Baker Hughes Corporation

Baker Hughes, a Ge Compnay, LLC

Wieland-werke Ag

Hendrik John

Sunil Kumar

Anthony Albert DiGiovanni

Othon Rego Monteiro

Danny Eugene Scott

Harald Grimmer

Claus-Peter Klages

Dan E Scott

Sven Hartwig

Andreas Krafczyk

Thomas Kruspe

Andreas Peter

Michael R Wells

Joachim F Oppelt

Michael Koppe

Hilmar R Mueller

Andreas Boegel

Erik Bartscherer

Frank Michael Keppeler

Klaus Ohla

MacMillian M Wisler

Denis S Kopecki

Sven Van Delden

Jan Tomczak

Jing Xu

Gabriela Wiese

Anthony A Digiovanni

Anthony Digiovanni

Tom Tomczak

A Polycrystalline Diamond Compact (PDC) cutter for a rotary drill bit is provided with an integrated sensor and circuitry for making measurements of a property of a fluid in the borehole and/or an operating condition of the drill bit. A method of manufacture of the PDC cutter and the rotary drill bit is discussed.

PDC sensing element fabrication process and tool

A dispersion includes a carbonaceous nanoparticle, a dispersant including a graft polymer having a poly(alkylene glycol) side chain, and a polar solvent. An article coated with the dispersion and a method of making the dispersion are disclosed.

Dispersion of carbonaceous nanoparticles and method of making the same

A component of a wellbore tool comprises a plurality of compartments disposed over a body of the component and a coating disposed over at least a portion of a surface of the body. Each compartment comprises a healing agent formulated to form or catalyze the formation of a barrier upon release from the compartment. A matrix material separates the plurality of compartments. Methods of forming wellbore tools include forming a body, forming a plurality of capsules, and forming a coating comprising the capsules over the body. Methods of utilizing a wellbore tool in a subterranean borehole include contacting at least a portion of a body with a fluid comprising a healing agent formulated to a barrier. Coatings for wellbore tools include a fiber comprising a plurality of discrete cells and a matrix material contacting and at least partially surrounding the fiber. Each cell comprises a healing agent.

Coatings for wellbore tools, components having such coatings, and related methods

A method for forming a coating upon a wellbore tool includes forming a pattern of features supported by a body and forming a coating over the pattern of features. Forming the pattern of features includes forming a first feature and forming a second feature spaced from the first feature by a first width at a first elevation and by a second width at a second elevation, the second width being different than the first width, and the first elevation being further from an interior region of the body than the second elevation. Also disclosed is a wellbore tool comprising a coating covering a pattern of features and a method of utilizing a wellbore tool in a subterranean formation, the method including forming a pattern of features, forming a coating over the pattern of features, and disposing the wellbore tool in a borehole.

Methods of coating wellbore tools and components having such coatings

An apparatus for measuring strain on a downhole component includes: at least one strain sensitive device disposed proximate to a surface of a component of a drilling assembly or disposed within a material forming the component; and a processor in operable communication with the at least one strain sensitive device, the processor configured to detect changes in the at least one strain sensitive device and detect at least one of erosion, crack formation and crack propagation in the component surface. An apparatus for measuring strain on a downhole component includes: at least one strain gauge deposited on a surface of a drive shaft or disposed within a material forming the drive shaft; and a processor in operable communication with the at least one strain gauge, the processor configured to detect changes in the at least one strain gauge and detect conditions affecting operation of the drive shaft.

Measurement of downhole component stress and surface conditions

A well tool is disclosed. The tool includes a first member having a surface that is configured for exposure to a well fluid, the first member comprising a metallic coating disposed on a substrate, the metallic coating having a plurality of dispersed nanoparticles disposed therein and providing the surface. The tool also includes a second member that is disposed in slidable engagement on the surface of the first member. In another exemplary embodiment, a well tool includes a first member having a surface that is configured for exposure to a well fluid, the first member comprising a metallic alloy, the metallic alloy having a plurality of dispersed nanoparticles disposed therein and providing the surface.

Well tool having a nanoparticle reinforced metallic coating

Articles of manufacture comprise a body. A porous material is plated on the body, the porous material comprising nickel having a plurality of pores disposed in a generally ordered array extending into the nickel. Methods of forming a porous material on a body comprise disposing an anode and a cathode in an electrolyte comprising nickel ions. An electrical signal is pulsed to at least one of the anode and the cathode. A porous material comprising nickel having a plurality of pores generally disposed in an ordered array extending into the nickel is deposited on the cathode.

Porous materials, articles including such porous materials, and methods of making such porous materials

In aspects, the disclosure provides a drilling motor that includes a lubricating unit that selectively supplies a lubricant to the drilling fluid before the drilling fluid passes through the drilling motor so as to lubricate the stator and/or the rotor to reduce friction between the stator and the rotor and to reduce wear of the motor.

Downhole motors with a lubricating unit for lubricating the stator and rotor

An apparatus for forming a wellbore in a formation may include a bit body and a sensor in the bit body. The sensor may include at least one cutting element and may be configured to generate information relating to a parameter of interest when the drill bit engages a wellbore surface.

At-bit evaluation of formation parameters and drilling parameters

The present disclosure relates methods and apparatuses for testing and sampling of underground formations or reservoirs. The apparatus may include at least one extendable element configured to penetrate a formation. The at least one extendable element may include at least one drill bit with a nozzle configured to receive formation fluids. The at least one extendable element may include at least one sensor disposed on the at least one extendable element. The at least one extendable element may also include a source of stimulus for stimulating the formation. The at least one extendable element may be configured to detach and/or attach from/to a bottom hole assembly (BHA). One method may include steps for performing testing on the formation for estimating a parameter of interest of the formation. Another method may include steps for performing testing to estimate a parameter of interest of the formation fluid.

Formation sensing and evaluation drill

A composition including a high temperature thermoplastic polymer and a filler material is disclosed. A method for forming a coating upon a wellbore tool includes forming a powder composition comprising a thermoplastic polymer and a filler material and applying the composition on the body surface. Wellbore tools having components coated with such compositions are also disclosed.

Methods of forming coatings upon wellbore tools

Disclosed are corrosion resistant, non-magnetic austenitic stainless steels containing alloying elements molybdenum, nickel, and copper and further containing small quantities of an additional element selected from the group consisting of a rare-earth element, calcium, cobalt, iridium, osmium, rhenium, rhodium, ruthenium, silver, and a combination thereof.

Pitting corrosion resistant non-magnetic stainless steel

A method for forming a protective coat upon an article includes forming a liquid coating mixture comprising a cross-linking agent and a polymer dissolved within a solvent; applying a first coat of the coating mixture upon the article; evaporating the solvent from the first coat; and cross-linking the article. Also disclosed is a device containing an exterior surface at least partially covered by a coating comprising a cross-linked polymer and a filler material that is selected from the group consisting of a fullerene, a micro-encapsulated material, and a combination of two or more thereof.

Growing community of inventors

Celle, Germany

Hendrik John