central axis. The rolling DOCC also includes a second retainer secured to the first retainer at the mating surface via at least one fastening feature. Additionally, the rolling DOCC includes a rolling element disposed at least partially within a cavity formed between the first retainer and the second retainer. The rolling element is configured to rotate within the cavity about the central axis, and an exposed portion of the rolling element is configured to provide depth-of-cut control for a drill bit.

Rolling depth of cut controller with clamshell retainer and solid diamond rolling element

Disclosed herein is a pressure compensation system for a bottom hole assembly. The disclosed pressure compensation system improves the responsiveness of a hydraulically actuated component carried by the bottom hole assembly.

Pressure compensation system for a rotary drilling tool string which includes a rotary steerable component

A drill bit for drilling a borehole in an earthen formation includes a connection member having a pin end. In addition, the drill bit includes a bit body coupled to the connection member and configured to rotate relative to the connection member about a central axis of the bit. The bit body includes a bit face. Further, the drill bit includes a blade extending radially along the bit face. Still further, the drill bit includes a plurality of cutter elements mounted to a cutter-supporting surface of the blade. Moreover, the drill bit includes a depth-of-cut limiting structure slidably disposed in a bore extending axially from the cutter-supporting surface. The depth-of-cut limiting structure is configured to move axially relative to the bit body in response to rotation of the bit body relative to the connection member.

Drilling systems and fixed cutter bits with adjustable depth-of-cut to control torque-on-bit

A valve () for controlling the flow of a drilling fluid through a down-hole tool () positionable in a wellbore penetrating a subterranean formation. The down-hole tool has a housing with a drilling motor therein and a drill bit () at an end thereof. The drilling motor () has a housing with a rotor () rotationally movable in a rotor channel () as the drilling fluid passes through a rotor channel between the housing and the rotor. The rotor has a bypass channel therethrough for bypassing a portion of the drilling fluid therethrough. The valve includes a valve plate positionable upstream of the motor. The valve plate () has at least one flow passage () and at least one bypass passage () therethrough. The flow passage is in fluid communication with the rotor channel for passing the drilling fluid therethrough. The bypass passage is in selective fluid communication with the bypass channel when the rotor rotates about the housing and moves the bypass channel into alignment with at least a portion of the bypass passage for bypassing a portion of the drilling fluid therethrough whereby a hammering effect is generated on the bit.

Growing community of inventors

Montgomery, TX, United States of America

Curtis Clifford Lanning