Halliburton Energy Services, Inc.

John Kenneth Snyder

Victor Gawski

Michael John Strachan

Jim Darin Tilley

Richard Thomas Hay

Michael Dewayne Finke

Jeremy Buc Slay

Jeremy Alexander Greenwood

Vinodh Kumar Palani

Winston James Webber

David Lyle

Philip Park-Hung Leung

Patrick William Torbett

Graeme O'Brien Phillip Salmon

Provided is a stabilizer for use in a wellbore. The stabilizer, in one example, includes a downhole tubular coupleable to a downhole conveyance in a wellbore. In accordance with this example, the stabilizer additionally includes two or more helical wellbore stabilizing elements extending radially outward from the downhole component, the two or more helical wellbore stabilizing elements shaped such that an annular flow area between leading edges of adjacent helical wellbore stabilizing elements and between trailing edges of adjacent helical wellbore stabilizing elements is variable along at least a portion of a length (L) of the two or more helical wellbore stabilizing elements, and such that an unobstructed axial flow path exists between the adjacent helical wellbore stabilizing elements along the length (L).

Stabilizer including modified helical wellbore stabilizing elements

A stabilizer for use in a wellbore may include a downhole tubular configured to couple to a downhole conveyance in a wellbore, as well as two or more helical blades extending radially outward from the downhole tubular. The two or more helical blades are oriented about the downhole tubular to form respective flow paths between adjacent blades. Further, each blade of the two or more helical blades may include a line-of-sight face and a gauge ramp. The line-of-sight face is formed adjacent a leading inner blade wall of the blade at a lower end of the blade and is angularly offset from the leading inner blade wall. The gauge ramp extends from an outer surface of the downhole tubular toward an outer blade surface of the blade proximate the lower end of the blade.

Helical blade stabilizer with line-of-sight faces

A method for configuring a bottom hole assembly (BHA) includes receiving bending moment values for the BHA, curvature values and drilling conditions for a wellbore, and processing the bending moment values to create a representation of the curvature of the drilled wellbore. Processing the bending moment values includes selecting a set of curvature values in a specified range for a selected location, calculating a bending moment value for each curvature value, and determining an actual wellbore curvature at the location by matching the received bending moment value to one of the calculated bending moment values. The method further includes generating a representation of an actual path of the wellbore using selected curvature values at a plurality of wellbore locations, comparing the actual path of the wellbore with a planned path of the wellbore; and based on the comparison, determining a configuration of the BHA to drill a next wellbore.

Determining approximate wellbore curvature

A resonant receiver for electromagnetic telemetry of wellbore-related data can be used to improve signal reception for transmitting or receiving low-amplitude downhole signals that include noise. A system can comprise a surface assembly with an antenna for wirelessly communicating signals with equipment positioned downhole in a wellbore. The surface assembly can comprise an amplifier and a tank circuit operable to resonate at a resonant frequency to pass a received signal at the resonant frequency to the amplifier while also shunting noise outside of the resonant frequency to ground. In some embodiments, a downhole transceiver in wireless communication with the surface assembly can comprise a similar tank circuit and amplifier.

Resonant receiver for electromagnetic telemetry

In some embodiments, a method includes performing a directional drilling operation using a drill string having a drilling motor and cutting structures that include a drill bit and a reamer. The method includes receiving data from one or more sensors, wherein at least one of the one or more sensors output data related to at least one performance attribute associated with load monitoring between the drill bit and the reamer. The load monitoring is distributed between the drill bit and the reamer by the drilling motor. The at least one performance attribute comprises a differentiation of distribution of at least one of a weight and a torque applied to each of the drill bit and the reamer. The method includes displaying the data related to the at least one performance attribute associated with the load monitoring in a graphical and numerical representation on a graphical user interface screen.

Monitor and control of directional drilling operations and simulations

A ranging system includes a drill string comprising a bottom hole assembly (BHA). A plurality of ranging devices are positioned in a spaced-apart orientation on the drill string and are operable to provide a conducting contact with a formation. At least one insulator member is positioned on the drill string between the plurality of ranging devices and is operable to provide a non-conducting contact with the formation. During drilling operations, the plurality of ranging devices provide conducting contact with a formation while the at least one insulator member provides non-conducting contact with the formation so to enhancing ranging operations while drilling. A method of modeling and simulating drill string response is provided to identify locations along the drill string for positioning insulator members.

Systems and methods for downhole BHA insulation in magnetic ranging applications

A progressing cavity-type drilling motor having an electrical generator disposed within the rotor of the drilling motor. In some embodiments, the electrical generator produces electrical energy from a flow of drilling fluid through a bore in the rotor. In other embodiments, the electrical generator produces electrical energy by harnessing the kinetic energy of the rotor as the drilling motor is used to drill into a formation. The electrical energy generated by the generator can be stored or used to power sensors, actuators, control systems, and other downhole equipment.

Electricity generation within a downhole drilling motor

An electrical generator positionable downhole in a well bore includes a tubular housing having a first longitudinal end and a second longitudinal end, the housing having an internal passageway with a plurality of layers. The layers comprise at least a first protective layer, a second protective layer, and an electrically conductive layer positioned between the first and second protective layers. The layers define an internal cavity. A shaft with magnetic inserts is movably positioned in the internal cavity. Electrical current is generated when the shaft is moved. Alternatively, the device may be supplied with electrical power and used as a downhole motor.

Electrical generator and electric motor for downhole drilling equipment

A progressing cavity drilling motor positionable in a wellbore includes a tubular housing, a stator having a collection of helical lobes, and a rotor having a collection of helical lobes. The rotor orbits about the central longitudinal axis of the stator. A bearing assembly is coupled to an end of the housing and is disposed around an end of the rotor. The bearing assembly includes a bearing housing disposed concentrically in the stator housing, an outer bearing disposed concentrically in the bearing housing, and an inner bearing disposed on the first cylindrical end of the rotor. The inner bearing has a central axis aligned with the central axis of the rotor and is positioned in the outer bearing such that the inner bearing orbits around the central longitudinal axis of the stator when the rotor is rotated in the stator.

Rotor bearing for progressing cavity downhole drilling motor

An electrical connector assembly positionable in a wellbore includes a flexible conductor, a first hanger ring connected to a first end of the flexible conductor, a first hanger ring landing shelf in an outer housing, a second hanger ring positioned on a second end of the flexible conductor, and a second hanger ring landing shelf in the housing.

Downhole electrical connector

A method includes performing a directional drilling operation. The method also includes receiving data from one or more sensors, wherein at least one of the one or more sensors output data related to a performance attribute of a downhole component that is from a group consisting of a downhole drilling motor and a rotary steerable tool. The downhole component comprises part of a drill string that is used to perform the directional drilling operation. The performance attribute is selected from a group consisting of rotations per unit of time of the downhole component, operating differential pressure across the downhole component and torque output of the downhole component. The method also includes displaying the data in a graphical and numerical representation on a graphical user interface screen.

An electrical connector assembly positionable in a wellbore includes an upper longitudinal member having an electrical conductor disposed therein; a lower longitudinal member having an electrical conductor disposed therein; a telescoping electrically conductive assembly; and an electrical contact member disposed around and movably contacting the electrical conductor of the lower longitudinal member and movably contacting an inner surface of the upper longitudinal member. The assembly further includes an outer housing including a telescoping portion.

A drilling assembly positionable in a well bore includes a turbine motor couplable to a drill string and a harmonic drive transmission coupled to the turbine motor. The harmonic drive transmission includes a circular spline, a wave generator, a flexspline, and a sealing subsystem. The sealing subsystem defines a substantially sealed volume containing the circular spline, wave generator, and flexspline, and isolates the circular spline, wave generator, and flexspline from drilling fluid exiting the turbine motor and flowing through the harmonic drive transmission.

Down hole harmonic drive transmission

Various embodiments include apparatus and methods that use hand mobile communications device with respect to a drilling operation at a drilling site. Data with respect to one or more sensors downhole at a drilling site can be wirelessly received in the hand mobile communications device. Representations of the received data can be displayed on a graphical user interface screen of the hand mobile communications device. The representations can include displaying the data in a graphical representation, a numerical representation, or a graphical and numerical representation on the graphical user interface screen. Additional apparatus, systems, and methods are disclosed.

Growing community of inventors

Cypress, TX, United States of America

John Kenneth Snyder